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{{#Wiki_filter:Safety Evaluation ReportRelated to the License Renewal of the MonticelloNuclear Generating PlantDocket No. 50-263Nuclear Management Company, LLCU.S. Nuclear Regulatory CommissionOffice of Nuclear Reactor RegulationJuly 2006 THIS PAGE IS INTENTIONALLY LEFT BLANK.
iiiABSTRACTThis safety evaluation report (SER) documents the technical review of the Monticello NuclearGenerating Plant (MNGP) license renewal application (LRA) by the staff of the U.S. NuclearRegulatory Commission (NRC or the staff). By letter dated March 16, 2005, NuclearManagement Company, LLC (NMC or the applicant), submitted the LRA for MNGP in accordance with Title 10, Part 54, "Requirements for Renewal of Operating Licenses for Nuclear Power Plants," of the Code of Federal Regulations (10 CFR Part 54). NMC isrequesting renewal of the operating license for MNGP (Facility Operating License NumberDPR-22) for a period of 20 years beyond the current expiration date of midnight September 8, 2010.MNGP is located approximately 30 miles northwest of Minneapolis, Minnesota. The NRC issuedthe construction permit for MNGP on June 19, 1967. The NRC issued the operating license forMNGP on January 9, 1981. MNGP is a single-cycle, forced circulation, General Electric BWR-3,a boiling-water reactor producing steam for direct use in a steam turbine. General Electric Corporation supplied the nuclear steam supply system and Bechtel Corporation originallydesigned and constructed the balance of the plant. MNGP operates at a licensed power outputof 1775 megawatt thermal (MWt), with a gross electrical output of approximately 600 megawatt electric (MWe).The staff reviewed the MNGP LRA in accordance with Commission regulations and NUREG-1800, "Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants," dated July 2001. Section 6 of this SER provides the staff's conclusion of its review of the MNGP LRA.The NRC license renewal project manager is Mr. Daniel Merzke. Mr. Merzke may be reached at(301) 415-3777. Written correspondence should be addressed to the Division of License Renewal, Mail Stop O-11F1, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001.
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vTABLE OF CONTENTSAbstract.................................................................iiiTable of Contents...........................................................v Abbreviations............................................................xiv 1  Introduction and General Discussion........................................1-11.1  Introduction........................................................1-11.2  License Renewal Background..........................................1-21.2.1  Safety Review.................................................1-3
 
====1.2.2 Environmental====
Review...........................................1-41.3  Principal Review Matters..............................................1-5
 
===1.4 Interim===
Staff Guidance................................................1-61.5  Summary of Open Items..............................................1-81.6  Summary of Confirmatory Items........................................1-8
 
===1.7 Summary===
of Proposed License Conditions................................1-82  Structures and Components Subject to Aging Management Review................2-12.1  Scoping and Screening Methodology....................................2-12.1.1  Introduction...................................................2-12.1.2  Summary of Technical Information in the Application...................2-12.1.2.1  Scoping Methodology.....................................2-22.1.2.2  Screening Methodology...................................2-72.1.3  Staff Evaluation................................................2-82.1.3.1  Scoping Methodology.....................................2-92.1.3.2  Screening Methodology..................................2-202.1.3.3  QA Controls Applied to LRA Development....................2-24 2.1.3.4 Training...............................................2-242.1.4  Conclusion..................................................2-252.2  Plant-Level Scoping Results..........................................2-252.2.1  Introduction..................................................2-252.2.2  Summary of Technical Information in the Application..................2-25
 
====2.2.3 Staff====
Evaluation...............................................2-25 2.2.4  Conclusion..................................................2-272.3  Scoping and Screening Results:  Mechanical Systems......................2-272.3.1  Reactor Vessel, Internals, and Reactor Coolant System................2-282.3.1.1  Reactor Head Vent System...............................2-292.3.1.2  Reactor Pressure Vessel.................................2-30 2.3.1.3  Reactor Pressure Vessel Internals..........................2-32 2.3.1.4  Reactor Recirculation System.............................2-34 2.3.1.5  Reactor Vessel Instrumentation............................2-372.3.2  Engineered Safety Features.....................................2-382.3.2.1  Automatic Pressure Relief System..........................2-39 2.3.2.2  Combustible Gas Control System..........................2-40 2.3.2.3  Core Spray System.....................................2-40 2.3.2.4  High-Pressure Coolant Injection System.....................2-42 vi2.3.2.5  Primary Containment Mechanical System....................2-432.3.2.6  Reactor Core Isolation Cooling System......................2-45 2.3.2.7  Residual Heat Removal System............................2-462.3.2.8  Secondary Containment System...........................2-482.3.3  Auxiliary Systems.............................................2-492.3.3.1  Alternate Nitrogen System................................2-502.3.3.2  Chemistry Sampling System..............................2-51 2.3.3.3  Circulating Water System.................................2-52 2.3.3.4  Control Rod Drive System................................2-54 2.3.3.5  Demineralized Water System..............................2-55 2.3.3.6  Emergency Diesel Generators System......................2-562.3.3.7  Emergency Filtration Train System.........................2-59 2.3.3.8  Emergency Service Water System..........................2-61 2.3.3.9  Fire System...........................................2-63 2.3.3.10  Fuel Pool Cooling and Cleanup System.....................2-712.3.3.11  Heating and Ventilation System...........................2-742.3.3.12  Instrument and Service Air System........................2-772.3.3.13  Radwaste Solid and Liquid System........................2-792.3.3.14  Reactor Building Closed Cooling Water System..............2-85 2.3.3.15  Reactor Water Cleanup System...........................2-862.3.3.16  Service and Seal Water System..........................2-892.3.3.17  Standby Liquid Control System...........................2-912.3.3.18  Wells and Domestic Water System........................2-922.3.4  Steam and Power Conversion System.............................2-932.3.4.1  Condensate Storage System..............................2-932.3.4.2  Condensate and Feedwater System........................2-962.3.4.3  Main Condenser System.................................2-992.3.4.4  Main Steam System....................................2-103 2.3.4.5  Turbine Generator System...............................2-1052.4  Scoping and Screening Results:  Containments, Structures, andComponent Supports..............................................2-1082.4.1  Cranes, Heavy Loads, Rigging..................................2-1092.4.1.1  Summary of Technical Information in the Application..........2-109 2.4.1.2  Staff Evaluation.......................................2-110 2.4.1.3  Conclusion...........................................2-1102.4.2  Diesel Fuel Oil Transfer House..................................2-1102.4.2.1  Summary of Technical Information in the Application..........2-110 2.4.2.2  Staff Evaluation.......................................2-111 2.4.2.3  Conclusion...........................................2-1122.4.3  Emergency Diesel Generator Building............................2-1132.4.3.1  Summary of Technical Information in the Application..........2-113 2.4.3.2  Staff Evaluation.......................................2-114 2.4.3.3  Conclusion...........................................2-1142.4.4  Emergency Filtration Train Building...............................2-1142.4.4.1  Summary of Technical Information in the Application..........2-114 2.4.4.2  Staff Evaluation.......................................2-115 2.4.4.3  Conclusion...........................................2-1162.4.5  Fire Protection Barriers Commodity Group.........................2-1162.4.5.1  Summary of Technical Information in the Application..........2-116 vii2.4.5.2  Staff Evaluation.......................................2-1172.4.5.3  Conclusion...........................................2-1182.4.6  Hangers and Supports Commodity Group.........................2-1182.4.6.1  Summary of Technical Information in the Application..........2-118 2.4.6.2  Staff Evaluation.......................................2-122 2.4.6.3  Conclusion...........................................2-1242.4.7  HPCI Building...............................................2-1242.4.7.1  Summary of Technical Information in the Application..........2-124 2.4.7.2  Staff Evaluation.......................................2-125 2.4.7.3  Conclusion...........................................2-1252.4.8  Intake Structure..............................................2-1252.4.8.1  Summary of Technical Information in the Application..........2-125 2.4.8.2  Staff Evaluation.......................................2-127 2.4.8.3  Conclusion...........................................2-1272.4.9  Miscellaneous SBO Yard Structures..............................2-1272.4.9.1  Summary of Technical Information in the Application..........2-127 2.4.9.2  Staff Evaluation.......................................2-128 2.4.9.3  Conclusion...........................................2-1292.4.10  Offgas Stack...............................................2-1292.4.10.1  Summary of Technical Information in the Application.........2-129 2.4.10.2  Staff Evaluation......................................2-130 2.4.10.3  Conclusion..........................................2-1302.4.11  Offgas Storage and Compressor Building.........................2-1312.4.11.1  Summary of Technical Information in the Application.........2-131 2.4.11.2  Staff Evaluation......................................2-131 2.4.11.3  Conclusion..........................................2-1322.4.12  Plant Control and Cable Spreading Structure......................2-1322.4.12.1  Summary of Technical Information in the Application.........2-132 2.4.12.2  Staff Evaluation......................................2-133 2.4.12.3  Conclusion..........................................2-1332.4.13  Primary Containment.........................................2-1342.4.13.1  Summary of Technical Information in the Application.........2-134 2.4.13.2  Staff Evaluation......................................2-136 2.4.13.3  Conclusion..........................................2-1382.4.14  Radioactive Waste Building...................................2-1382.4.14.1  Summary of Technical Information in the Application.........2-138 2.4.14.2  Staff Evaluation......................................2-139 2.4.14.3  Conclusion..........................................2-1402.4.15  Reactor Building............................................2-1402.4.15.1  Summary of Technical Information in the Application.........2-140 2.4.15.2  Staff Evaluation......................................2-142 2.4.15.3  Conclusion..........................................2-1422.4.16  Structures Affecting Safety....................................2-1432.4.16.1  Summary of Technical Information in the Application.........2-143 2.4.16.2  Staff Evaluation......................................2-144 2.4.16.3  Conclusion..........................................2-1442.4.17  Turbine Building............................................2-1442.4.17.1  Summary of Technical Information in the Application.........2-144 2.4.17.2  Staff Evaluation......................................2-146 viii2.4.17.3  Conclusion..........................................2-1472.4.18  Underground Duct Bank......................................2-1472.4.18.1  Summary of Technical Information in the Application.........2-147 2.4.18.2  Staff Evaluation......................................2-148 2.4.18.3  Conclusion..........................................2-1482.5  Scoping and Screening Results: Electrical and Instrumentation andControls.........................................................2-148
 
====2.5.1 Electrical====
and Instrumentation and Controls Systems.................2-1492.5.1.1  480-V Station Auxiliary..................................2-1502.5.1.2  4.16-kV Station Auxiliary................................2-1512.5.1.3  Alternate Shutdown....................................2-152 2.5.1.4  Annunciators.........................................2-1532.5.1.5  Communications......................................2-154 2.5.1.6  DC Battery...........................................2-155 2.5.1.7  Lighting.............................................2-157 2.5.1.8  Neutron Monitoring.....................................2-158 2.5.1.9  Offsite Power.........................................2-159 2.5.1.10  Plant Protection......................................2-159 2.5.1.11  Radiation Monitoring..................................2-160 2.5.1.12  Reactor Level Control.................................2-161 2.5.1.13  Uninterruptible AC....................................2-1622.5.2  Electrical Commodities........................................2-1632.5.2.1  Electrical Penetrations..................................2-1642.5.2.2  Fuse Holders.........................................2-165 2.5.2.3  Non-EQ Cables and Connections.........................2-1662.5.2.4  Offsite Power/SBO Recovery Path........................2-1672.6  Conclusion for Scoping and Screening.................................2-1683  Aging Management Review Results.........................................3-13.0  Applicant's Use of the Generic Aging Lessons Learned Report................3-13.0.1  Format of the License Renewal Application..........................3-23.0.1.1  Overview of Table 1......................................3-2 3.0.1.2  Overview of Table 2......................................3-33.0.2  Staff's Review Process..........................................3-43.0.2.1  Review of AMPs.........................................3-4 3.0.2.2  Review of AMR Results...................................3-5 3.0.2.3  USAR Supplement.......................................3-63.0.2.4  Documentation and Documents Reviewed....................3-63.0.3  Aging Management Programs.....................................3-63.0.3.1  AMPs That Are Consistent with the GALL Report..............3-103.0.3.2  AMPs That Are Consistent with the GALL Report withExceptions or Enhancements.............................3-303.0.3.3  AMPs That Are Not Consistent with or Not Addressedin the GALL Report....................................3-1283.0.4  Quality Assurance Program Attributes Integral to AgingManagement Programs........................................3-1393.0.4.1  Summary of Technical Information in the Application..........3-140 3.0.4.2  Staff Evaluation.......................................3-141 3.0.4.3  Conclusion...........................................3-141 ix3.1  Aging Management of Reactor Coolant System..........................3-1413.1.1  Summary of Technical Information in the Application.................3-141
 
====3.1.2 Staff====
Evaluation..............................................3-1423.1.2.1  AMR Results That Are Consistent with the GALL Report........3-1493.1.2.2  AMR Results That Are Consistent with the GALL Report,for Which Further Evaluation is Recommended...............3-1513.1.2.3  AMR Results That Are Not Consistent with or NotAddressed in the GALL Report...........................3-1613.1.3  Conclusion.................................................3-1653.2  Aging Management of Engineered Safety Features.......................3-1653.2.1  Summary of Technical Information in the Application.................3-165
 
====3.2.2 Staff====
Evaluation..............................................3-1663.2.2.1  AMR Results That Are Consistent with the GALL Report........3-1703.2.2.2  AMR Results That Are Consistent with the GALL Report,for Which Further Evaluation is Recommended...............3-1723.2.2.3  AMR Results That Are Not Consistent with or NotAddressed in the GALL Report...........................3-1813.2.3  Conclusion.................................................3-1903.3  Aging Management of Auxiliary Systems...............................3-1903.3.1  Summary of Technical Information in the Application.................3-191
 
====3.3.2 Staff====
Evaluation..............................................3-1913.3.2.1  AMR Results That Are Consistent with the GALL Report........3-1973.3.2.2  AMR Results That Are Consistent with the GALL Report,for Which Further Evaluation is Recommended...............3-2003.3.2.3  AMR Results That Are Not Consistent with or NotAddressed in the GALL Report...........................3-2113.3.3  Conclusion.................................................3-2403.4  Aging Management of Steam and Power Conversion System...............3-2403.4.1  Summary of Technical Information in the Application.................3-240
 
====3.4.2 Staff====
Evaluation..............................................3-2403.4.2.1  AMR Results That Are Consistent with the GALL Report........3-2433.4.2.2  AMR Results That Are Consistent with the GALL Report,for Which Further Evaluation is Recommended...............3-2463.4.2.3  AMR Results That Are Not Consistent with or NotAddressed in the GALL Report...........................3-2503.4.3  Conclusion.................................................3-2583.5  Aging Management of Containments, Structures, and Component Supports...............................................................3-2583.5.1  Summary of Technical Information in the Application.................3-258
 
====3.5.2 Staff====
Evaluation..............................................3-2593.5.2.1  AMR Results That Are Consistent with the GALL Report........3-2663.5.2.2  AMR Results That Are Consistent with the GALL Report,for Which Further Evaluation is Recommended...............3-2683.5.2.3  AMR Results That Are Not Consistent with or NotAddressed in the GALL Report...........................3-2813.5.3  Conclusion.................................................3-3053.6  Aging Management of Electrical and Instrumentation and Controls...........3-3053.6.1  Summary of Technical Information in the Application.................3-305
 
====3.6.2 Staff====
Evaluation..............................................3-306 x3.6.2.1  AMR Results That Are Consistent with the GALL Report........3-3083.6.2.2  AMR Results That Are Consistent with the GALL Report,for Which Further Evaluation is Recommended...............3-3103.6.2.3  AMR Results That Are Not Consistent with or NotAddressed in the GALL Report...........................3-3113.6.3  Conclusion.................................................3-3193.7  Conclusion for Aging Management Review Results.......................3-3204  Time-Limited Aging Analyses..............................................4-14.1  Identification of Time-Limited Aging Analyses..............................4-14.1.1  Summary of Technical Information in the Application...................4-1
 
====4.1.2 Staff====
Evaluation................................................4-2 4.1.3  Conclusion...................................................4-24.2  Neutron Embrittlement of the Reactor Vessel and Internals...................4-24.2.1  RPV Materials USE Reduction Due to Neutron Embrittlement............4-34.2.1.1  Summary of Technical Information in the Application............4-3 4.2.1.2  Staff Evaluation.........................................4-4 4.2.1.3  USAR Supplement.......................................4-94.2.1.4  Conclusion.............................................4-94.2.2  Adjusted Reference Temperature (ART) for RPV Materials Dueto Neutron Embrittlement........................................4-9 4.2.2.1  Summary of Technical Information in the Application............4-9 4.2.2.2  Staff Evaluation.........................................4-9 4.2.2.3  USAR Supplement......................................4-104.2.2.4  Conclusion............................................4-104.2.3  Reflood Thermal Shock Analysis of the RPV........................4-104.2.3.1  Summary of Technical Information in the Application...........4-10 4.2.3.2  Staff Evaluation........................................4-10 4.2.3.3  USAR Supplement......................................4-124.2.3.4  Conclusion............................................4-124.2.4  Reflood Thermal Shock Analysis of the RPV Core Shroud..............4-124.2.4.1  Summary of Technical Information in the Application...........4-12 4.2.4.2  Staff Evaluation........................................4-12 4.2.4.3  USAR Supplement......................................4-134.2.4.4  Conclusion............................................4-134.2.5  RPV Thermal Limit Analysis:  Operating Pressure-TemperatureLimits.......................................................4-13 4.2.5.1  Summary of Technical Information in the Application...........4-13 4.2.5.2  Staff Evaluation........................................4-14 4.2.5.3  USAR Supplement......................................4-144.2.5.4  Conclusion............................................4-144.2.6  RPV Circumferential Weld Examination Relief.......................4-154.2.6.1  Summary of Technical Information in the Application...........4-15 4.2.6.2  Staff Evaluation........................................4-15 4.2.6.3  USAR Supplement......................................4-174.2.6.4  Conclusion............................................4-174.2.7  RPV Axial Weld Failure Probability................................4-174.2.7.1  Summary of Technical Information in the Application...........4-17 4.2.7.2  Staff Evaluation........................................4-17 xi4.2.7.3  USAR Supplement......................................4-184.2.7.4  Conclusion............................................4-184.3  Metal Fatigue of the RPV and Internals, and Reactor Coolant Pressure Boundary Piping and Components.....................................4-194.3.1  RPV Fatigue Analyses.........................................4-194.3.1.1  Summary of Technical Information in the Application...........4-19 4.3.1.2  Staff Evaluation........................................4-19 4.3.1.3  USAR Supplement......................................4-204.3.1.4  Conclusion............................................4-204.3.2  Fatigue Analysis of RPV Internals.................................4-214.3.2.1  Summary of Technical Information in the Application...........4-21 4.3.2.2  Staff Evaluation........................................4-21 4.3.2.3  USAR Supplement......................................4-224.3.2.4  Conclusion............................................4-224.3.3  ASME Section III Class 1 Reactor Coolant Pressure Boundary (RCPB) Piping and Fatigue Analysis...............................4-224.3.3.1  Summary of Technical Information in the Application...........4-22 4.3.3.2  Staff Evaluation........................................4-22 4.3.3.3  USAR Supplement......................................4-234.3.3.4  Conclusion............................................4-244.3.4  RCPB Section III Class 2 and 3, Piping and Components..............4-244.3.4.1  Summary of Technical Information in the Application...........4-24 4.3.4.2  Staff Evaluation........................................4-24 4.3.4.3  USAR Supplement......................................4-254.3.4.4  Conclusion............................................4-254.4  Irradiation-Assisted Stress-Corrosion Cracking (IASCC).....................4-254.4.1  Summary of Technical Information in the Application..................4-25
 
====4.4.2 Staff====
Evaluation...............................................4-25 4.4.3  USAR Supplement............................................4-274.4.4  Conclusion..................................................4-274.5  Effects of Reactor Coolant Environment.................................4-274.5.1  Summary of Technical Information in the Application..................4-27
 
====4.5.2 Staff====
Evaluation...............................................4-28 4.5.3  USAR Supplement............................................4-304.5.4  Conclusion..................................................4-304.6  Fatigue Analyses of the Primary Containment, Attached Piping, andComponents......................................................4-304.6.1  Fatigue Analysis of the Suppression Chamber, Vents, andDowncomers.................................................4-31 4.6.1.1  Summary of Technical Information in the Application...........4-31 4.6.1.2  Staff Evaluation........................................4-31 4.6.1.3  USAR Supplement......................................4-314.6.1.4  Conclusion............................................4-314.6.2  Fatigue Analysis of the SRV Piping Inside the SuppressionChamber and Internal Structures.................................4-324.6.2.1  Summary of Technical Information in the Application...........4-32 4.6.2.2  Staff Evaluation........................................4-32 4.6.2.3  USAR Supplement......................................4-324.6.2.4  Conclusion............................................4-33 xii4.6.3  Fatigue Analysis of Suppression Chamber External Piping and Penetrations4-334.6.3.1  Summary of Technical Information in the Application...........4-33 4.6.3.2  Staff Evaluation........................................4-33 4.6.3.3  USAR Supplement......................................4-344.6.3.4  Conclusion............................................4-344.6.4  Drywell-to-Suppression Chamber Vent Line Bellows FatigueAnalysis.....................................................4-34 4.6.4.1  Summary of Technical Information in the Application...........4-34 4.6.4.2  Staff Evaluation........................................4-34 4.6.4.3  USAR Supplement......................................4-354.6.4.4  Conclusion............................................4-354.6.5  Primary Containment Process Penetration Bellows FatigueAnalysis.....................................................4-35 4.6.5.1  Summary of Technical Information in the Application...........4-35 4.6.5.2  Staff Evaluation........................................4-35 4.6.5.3  USAR Supplement......................................4-364.6.5.4  Conclusion............................................4-364.7  Environmental Qualification of Electrical Equipment (EQ)....................4-364.7.1  Summary of Technical Information in the Application..................4-36
 
====4.7.2 Staff====
Evaluation...............................................4-36 4.7.3  USAR Supplement............................................4-394.7.4  Conclusion..................................................4-394.8  Stress Relaxation of Rim Holddown Bolts................................4-394.8.1  Summary of Technical Information in the Application..................4-39
 
====4.8.2 Staff====
Evaluation...............................................4-39 4.8.3  USAR Supplement............................................4-424.8.4  Conclusion..................................................4-434.9  Reactor Building Crane Load Cycles....................................4-434.9.1  Summary of Technical Information in the Application..................4-43
 
====4.9.2 Staff====
Evaluation...............................................4-43 4.9.3  USAR Supplement............................................4-444.9.4  Conclusion..................................................4-454.10  Fatigue Analyses of HPCI and RCIC Turbine Exhaust Penetrations...........4-454.10.1  Summary of Technical Information in the Application.................4-45 4.10.2  Staff Evaluation..............................................4-45 4.10.3  USAR Supplement...........................................4-464.10.4  Conclusion.................................................4-464.11  Conclusion for Time-Limited Aging Analyses............................4-465  Review by the Advisory Committee on Reactor Safeguards.......................5-16  Conclusion............................................................6-1 xiiiAppendicesAppendix A:  Commitments for License Renewal................................A-1Appendix B:  Chronology...................................................B-1Appendix C:  Principal Contributors...........................................C-1Appendix D:  References...................................................D-1TablesTable 3.0.3-1  MNGP's Aging Management Programs.............................3-6Table 3.1-1  Staff Evaluation for Reactor Coolant System Components in the GALL Report................................................................3-143Table 3.2-1  Staff Evaluation for Engineered Safety Features Components in the GALL Report...........................................................3-167Table 3.3-1  Staff Evaluation for Auxiliary Systems Components in the GALL Report...3-192Table 3.4-1  Staff Evaluation for Steam and Power Conversion System Components in the GALL Report......................................................3-241Table 3.5-1  Staff Evaluation for Containments, Structures, and Component Supports in theGALL Report...........................................................3-260Table 3.6-1  Staff Evaluation for Electrical and Instrumentation and Controls Components in the GALL Report...........................................3-307Table 4.2.1-1  Reactor Vessel Upper Shelf Energy Analysis Summary................4-8Table 4.2.6-1  Effects of Irradiation on RPV Circumferential Weld Properties for MNGP..4-16 Table 4.2.7-1  Effects of Irradiation on RPV Axial Weld Properties for MNGP..........4-18 xivABBREVIATIONSACalternating currentACIAmerican Concrete Institute ACRSAdvisory Committee on Reactor Safeguards ADAMSAgencywide Document Access and Management System ADSautomatic depressurization systemAERMaging effect requiring management AFWauxiliary feedwaterAIRinstrument and service air AMAsaging management activities AMGaging management guideline AMPaging management program AMRaging management review AN2alternate nitrogen systemANSIAmerican National Standards Institute APRautomatic pressure relief APRMaverage power range monitor ARaction request ARMarea radiation monitor ARTadjusted reference temperature ASAAmerican Standards Association ASDalternate shutdown ASMEAmerican Society of Mechanical Engineers ASTMAmerican Society for Testing and Materials ATWSanticipated transient without scram AWIadministrative work instructionB&WBabcock and WilcoxBWRboiling-water reactor BWROGBoiling Water Reactor Owners Group BWRVIPBoiling Water Reactor Vessel and Internals ProjectCAPCorrective Action ProgramCASScast austenitic stainless steel CB&IChicago Bridge & Iron CCCWclosed-cycle cooling water CCWclosed cooling water or component cooling water CDRmain condenser CECombustion Engineering
 
CFRCode of Federal RegulationsCFWcondensate and feedwater CGCcombustible gas control CIconfirmatory item CLBcurrent licensing basis CMAACrane Manufacturers Association of America CRcondition report xvCRDcontrol rod driveCRDAcontrol rod drop acci dentCRDMcontrol rod drive mechanismCRGTcontrol rod guide tube CScontainment spray CSPcore spray CSTcondensate storage tank CUFcumulative usage factor CVCSchemical and volume control systemCWcirculating waterDBAdesign-basis accidentDBDdesign-basis document DBEdesign-basis event DCdirect current DGdiesel generator DGNEDG system DOEDepartment of Energy DOLdiesel oil DWSdemineralized water systemECCSemergency core cooling systemECPelectrochemical potential EDGemergency diesel generator EFBemergency filtration train building EFPYeffective full-power years EFTemergency filtration train EMAequivalent margin analysis EOCIElectric Overhead Crane Institute EOLend of license EPRIElectric Power Research Institute EQenvironmental qualification ESFengineered safety feature ESWemergency service waterFACflow-accelerated corrosionFERCFederal Energy Commission, U.S.
 
F enenvironmental fatigue factorFHAfire hazards analysis FIRfire system FPfire protection FPCfuel pool cooling and cleanup
 
FRFederal Registerft-lbfoot-pound FPPfire protection plan FSARfinal safety analysis report FSDfunctional system descriptionFWfeedwater xviGALLgeneric aging lessons learnedGEGeneral Electric GEISGeneric Environmental Impact Statement GLgeneric letter GSIgeneric safety issueHCUhydraulic accumulatorHELBhigh-energy line break HPhorsepower HE/MEhigh energy/moderate energy HEPAhigh efficiency particulate filter HGRhangers and supports HJTCheated junction thermocouple HPBHPCI building HPChigh pressure coolant injection HPCIhigh-pressure coolant injection HTVheating and ventilation HVACheating, ventilation, and air conditioning HWChydrogen water chemistryI&Cinstrumentation and controlsIASCCirradiation assisted stress-corrosion cracking IDinside diameter IEBInspection and Enforcement Bulletin IEEEInstitute of Electrical and Electronics Engineers IFintended function IGAintergranular attack IGSCCintergranular stress-corrosion cracking INinformation notice INPOInstitute of Nuclear Power Operations IPAintegrated plant assessment IRinsulation resistance IRMintermediate range monitor ISAInstrument Society of America ISGinterim staff guidance ISIinservice inspection ISPIntegrated Surveillance Program IWBrequirements for Class 1 components of light-water cooled power plants IWCrequirements for Class 2 components of light-water cooled power plants IWDrequirements for Class 3 components of light-water cooled power plants IWErequirements for Class MC and metallic liners of Class CC components oflight-water cooled power plantsIWFrequirements for Class 1, 2, 3, and MC component supports of light-water cooledpower plantsIWLrequirements for Class CC concrete components of light-water cooled powerplantsksione KIP per square inch, 1000 psiksi-in1/2kilopound per square inch times square root of inches xviikV1000 volts or 1 kilovoltlb/ft 2pound(s) per square footLISLicensing Information Service LLClimited liability com panyLOlubricating oil LLRTlocal leak-rate test LOCAloss-of-coolant accident LOOPloss of offsite power LPlow pressure LPCIlow-pressure coolant injection LPRMlocal power range monitor LRlicense renewal LRAlicense renewal applicationMCCmotor control centerMCRmain control room MEAPmaterial, environment, aging effects, and aging management program MeVmillion electron volts MICmicrobiologically influenced corrosion MNGPMonticello Nuclear Generating Plant MODmotor-operated disconnect MRmaintenance rule MSIVmain steam isolation valve MSTmain steam MTEBNOT DEFINED MUDmakeup demineralizer MVPmechanical vacuum pump MWmegawatts MWemegawatt electric MWhmegawatt hour MWtmegawatt thermaln/cm 2neutrons per square centimeterNDEnondestructive examination NEINuclear Energy Institute NEPANational Environmental Policy Act of 1969 NFPANational Fire Protection Association NMCNuclear Management Company, LLC NMSneutron monitori ng syst emNPSnominal pipe size NRCU.S. Nuclear Regulatory Commission NSRnonsafety-related NSSSnuclear steam suppl y systemNUMARCNuclear Utility Management and Resource CouncilNUREGdesignation of publication prepared by NRC staffOBEoperating-basis earthquake xviiiOCCWopen-cycle cooling water programODSCCoutside-diameter stress-corrosion cracking OEoperating experience OGBoff gas storage and compressor building OGSoff gas stack OIopen itemP&IDpiping and instrumentation diagramPApublic addr ess systemPABplant administration building PASSpost-accident sampli ng syst emPBDprogram-basis document PBXprivate branch exchange PCISprimary containment isolation system PCMprimary containment mechanical PCSprocess computer system PCTprimary containment pHconcentration of hydrogen ions PMpreventive maintenance ppbparts per billion ppmparts per million PPSplant protection system PRMprocess radiation monitor psipounds per square inch psigpounds per square inch gauge P-Tpressure temperature PTpenetrant testing PVCpolyvinyl chloride (plastic)
PWRpressurized-water reactor PWSCCprimary water stress-corrosion crackingQAquality assuranceQCquality control Q-Listquality listRADradwaste solid and liquidRAIrequest for additional information RBCreactor building closed cooling water RBMrod block monitor RCIreactor core isolation cooling RCICreactor core isolation cooling RCPreactor coolant pump RCPBreactor coolant pressure boundary RCSreactor coolant system RECreactor recirculation RGregulatory guide RHRresidual heat removal RI-ISIrisk-informed inservice inspection xixRITreactor internalsRLCreactor level control RPVreactor pressure vessel RSWresidual heat removal service water
 
RTNDTreference temperature nil ductility transitionRVIreactor vessel instrumentation RVIDReactor Vessel Integrity Database RWBradioactive waste building RWCreactor water cleanupSBOstation blackoutSCstructure and component SCBAself-contained breathing apparatus SCCstress-corrosion cracking SCTsecondary containment SEsafety evaluation SERsafety evaluation report SFPspent fuel pool SIsafety injection SILservice information letter SJAEsteam jet air ejector SLCstandby liquid control SMAWshield metal arc weld SOERsignificant operating event report SPCsteam and power conversion SPDSsafety parameter display system SRsafety-related SRMsource range monitor SRPStandard Review Plan SRP-LRStandard Review Plan for Review of License Renewal Applications for NuclearPower PlantsSRVsafety relief valve SSCsystem, structure, or componentSSWservice & seal water SWservice waterTACtechnical assignment control (internal NRC work management tool)TAPtorus attached piping TASCSthermal stratification, cycling, and striping TGSCCtransgranular stress-corrosion cracking TLAAtime-limited aging analysis TRtopical report TStechnical specification TTthermal transientUACuninterruptible alternating currentµmmicrometer UDBunderground duct bank UPSuninterruptible power supply xxUSARUpdated Safety Analysis ReportUSASUnited States of America Standards USEupper-shelf energy UTultrasonic testing UVultravioletVACvolts-alternating currentVDCvolts-direct current VTvisual examinationWDWwell and domestic waterWOwork orderXLPEcross-linked polyethylene 1-1SECTION 1INTRODUCTION AND GENERAL DISCUSSION1.1  IntroductionThis document is a safety evaluation report (SER) on the application for license renewal (LR)for the Monticello Nuclear Generating Plant (MNGP), as filed by the Nuclear Management Company, LLC (NMC or the applicant). By letter dated March 16, 2005, NMC submitted its application to the U.S. Nuclear Regulatory Commission (NRC or the Commission) for renewalof the MNGP operating license for an additional 20 years. The NRC staff (the staff) preparedthis report, which summarizes the results of its safety review of the renewal application for compliance with the requirements of Title 10, Part 54, "Requirements for Renewal of OperatingLicenses for Nuclear Power Plants," of the Code of Federal Regulations (10 CFR Part 54). TheNRC license renewal project manager for the MNGP license renewal review is Daniel Merzke.Mr. Merzke can be contacted by telephone at 301-415-3777 or by electronic mail at DXM2@nrc.gov. Alternatively, written correspondence may be sent to the following address:Division of License RenewalU.S. Nuclear Regulatory Commission Washington, DC  20555-0001 Attention:  Daniel Merzke, Mail Stop 0-11F1In its March 16, 2005, submittal letter, the applicant requested renewal of the operating licenseissued under Section 104b (Operating License No. DPR-22) of the Atomic Energy Act of 1954, as amended, for MNGP, for a period of 20 years beyond the current license expiration date of midnight September 8, 2010. MNGP is located approximately 30 miles northwest of Minneapolis, Minnesota. The NRC issued the construction permit for MNGP on June 19, 1967.The NRC issued the operating license for MNGP on January 9, 1981. MNGP is a single-cycle,forced circulation, General Electric BWR-3, boiling-water reactor producing steam for direct usein a steam turbine. General Electric Corporation supplied the nuclear steam supply system andBechtel Corporation originally designed and constructed the balance of the plant. MNGP operates at a licensed power output of 1775 megawatt thermal (MWt), with a gross electrical output of approximately 600 megawatt electric (MWe). The Updated Safety Analysis Report (USAR) contains details concerning the plant and the site.The license renewal process consists of two concurrent reviews-a technical review of safetyissues and an environmental review. The NRC regulations found in 10 CFR Part 54 and 10CFR Part 51, "Environmental Protection Regulations for Domestic Licensing and Related Regulatory Functions," respectively, set forth the requirements for these reviews. The safety review for the MNGP license renewal is based on the applicant's license renewal application (LRA) and on its responses to the staff's requests for additional information (RAIs). The applicant supplemented and clarified its responses to the LRA and RAIs in audits, meetings, and docketed correspondence. The staff reviewed and considered all information submitted in support of the LRA. The public may view the LRA and all pertinent information and materials, including the USAR mentioned above, at the NRC Public Document Room, located in OneWhite Flint North, 11555 Rockville Pike (first floor), Rockville, MD 20852-2738(301-415-4737/800-397-4209), and at the Monticello Public Library, 200 West 6 th Street, 1-2Monticello, MN 55362. In addition, the public may find the MNGP LRA, as well as materialsrelated 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 MNGP LRA and describesthe 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 staffreviewed the LRA in accordance with NRC regulations and the guidance provided inNUREG-1800, "Standard Review Plan for Review of License Renewal Applications for NuclearPower Plants" (SRP-LR), dated July 2001.Sections 2 through 4 of this SER address the staff's review and evaluation of license renewalissues that it considered during the review of the application. Section 5 is reserved for the reportof the Advisory Committee on Reactor Safeguards (ACRS). Section  6 provides the conclusions of this report.Appendix A to this SER is a table that identifies the applicant's commitments associated withthe renewal of the operating license. Appendix B provides a chronology of the principal correspondence between the NRC and the applicant related to the review of the application.Appendix C is a list of principal contributors to the SER. Appendix D is a bibliography of the references used in support of the review.In accordance with 10 CFR Part 51, the staff prepared a draft plant-specific supplement to theGeneric Environmental Impact Statement (GEIS). This supplement discusses the environmental considerations related to renewing the license for MNGP. The staff issued draft Supplement 26 to NUREG-1437, "Generic Environmental Impact Statement for LicenseRenewal of Nuclear Plants Regarding Monticello Nuclear Generating Plant (NUREG-1437,Supplement 26) Draft Report for Comment," on
.1.2  License Renewal Backgr oundPursuant to Section 103c of the Atomic Energy Act of 1954, as amended, and NRC regulations(10 CFR 50.51(a)), operating licenses for commercial power reactors are issued for 40 years.
Pursuant to 10 CFR 54.31(b), these licenses can be renewed for up to 20 additional years. The original 40-year license term was selected on the basis of economic and antitrust considerations, rather than on technical limitations; however, some individual plant and equipment designs may have been engineered on the basis of an expected 40-year service life.In 1982, the NRC anticipated interest in license renewal and held a workshop on nuclear powerplant aging. This workshop led the NRC to establish a comprehensive program plan for nuclearplant aging research. On the basis of the results of that research, a technical review group concluded that many aging phenomena are readily manageable and do not pose technical issues that would preclude life extension for nuclear power plants. In 1986, the NRC publisheda 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 NRC published the license renewal rule in 10 CFR Part 54 (the Rule) (Volume 56,page 64943, of the Federal Register (56 FR 64943), dated December 13, 1991). The NRCparticipated in an industry-sponsored demonstration program to apply the Rule to a pilot plant 1-3and to gain experience necessary to develop implementation guidance. To establish a scope ofreview for license renewal, the Rule defined age-related degradation unique to license renewal; however, during the demonstration program, the NRC found that many aging mechanismsoccur and are managed during the period of initial license. In addition, the NRC f ound that thescope of the review did not allow sufficient credit for existing programs, particularly the implementation of the Maintenance Rule, which also manages plant-aging phenomena. As aresult, the NRC amended the Rule 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, andmore predictable than the previous Rule. In particular, the NRC amended 10 CFR Part 54 tofocus on managing the adverse effects of aging, rather than on identifying age-related degradation unique to license renewal. The NRC initiated these rule changes to ensure thatimportant systems, structures, and components (SSCs) will continue to perform their intendedfunctions during the period of extended operation. In addition, the revised Rule clarified andsimplified the integrated plant assessment (IPA) process to be consistent with the revised focuson 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 environmental impacts of license renewal and to fulfill the NRC's responsibilities underthe National Environmental Policy Act of 1969 (NEPA).1.2.1  Safety Review License renewal requirements for power reactors are based on two key principles:(1)The regulatory process is adequate to ensure that the licensing bases of all currentlyoperating plants provide and maintain an acceptable level of safety, with the possible exception of the detrimental effects of aging on the functionality of certain SSCs, as well as a few other safety-related (SR) issues, during the period of extended operation.(2)The plant-specific licensing basis must be maintained during the renewal term in thesame manner and to the same extent as during the original licensing term.In implementing these two principles, 10 CFR 54.4, "Scope," defines the scope of licenserenewal as including those SSCs (1) that are SR, (2) whose failure could affect SR functions, and (3) that are relied on to demonstrate compliance with the NRC's regulations for fireprotection (FP), environmental qualification (EQ), pressurized thermal shock (PTS), anticipated transient without scram (ATWS), and station blackout (SBO).Pursuant to 10 CFR 54.21(a), an applicant for a renewed license must review all SSCs that arewithin the scope of the Rule to identify SCs that are subject to an aging management review (AMR). Those SCs that are subject to an AMR perform an intended function without moving parts, or without a change in configuration or properties, and are not subject to replacement based on qualified life or specified time period. As required by 10 CFR 54.21(a), an applicant for a renewed license must demonstrate that the effects of aging will be managed in such a waythat the intended function, or functions, of those SCs will be maintained, consistent with thecurrent licensing basis (CLB), for the period of extended operation; however, active equipment is considered to be adequately monitored and maintained by existing programs. In other words, the detrimental effects of aging that may affect active equipment are more readily detectable 1-4and can be identified and corrected through routine surveillance, performance monitoring, andmaintenance activities. The surveillance and maintenance activities programs for activeequipment, as well as other aspects of maintaining the plant's design and licensing basis, are required throughout the period of extended operation.Pursuant to 10 CFR 54.21(d), each LRA is required to include a supplement to the USAR. Thissupplement must contain a summary description of the applicant's programs and activities for managing the effects of aging and the evaluation of time-limited aging analyses (TLAAs) for the period of extended operation.License renewal also requires the identification and updating of the TLAAs. During the designphase for a plant, certain assumptions are made about the length of time the plant can operate.
These assumptions are incorporated into design calculations for several of the plant's SSCs. In accordance with 10 CFR 54.21(c)(1), the applicant must either show that these calculations willremain valid for the period of extended operation, project the analyses to the end of the periodof extended operation, or demonstrate that the effects of aging on these SSCs can beadequately managed for the period of extended operation.In 2001, the NRC developed and issued Regulatory Guide (RG) 1.188, "Standard Format andContent for Applications to Renew Nuclear Power Plant Operating Licenses." This RG endorses NEI 95-10, Revision 3, "Industry Guideline for Implementing the Requirements of 10 CFR Part 54-The License Renewal Rule," which the Nuclear Energy Institute (NEI) issued in March 2001. NEI 95-10 details an acceptable method of implementing the license renewal rule. TheNRC also used the SRP-LR to review this application.In the LRA, MNGP fully utilizes the process defined in NUREG-1801, "Generic Aging LessonsLearned (GALL) Report," issued in July 2001. The GALL Report provides a summary of staff-approved aging management programs (AMPs) for the aging of many SCs that are subject to an AMR. If an applicant commits to implementing these staff-approved AMPs, the time, effort, and resources used to review an applicant's LRA can be greatly reduced, thereby improving the efficiency and effectiveness of the license renewal review process. The GALL Report summarizes the aging management evaluations, programs, and activities credited for managing aging for most of the SCs used throughout the industry. The report also serves as a reference for both applicants and staff reviewers to quickly identify those AMPs and activities that the staff has determined can provide adequate aging management during the period ofextended operation.1.2.2  Environmental Review In December 1996, the staff revised the environmental protection regulations to facilitate theenvironmental review for license renewal. The staff prepared NUREG-1437, Revision 1,"Generic Environmental Impact Statement for License Renewal of Nuclear Plants,"  to document its evaluation of the possible environmental impacts associated with renewing licenses of nuclear power plants. For certain types of environmental impacts, the GEIS establishes generic findings that are applicable to all nuclear power plants. These generic findings are codified in Appendix B, "Environmental Effect of Renewing the Operating Licenseof 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), an 1-5applicant for license renewal may incorporate these generic findings in its environmental report.In accordance with 10 CFR 51.53(c)(3)(ii), an environmental report must also include analyses of those environmental impacts that must be evaluated on a plant-specific basis (i.e.,
Category 2 issues).In accordance with NEPA and the requirements of 10 CFR Part 51, the NRC performed aplant-specific review of the environmental impacts of license renewal, including whether new and significant information existed that the GEIS did not consider. As part of its scoping process, the NRC held a public meeting on June 30, 2005, in Monticello, Minnesota, to identifyenvironmental issues specific to the plant. The NRC's draft plant-specific Supplement 26 to theGEIS regarding MNGP documents the results of the environmental review and includes a preliminary recommendation with respect to the license renewal action. The NRC held anotherpublic meeting on March 22, 2006, in Monticello, Minnesota, to discuss the draft plant-specificSupplement 26 to the GEIS regarding MNGP. After considering comments on the draft, the NRC will prepare and publish a final, plant-specific supplement to the GEIS separately from thisreport.1.3  Principal Review MattersTitle 10, Part 54, of the Code of Federal Regulations describes the requirements for renewingoperating licenses for nuclear power plants. The staff performed its technical review of the MNGP LRA in accordance with NRC guidance and the requirements of 10 CFR Part 54.Title 10, Section 54.29, "Standards for Issuance of a Renewed License," of the Code of FederalRegulations sets forth the standards for renewing a license. This SER describes the results ofthe staff's safety review.In 10 CFR 54.19(a), the NRC requires a license renewal applicant to submit generalinformation. The applicant provided this general information in Section 1 of its LRA for MNGP, which it submitted to the NRC by letter dated March 16, 2005. The staff reviewed Section 1 andfound that the applicant had submitted the information required by 10 CFR 54.19(a).In 10 CFR 54.19(b), the NRC requires that each LRA include "conforming changes to thestandard indemnity agreement, 10 CFR 140.92, Appendix B to account for the expiration term of the proposed renewed license." The applicant stated the following in the LRA regarding thisissue:The current indemnity agreement No. B-42 for the Monticello Nuclear GeneratingPlant states that the agreement shall terminate at the time of expiration of thelicense.The indemnity agreement lists DPR-22 as the applicable license number. Shouldthe license number be changed upon issuance of the renewed license, NMC requests that conforming changes be made to the indemnity agreement as appropriate.The staff intends to maintain the original license number upon issuance of the renewed license.Therefore, conforming changes to the indemnity agreement do not need to be made, and the requirements of 10 CFR 54.19(b) have been met.
1-6In 10 CFR 54.21, "Contents of Application-Technical Information," the NRC requires that eachLRA must contain (a) an IPA, (b) a description of any CLB changes that occurred during the staff review of the LRA, (c) an evaluation of TLAAs, and (d) an FSAR (Final Safety Analysis Report) supplement. Sections 3 and 4 and Appendix B to the LRA address the license renewal requirements of 10 CFR 54.21(a), (b), and (c). Appendix A to the LRA contains the USAR supplement required by 10 CFR 54.21(d).In 10 CFR 54.21(b), the NRC requires that each year following submission of the LRA, and atleast 3 months before the scheduled completion of the staff's review, the applicant must submit an amendment to the renewal application that identifies any changes to the CLB of the facilitythat materially affect the contents of the LRA, including the USAR supplement. The applicantsubmitted an update to the LRA by letter dated March 15, 2006, which summarized the changes to the CLB that had occurred at MNGP during the staff's review of the LRA. Thissubmission satisfies the requirements of 10 CFR 54.21(b) and is st ill under staff review.In accordance with 10 CFR 54.22, "Contents of Application-Technical Specifications," anapplicant's LRA must include changes or additions to the technical specifications (TSs) that are necessary to manage the effects of aging during the period of extended operation. In Appendix D to the LRA, the applicant stated that it had not identified any TS changes necessaryto support issuance of the renewed operating license for MNGP. This adequately addresses the requirement specified in 10 CFR 54.22.The staff evaluated the technical information required by 10 CFR 54.21 and 10 CFR 54.22 inaccordance with NRC regulations and the guidance provided by the SRP-LR. Sections 2, 3, and4 of this SER document the staff's evaluation of the technical information contained in the LRA.The final plant-specific supplement to the GEIS will document the staff's evaluation of theenvironmental information required by 10 CFR 54.23, "Contents of Application-EnvironmentalInformation," and will specify the considerations related to renewing the license for MNGP. Thestaff will prepare this supplement separately from this SER.1.4  Interim Staff GuidanceThe license renewal program is a living program. The NRC staff, industry, and other interestedstakeholders gain experience and develop lessons learned with each renewed license. The lessons learned address the NRC's performance goals of safety, openness, and effectiveness.Interim staff guidance (ISG) is documented for use by the NRC staff, industry, and otherinterested stakeholders until it is incorporated into license renewal guidance documents, such as the SRP-LR and the GALL Report.Table 1.4-1 provides the current set of ISGs issued by the staff, as well as the SER sections inwhich the staff addresses them.
1-7Table 1.4-1  Current Interim Staff GuidanceISG Issue(Approved ISG No.)PurposeSER SectionGALL Report presents oneacceptable way to manage agingeffects(ISG-1)This ISG clarifies that the GALLReport contains one acceptableway, but not the only way, tomanage aging for license renewal.N/ASBO Scoping(ISG-2)The license renewal rule10 CFR 54.4(a)(3) includes10 CFR 50.63(a)(1)-SBO.The SBO rule requires that a plantmust withstand and recover froman SBO event. The recovery timefor offsite power is much fasterthan that of EDGs.The offsite power system should beincluded within the scope of licenserenewal.Concrete AMP(ISG-3)Lessons learned from the GALLdemonstration project indicate thatGALL is not clear on whetherconcrete requires an AMP.FP System Piping(ISG-4)This ISG clarifies the staff positionfor wall-thinning of the FP pipingsystem in GALL AMPs XI.M26 andXI.M27.The staff's new position is thatthere is no need to disassemble FPpiping, as disassembly canintroduce oxygen to FP piping,which can accelerate corrosion.Instead, a nonintrusive method,such as volumetric inspection, canbe used.Testing of sprinkler heads shouldbe performed at year 50 ofsprinkler system service life, andevery 10 years thereafter.This ISG eliminates thehalon/carbon dioxide systeminspections for charging pressure,valve lineups, and the automaticmode of operation test from GALL;the staff considers these testverifications to be operationalactivities.
ISG Issue(Approved ISG No.)PurposeSER Section1-8Identification and Treatment ofElectrical Fuse Holders(ISG-5)This ISG includes electrical fuseholders AMR and AMP (i.e., sameas terminal blocks and otherelectrical connections).The position includes only fuseholders that are not inside theenclosure of active components(e.g., inside of switchgears andinverters).Operating experience finds thatmetallic clamps (spring-loadedclips) have a history of age-relatedfailures from aging stressors suchas vibration, thermal cycling,mechanical stress, corrosion, andchemical contamination.The staff finds that visualinspection of fuse clips is notsufficient to detect the aging effectsfrom fatigue, mechanical stress,and vibration.The ISG Process(ISG-8)This ISG clarifies and updates theISG process on improved licenserenewal guidance documents.N/AStandardized Format for LicenseRenewal Applications(ISG-10)This ISG provides a standardizedLRA format for applicants.N/A1.5  Summary of Open ItemsAn open item (OI) is an issue that, in the staff's judgment, has not been resolved in a mannerthat meets all applicable regulatory requirements. The NRC issued the initial SER on April 26,2006, with no OIs. The staff did not identify any subsequent open items in preparing the final SER.1.6  Summary of Confirmatory ItemsA confirmatory item (CI) is an issue that the applicant and the staff have resolved, but for whichthe applicant has not yet formally submitted the resolution. The NRC issued the initial SER onApril 26, 2006, with no CIs. The staff did not identify any subsequent CIs in preparing the finalSER.1.7  Summary of Proposed License ConditionsAs a result of the staff's review of the LRA for MNGP, including subsequent information andclarifications provided by the applicant, the staff identified three proposed license conditions.
1-9The first license condition requires the applicant to include the USAR supplement required by10 CFR 54.21(d) in the next USAR update, as required by 10 CFR 50.71(e), following the issuance of the renewed license.The second license condition requires that the list of commitments identified in Appendix A tothis SER be completed in accordance with the schedule in Appendix A.The third license condition requires that all capsules placed in storage must be maintained forfuture insertion. Any changes to storage requirements must be approved by the NRC, asrequired by 10 CFR Part 50, Appendix H.
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2-1SECTION 2STRUCTURES AND COMPONENTS SUBJECT TO AGINGMANAGEMENT REVIEW2.1  Scoping and Screening Methodology2.1.1  IntroductionTitle 10, Section 54.21, "Contents of Application-Technical Information," of the Code ofFederal Regulations (10 CFR 54.21) requires that each license renewal application (LRA)contain an integrated plant assessment (IPA). Furthermore, the IPA must list and identifystructures and components (SCs) subject to an aging management review (AMR) from all of the systems, structures, and components (SSCs) within the scope of license renewal inaccordance with 10 CFR 54.4, "Scope."In LRA Section 2.1, "Scoping and Screening Methodology," the applicant described the scopingand screening methodology used to identify SSCs at the Monticello Nuclear GeneratingPlant (MNGP) within the scope of license renewal and the SCs subject to an AMR. The staff reviewed the applicant's scoping and screening methodology to determine whether it meets thescoping requirements stated in 10 CFR 54.4(a) and the screening requirements stated in10 CFR 54.21.In developing the scoping and screening methodology for the MNGP LRA, the applicantconsidered the requirements of 10 CFR Part 54, "Requirements for Renewal of OperatingLicenses for Nuclear Power Plants," (the Rule), the Statements of Consideration for the Rule,and the guidance presented by the Nuclear Energy Institute (NEI), in NEI 95-10, Revision 4, "Industry Guideline for Implementing the Requirements of 10 CFR Part 54-The License Renewal Rule."  In developing this methodology, the applicant also considered the correspondence between the U.S. Nuclear Regulatory Commission (NRC or the staff) and otherapplicants or NEI.2.1.2  Summary of Technical Information in the Application In LRA Sections 2 and 3, the applicant provided the technical information required by10 CFR 54.21(a). In LRA Section 2.1, the applicant described the process used to identifySSCs that meet the license renewal scoping criteria under 10 CFR 54.4(a), as well as the process used to identify SCs subject to an AMR, pursuant to 10 CFR 54.21(a)(1).Additionally, LRA Sections 2.2, "Plant Level Scoping Results," 2.3, "System Scoping andScreening Results: Mechanical Systems," 2.4, "Scoping and Screening Results: Containments, Structures, and Component Supports," and 2.5, "Scoping and Screening Results: Electrical and Instrumentation and Controls Systems," amplify the process the applicant used to identify SCssubject to an AMR. LRA Section 3, "Aging Management Review Results," contains the following information:
2-2
* Section 3.1, "Aging Management of Reactor Coolant System"
* Section 3.2, "Aging Management of Engineered Safety Features"
* Section 3.3, "Aging Management of Auxiliary Systems"
* Section 3.4, "Aging Management of Steam and Power Conversion System"
* Section 3.5, "Aging Management of Containments, Structures, and ComponentSupports"
* Section 3.6, "Aging Management of Electrical and Instrumentation and Controls" LRA Section 4, "Time-Limited Aging Analyses," contains the applicant's identification andevaluation of time-limited aging analyses.2.1.2.1  Scoping Methodology In LRA Section 2.1, the applicant described the methodology used to scope SSCs, pursuant tothe 10 CFR 54.4(a) scoping criteria. The following sections present the applicant's scoping methodology, as described in the LRA.2.1.2.1.1  Application of the Scoping Criteria in 10 CFR 54.4(a)The applicant described the general approach to scoping safety-related (SR) andnonsafety-related (NSR) SSCs and SSCs credited with demonstrating compliance with certain regulated events in LRA Section 2.1.2, "Application of Scoping Criteria in 10 CFR 54.4(a)." Thefollowing sections describe the scoping approaches specific to each of the three 10 CFR 54.4(a) scoping criteria.Application of the Scoping Criterion in 10 CFR 54.4(a)(1)In LRA Section 2.1.4.2.1, "Scoping Criterion 1-Safety Related SSCs," the applicant presentedits scoping methodology as it pertains to SR criteria pursuant to 10 CFR 54.4(a)(1). The applicant used MNGP Q-List and Q-List Extension color-coded drawings to code items as SR in the MNGP plant equipment electronic database (CHAMPS), which also served as one of a number of information sources in the current licensing basis (CLB) used to identify SSCs meeting Scoping Criterion 1. For example, information from the Updated Safety Analysis Report (USAR), technical specifications (TSs), and design documents was reviewed to ensure all major system and structure functions had been identified properly. These functions werecompared to Scoping Criterion 1 to identify SSCs within the scope of license renewal which are relied upon to remain functional during and following design-basis events (DBEs).CHAMPS and controlled drawings were used to identify components required to supportsystem-level and structure-level functions within the scope of license renewal. Thosecomponents included within the scope of license renewal generally matched information in CHAMPS. Differences noted were documented and resolved.
2-3Application of the Scoping Criterion in 10 CFR 54.4(a)(2)In LRA Section 2.1.4.2.2, "Non-Safety Related Affecting Safety Related," the applicantpresented the scoping methodology as it related to the NSR criteria pursuant to 10 CFR 54.4(a)(2). The applicant stated that MNGP SSCs meeting Scoping Criterion 2 weregrouped into three categories, (1) CLB topics, (2) NSR SSCs directly connected to Scoping Criterion 1 SSCs (typically piping systems), or (3) NSR SSCs not directly connected to ScopingCriterion 1 SSCs, but whose failure could prevent, as a result of spatial proximity, the satisfactory accomplishment of a Scoping Criterion 1 function. SSCs meeting Scoping Criterion 2 in the first two categories typically were identified during document reviews, including the MNGP USAR, plant drawings, design documents, piping analyses, CHAMPS, and other CLB documents. SSCs in the third category typically were identified by both document reviews and extensive plant walkdowns to identify spatial interactions meeting broader criteria for license renewal.CLB Topics A review of the MNGP CLB identified NSR SSCs with preventive or mitigative functionssupporting safe shutdown, the failure of which could prevent satisfactory accomplishment of a Scoping Criterion 1 function. High-energy line breaks (HELB), internal and external flooding events, internal and external missile hazards, overhead handling systems, and seismicinteractions were evaluated. NSR SSCs were placed within the scope of license renewal as a result of this review if their failure could adversely affect an SR SSC.NSR SSCs Directly Connected to Scoping Criterion 1 SSCs NSR SSCs directly connected to Scoping Criterion 1 SSCs (typically pipi ng systems) andcomponent supports required to prevent NSR SSCs from physical interaction with SR SSCs are within the scope of license renewal. All piping supports in buildings with Scoping Criterion 1 components are within the scope of license renewal. The LRA describes the applicable supports as those that must remain in place so they do not prevent equipment required toperform intended functions from performing them. SCs within the scope of license renewal extend into the NSR portion of the piping and supports up to and including the first equivalent anchor beyond the safety/nonsafety interface, that point beyond which failure of the pipingsystem will not prevent satisfactory performance of Scoping Criterion 1 functions of connectedSSCs. The piping components and supports up to and including the first equivalent anchor are within the scope of license renewal.NSR structures attached or next to Scoping Criterion 1 structures are within the scope oflicense renewal if their failure could prevent a Scoping Criterion 1 SSC from performing its intended function.NSR SSCs Not Directly Connected to Scoping Criterion 1 SSCs NSR SSCs not directly connected, but in spatial proximity, to Criterion 1 SSCs whose failurecould prevent the satisfactory accomplishment of a Criterion 1 function are within the scope of license renewal. The LRA states that both spray (pressurized liquid or steamlines) and leaks (nonpressurized liquid lines) were evaluated for their impact on Scoping Criterion 1 components without regard to whether the Scoping Criterion 1 components were active or passive and 2-4without regard to the duration of the spray or leak. All pressurized liquid systems in the generalarea of Scoping Criterion 1 components are within the scope of license renewal and assumed to leak anywhere around the circumference or along the length of the pipe. All nonpressurized liquid systems directly above Scoping Criterion 1 components are also within the scope oflicense renewal. Leaks were assumed to occur anywhere along the length of the piping system.Air and gas systems are not included within the scope of license renewal becaus e they do notcontain NSR components whose failure could prevent satisfactory accomplishment of Scoping Criterion 1 functions. Site-specific operating experience was reviewed to verify that MNGP air/gas systems have not affected other plant equipment negatively. The applicant's review ofindustry operating experience also revealed no events of this nature. Because none of the air/gas lines are high-energy lines and all supports in buildings with Scoping Criterion 1 components are within the scope of license renewal, air/gas systems are not ScopingCriterion 2 items.NSR conduits, cable trays, junction boxes, or lighting fixtures may contain or be routed nearScoping Criterion 1 cables or other components; therefore, all NSR conduits, trays, junction boxes, and lighting fixtures and their supports located within structures housing SR equipment are within the scope of license renewal. Additionally, conduits, trays, junction boxes, and lighting fixtures and their supports required for regulated events located in structures not housing Scoping Criterion 1 equipment are within the scope of license renewal.Though most heating, ventilation, and air conditioning (HVAC) ducts and their supports areNSR, they are located throughout the plant, typically along ceilings, and thus above manyScoping Criterion 1 SSCs. Like air/gas pipe systems, HVAC ducts are not hazards to other plant equipment. Falling is a concern; therefore, all HVAC duct supports located withinstructures housing Scoping Criterion 1 components are within the scope of license renewal.Application of the Scoping Criterion in 10 CFR 54.4(a)(3)In LRA Section 2.1.4.2.3, "Scoping Criterion 3-Other Regulations Identified in 10 CFRPart 54," the applicant discussed the methodology used to identify SSCs credited with functionsthat demonstrate compliance with regulations for fire protection (FP), environmental qualification (EQ), anticipated transients without scram (ATWS), and station blackout (SBO),pursuant to the 10 CFR 54.4(a)(3) license renewal scoping criteria. The applicant did not evaluate pressurized thermal shock because it is not applicable to boiling-water reactors (BWRs).Fire Protection In LRA Section 2.1.4.2.4, "Fire Protection," the applicant described the scoping of SSCs reliedon to perform functions that demonstrate compliance with 10 CFR 50.48, "Fire Protection";
Appendix R, "Fire Protection Program for Nuclear Power Facilities Operating Prior to January 1,1979," to 10 CFR Part 50, "Domestic Licensing of Production and Utilization Facilities"; andcommitments made in response to Appendix A to NRC Branch Technical Position APCSB 9.5-1, "Guidelines for Fire Protection for Nuclear Power Plants Docketed Prior to July 1, 1976." The applicant stated that a detailed evaluation of the CLB, including CHAMPS, the safe-shutdownanalysis, the fire hazards analysis, plant drawings, the USAR, and the operations manual was 2-5performed for FP, and SSCs supporting either FP design features or safe shutdown followingpostulated fires are within the scope of license renewal.Environmental Qualification In LRA Section 2.1.4.2.5, "Environmental Qualification," the applicant described the scoping ofSSCs relied on to perform functions that demonstrate compliance with 10 CFR 50.49, "Environmental Qualification of Electric Equipment Important to Safety for Nuclear Power Plants," which defines electric equipment important to safety that is required to be environmentally qualified to mitigate certain accidents that would result in harsh environmental plant conditions. The applicant stated that components that meet the requirements of10 CFR 50.49 are identified on the EQ Master List. All equipment identified on the EQ MasterList supporting the MNGP CLB was included within the scope of license renewal as components or commodities, pursuant to 10 CFR 54.4(a)(3).Anticipated Transients without Scram (ATWS)
In LRA Section 2.1.4.2.7, "Anticipated Transients without Scram," the applicant described thescoping of SSCs relied on to perform functions that demonstrate compliance with the ATWS requirements of 10 CFR 50.62, "Requirements for Reduction of Risk from Anticipated Transients Without Scram (ATWS) Events for Light-Water-Cooled Nuclear Power Plants."  Theapplicant stated that the MNGP design features related to ATWS are within the scope of licenserenewal because they are relied on to meet 10 CFR 50.62 requirements. The applicant statedthat ATWS mitigation is accomplished by the use of three systems, (1) the alternate rodinjection subsystem, (2) the standby liquid control system, and (3) the recirculation pump tripsystem. Based on a review of the CLB, plant and vendor drawings, the USAR, docketedcorrespondence, modifications, and CHAMPS, the components relied upon to mitigate ATWS events were determined to be within the scope of license renewal.Station Blackout In LRA Section 2.1.4.2.8, "Station Blackout," the applicant described the scoping of SSCs reliedon to perform functions that demonstrate compliance with the requirements of 10 CFR 50.63, "Loss of Alternating Current Power."  The applicant stated that, based on the review of plant-specific SBO calculations, the USAR, plant drawings, modifications, and CHAMPS, the components relied upon to mitigate SBO were determined to be within the scope of license renewal.2.1.2.1.2  Documentation Sources Used for Scoping and ScreeningIn LRA Section 2.1.3, "Plant Information Sources," the applicant stated that it had evaluatedinformation from the following sources during the license renewal scoping and screening process:
* USAR
* CLB information including TSs and docketed licensing correspondence
* design-basis documents (DBDs) 2-6
* Q-List and Q-List Extension
* controlled drawing file
* industry codes, standards, and regulations
* technical correspondence, analyses, and reports
* calculations
* plant modifications and alterations
* nuclear steam supply system supplier; architect-engineer; and vendor reports,specifications, and drawings
* Maintenance Rule documents
* CHAMPSThe applicant stated that it reviewed these documents to identify the major SSCs and theirrespective functions. Functions of SSCs that were determined to be within the scope of license renewal were identified as intended functions, pursuant to 10 CFR 54.4(b). CHAMPS and controlled drawings were used to identify components requir ed to support system-level andstructure-level functions within the scope of license renewal. These sources also were used to develop the list of SCs subject to an AMR.2.1.2.1.3  Plant and System-Level Scoping LRA Section 2.1.4 states that the scoping process categorizes the entire plant according tomajor SSCs and commodity groups. The applicant identified and evaluated SSC and commodity group functions against criteria in 10 CFR 54.4(a) to determine whether the function was an intended function. The SSC or commodity was deemed within the scope of license renewal and received further screening if a portion of the SSC or commodity fulfilled a scopingcriterion.2.1.2.1.4  Component-Level Scoping After identifying the intended functions of systems and structures, the applicant identifiedcomponents that support intended functions. The applicant considered components supporting intended functions as within the scope of license renewal and screened them to determine whether an AMR was required.Commodity groups were used when component evaluations were by component type ratherthan by system or structure. Components constructed from similar materials, exposed to similarenvironments, and performing similar intended functions form the commodity groups.
Commodity group components were not associated with specific systems or structures duringthe evaluation, but with their assigned commodity groups. An AMR of each commodity group took place as if it were a separate, individual system. Electrical components, componentsupports, and fire stops and seals were placed in separate commodity groups.CHAMPS does not uniquely identify all components installed in the plant. For example,CHAMPS does not typically include such items as cables, raceways, piping, conduits, fireproofing, general construction items (e.g., nuts, bolts), or consumable materials (e.g., diesel 2-7fuel, resins). Components not uniquely identified in CHAMPS that are within the scope oflicense renewal are identified as commodities or generic assets (e.g., pipe, structural steel) in their respective system or structure in the license renewal database to ensure proper coverageand evaluation.2.1.2.1.5  Structure Scoping LRA Section 2.1.4.1 states that CHAMPS includes a category for structures that comprise all ofthe MNGP buildings and structures. Buildings were categorized as individual or grouped license renewal structures. The applicant electronically searched other information sources, like CLB documentation, using several keywords (e.g., "structure," "new structure," "building modification") to ensure evaluation of all plant structures for license renewal intended functions, regardless of their coverage in CHAMPS.2.1.2.2  Screening Methodology After identifying the SSCs within the scope of license renewal, the applicant implemented aprocess for determining which SSCs would be subject to an AMR, pursuant to 10 CFR 54.21(a)(1). In LRA Section 2.1.5, "Screening Process," the applicant discussed the screening of SSCs within the scope of license renewal.System, Structure, and Commodity Group Component ScreeningLRA Section 2.1.5.2, "General Screening Methodology," states that the screening processidentifies the components from the systems, structures, and commodity groups within the scopeof license renewal that are subject to an AMR. These components perform or support a component-level intended function without moving parts or a change in configuration or properties and are not subject to replacement based on a qualified life or specified time period.
Component-level intended functions support system-level intended functions. The plantsystems, structures, and commodity groups within the scope of license renewal and theirsystem-level intended functions were identified previously in the scoping process. Thescreening process consists of the following distinctive steps:
* identification of components subject to an AMR (passive and long-lived) for eachsystem, structure, or commodity within the scope of license renewal
* identification of the component-level intended functions of all components subject toAMRs
* identification of applicable references for making these determinationsThe applicant identified SCs within the scope of license renewal performing intended functionswithout moving parts or a change in configuration or properties (10 CFR 54.21(a)(1)(I) screening criterion). Active/passive screening determinations were based on the guidance in Appendix B to NEI 95-10. Passive SCs within the scope of license renewal not subject to replacement based on a qualified life or specified time period (10 CFR 54.21(a)(1)(ii) screening criterion) were identified as requiring AMRs. Component supports and fire stops and seals were binned in separate structural commodity groupings.
2-8Electrical/Instrumentation and Control (I&C) Component ScreeningIn LRA Section 2.1.5.4, "Scoping and Screening of Electrical Equipment," the applicantdescribed the methodology for screening electrical and I&C components. Component-level screening was performed for "in-scope" components associated with electrical systems.Components identified as within the scope of license renewal were evaluated pursuant to NEI 95-10, Appendix B guidance to determine whether they were considered "active." Componentswere either screened out as active or included in a commodity group. Long-lived, passive components were divided into four commodity groups, (1) Non-EQ Cables and Connections, (2)
Fuse Holders, (3) Electrical Penetrations, and (4) Offsite Power/SBO Recovery Path components. Aging management was performed on only these four commodity groups.2.1.3  Staff Evaluation The staff evaluated the LRA scoping and screening methodology in accordance with theguidance in Section 2.1, "Scoping and Screening Methodology," of NUREG-1800, "StandardReview Plan for Review of License Renewal Applications for Nuclear Power Plants" (SRP-LR).
The following regulations form the basis for the acceptance criteria for the scoping and screening methodology review:
* 10 CFR 54.4(a) relating to the identification of plant SSCs within the scope of licenserenewal
* 10 CFR 54.4(b) relating to the identification of intended functions of plant SSCs withinthe scope of license renewal
* 10 CFR 54.21(a)(1) and 10 CFR 54.21(a)(2) relating to the applicant's methods foridentifying plant SCs subject to an AMRAs part of the review of the applicant's scoping and screening methodology, the staff reviewedthe activities described in the following sections of the LRA using the guidance in the SRP-LR:
* Section 2.1 to ensure that the applicant described a process for identifying SSCs withinthe scope of license renewal, in accordance with the requirements of 10 CFR 54.4(a)
* Sections 2.2, 2.3, 2.4, and 2.5 to ensure that the applicant described a process foridentifying structural, mechanical, and electrical components subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1) and 10 CFR 54.21(a)(2)In addition, the staff conducted a scoping and screening methodology audit at the MNGP facilityin Minnesota during the week of June 20-24, 2005. The audit focused on ensuring that theapplicant had developed and implemented adequate guidance to conduct the scoping and screening of SSCs in accordance with the LRA methodologies and the requirements of the Rule. The staff reviewed implementation procedures and technical reports describing the applicant's scoping and screening methodologies. In addition, the staff conducted detaileddiscussions with the applicant on the implementation and control of the license renewalprogram and reviewed administrative control documentation and selected design documentation used by the applicant during the scoping and screening process. The staff reviewed the applicant's processes for quality assurance (QA) related to the development of the applicant's LRA and training and qualification of the LRA development team. The staff also 2-9reviewed a sample of system scoping and screening results reports for the control roddrive (CRD) system and intake structure (flood control) to ensure that the applicantappropriately implemented the methodology outlined in the administrative controls and that theresults were consistent with the CLB. The staff documented its review in an audit report issued July 18, 2005, identifying several issues requiring additional information from the applicant before completion of the review. Each of those issues is identified and addressed in detail in SER Sections 2.1.
3.1.2 and 2.1.3.1.4.2.1.3.1  Scoping Methodology The applicant's license renewal project personnel and contractors performed the scopingevaluations for the LRA. The staff had detailed discussions with the applicant's license renewalproject personnel and reviewed documentation of the scoping process. The staff assessed whether the scoping methodology described in the LRA and implementation procedures hadbeen implemented appropriately and whether the scoping results were consistent with CLB requirements. The staff also reviewed a sample of system scoping results for the CRD systemand intake structure (flood control).2.1.3.1.1Implementation Procedures and Documentation Sources Used for Scoping andScreeningThe staff reviewed the applicant's scoping and screening implementation procedures to verifythat the process used to identify SCs subject to an AMR was consistent with the LRA andSRP-LR, and that the applicant appropriately implemented the procedural guidance. The staffalso reviewed the scope of CLB documentation sources supporting the LRA and the process used by the applicant to ensure that CLB commitments were considered appropriately in scoping and screening.Scoping and Screening Implementation ProceduresThe staff reviewed the scoping and screening methodology implementation procedures andengineering reports, as documented in the audit report dated July 18, 2005.In reviewing these procedures, the staff focused on the consistency of the detailed proceduralguidance with the LRA and the staff positions documented in the SRP-LR and interim staff guidance documents. The staff found that the scoping and screening methodology instructions were consistent with LRA Section 2.1 and were of sufficient detail to guide the applicant on thescoping and screening implementation process followed during LRA activities.In addition to the implementing procedures, the staff reviewed supplemental design informationincluding DBDs, system drawings, and selected licensing documentation on which the applicantrelied during scoping and screening. The staff found these design documentation sources useful in ensuring that the initial scope of SSCs identified by the applicant was consistent withthe CLB.Sources of Current Licensing Basis InformationThe staff reviewed the scope and depth of the applicant's CLB evaluation to verify that themethodology was sufficiently comprehensive to identify SSCs within the scope of license 2-10renewal and SCs requiring an AMR. As defined in 10 CFR 54.3(a), the CLB is the set of NRCrequirements applicable to a specific plant and a licensee's written commitments for ensuring compliance with and operation within such requirements and the plant-specific design-basis docketed and in effect. The CLB includes NRC regulations, orders, license conditions,exemptions, TSs, design-basis information docketed in the USAR, and licensee commitments remaining in effect that were made in such docketed licensing correspondence as licensee responses to NRC bulletins, generic letters, and enforcement actions, as well as licenseecommitments documented in NRC safety evaluations or licensee event reports.LRA Section 2.1.3 provides a description of the CLB and related documents used during thescoping and screening process that is consistent with the guidance in the SRP-LR andNEI 95-10. Specifically, LRA Section 2.1.3 identified the USAR, TSs, docketed licensing correspondence, the Q-List, controlled plant drawings, industry codes, and plant design records. Additionally, in the scoping and screening implementation procedure, the applicant provided a comprehensive listing of documents that could be used to support scoping and screening evaluations. The applicant noted that system descripti ons and system intendedfunctions were identified based on the review of the applicable sections of the USAR, operations manual, Maintenance Rule scoping document, design- and licensing-basis documents, and license renewal project technical reports.During the audit, the staff reviewed the applicant's technical report, which specifically addressesDBEs. The report addressed in detail various sections of the USAR related to design-basis accidents (DBAs) and bounding transients and evaluated natural phenomena and external events applicable to MNGP. Supplemental information used to verify complete identification of DBEs included selected DBDs covering a number of support and accident mitigation systems,as well as selected topical reports developed to support the license renewal evaluation. Design descriptions for each system described in the USAR were reviewed to identify DBE mitigationfunctions credited in the CLB. The applicant identified these event mitigation functions andconfirmed that the SSCs credited with performing those functions were evaluated adequately inthe scoping and screening process.CHAMPS is the applicant's primary repository for component safety classification information.During the audit, the staff reviewed the applicant's administrative controls for CHAMPS safety classification data and concluded that the applicant had adequate measures to control theintegrity and reliability of CHAMPS safety classification data. Therefore, the staff concl uded thatCHAMPS provides a sufficiently controlled source of component data to support scoping and screening evaluations.The applicant identified topical reports as a source of information supporting identification ofsystems and structures relied upon to demonstrate compliance with events within the scope of10 CFR 54.4(a)(3), as well as documenting evaluation of special topics like scoping and screening of thermal insulation, treatment of consumables, and intended functions of heat exchangers. These reports were developed in accordance with MNGP directives that describe the requirements for preparation of such topical reports. The topical reports contain a listing of CLB references used for their development that was consistent with LRA Section 2.1.3. Thestaff reviewed these reports and concluded that the preparation of the topical reports accordingto applicant requirements reasonably ensured adequate summaries of CLB information for scoping purposes. The staff further verified the adequacy of the technical information in a 2-11sample of the reports by reviewing selected CLB source documents used to develop thetechnical reports.ConclusionAs part of the audit, the staff evaluated the scope and depth of the applicant's CLB evaluationfor assurance that the scoping methodology considered all SSC intended functions. In reviewing the LRA, scoping and screening implementation procedures, and license renewal technical reports, the staff determined that the applicant had developed and reviewed anadequately broad set of documents encompassing its CLB that is consistent with the guidancein the SRP-LR and NEI 95-10. The applicant's document review process adequately identified and documented system description and intended function evaluations performed during thescoping phase of the review. Therefore, the staff concluded that the applicant's methodology forthe identification, review, and documentation of CLB information to support the scoping ofSSCs is adequate.2.1.3.1.2  Application of the Scoping Criteria in 10 CFR 54.4(a)Application of the Scoping Criterion in 10 CFR 54.4(a)(1)In part, 10 CFR 54.4(a)(1) provides that, to identify SSCs within the scope of license renewal,the applicant must include all SR SSCs relied upon to remain functional during and following DBEs to ensure the following functions:
* the integrity of the reactor coolant pressure boundary
* the ability to shut down the reactor and maintain it in a safe-shutdown condition
* the capability to prevent or mitigate the consequences of accidents that could result inpotential offsite exposures comparable to those referred to in 10 CFR 50.34(a)(1),
10 CFR 50.67(b)(2), or 10 CFR 100.11, "Determination of Exclusion Area, LowPopulation Zone, and Population Center Distance"As to identification of DBEs, Section 2.1.3, "Review Procedures," of the SRP-LR states thefollowing:The set of DBEs as defined in the rule is not limited to Chapter 15 (or equivalent)of the Updated Final Safety Analyses Report (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, theCommission's regulations, NRC orders, exemptions, or license conditions withinthe CLB. These sources should also be reviewed to identify SSCs that are relied upon to remain functional during and following DBEs (as defined in 10 CFR 50.49(b)(1)) to ensure the functions described in 10 CFR 54.4(a)(1).The applicant's program for satisfying the scoping requirements of 10 CFR 54.4(a) requiresidentification of all major SR and NSR SSCs and the function or functions that each major SSC is required to perform. The applicant used a number of information sources, the CLB, DBEs, 2-12and quality classifications to identify the major SSCs and their respective functions. USARChapters 12 and 14 address DBEs. The applicant also used its DBDs to identify SR SSCs relied upon to remain functional during and following DBEs. The Q-List of the Operational QA Plan and the Q-List Extension drawings (color-coded piping &instrumentation drawings (P&ID))
specify the QA program boundaries for SSCs. These documents define the SSCs subject to the requirements of Appendix B, "Quality Assurance Criteria for Nuclear Power Plants and Fuel Reprocessing Plants," to 10 CFR Part 50, and were used to code items as SR in CHAMPS.The applicant's review of these documents identified the major SSCs and their respectivefunctions, which were compared to the scoping criteria of 10 CFR 54.4(a) to identify functions within the scope of license renewal. SSC functions that meet 10 CFR 54.4(a) scoping criteria requirements are identified as intended functions in the Advanced License Extension Management System (ALEX) license renewal database. SSC intended functions support one or more of the 10 CFR 54.4(a) scoping criteria.CHAMPS electronically stores component information used to prepare work orders and otheruses. CHAMPS provides seismic and quality classification. The applicant used CHAMPS and controlled drawings to identify components required to support system-level and structure-levelintended functions. Such components were included within the scope of license renewal.The applicant scoped SSCs in accordance with its implementing procedures. For additionalassurance that the applicant adequately implemented its SR scoping methodology, the staffreviewed a sample of the license renewal scoping report results for the CRD system anddiscussed the methodology and results with the applicant's personnel responsible for these evaluations. The staff verified that the applicant had identified and used pertinent engineeringand licensing information to identify the SSCs within the scope of license renewal, in accordance with the 10 CFR 54.4(a)(1) criteria.ConclusionOn the basis of this sample review, discussions with the applicant, and review of the applicant'sscoping process, the staff concluded that the applicant's methodology for identifying systemsand structures meets the 10 CFR 54.4(a)(1) scoping criteria.Application of the Scoping Criterion in 10 CFR 54.4(a)(2)In part, 10 CFR 54.4(a)(2) requires that the applicant consider all NSR SSCs whose failurecould prevent satisfactory accomplishment of any of the functions identified in 10 CFR 54.4(a)(1)(I), 10 CFR 54.4(a)(1)(ii), or 10 CFR 54.4(a)(1)(iii) as within the sc ope oflicense renewal. By letters dated December 3, 2001, and March 15, 2002, the NRC iss ued astaff position to the NEI which provided staff expectations for determining which SSCs meet the 10 CFR 54.4(a)(2) criterion. The December 3, 2001, letter provides specific examples of operating experience which identified pipe failure events (summarized in Information Notice (IN) 2001-09, "Main Feedwater System Degradation in Safety-Related ASME Code Class 2 Piping Inside the Containment of a Pressurized Water Reactor," and the approaches the staff considers acceptable for determining which piping systems should be within the scope oflicense renewal based on the 10 CFR 54.4(a)(2) criterion. The March 15, 2002, letter further describes the staff's expectations for the evaluation of nonpiping SSCs to identify additional NSR SSCs within the scope of license renewal. The position states that applicants should not 2-13consider hypothetical failures, but rather the plant's CLB, engineering judgment and analyses,and relevant operating experience. The paper further describes operating experience as all documented plant-specific and industry-wide experience useful in determining the plausibility ofa failure. Documentation would include NRC generic communications and event reports,plant-specific condition reports, industry reports, such as significant operating event reports (SOERs), and engineering evaluations.In its scoping implementation procedures, the applicant documented its methodology forperforming 10 CFR 54.4(a)(2) scoping of NSR SSCs and described the general methodology for identifying those NSR SSCs whose failure could affect the ability to maintain int endedfunctions of SR SSCs within the scope of license renewal. The procedure provides general guidance consistent with that of Appendix F to NEI 95-10, Revision 4, regarding the use ofmitigative and preventive approaches to identify SSCs within the scope of license renewal to meet the 10 CFR 54.4(a)(2) criterion. The procedure further describes the process for identifying the SSCs within the scope of license renewal and includes guidance for each discipline review (mechanical, structural, and electrical).In addition, the applicant developed a technical report, as documented in the audit report,  tofurther define the methodology used for the 10 CFR 54.4(a)(2) evaluation. This technical reportdescribes the current regulation and the interim staff position on scoping of SSCs according to the 10 CFR 54.4(a)(2) criterion; the applicant's evaluation of licensing-basis topics, includingHELB, internal and external missiles, internal and external flooding, and heavy loads; evaluation of NSR SSCs attached directly to SR SSCs; and NSR SSCs within close spatial proximity to SR SSCs. Section 4.0 of the report addresses in detail the results of the 10 CFR 54.4(a)(2) evaluation.With respect to the CLB topics, including HELB, internal and external missiles, internal andexternal flooding, and heavy loads, the applicant's methodology evaluated information for each to identify NSR SSCs of interest. To ensure a complete and extensive evaluation of the existing CLB, the applicant developed a process which included searching CHAMPS to identify relevant references to the TS-bases documents, USAR sections, DBDs, licensing correspondence, plant drawings, plant modification packages, technical reports, and operations manuals for each topic. These documents were reviewed and an evaluation for each topic was performed to identify design features relied on for these events as within the scope of license renewal.The staff reviewed the applicant's methodology in evaluating these CLB topics, discussed theevaluation process with the applicant's staff responsible for performing these reviews, and evaluated a sample of the results of this evaluation to ensure that implementation of writteninstructions and the results are consistent with those evaluations. The staff determined that theapplicant's documented methodology was consistent with the 10 CFR 54.4(a)(2) requirementsand that the applicant's evaluation was consistent with that methodology. The staff reviewed asample of the CLB information used for the applicant's evaluations and confirmed its consistency with that design information.The applicant's evaluation of NSR SSCs attached directly and those within close spatialproximity to SR SSCs considered current industry guidance on the subject as a result of recent staff license renewal evaluations, taking into account that all active as well as passive SR SSCs could be affected adversely by spray or wetting from an NSR pressurized system in the same general location of the plant, regardless of the duration of that exposure. Specifically, the 2-14applicant used a "spaces" approach to identify SR SSCs and NSR SSCs within the same"general area," which is defined as a location sharing a common floor and common walls. This definition was expanded during plant walkdowns in the 10 CFR 54.4(a)(2) evaluation to include adjacent areas (i.e., those separated by a wall or barrier), if there could be communication between the two areas. In those instances, the adjacent area was considered part of the general area.As part of this evaluation, the applicant first listed the SR components and their locations withinthe plant. Review of plant-controlled documents like P&IDs, DBDs, and CHAMPS identified plant areas where NSR and SR SSCs were located. The applicant performed walkdowns of all accessible locations to identify NSR SSCs within these areas and the types of potential interactions that could occur (i.e., leaking, spraying, physical impact). For inaccessible areas, the applicant relied on controlled plant piping layout drawings and operator knowledge of theplant design and operation to identify potential component interactions. The inaccessible areasincluded the drywell/suppression chamber, steam chase, reactor water cleanup (RWCU) and traversing incore probe rooms, condenser room, and steam jet air ejector (SJAE) room. Where the applicant identified potential interactions between the NSR SSCs and SR SSCs within ageneral area, it included those NSR SSCs within the scope of license renewal. The applicant further documented the results on marked-up P&IDs, which highlighted the NSR SCs identified and described the general area, as well as SR SCs that could be affected by the NSR line failure. The staff reviewed a sample of the marked-up P&IDs for the CRD system and reviewedthe applicant's determination of areas of no potential interactions between NSR and SR SSCs.The staff determined that the applicant had evaluated the 10 CFR 54.4(a)(2) scoping criterionconsistently with the applicant's written instructions for such an evaluation and that the resultshad been documented with technical supporting justifications. The staff did not identify any specific concerns regarding the implementation of the 10 CFR 54.4(a)(2) scoping methodologyfor the system sample reviewed.The applicant also discussed its 10 CFR 54.4(a)(2) scoping evaluation process for NSR SSCsdirectly attached to SR SSCs to determine equivalent anchor locations required to establish system boundaries for the evaluation. With respect to the equivalent anchor criteria, theapplicant identified locations in each relevant system where support and attachment are suchthat failure of the piping system beyond the boundary point would not adversely affect the SRfunctions of connected SR components. The applicant relied on its piping stress analysis of record to determine equivalent anchor locations. In most cases, this boundary encompassed at least two levels of supports in each orthogonal direction, and for those few cases where such support was not available, the applicant evaluated the piping stress analysis to determinealternate anchorage locations. The alternate anchorage locations included (1) selected wall penetrations, (2) large pieces of plant equipment, (3) transition points between the piping systems and flexible connections like tubing and ducting, and (4) locations where the pipingsystem moment of inertia ratio exceeds 40:1 between the main and branch lines. In each case,the applicant provided a technical justification for the use of the equivalent anchorage locationbased on CLB information related to the piping stress analysis of record. The staff reviewed the methodology for a selected sample of mechanical systems and confirmed that the applicant'sevaluation was consistent with the guidance and that results had been documented adequatelyand justified technically.In addition to reviewing the implementation procedures associated with the applicant's10 CFR 54.4(a)(2) evaluations, the staff discussed the review process with the applicant's 2-15personnel responsible for performing the review and evaluated a sample of systems andstructures to ensure that the methodology was implemented in accordance with the written instructions and that the results were consistent with those evaluations.The applicant's implementing procedures provided guidance for establishing system boundariesfor NSR piping systems connected directly to SR piping systems. The guidance states, in part,that for NSR SSCs connected to SR SSCs, the NSR SSCs should be included up to the first seismic anchor past the SR-NSR interface, and the boundary drawings should also identify the anchor. A review of piping analyses provided information to extend the piping system to the firstanchor. Where there was no true anchor, the piping analysis was extended far enough to ensure that the NSR portion would have no effect on the SR portion. Typically, the extensionencompassed at least two restraints in each orthogonal direction. Where there were no such restraints in each orthogonal direction, the boundary was extended to an equivalent anchor such as a wall. As an example, the applicant stated that in certain cases of small-bore piping (i.e., 2 inches or less), grouted wall penetrations served as equivalent anchor locations.The staff's review of LRA Section 2.1 identified an area for which it needed additionalinformation to complete its evaluation of the applicant's scoping and screening methodology.
The applicant responded to the staff's RAI as discussed below.In RAI 2.1-2, dated July 20, 2005, the staff requested that the applicant provide the technicalbasis for establishing the grouted wall penetrations as equivalent anchor locations for NSR piping systems connected to SR piping systems and confirm that nongrouted wall penetrationswere not used as equivalent anchor locations for NSR piping systems connected to SR pipingsystems.In its response, by letters dated August 16, 2005, and November 17, 2005, the applicant statedthat 10 grouted wall/floor NSR piping penetrations were considered equivalent anchors. The CLB piping analysis addressed 9 of the 10 grouted penetrations, while 1 of the 10 was not addressed. In its response, the applicant provided an acceptable technical justification forcrediting this one grouted wall/floor piping penetration not addressed as an equivalent anchor.The applicant additionally stated that, in five instances, NSR underground piping was used asan equivalent anchor. In three of the five instances, the CLB piping analysis addressed the use of NSR underground piping as an equivalent anchor. The remaining two instances were not addressed. The applicant provided an acceptable technical justification for crediting the two instances in which underground piping was used as an equivalent anchor. The applicant also stated that it had added NSR underground piping to the scope of license renewal, which was subject to an AMR when credited as an equivalent anchor.Based on its review, the staff found the applicant's response to RAI 2.1-2 acceptable becausethe applicant adequately described its process for establishing the use of grouted wallpenetrations and underground piping as an equivalent anchor termination point. Therefore, the applicant resolved the staff concern described in RAI 2.1-2.ConclusionOn the basis of the additional information supplied by the applicant, which provides technicaljustification for identification of certain equivalent anchor locations, and as a result of the NRC 2-16inspection and audit activities, the staff concluded that the applicant has supplied sufficientinformation to demonstrate that the methodology for identifying systems and structures meetingthe scoping criteria of 10 CFR 54(a)(2) is adequate.Application of the Scoping Criterion in 10 CFR 54.4(a)(3)In part, 10 CFR 54.4(a)(3) requires applicants to consider in safety analyses or plantevaluations all SSCs relied on to perform functions demonstrating compliance with the Commission's regulations for FP (10 CFR 50.48), EQ (10 CFR 50.49), pressurized thermal shock (10 CFR 50.61, "Fracture Toughness Requirements for Protection against Pressurized Thermal Shock Events"), ATWS (10 CFR 50.62), and SBO (10 CFR 50.63) to be within the scope of license renewal. Pressurized thermal shock is not applicable to BWRs and, therefore, the applicant did not evaluate it. SRP-LR Section 2.1.3.1.3, "Regulated Events," states that allSSCs relied upon in the plant's CLB (as defined in 10 CFR 54.3), plant-specific operating experience, industry-wide operating experience (as appropriate), and safety analyses or plant evaluations to perform functions demonstrating compliance with NRC regulations under10 CFR 54.4(a)(3) must be included within the scope of license renewal; however, consideration is not required of hypothetical failures from system interdependencies not part ofthe CLB and not previously experienced.The staff reviewed the applicant's approach to identifying SSCs relied upon to performfunctions related to the four regulated events, as described in 10 CFR 54.4(a)(3). As part of this review, the staff discussed the methodology with the applicant's LRA team, reviewed supporting documentation, and evaluated a sample of the SSCs identified as within scope, pursuant to the10 CFR 54.4(a)(3) criterion.The applicant documented its methodology for scoping SSCs in accordance with10 CFR 54.4(a)(3) in implementation procedures, as described in the audit report. The applicant's initial scoping for regulated events evaluated relevant CLB information to determine whether the structure or system met the scoping criterion of 10 CFR 54.4(a)(3). For the fourregulated events, the applicant developed technical reports describing the relevant rulerequirements, implementation of the requirements, specific information about systems andcomponents credited for the event, the process to identify the scoping boundaries of thesystems credited, a list of CLB information sources for the analysi s, and systems andcomponents within the scope of license renewal for the given regulated event. Systems or structures with one or more components credited for demonstrating compliance with one of the regulated events are within the scope of license renewal, pursuant to the 10 CFR 54.4(a)(3)criterion. In addition, the staff determined that identification of SSCs within the scope of licenserenewal to support 10 CFR 50.63 had been in accordance with the guidance of ISG-02, "Station Blackout Scoping." In summary, the applicant included within the scope of license renewal the SSCs relied upon in safety analyses or plant evaluations to perform intended functions demonstrating compliance with NRC regulations for FP, EQ, ATWS, and SBO, in accordancewith the 10 CFR 54.4(a)(3) criterion.The staff's review of the applicant's scoping methodology included the set of scopingcalculations for each regulated event, a sample of the supporting analyses and documentation, discussion of the methodology and results with the applicant's personnel responsible for these evaluations, and a review of ALEX. The staff verified that the applicant had identified and used 2-17pertinent engineering and licensing information to determine the SSCs within the scope oflicense renewal, in accordance with the 10 CFR 54.4(a)(3) criterion.ConclusionBased on this sampling review, discussions with the applicant, and review of the applicant'sscoping process, the staff determined that the applicant's methodology for identifying systemsand structures meeting the 10 CFR 54.4(a)(3) scoping criterion is adequate.2.1.3.1.3  Plant-Level Scoping of Systems The applicant documented its methodology for scoping systems in accordance with10 CFR 54.4(a) in its implementing procedures. The applicant's appr oach to scoping systemswas consistent with the methodology described in LRA Section 2.1.4. Specifically, theimplementing procedure specified that personnel scoping for license renewal use CLB and DBE documents to describe systems, including lists of all functions that the system is required toaccomplish. Sources of information included the USAR, DBDs, Q-List and Q-List Extension drawings, CHAMPS, the Maintenance Rule documents, P&IDs, and docketed correspondence.
The applicant then compar ed system function lists to the scoping criteria to determine whether the system functions met the 10 CFR 54.4(a) scoping criteria. The applicant documented thescoping results in ALEX, which included a description of t he system, a list of functionsperformed by the system, identification of intended functions, the 10 CFR 54.4(a) scopingcriteria met by the system, references, and a list of components performing intended functions.During the scoping methodology audit, the staff reviewed a sampling of ALEX scoping reports and concluded that they contain an appropriate level of detail to document the scoping process.The applicant established color-coded boundary P&IDs for each mechanical system within thescope of license renewal. A preparer and an independent reviewer comprehensively evaluated the license renewal color-coded P&IDs for completeness and accuracy of the review results.
The staff reviewed several license renewal color-coded boundary P&IDs and verified that ALEX did identify the systems within license renewal boundaries.ConclusionOn the basis of a review of the LRA, ALEX, scoping and screening implementation procedures,license renewal color-coded P&IDs, and a sampling review of system scoping results, the staffconcluded that the applicant's scoping methodology for systems is adequate. In particular, thestaff determined that the applicant's methodology reasonably identified systems within thescope of license renewal and their associated intended functions.2.1.3.1.4  Mechanical Component-Level Scoping After the applicant had identified systems within the scope of license renewal and theirassociated intended functions, it identified the components of each system within the scope oflicense renewal that supported an intended function. As described in LRA Section 2.1.4, theapplicant considered a component to be within the scope of license renewal if needed for performance of a system intended function.
2-18The applicant described the methodology used for component scoping in LRA Section 2.1.4,and its implementing procedures, as documented in the audit report. The applicant evaluated CHAMPS, the USAR, DBDs, DBEs, plant walkdowns, training materials, license renewal color-coded boundary P&IDs, specifications, codes/standards, design changes, plant procedures, and CLB documentation to identify components credited with compliance to 10 CFR 54.4(a). Components meeting the requirements of 10 CFR 54.4(a) were consideredwithin the scope of license renewal and the applicant entered this information into ALEX.The staff reviewed the results of the ALEX scoping reports and discussed the scoping processin detail with the applicant's license renewal project personnel. The staff assessed whether the applicant appropriately applied the LRA scoping methodology and implementation procedures and whether the scoping results were consistent with CLB requirements. The staff determinedthat the applicant's proceduralized methodology was consistent with the description in LRASection 2.1.4 and the guidance in SRP-LR Section 2.1 and was adequately implemented.The staff reviewed the scoping process for the CRD system. The staff verified that the applicanthad developed color-coded system boundary P&IDs that identified license renewal CRD systemboundaries in accordance with the procedural guidance. The staff verified that CRD systemcomponents meeting 10 CFR 54.4(a) requirements were within the scope of license renewal.
The staff found the applicant knowledgeable about the process and conventions for establishing boundaries as defined in the license renewal implementation procedures.ConclusionOn the basis of the applicant's detailed scoping implementation procedures and a samplingreview of CRD system mechanical components scoping results, the staff concluded that theapplicant's methodology for identifying mechanical components within the scope of license renewal meets 10 CFR 54.4(a) requirements.Structural Component ScopingThe applicant described the methodology used for structural scoping in LRA Section 2.1.4, andits implementing procedures, as documented in the audit report. The applicant developed a list of SSCs using CHAMPS information. The applicant's technical reports listed all civil/structural SCs within the scope of license renewal. The applicant evaluated CHAMPS, the USAR, DBDs, training materials, drawings, specifications, codes/standards, design changes, plant procedures, and CLB documentation to identify structures credited with compliance to 10 CFR 54.4(a). In addition, the applicant performed walkdowns of plant buildings. Systems which contained components determined to meet 10 CFR 54.4(a) requirements wereconsidered within the scope of license renewal and the applicant entered this information into ALEX. The scope of license renewal included all SR structures and structural components. SR items within the scope of license renewal include walls, piping and equipment supports, conduit, cable trays, electrical enclosures, and instrument panels relied upon in the CLB. The NSR structures and structural components that perform functions required for compliance with FP, ATWS, and SBO regulations were included within the scope of license renewal. NSR structural items within the scope of license renewal include missile shields that protect SR equipment; overhead handling systems that could affect SR equipment; permanently installed walls, curbs,and doors that provide flood protection for SR equipment; and jet impingement shields and blowout panels that protect SR equipment from the effects of an HELB. The staff reviewed the 2-19LRA, procedures, drawings, and the ALEX database. The staff reviewed the results of thescoping methodology for select structures that included the diesel fuel oil transfer house, offgas stack, and the intake structure (flood control).The audit team reviewed plant procedures which provide instructions for the response of MNGPpersonnel to extreme natural conditions. These procedures address tornados, external flooding, high river water temperature, low river water flow/level, high-wind conditions, heavy snowfall, and high ambient (outside) air temperature. Plant procedures also provide instructions for protecting structures from flooding in the event that Mississippi River flood waters are predicted to exceed specific elevations. For example, steel plates required to be bolted over specific structure openings are stored on site to accomplish this task. Another example of an action to prevent flooding is the removal of the intake structure Amertap hatch covers and installation of the original floor hatches. The staff noted that equipment stored for use, such as steel platesand floor hatches, was not included within the scope of license renewal.The staff's review of LRA Section 2.1.4 identified an area for which it needed additionalinformation to complete its evaluation of the applicant's scoping and screening methodology.
The applicant responded to the staff's RAI as discussed below.In RAI 2.1-1, dated July 20, 2005, the staff requested that the applicant provide the technicalbasis for not including, within the scope of license renewal, equipment stored on site that stationprocedures require to be installed during emergency or abnormal conditions, in accordance with the CLB, or describe the methodology for ensuring that the license renewal scoping addressedall such equipment.In its response, by letter dated August 16, 2005, the applicant stated that it had added steelplates stored outside, which are dedicated for use during postulated external events, and steelhatch covers stored in the warehouse, which are dedicated for external flood use to the scope of license renewal and this equipment was subject to an AMR.Based on its review, the staff found the applicant's response to RAI 2.1-1 acceptable, becausethe applicant revised its scoping and screening methodology to include the appropriate equipment stored on site that the station procedures require to be installed during emergency or abnormal condition in accordance with the CLB. Therefore, the applicant resolved the staffconcern described in RAI 2.1-1.ConclusionThe staff determined that the applicant's methodology is consistent with the description in LRASection 2.1.4 and the guidance in SRP-LR Section 2.1. Based on review of information in the LRA, the applicant's detailed scoping implementation procedures, the additional informationfrom the applicant on scoping and screening methodology for equipment stored on site, and a sampling review of structural scoping results, the staff concluded that the applicant's methodology for identification of structural SSCs within the scope of license renewal meets 10 CFR 54.4(a) requirements.
2-20Electrical and I&C Component ScopingThe applicant described the methodology for electrical and I&C scoping in LRA Section 2.1.5.4,and its implementing procedures, as documented in the audit report. The applicant performed electrical and I&C scoping at a system level. The applicant developed information fromnumerous sources including CHAMPS, the USAR, and the Maintenance Rule program systembasis documents. The applicant entered the system description, the applicable design-basisreference, and system functions into ALEX. The applicant eval uated the system functions inaccordance with the 10 CFR 54.4(a) criteria to determine whether the system was within thescope of license renewal. Following evaluation of t he system functions, the applicant added thereference identifying t he system function which pl aced the system within the scope of licenserenewal to ALEX. The applic ant added systems to the license renewal database which werecreated to include electrical and I&C components not already specifically identified within an existing system (such as cables) in CHAMPS. The System/Structure Scoping and ScreeningOutput Reports document these activities.ConclusionThe staff reviewed the LRA, procedures, drawings, ALEX, and a sample of the results of theapplication of the scoping methodology for select systems. The staff found the applicant'smethodology consistent with the description in LRA Section 2.1.5.4 and with the applicant'simplementing procedures. Based on review of information in the LRA, the applicant's detailed scoping implementation procedures, and a sampling review of electrical and I&C scoping results, the staff concluded that the applicant's methodology for identifying electrical and I&Ccomponents within the scope of license renewal meets 10 CFR 54.4(a) requirements.2.1.3.2  Screening Methodology The applicant described its screening process in LRA Section 2.1.5. In general, the applicant'sscreening consisted of evaluations to determine which SCs within the scope of license renewal were passive and long-lived. Passive and long-lived SCs were then subject to further AMR. The staff reviewed the methodology used by the applicant to determine whether mechanical,structural, and electrical and I&C components within the scope of license renewal would be subject to further AMR. The applicant provided the staff with a detailed discussion of the processes for each discipline and provided administrative documentation that described the screening methodology. The staff also reviewed the screening results report for the CRD system. The staff noted that the applicant's screening process was performed in accordancewith its written requirements and was consistent with the guidance of the SRP-LR and NEI95-10, Revision 4. The staff determined that the screening methodology was consistent with therequirements of the Rule and that the screening methodology identified SCs meeting the10 CFR 54.21(a)(1) screening criterion.The staff evaluated the applicant's screening methodology against the 10 CFR 54.21(a)(1)criterion using the review guidance of SRP-LR, Section 2.1.3.2, "Screening." Pursuant to10 CFR 54.21(a)(1), the applicant's IPA must identify and list SCs subject to an AMR. Further, 10 CFR 54.21(a)(1) requires that SCs subject to an AMR encompass those SCs that (1) perform an intended function, as described in 10 CFR 54.4, without moving parts or changes in configurations or properties and (2) are not subject to replacement based on a qualified life or specified time period. Pursuant to 10 CFR 54.21(a)(2), the applicant must describe and justify 2-21the methods used to meet 10 CFR 54.21(a)(1) requirements. In the LRA, the applicantdescribed screening methodologies unique to the mechanical, structural, and electrical disciplines. The following sections describe the staff's evaluation of the applicant's screening approach for each of these disciplines.Mechanical Component ScreeningThe staff reviewed the methodology used by the applicant to determine whether mechanicalcomponents within the scope of license renewal would be subject to further AMR. The applicant applied a screening process to each mechanical component in ALEX. Implementing procedures require that each component in ALEX be identified as periodically replaced, no intended function, active, or requiring an AMR. CHAMPS was used to determine whether components are periodically replaced. The applicant had previously entered component intended functions into ALEX. The audit team reviewed technical reports which provided specific guidance for determining whether components were active or passive. Technical reports also referred to Appendix B to NEI 95-10 for component types generally considered active or passive. The applicant provided the staff with a detailed discussion of the process and provided ALEX screening report information describing the screening methodology, as well as a sample of the screening result reports for a selected group of SR and NSR systems.During the audit, the staff reviewed the methodology used by the applicant to identify and listthe mechanical components subject to an AMR, as well as the applicant's technical justification for this methodology. The staff also examined the applicant's results from the implementation ofthis methodology by reviewing the CRD system. The review included the license renewalcolor-coded boundary P&IDs and resultant components within the scope of license renewal, the corresponding component-level intended functions, and the resulting list of mechanical components subject to an AMR. The staff reviewed several summary screening reports breaking down the mechanical components within the scope of license renewal into several categories, including component type, AMR requirement, and material, and a comment section.
The staff also discussed the process and results with the cognizant engineers who performed the review. The staff did not identify any discrepancies between the methodology documentedand the implementation results.ConclusionOn the basis of a review of the LRA, the scoping and screening implementation procedures,and a sampling review of system and screening results, the staff determined that the applicant'smechanical component screening methodology is consistent with the guidance of the SRP-LRand is adequate for identifying passive, long-lived components within the scope of license renewal subject to an AMR. Therefore, the staff concluded that the applicant's methodology foridentification of mechanical components subject to an AMR meets 10 CFR 54.21(a)(1) requirements.Structural Component ScreeningAfter determining which structural SSCs were within the scope of license renewal, the applicantimplemented a process for determining which SSCs would be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1). LRA Section 2.1.5 discusses the screening of SSCs within the scope of license renewal. Screening activities identified passive 2-22components, long-lived components, component intended functions, consumables, andcomponent replacement based on performance or condition. The applicant relied on the guidance of NEI 95-10 to develop the plant-specific listing of passive components of interest during the review.ConclusionThe staff reviewed the LRA, procedures, drawings, and the ALEX database. The staff alsoreviewed the results of the scoping and screening methodology for select structures, including the diesel fuel oil transfer house, offgas stack, and intake structure (flood control). The staff found the applicant's methodology consistent with the description in LRA Sections 2.1.4 and2.1.5 and the guidance of SRP-LR Section 2.1. Based on review of information contained in the LRA, the applicant's detailed scoping implementation procedures, and a sampling review ofstructural scoping and screening results, the staff concluded that the applicant's methodologyfor identification of structural SSCs subject to an AMR meets 10 CFR 54.21(a)(1) requirements.Electrical and I&C Component ScreeningThe applicant described the electrical and I&C screening methodology in LRA Section 2.1.5.4,and its implementing procedures, as documented in the audit report. The applicant identified evaluation boundaries for the electrical and I&C systems previously determined to be within thescope of license renewal. The applicant also reviewed components within the evaluation boundary to identify SCs performing intended functions, and compiled such SCs into ALEX.
The applicant reviewed ALEX to identify the passive and long-lived components subject to an AMR in accordance with 10 CFR 54.21. In addition, the applicant identified and reviewed fuse holders, in accordance with the guidance contained in ISG-05, "Electrical Fuse Holders." The applicant documented the results of these activities in four technical reports, "Electrical Penetrations," "Non-EQ Cables and Connections," "Fuse Holders," and "Offsite Power/SBO Recovery Path."ConclusionThe staff reviewed the LRA, procedures, drawings, ALEX, and a sample of the results of thescreening methodology. The staff found the applicant's methodology consistent with thedescription in LRA Section 2.1.5.4 and the applicant's implementing procedures. Based onreview of information in the LRA, the applicant's detailed screening implementation procedures,and a sampling review of electrical and I&C screening results, the staff concluded that the applicant's methodology for identification of electrical and I&C SCs subject to an AMR meets 10 CFR 54.21(a)(1) requirements.InsulationLRA Table 2.1-1 describes the intended function of thermal insulation to "limit heat transfer tomaintain temperature within design limits." During the audit, the staff reviewed technical reports, as documented in the audit report, which described how thermal insulation was scoped and screened at MNGP. No insulation at MNGP is classified as SR, so insulation can be within the scope of license renewal only for environment control or seismic II/I intended functions. The applicant stated that thermal insulation to limit room heat-up was within the scope of licenserenewal in two areas: high pressure coolant injection (HPCI) room piping insulation and residual 2-23heat removal (RHR) room heat exchanger insulation. Therefore, this specific thermal insulationwas subject to an AMR.ConclusionThe staff reviewed the LRA, technical report, and the results of the scoping and screeningmethodology for thermal insulation. The staff found the applicant's methodology consistent withthe description in LRA Table 2.1-1 and the applicant's implementing procedures. Based on review of information in the LRA and the applicant's detailed technical report, the staff determined that the applicant's methodology for identification of insulation subject to an AMRmeets 10 CFR 54.21(a)(1) requirements.ConsumablesDuring the audit, the applicant described the screening review for certain consumablecommodities in LRA Section 2.1.5.3, "Component Classification (Passive, long-lived)."
Section 2.1.5.3 states that evaluation of items to determine whether they are consumablesfollowed the NRC screening guidance of SRP-LR Table 2.1-3, "Specific Staff Guidance onScreening," for determining whether consumable items are subject to an AMR. For consumables periodically replaced, SRP-LR Table 2.1-3 states that the applicant should identifythe standards that are relied on for replacement as part of the methodology description.The table states that consumables like packing, gaskets, component seals, and O-rings may beexcluded from an AMR using a clear basis. Consistent with SRP-LR Table 2.1-3, the applicant divided consumables into four basic categories, (1) packing, gaskets, component seals, and O-rings, (2) structural sealants, (3) oil, grease, and filters (system and component filters), and(4) fire extinguishers, fire hoses, and air packs. The applicant's guidance for performingscreening reviews for commodity groups states that, regardless of how consumables associated with components or structures are screened for an AMR, the bases for the determinations made are presented in the respective AMR reports.The staff selected various AMR reports and verified that each contained a discussion of thetreatment of consumables. The staff reviewed several AMRs during its scoping and screening audit and verified that they contained components subject to short-lived/replaceable determinations.ConclusionThe staff reviewed the LRA, technical report, a sample of the screening methodology results,and AMRs. The staff found the applicant's methodology consistent with the description in LRA Section 2.1.5.3 and the applicant's implementing procedures. Based on review of informationcontained in the LRA, the applicant's detailed screening implementation procedures andtechnical report, a sampling review of consumable screening results, and AMRs, the staff concluded that the applicant's methodology for identification of consumables subject to an AMRmeets 10 CFR 54.21(a)(1) requirements.
2-242.1.3.3  QA Controls Applied to LRA DevelopmentThe staff reviewed the QA controls used by the applicant for reasonable confidence that theLRA scoping and screening methodologies were adequately implemented. Although the applicant did not develop the LRA under a 10 CFR Part 50, Appendix B QA program, the staff determined that the applicant utilized the following QA processes during the LRA development:
* Written procedures and guidelines governed implementation of the scoping andscreening methodology.
* The Offsite Review Committee and the Plant Operations Review Committee reviewedand approved the LRA before its submission to the staff.
* The applicant planned to retain certain license renewal documents as quality records orcontrolled documents.
* The applicant performed an industry peer review of license renewal activities.
* The applicant's Nuclear Oversight Department performed a self-assessment in the areaof implementation of license renewal procedures.ConclusionOn the basis of review of pertinent LRA development guidance, discussion with the applicant'slicense renewal personnel, and review of the Nuclear Oversight quality audit report, the staff concluded that such QA activities provide reasonable assurance that LRA development activities were consistent with LRA descriptions.2.1.3.4  Training The staff reviewed the applicant's training process to ensure that guidelines and methodologyfor scoping and screening activities were consistent and appropriate. The applicant had developed 10 license renewal lesson plans to train all technical leads and site personnel in license renewal activities. The applicant developed and used implementing procedures to train contract personnel supporting the license renewal effort. The applicant also required contract personnel to review the applicable regulations, NEI 95-10, the applicable administrative work instruction, and the License Renewal Project Plans. In addition, the applicant created "Documentation of Information Sharing" on specific license renewal topics as they were developed and conducted periodic training sessions for all license renewal personnel.ConclusionOn the basis of discussions with the applicant's license renewal project team responsible for thescoping and screening process and a review of selected documentation in support of the process, the staff concluded that the applicant's personnel understood the requirements andguidance and adequately implemented the scoping and screening methodology documented in the LRA. The staff concluded that license renewal personnel were adequately trained and qualified to perform the applicable license renewal activities.
2-252.1.4  ConclusionThe staff reviewed the information in LRA Section 2.1, the supporting information in the scopingand screening implementation procedures and reports, and the information presented during the scoping and screening methodology audit. The staff verified that the applicant's scopingand screening methodology is consistent with the requirements of the Rule. On the basis of thisreview, the staff concluded that, with the exceptions noted above, the applicant's methodologyfor identifying SSCs within the scope of license renewal and the SCs requiring an AMR is consistent with the requirements of 10 CFR 54.4(a) and 10 CFR 54.21(a)(1).2.2  Plant-Level Scoping Results2.2.1  Introduction In LRA Section 2.1, the applicant described the methodology for identifying the SSCs within thescope of license renewal. In LRA Section 2.2, the applicant used the scoping methodology to determine which SSCs are required to be included within the scope of license renewal. The staff reviewed the plant-level scoping results to determine whether the applicant had properlyidentified all plant-level systems and structures relied upon to remain functional during andfollowing DBEs, as required by 10 CFR 54.4(a)(1), or whose failure could prevent satisfactory accomplishment of any of the SR functions of SSCs within the scope of license renewal, as required by 10 CFR 54.4(a)(2), as well as the systems and structures relied on in safetyanalyses or plant evaluations to perform a function that demonstrates compliance with one of the regulations referenced in 10 CFR 54.4(a)(3).2.2.2  Summary of Technical Information in the Application In LRA Table 2.2-1, the applicant provided a list of the plant-level scoping results, identifyingthose systems, structures, and commodities that are within the scope of license renewal. Basedon the DBEs considered in the plant's CLB, other CLB information relating to NSR systems and structures, and certain regulated events referenced in 10 CFR 54.4(a)(3), the applicant identified those plant-level systems and structures that are within the scope of license renewal,as defined by 10 CFR 54.4.2.2.3  Staff Evaluation In LRA Section 2.1, the applicant described its methodology for identifying the systems andstructures that are within the scope of license renewal and subject to an AMR. The staff reviewed the scoping and screening methodology and provided its evaluation in Section 2.1 of this SER. To verify that the applicant properly implemented its methodology, the staff focusedits review on the implementation results, as shown in LRA Table 2.2-1, to confirm that noplant-level systems and structures were omitted from the scope of license renewal.The staff determined whether the applicant properly identified the systems and structures withinthe scope of license renewal, in accordance with 10 CFR 54.4. The staff reviewed selected systems and structures that the applicant did not identify as falling within the scope of licenserenewal to verify whether the systems and structures have any intended functions that wouldrequire their inclusion within the scope of license renewal. The staff conducted its review of the 2-26applicant's implementation in accordance with the guidance described in SRP-LR Section 2.2,"Plant-Level Scoping Results."In reviewing LRA Section 2.2, the staff identified areas for which it needed additionalinformation to complete its evaluation of the applicant's plant-level scoping results. Therefore, the staff issued RAIs concerning each specific issue to determine whether the applicant properly applied the scoping criteria of 10 CFR 54.4. The following paragraphs describe the staff's RAIs and the applicant's related responses.In RAI 2.2-1, dated June 21, 2005, the staff noted that the control rod velocity limiters describedin USAR Section 6.4 are integral parts of each control rod providing hydraulic damping to reduce the freefall velocity of the rod and reduce consequences if the control rod becomes detached from its drive and drops from the core. The LRA does not mention this component, nor does it appear to refer to USAR Section 6.4; therefore, the staff requested that the applicantclarify whether these components are included within the scope of license renewal or state the basis for their exclusion.In its response, by letter dated July 21, 2005, the applicant stated that control rod velocitylimiters are plant-engineered safety features (ESFs), as described in USAR Chapter 6. Control rod velocity limiters are provided as an integral part of each control rod. They provide hydraulic damping to reduce the freefall velocity of the rod and thereby reduce the consequences if the control rod becomes detached from its drive and drops from the core. Since the control rod velocity limiters are an integral part of each control rod, the velocity limiters are within the scope of license renewal; however, the control rods (including the velocity limiters) are screened out of the AMR process since they are replaced periodically.Based on its review, the staff found the applicant's response to RAI 2.2-1 acceptable. Theapplicant stated that all ESFs are within the scope of license renewal and are in addition to the safety features included in the design of the reactor, reactor primary system, plant and reactorcontrol systems, and other instrumentation or process systems. Most of the ESFs serve nofunction during normal plant operation, but are included for the sole purpose of reducing the consequences of DBAs described in USAR Section 14. The applicant stated that LRA Section 2.3.3.4 includes a discussion of the control rod velocity limiters. Therefore, the applicantresolved the staff concern described in RAI 2.2-1.In RAI 2.2-2, dated June 21, 2002, the staff noted that the safety parameter displaysystem (SPDS) is described in USAR Section 7.13. The SPDS provides a concise display ofcritical plant variables to control room operators to aid them in rapidly and reliably determining the safety status of the plant. The LRA does not mention this system, nor does it appear torefer to USAR Section 7.13 in the text; therefore, the staff requested that the applicant clarifywhether this system is within the scope of license renewal or state the basis for its exclusion.In its response, by letter dated July 21, 2005, the applicant stated that it included the processcomputer system (PCS) in the license renewal system under "Computer."  The LRA lists thecomputer system in Table 2.2-1, "Plant Level Scoping Results," page 2-47, which states that the system is not within the scope of license renewal. The PCS provides input to the SPDS andthe SPDS is considered a PCS subsystem.
2-27The applicant further stated that the purpose of the PCS system is to aid the operator in timelydetermination of the plant's operability status during all plant conditions by providing a real-timepresentation of operational data, including input to the SPDS, pertaining to the reactor core andother plant equipment. USAR Section 7.13 states that the SPDS is not essential to safeoperation of the plant, prevention of events that endanger public health and safety, or mitigationof the consequences of an accident. The PCS also records plant operational data, which can be recalled for evaluation of abnormal and unusual events.The applicant stated that the USAR discusses the PCS in relation to such topics as the rodworth minimizer, accident monitoring instrumentation, and the SPDS. The process computer isnot SR and its failure will not cause an SR function to fail (USAR Section 7.8.3). SR isolationdevices between the PCS, neutron monitoring, and the plant protection system (PPS) signalinputs are parts of these other systems for purposes of license renewal.Based on its review, the staff found the applicant's response to RAI 2.2-2 acceptable. Theapplicant stated that the process computer is not on the MNGP Q-list. The process computer isnot required for any of the regulated events referenced in 10 CFR 54.4(a)(3). The 250-volts-direct current (VDC) system battery that powers the process computer is not required tofunction during an SBO event. The FP system does not rely on the computer to process firedetection and alarm signals. The required ATWS monitoring instrumentation does not rely on the PCS; thus, the PCS, including the SPDS, was determined to be outside the scope of licenserenewal. Therefore, the staff's concern described in RAI 2.2-2 is resolved.2.2.4  Conclusion The staff reviewed LRA Section 2.2, the RAI responses described above, and the supportinginformation in the MNGP USAR to determine whether the applicant had failed to identify any systems and structures that should be within the scope of license renewal. The staff's reviewdid not identify any omissions. On the basis of this review, the staff concluded that the applicantproperly identified the systems and structures that are within the scope of license renewal inaccordance with 10 CFR 54.4.2.3  Scoping and Screening Results:  Mechanical SystemsThis section documents the staff's review of the applicant's scoping and screening results formechanical systems. Specifically, this section discusses the following mechanical systems:
* reactor vessel, internals, and reactor cool ant system (RCS)
* ESFs
* auxiliary systems
* steam and power conversion systemIn accordance with the requirements of 10 CFR 54.21(a)(1), the applicant must identify and listpassive, long-lived mechanical SSCs that are within the scope of license renewal and subject to an AMR. To verify that the applicant properly implemented its methodology, the staff focused itsreview on the implementation results. This approach allowed the staff to confirm that nomechanical system components that meet the scoping criteria and are subject to an AMR wereomitted.
2-28Staff Evaluation Methodology. The staff performed its evaluation of the information in the LRAin the same manner for all mechanical systems. The objective of the review was to determinewhether the applicant had identified the components and supporting structures for a specificmechanical system, that appeared to meet the scoping criteria specified in the Rule, as withinthe scope of license renewal, in accordance with 10 CFR 54.4. Similarly, the staff evaluated the applicant's screening results to verify that all long-lived, passive components were subject to an AMR, in accordance with 10 CFR 54.21(a)(1).Scoping. To perform its evaluation, the staff reviewed the applicable LRA section andassociated component drawings, focusing its review on components that had not been identified as within the scope of license renewal. The staff reviewed relevant licensing-basis documents, including the USAR, for each mechanical system to determine whether theapplicant had omitted components with intended functions delineated under 10 CFR 54.4(a)from the scope of license renewal. The staff also reviewed the licensing-basis documents to determine whether the LRA specified all intended functions delineated under 10 CFR 54.4(a). Ifomissions were identified, the staff requested additional information to resolve the discrepancies.Screening. Once the staff completed its review of the scoping results, the staff evaluated theapplicant's screening results. For those systems and components with intended functions, thestaff sought to determine (1) if the functions are performed with moving parts or a change in configuration or properties or (2) if the components are subject to replacement based on a qualified life or specified time period, as described in 10 CFR 54.21(a)(1). For t hose systemsand components that did not meet either of these criteria, the staff sought to confirm that thesemechanical systems and components were subject to an AMR, as required by10 CFR 54.21(a)(1). If discrepancies were identified, the staff requested additional information to resolve them.2.3.1  Reactor Vessel, Internals, and Reactor Coolant System In LRA Section 2.3.1, the applicant identified the SCs of the reactor vessel, internals, and RCSthat are subject to an AMR for license renewal.The applicant described the supporting SCs of the reactor vessel, internals, and RCS in thefollowing sections of the LRA:
* 2.3.1.1reactor head v ent system
* 2.3.1.2reactor pressure vessel
* 2.3.1.3reactor pressure vessel internals
* 2.3.1.4reactor recirculation system
* 2.3.1.5reactor vessel instrumentationSER Sections 2.3.1.1-2.3.1.5 present the staff's review findings regarding LRASections 2.3.1.1-2.3.1.5, respectively.
2-292.3.1.1  Reactor Head Vent System2.3.1.1.1  Summary of Technical Information in the Application In LRA Section 2.3.1.1, the applicant described the reactor head vent system. The reactor headvent system maintains the reactor pressure boundary. The reactor head v ent system provides ameans to (1) permit venting the RPV during filling for hydrostatic test, (2) permit remote ventingof noncondensable gases which may accumulate in the vessel head space during reactor cooldown after the main steamlines have been flooded, and (3) permit venting of noncondensable disassociated gases which might accumulate in the vessel head space during reactor operation to one of the main steamlines.The reactor head vent system contains SR components that are relied upon to remainfunctional during and following DBEs.The intended function, within the scope of license renewal, is to provide a pressure-retainingboundary.In LRA Table 2.3.1-1, the applicant identified the following reactor head vent system componenttypes that are within the scope of license renewal and subject to an AMR:
* fasteners/bolting
* piping and fittings
* valve bodies2.3.1.1.2  Staff Evaluation The staff reviewed LRA Section 2.3.1.1 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.3.1.1.3  Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the reactor head vent systemcomponents that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the reactor head vent system components that are subject to an AMR, as required by10 CFR 54.21(a)(1).
2-302.3.1.2  Reactor Pressure Vessel2.3.1.2.1  Summary of Technical Information in the Application In LRA Section 2.3.1.2, the applicant described the RPV system. The RPV system consists ofthe RPV top head enclosure, vessel shell, nozzles, nozzle safe ends, penetrations, bottom head, and support skirt and attachment welds. RPV internals are included in the reactor internals system. The RPV serves as a high-integrity barrier against leakage of radioactivematerials to the drywell.The RPV system contains SR components that are relied upon to remain functional during andfollowing DBEs. In addition, the RPV system performs functions that support FP, ATWS, and SBO.The intended functions within the scope of license renewal include the following:
* provide a pressure-retaining boundary
* provide structural support to SR components (vessel internals)In LRA Table 2.3.1-2, the applicant identified the following RPV system com ponent types thatare within the scope of license renewal and subject to an AMR:
* bottom head components-bottom head dollar plate, bottom head torus
* nozzle safe ends-control rod drive return line cap
* nozzle safe ends-core spray
* nozzle safe ends-feedwater (FW) nozzle
* nozzle safe ends-instrument and standby liquid control (SLC)
* nozzle safe ends-jet pump instrument
* nozzle safe ends-main steam
* nozzle safe ends-recirculating water
* nozzle safe ends and flanges-instrument
* nozzles-CRD return line
* nozzles-FW
* nozzles-main steam
* nozzles-recirculation outlet, recirculation inlet, core spray, jet pump instrument,instrument and SLC
* penetration-bottom head drainline
* penetration-CRD stub t ubes
* penetration-flux monitor
* penetration-instrument 2-31
* RPV external surface
* support skirt and attachment welds
* top head enclosure-closure studs and nuts
* top head enclosure-head spray cap
* top head enclosure-instrument nozzle (head spare)
* top head enclosure-instrument nozzle flange (head spare)
* top head enclosure-top head dollar plate
* top head enclosure-top head flange
* top head enclosure-top head torus
* top head enclosure-vent nozzle
* vessel shell attachment welds
* vessel shell-upper intermediate shell, lower intermediate shell, lower shell, beltlinewelds
* vessel shell-vessel flange, upper shell2.3.1.2.2  Staff Evaluation The staff reviewed LRA Section 2.3.1.2 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.3.1.2.3  Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs thatshould be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the RPV system componentsthat are within the scope of license renewal, as required by 10 CFR 54.4(a), and the RPV system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2-322.3.1.3  Reactor Pressure Vessel Internals2.3.1.3.1  Summary of Technical Information in the Application In LRA Section 2.3.1.3, the applicant described the RPV internals. The RPV internals consist ofall the SCs within the reactor vessel that provide support for the core, control rod systemsupport, instrumentation support, and steam quality enhancement and that direct coolant flow.The RPV internals contain SR components that are relied upon to remain functional during andfollowing DBEs. The failure of NSR SSCs in the RPV internals could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the RPV internals perform functions that support FP, ATWS, and SBO.The intended functions within the scope of license renewal include the following:
* provide a pressure-retaining boundary
* provide structural support to SR components (vessel internals)
* provide adequate flow in a specified distribution spray patternIn LRA Table 2.3.1-3, the applicant identified the following RPV internals component types thatare within the scope of license renewal and subject to an AMR:
* access hole covers
* control rod drive housing
* control rod guide tube (CRGT)
* CRGT base
* core plate
* core plate bolts
* core shroud (upper, central, lower)
* core spray lines and spargers, piping supports, clamp modification, core spray lines(headers), spray rings, spray nozzles, thermal sleeves
* intermediate-range monitor dry tubes, source range monitor dry tubes, incore fluxmonitor guide tubes, low-power range monitor (LPRM) dry tubes
* jet pump assembly-riser pipe
* jet pump assemblies-castings (elbow, collar, flare, flange, transition piece)
* jet pump assemblies-diffuser
* jet pump assemblies-holddown beams
* jet pump assemblies-inlet header
* jet pump assemblies-inlet elbow
* jet pump assemblies-mixing assembly
* jet pump assemblies-riser brace arm 2-33
* jet pump assemblies-thermal sleeves
* LPRM dry tubes
* orificed fuel support
* shroud support structure (shroud support cylinder, shroud support plate, shroud supportlegs)
* standby liquid control distribution pipe
* steam dryer
* top guide2.3.1.3.2  Staff Evaluation The staff reviewed LRA Section 2.3.1.3 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive, long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.3.1.3 identified areas for which it needed additionalinformation to complete its evaluation of the applicant's scoping and screening results. The applicant responded to the staff's RAIs as discussed below.In RAI 2.3.1-1, dated September 15, 2005, the staff noted that LRA Section 3.1.2.2.4.2 statesthe jet pump sensing lines internal to the reactor vessel are not within the scope of license renewal; however, it is unclear whether the portion of the jet pump sensing line external to the reactor vessel that can provide a pressure boundary and structural support is within the scope of license renewal. The staff requested that the applicant indicate whether it had included the external jet pump sensing line piping within the scope of license renewal and identify the LRA table and subcomponent group including the subject component or justify the exclusion.In its response, by letter dated October 14, 2005, the applicant stated the following:Jet Pump Sensing Lines external to the vessel are in scope for license renewal.The sentence on page 3-30 of the LRA was intended to indicate that only internal lines are outside scope. The sensing lines are 1-inch stainless steel pipes in the Reactor Vessel Instrumentation (RVI) system. The aging management for theinternal (Treated Water) environment is shown in LRA Table 3.1.2-5 Reactor Coolant System-Reactor Vessel Instrumentation, on Page 3-82. The applicable aging effects are cracking and loss of material which are managed by American Society of Mechanical Engineers (ASME) Section XI Subsections IWB, IWC, and IWD, the Plant Chemistry Program, and the One-Time Inspection Program. No 2-34aging management is required for the external surfaces of the stainless steelsensing lines exposed to primary containment and plant indoor air.Based on its review, the staff found the applicant's response to RAI 2.3.1-1 acceptable basedon the inclusion of the subject component; therefore, the applicant resolved the staff concerndescribed in RAI 2.3.1-1.In RAI 2.3.1-2, dated September 15, 2005, the staff noted that in LRA Table 2.3.1-3, "ReactorPressure Vessel Internals," core spray (CSP) lines and spargers have been identified as a component type within the scope of license renewal; however, for these components, pressure boundary was identified as the only intended function requiring aging management and not theirfunction of providing adequate flow in a properly distributed spray pattern. The staff requested that the applicant clarify why it had not identified the spray pattern function, in addition topressure boundary function, as an intended function needing maintenance during the extended period of operation.In its response, dated October 14, 2005, the applicant stated the USAR Section 3.6.2.10, "CoreSpray Spargers," states, "The supply line pairs terminate at a common vessel nozzle. Each half has distribution nozzles pointed radially inward and downward at a slight angle to achieve a specified distribution pattern." Therefore, an intended function of 'spray pattern' is assigned to the CSP lines and spargers by revision to LRA Tables 2.3.1-3, "Reactor Pressure Vessel Internals," and 3.1.2-3, "Reactor Coolant System-Reactor Pressure Vessel Internals." There are no changes to the aging effects or the aging management programs (AMPs). The applicant added the component intended function, "spray pattern-to provide adequate flow in a specified distribution spray pattern," by revising LRA Table 2.1-1, "lntended Function Definitions."Based on its review, the staff found the applicant's response to RAI 2.3.1-1 acceptable basedon the inclusion of the spray pattern intended function for the above component; therefore, the applicant resolved the staff concern described in RAI 2.3.1-2.2.3.1.3.3  Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant had adequately identified the RPV internalscomponents that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the RPV internals components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.1.4  Reactor Recirculation System 2.3.1.4.1  Summary of Technical Information in the Application In LRA Section 2.3.1.4, the applicant described the reactor recirculation (REC) system. TheREC system includes the recirculation flow control (RFC) subsystem for license renewalpurposes. The REC system forces water through the reactor core to provide forced convectioncooling of the reactor core. The system consists of two recirculation pump loops outside thevessel and twenty jet pumps inside the vessel. The jet pumps are part of the reactor internals 2-35system. Each REC system loop outside the vessel consists of a motor-driven recirculationpump, two motor-operated gate valves for pump isolation, piping, and required recirculation flowmeasurement devices. Jet pump flow instrumentation outside the reactor vessel is included within the license renewal boundary of the REC system. The REC system (via the recirculationflow control subsystem) also functions as a method of controlling the reactor power level. TheREC system pumps, motors, and loop piping are located in the drywell outside the biologicalshield.The REC system contains SR components that are relied upon to remain functional during andfollowing DBEs. The failure of NSR SSCs in the REC system could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the REC system performs functions that support EQ and ATWS.The intended function, within the scope of license renewal, is to provide a pressure-retainingboundary.In LRA Table 2.3.1-4, the applicant identified the following REC system com ponent types thatare within the scope of license renewal and subject to an AMR:
* fasteners/bolting
* filters/strainers
* heat exchangers
* manifolds
* piping and fittings
* pump casings
* restricting orifices
* tanks
* thermowells
* valve bodies2.3.1.4.2  Staff Evaluation The staff reviewed LRA Section 2.3.1.4 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.3.1.4 identified an area for which it needed additionalinformation to complete its evaluation of the applicant's scoping and screening results. The applicant responded to the staff's RAI as discussed below.
2-36In RAI 2.3.1-3, dated September 15, 2005, the staff noted that, in LRA Table 2.3.1-4, "ReactorRecirculation System," and for a few other systems (for example the CSP and CRD systems),heat exchangers were identified as a component type within the scope of license renewal; however, for these heat exchangers, pressure boundary was identified as the only intended function requiring aging management and not their heat transfer function. Therefore, the staffrequested that the applicant clarify why it did not identify the heat transfer function, in additionto the pressure boundary function, as an intended function needing maintenance during the extended period of operation.In its response, by letter dated October 14, 2005, the applicant stated the following:The heat exchangers in scope for the Reactor Recirculation (REC) system are:
* The No. 11 and No.12 REC Motor/Generator Set Oil Coolers - Theseheat exchangers are shown on License Renewal (LR) drawing LR-36041 and are in scope for non-safety related components that could adversely affect safety related systems, structures, and components (SSCs) andare only required to maintain a pressure boundary. Therefore, no heat transfer function is required for these components to meet their intended functions.
* The REC Pump Lower Seal Cooler and REC Pump Upper Seal Cooler -These heat exchangers are shown on drawing LR-36243-1. The heat exchanger tubes serve as a reactor coolant pressure boundary, whereas the shells are in scope for non-safety related components that could adversely affect safety related SSCs and are only required to maintain a pressure boundary. Therefore, no heat transfer function is required for these components to meet their intended functions.The heat exchangers in scope for the Core Spray (CSP) System are:
* The CSP Pump Motor Oil Coolers - The heat exchangers are shown ondrawing LR-36664. An analysis concluded that the core spray motors are operable if motor cooling water is reduced to zero under worst case room temperatures. Therefore the heat exchanger does not have an intended function of providing heat transfer. The heat exchanger serves only a pressure boundary function.The heat exchangers in scope for the Control Rod Drive (CRD) system are:
* The CRD Pump Thrust Bearing Cooler and the Lube Oil Cooler for theCRD Pump Speed Increaser Assemblies - These heat exchangers areshown on drawing LR-36244. The heat exchangers are in scope as non-safety related components that could adversely affect safety related SSCs. They are only required to maintain a pressure boundary.
Therefore, no heat transfer function is required for these components to meet their intended safety functions.
2-37Based on its review, the staff found the applicant's response to RAI 2.3.1-3 acceptable. Heattransfer is not an intended function for the REC system heat exchangers; therefore, theapplicant resolved the staff concern described in RAI 2.3.1-3.2.3.1.4.3  Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs thatshould be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the REC system components that arewithin the scope of license renewal, as required by 10 CFR 54.4(a), and the REC systemcomponents that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.1.5  Reactor Vessel Instrumentation 2.3.1.5.1  Summary of Technical Information in the Application In LRA Section 2.3.1.5, the applicant described the RVI system. The RVI system is designed tofulfill a number of requirements pertaining to the vessel itself or the reactor core. Theinstrumentation must (1) provide the operator with sufficient information in the control room toprotect the vessel from undue stresses, (2) provide information which can be used to assure that the reactor core remains covered with water and that the steam separators are not flooded,(3) provide redundant, reliable inputs to the reactor protection system to shut the reactor downwhen fuel damage limits are approached, and (4) provide a method of detecting leakage from the reactor vessel head flange. The RVI system also includes the reference leg backfillsubsystem. This subsystem provides a constant backfill of water from the CRD system's charging water header to the safeguards and FW reference legs to flush any gas-laden water through the condensate chambers and back to the reactor vessel to eliminate level errors resulting from the degassing phenomenon.The RVI system contains SR components that are relied upon to remain functional during andfollowing DBEs. The failure of NSR SSCs in the RVI system could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the RVI system performs functions that support FP, EQ, ATWS, and SBO.The intended functions within the scope of license renewal include the following:
* provide a pressure-retaining boundary
* provide flow restrictionIn LRA Table 2.3.1-5, the applicant identified the following RVI system com ponent types thatare within the scope of license renewal and subject to an AMR:
* fasteners/bolting
* manifolds
* piping and fittings
* restricting orifices
* thermowells 2-38
* valve bodies2.3.1.5.2  Staff Evaluation The staff reviewed LRA Section 2.3.1.5 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.3.1.5.3  Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the RVI system componentsthat are within the scope of license renewal, as required by 10 CFR 54.4(a), and the RVI system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.2  Engineered Safety Features In LRA Section 2.3.2, the applicant identified the SCs of the ESFs that are subject to an AMRfor license renewal.The applicant described the supporting SCs of the ESFs in the following sections of the LRA:
* 2.3.2.1automatic pressure relief system
* 2.3.2.2combustible gas control system
* 2.3.2.3core spray system
* 2.3.2.4high pressure coolant injection system
* 2.3.2.5primary containment mechanical system
* 2.3.2.6reactor core isolation cooling system
* 2.3.2.7residual heat removal system
* 2.3.2.8secondary containm ent systemSER Sections 2.3.2.1-2.3.1.8 present the staff's review findings regarding LRASections 2.3.2.1-2.3.1.8, respectively.
2-392.3.2.1  Automatic Pressure Relief System2.3.2.1.1  Summary of Technical Information in the Application In LRA Section 2.3.2.1, the applicant described the automatic pressure relief (APR) system.The APR system is designed to prevent overpressurization and provide depressurization of thereactor vessel during DBEs. Two safety relief valves (SRVs) on each of the four steamlines are equipped to operate by automatic or manual initiation to blow down the reactor. Steam is passed through the valves, down a tailpipe, and through the torus vent headers to discharge underwater through T-quenchers in the event of SRV activation. The automatic depressurizati on system (ADS) is an APR subsystem that provides backup to the high pressurecoolant injection (HPC) system and is designed to reduce reactor vessel pressure to a rangesuitable for low-pressure emergency core cooling pumps to operate. The low-low set system isan APR subsystem designed to control post-shutdown overpressure with progressive SRVpressure release setpoints. The alternate shutdown (ASD) system panel provides for manualoperation of four APR system SRVs. The APR system is also used to implement the ASDcooling method. To use the ASD cooling method, the reactor is depressurized using the automatic depressurization subsystem of the APR system.The APR system contains SR components that are relied upon to remain functional during andfollowing DBEs. In addition, the APR system performs functions that support FP, EQ, and SBO.The intended function, within the scope of license renewal, is to provide a pressure-retainingboundary.In LRA Table 2.3.2-1, the applicant identified the following APR system com ponent types thatare within the scope of license renewal and subject to an AMR:
* accumulators
* fasteners/bolting
* manifolds
* piping and fittings
* thermowells
* valve bodies2.3.2.1.2  Staff Evaluation The staff reviewed LRA Section 2.3.2.1 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).
2-402.3.2.1.3  ConclusionThe staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the APR system componentsthat are within the scope of license renewal, as required by 10 CFR 54.4(a), and the APR system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.2.2  Combustible Gas Control System 2.3.2.2.1  Summary of Technical Information in the Application In LRA Section 2.3.2.2, the applicant described the combustible gas control (CGC) system. Inits letter, dated March 15, 2006, the applicant stated that the CGC system was deactivated bycutting and capping process lines connecting to interfacing systems during the 2005 refuelingoutage, in accordance with the NRC's approval of License Amendment 138, which eliminatedthe requirements for hydrogen recombiners and relaxed the requirements for hydrogen and oxygen monitoring. Therefor e, the system has been removed from the scope of licenserenewal.2.3.2.2.2  Conclusion On the basis of the isolation and capping of the CGC system due to License Amendment 138,the staff concluded that the applicant appropriately characterized t he system as outside thescope of license renewal.2.3.2.3  Core Spray System 2.3.2.3.1  Summary of Technical Information in the Application In LRA Section 2.3.2.3, the applicant described the CSP system. The CSP system restores andmaintains the coolant in the RPV in combination with other emergency core cooling systems (ECCS) such that the core is adequately cooled to preclude fuel damage. Twoindependent CSP system loops are provided for use under loss-of-coolant accident (LOCA)conditions associated with large pipe breaks and reactor vessel depressurization. Suction water is normally supplied from the suppression pool, but can also be supplied by the condensate storage tank (CST). The CSP system provides adequate cooling along with low-pressurecoolant injection (LPCI) for intermediate and large line break sizes up to and including the design-basis, double-ended recirculation line break, without assistance from any other ECCS.
In conjunction with the LPCI mode of the RHR system, the HPC system, and the APR, the CSPsystem can act automatically (in response to signals indicative of a LOCA) to reflood the reactorcore and maintain core cooling following a LOCA event. Initiation of the CSP system occurs onsignals indicating (1) reactor low-low water level coincident with low reactor pressure, or (2) sustained reactor low-low water level, or (3) high drywell pressure. The reactor low-low water level signal or the high drywell pressure signal also initiate the emergency diesel generators (EDGs). Cooling water to the CSP system pump motor coolers is supplied by the 2-41emergency service water (ESW) system. The power source for each CSP system is located onseparate emergency buses. The EDGs can supply power for these emergency buses.The CSP system contains SR components that are relied upon to remain functional during andfollowing DBEs. The failure of NSR SSCs in the CSP system could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the CSP system performs functions that support FP, EQ, and SBO.The intended functions within the scope of license renewal include the following:
* provide flow restriction
* provide a pressure-retaining boundaryIn LRA Table 2.3.2-3, the applicant identified the following CSP system com ponent types thatare within the scope of license renewal and subject to an AMR:
* fasteners/bolting
* gauges (flow, level, and sight)
* heat exchangers
* manifolds
* piping and fittings
* pump casings
* restricting orifices
* thermowells
* valve bodies2.3.2.3.2  Staff Evaluation The staff reviewed LRA Section 2.3.2.3 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.3.2.3.3  Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant had adequately identified the C SP systemcomponents that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the CSP system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2-422.3.2.4  High Pressure Coolant Injection System2.3.2.4.1  Summary of Technical Information in the Application In LRA Section 2.3.2.4, the applicant described the HPC system. The HPC system is part of theECCS. The ECCS provides for continuity of reactor core cooling over the entire range of postulated breaks in the reactor primary system. The HPC system provides adequate corecooling for all break sizes less than those sizes for which the LPCI subsystem or C SP systemcan adequately protect the core, without assistance from other safeguards systems. The HPCsystem performs this function without reliance on offsite power or a water source for theinjection. The HPC system can pump water into the RPV under LOCA conditi ons that do notresult in rapid depressurization of the RPV. The HPC system is a high-head, low-flow systemthat pumps water into the RPV when the reactor primary system is at high pressure. If the HPCsystem fails to deliver the required flow of cooling water to the RPV, the automaticdepressurization feature of the reactor APR system functions to reduce system pressure so thatthe LPCI subsystem can operate to inject water into the RPV. The HPC turbine trips when theturbine steam supply pressure has decreased to the isolation setpoint. All these operations are performed automatically.The HPC system contains SR components that are relied upon to remain functional during andfollowing DBEs. The failure of NSR SSCs in the HPC system could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the HPC system performs functions that support EQ and SBO.The intended functions within the scope of license renewal include the following:
* provide filtration
* provide flow restriction
* provide for heat transfer
* provide a pressure-retaining boundary
* limit heat transfer to maintain temperatureIn LRA Table 2.3.2-4, the applicant identified the following HPC system com ponent types thatare within the scope of license renewal and subject to an AMR:
* fan/blower/housings
* fasteners/bolting
* filters/housings
* gauges (flow, level, and sight)
* heat exchangers
* manifolds
* piping and fittings
* pump casings
* restricting orifices
* steam traps
* tanks
* thermowells
* turbines
* valve bodies 2-432.3.2.4.2  Staff EvaluationThe staff reviewed LRA Section 2.3.2.4 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.3.2.4.3  Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the HPC systemcomponents that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the HPC system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.2.5  Primary Containment Mechanical System 2.3.2.5.1  Summary of Technical Information in the Application In LRA Section 2.3.2.5, the applicant described the primary containment mechanical (PCM)system. The PCM system includes the containment atmosphere control and nitrogen controlcomponents, the hydrogen-oxygen analyzing, the post-accident sampling (PAS), and the hard pipe vent subsystems. The PCM system was created to separate out the mechanicalcomponents of the primary containment (PCT) system for license renewal evaluation purposes.The mechanical components, and the associated electrical and I&C components, were transferred from the PCT system to the PCM system. The resulting PCT system contains only the structural components of the primary containment system. For license renewal evaluations,the PCM system also includes the portions of the mechanical containment penetrationassemblies that are extensions of the mechanical piping. These are the flued heads and guardpipes of the mechanical containment penetration assemblies. The other components of the containment penetration assemblies (e.g., the sleeves) are evaluated in the PCT system. ThePAS subsystem consists of a liquid and gas sample station located outside the secondarycontainment in the turbine building near the control room access door. The system is designedto provide samples under all conditions ranging from normal shutdown and power operation to the design-basis LOCA. The hard pipe vent subsystem provides a vent path from the pressure suppression chamber (wetwell) vapor space to a release point above the reactor building.The PCM system contains SR components that are relied upon to remain functional during andfollowing DBEs. The failure of NSR SSCs in the PCM system could potentially prevent the 2-44satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. Inaddition, the PCM system performs functions that support FP, EQ, and SBO.The intended functions within the scope of license renewal include the following:
* provide filtration
* provide a pressure-retaining boundary
* provide pressure boundary or fission product retentionIn LRA Table 2.3.2-5, the applicant identified the following PCM system com ponent types thatare within the scope of license renewal and subject to an AMR:
* accumulators
* fasteners/bolting
* filters/strainers
* flow element
* manifolds
* piping and fittings
* rupture disks
* thermowells
* valve bodies2.3.2.5.2  Staff Evaluation The staff reviewed LRA Section 2.3.2.5 and USAR Sections 5.2.1.3, 5.2.2.
3, 5.2.2.7, 5.2.3.10, 5.2.3.11, and 10.3.10.1 using the evaluation methodology described in SER Section 2.3. Thestaff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.3.2.5.3  Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the PCM systemcomponents that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the PCM system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2-452.3.2.6  Reactor Core Isolation Cooling System2.3.2.6.1  Summary of Technical Information in the Application In LRA Section 2.3.2.6, the applicant described the reactor core isolation cooling (RCI) system.The MNGP licensing basis does not include the RCI system as an ESF system  The RCIsystem is included within this section, and the related aging management section, forconsistency with the SRP-LR and NUREG-1801, "Generic Aging Lessons Leaned (GALL)Report," issued July 2001. The RCI system uses a steam-driven turbine to drive a pump toinject water into the reactor vessel so that the core is not uncovered in the event of a loss of FW. While the system is not credited in the SBO analysis for mitigating loss of offsitepower (LOOP) events, the system may be used to cope with such events. The RCI pump issupplied demineralized makeup water from the CST and can use the suppression pool as an alternate SR source of water. All components necessary for the initiation and operation of the RCI system are completely independent of any auxiliary alternating current (AC) power, plantservice air, and external cooling water systems, requiring only direct current (DC) control andinstrument power from the plant batteries. The RCI system also provides for primary containment isolation. The pumping capacity of the RCI system is sufficient to maintain thewater level above the core without any other makeup water system in operation.The RCI system contains SR components that are relied upon to remain functional during andfollowing DBEs. The failure of NSR SSCs in the RCI system could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the RCI system performs functions that support EQ.The intended functions within the scope of license renewal include the following:
* provide filtration
* provide flow restriction
* provide for heat transfer
* provide a pressure-retaining boundaryIn LRA Table 2.3.2-6, the applicant identified the following RCI system com ponent types thatare within the scope of license renewal and subject to an AMR:
* fasteners/bolting
* filters/strainers
* heat exchangers
* manifolds
* piping and fittings
* pump casings
* restricting orifices
* steam traps
* tanks
* thermowells
* turbines
* valve bodies 2-462.3.2.6.2  Staff EvaluationThe staff reviewed LRA Section 2.3.2.6 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.3.2.6.3  Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the RCI system componentsthat are within the scope of license renewal, as required by 10 CFR 54.4(a), and the RCI system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.2.7  Residual Heat Removal System 2.3.2.7.1  Summary of Technical Information in the Application In LRA Section 2.3.2.7, the applicant described the RHR system. The RHR system restoresand maintains the reactor coolant inventory in the reactor core so that the reactor core isadequately cooled after depressurization during a LOCA. The RHR system also providescooling for the suppression pool to ensure condensation of the steam resulting from the blowdown from the design-basis LOCA. The RHR system further extends the redundancy of theECCS by providing for primary containment spray/cooling. In addition, the RHR systemprovides for primary containment isolation. The RHR system is designed for essentially threemodes of operation, (1) LPCI, (2) containment spray/cooling, and (3) reactor shutdown cooling.The shutdown cooling s ubsystem is used for routine operations. The LPCI s ubsystem is anintegral part of the RHR system. It operates to restore and maintain the reactor coolantinventory in the reactor core after a LOCA so that the core is sufficiently cooled. The LPCIsubsystem operates in conjunction with the HPC system, the APR system, and the CSP systemto achieve this goal. The RHR system provides a means to remove decay heat and residualheat from the reactor so that refueling and reactor systems servicing can be performed. Inaddition, the RHR system provides the means to supplement the spent fuel pool cooling systemwhen necessary to provide additional cooling capacity.The RHR system contains SR components that are relied upon to remain functional during andfollowing DBEs. The failure of NSR SSCs in the RHR system could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the RHR system performs functions that support FP, EQ, and SBO.
2-47The intended functions within the scope of license renewal include the following:
* provide filtration
* provide for heat transfer
* provide a pressure-retaining boundary
* limit heat transfer to maintain temperatureIn LRA Table 2.3.2-7, the applicant identified the following RHR system component types thatare within the scope of license renewal and subject to an AMR:
* accumulators
* fasteners/bolting
* filters/strainers
* heat exchangers
* manifolds
* nozzles
* piping and fittings
* pump casings
* restricting orifices
* thermowells
* valve bodies2.3.2.7.2  Staff Evaluation The staff reviewed LRA Section 2.3.2.7 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.3.2.7.3  Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the RHR systemcomponents that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the RHR system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2-482.3.2.8  Secondary Containment System2.3.2.8.1  Summary of Technical Information in the Application In LRA Section 2.3.2.8, the applicant described the secondary containment (SCT) system. TheSCT system completely encloses the reactor and its pressure suppression primarycontainment. The secondary containment enclosure structure provides secondary containment when the primary containment is closed and in service and primary containment when the primary containment is open, as during refueling. The reactor building houses the refueling and reactor servicing equipment, new and spent fuel storage facilities, and other reactor auxiliarysystems or service equipment. The primary purposes for the secondary containment are tominimize ground-level release of airborne radioactive materials to the environs and to provide means for a controlled, elevated release of the building atmosphere, if an accident shouldoccur. The standby gas treatment system (SGTS) is a subsystem of the SCT system and isprovided to maintain, whenever secondary containment isolation conditions exist, a small negative pressure to minimize ground-level escape of airborne radioactivity. Filters are in the system to remove radioactive particulates, and charcoal adsorbers are provided to removeradioactive halogens. All flow from the standby gas treatment system is released through theelevated offgas vent stack and continuously monitored by the stack gas monitori ng system.The SCT system contains SR components that are relied upon to remain functional during andfollowing DBEs. In addition, the SCT system performs functions that support EQ.The intended functions within the scope of license renewal include the following:
* provide flow restriction
* provide a pressure-retaining boundaryIn LRA Table 2.3.2-8, the applicant identified the following SCT system com ponent types thatare within the scope of license renewal and subject to an AMR:
* damper housings
* ductwork
* fan/blower/housings
* fasteners/bolting
* filters/housings
* flow element
* manifolds
* piping and fittings
* restricting orifices
* thermowells
* valve bodies
* ventilation seal2.3.2.8.2  Staff Evaluation The staff reviewed LRA Section 2.3.2.8 and USAR Section 5.3 using the evaluationmethodology described in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.
2-49In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.3.2.8.3  Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the SCT system componentsthat are within the scope of license renewal, as required by 10 CFR 54.4(a), and the SCT system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3  Auxiliary Systems In LRA Section 2.3.3, the applicant identified the SCs of the auxiliary systems that are subjectto an AMR for license renewal.The applicant described the supporting SCs of the auxiliary systems in the following sections ofthe LRA:
* 2.3.3.1alternate nitrogen system
* 2.3.3.2chemistry sampling system
* 2.3.3.3circulating water system
* 2.3.3.4control rod drive system
* 2.3.3.5demineralized water system
* 2.3.3.6emergency diesel generators system
* 2.3.3.7emergency filtration train system
* 2.3.3.8emergency service water system
* 2.3.3.9fire system
* 2.3.3.10fuel pool cooling and cleanup system
* 2.3.3.11heating and ventilation system
* 2.3.3.12instrument and service air system
* 2.3.3.13radwaste solid and liquid system
* 2.3.3.14reactor building closed cooling water system
* 2.3.3.15reactor water cleanup system
* 2.3.3.16service and seal water system
* 2.3.3.17standby liquid control system
* 2.3.3.18wells and domestic water systemSER Sections 2.3.3.1-2.3.3.18 present the staff's review findings regarding LRASections 2.3.3.1-2.3.3.18, respectively.
2-502.3.3.1  Alternate Nitrogen System2.3.3.1.1  Summary of Technical Information in the Application In LRA Section 2.3.3.1, the applicant described the alternate nitrogen system (AN2). The AN2system consists of two separate SR trains providing an SR backup pneumatic source fromnitrogen bottle racks located in the turbine building. The AN 2 system interfaces with theinstrument and service air (AIR) system through a check valve, with the nitrogen side held at aslightly lower pressure to allow the AIR system to be used during normal operation. In the eventof an accident, which also disables the AIR system, the AN2 system would automatically supplythe required pneumatic loads. Manifold and system pressures of each train are monitored bypressure switches, which give control room annunciation on low pressure. The nitrogen supply bottles connected to the distribution rack are not long-lived components, and therefore, are notsubject to an AMR.The AN2 system contains SR components that are relied upon to remain functional during andfollowing DBEs. In addition, the AN2 system performs functions that support FP, EQ, and SBO.The intended function, within the scope of license renewal, is to provide a pressure-retainingboundary.In LRA Table 2.3.3-1, the applicant identified the following AN2 system component types thatare within the scope of license renewal and subject to an AMR:
* fasteners/bolting
* flexible connections
* piping and fittings
* valve bodies2.3.3.1.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.1 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.3.3.1 identified an area for which it needed additionalinformation to complete its evaluation of the applicant's scoping and screening results. The applicant responded to the staff's RAI as discussed below.In RAI 2.3.3.1-1, dated September 16, 2005, the staff noted that the license renewal drawingLR-36049-10 at location B-8 and C-8 shows the nitrogen supply bottles as within the scope of 2-51license renewal; however, LRA Table 2.3.3-1 does not list these nitrogen supply bottles as acomponent type subject to an AMR. These nitrogen supply bottles provide a pressure boundary intended function and are passive and long-lived; therefore, the staff requested that theapplicant clarify whether these nitrogen supply bottles are included with another component type (i.e., tanks) and if not, the applicant should justify why they are not listed in Table 2.3.3-1or update the table to include these components.In its response, by letter dated October 14, 2005, the applicant stated that nitrogen supplybottles are periodically replaced and therefore are not long-lived and are not subject to an AMR, pursuant to the requirements of 10 CFR 54.21(a).Based on its review, the staff found the applicant's response to RAI 2.3.3.1-1 acceptablebecause the nitrogen supply bottles are periodically replaced and thus are not subject to AMR; therefore, the applicant resolved the staff concern described in RAI 2.3.3.1-1.2.3.3.1.3  Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the AN 2 system componentsthat are within the scope of license renewal, as required by 10 CFR 54.4(a), and the AN2 system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3.2  Chemistry Sampling System 2.3.3.2.1  Summary of Technical Information in the Application In LRA Section 2.3.3.2, the applicant described the chemistry sampling (CHM) system. TheCHM system provides for sampling the process fluid of various systems to obtain representative data to evaluate the performance of the plant systems and equipment. The sampling locationsare chosen to ensure that representative samples can be obtained. The sample streams arerouted by the shortest route to a common sample collection area. There is a collective sample station for each building in the plant-radwaste building sample station, located in the radwastebuilding; reactor building sample station, located in the reactor building; and turbine building sample station, located in the turbine building. The stations are provided with closed-loopprocess lines that discharge to the equipment drain tanks and then to the waste collector tankfor reprocessing. Each sample station typically consists of a sample rack with sample shutoff valves; sample coolers; sample chillers; sample modules; instrumentation for conductivity, pH,dissolved oxygen, dissolved hydrogen, and total organic carbon, as well as a local data acquisition system panel. There is a ventilated fume hood for collection of grab samplesadjacent to the sample rack.The failure of NSR SSCs in the CHM system could potentially prevent the satisfactoryaccomplishment of an SR function of SSCs within the scope of license renewal.The intended function, within the scope of license renewal, is to provide a pressure-retainingboundary.
2-52In LRA Table 2.3.3-2, the applicant identified the following CHM system com ponent types thatare within the scope of license renewal and subject to an AMR:
* chillers
* fasteners/bolting
* filters/housings
* flow element
* heat exchangers
* manifolds
* piping and fittings
* thermowells
* valve bodies2.3.3.2.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.2 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.3.3.2.3  Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the CHM systemcomponents that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the CHM system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3.3  Circulating Water System 2.3.3.3.1  Summary of Technical Information in the Application In LRA Section 2.3.3.3, the applicant described the circulating water (CWT) system. The CWTsystem removes the heat from the main condenser that is rejected by the turbine or turbinebypass system over the full range of operating loads. The CWT system is a flexible multi-cyclesystem with the capability of once-through circulation of river water, recirculation in a closedcycle with cooling towers, and several variations of these basic modes. Selection of theoperating mode will be determined by the prevailing river flow rate and river temperature toprovide economic plant operation and conformance with restrictions on river water use. The system is equipped with two half-capacity CWT pumps located at the intake structure. The 2-53pumps are designed to circulate cooling water through the main condenser. Two half-capacitycooling tower pumps, located at the discharge structure, are used during cooling tower operation. The pumps are designed to operate in series with the CWT pumps, discharging flow to each of two induced-draft cooling towers.The failure of NSR SSCs in the CWT system could potentially prevent the satisfactoryaccomplishment of an SR function of SSCs within the scope of license renewal.The intended function, within the scope of license renewal, is to provide a pressure-retainingboundary.In LRA Table 2.3.3-3, the applicant identified the following CWT system com ponent types thatare within the scope of license renewal and subject to an AMR:
* condenser water box
* expansion joints
* fasteners/bolting
* filters/strainers
* gauges (flow, level, and sight)
* manifolds
* piping and fittings
* pump casings
* tanks
* thermowells
* valve bodies2.3.3.3.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.3 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.3.3.3.3  Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the CWT systemcomponents that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the CWT system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2-542.3.3.4  Control Rod Drive System2.3.3.4.1  Summary of Technical Information in the Application In LRA Section 2.3.3.4, the applicant described the CRD system. The CRD system is desi gnedto allow control rod withdrawal or insertion at a limited rate, one control rod at a time, for power-level control and flux shaping during reactor operation. Stored energy available from gas-charged accumulators and/or from reactor pressure provides hydraulic power for rapid simultaneous insertion of all control rods for rapid (scram) reactor shutdown. Each control rod has its own separate drive mechanism, control, and scram devices. The CRD system isdesigned so that sufficient energy is available to force the control rods into the core under conditions associated with abnormal operational transients and accidents. Control rod insertion speed is sufficient to prevent fuel damage as a result of any abnormal operational transient.
The CRD system also supplies water to the RVI reference-leg backfill subsystem. Thissubsystem provides a constant backfill of water from the CRD system's charging water headerto the safeguards and FW reference legs to flush any gas-laden water through the condensate chambers and back to the reactor vessel to eliminate level errors from the degassing phenomenon.The CRD system contains SR components that are relied upon to remain functional during andfollowing DBEs. The failure of NSR SSCs in the CRD system could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the CRD system performs functions that support FP, EQ, ATWS, and SBO.The intended function, within the scope of license renewal, is to provide a pressure-retainingboundary.In LRA Table 2.3.3-4, the applicant identified the following CRD system component types thatare within the scope of license renewal and subject to an AMR:
* accumulators
* fasteners/bolting
* filters/strainers
* flow element
* gauges (flow, level, and sight)
* heat exchangers
* manifolds
* piping and fittings
* pump casings
* restricting orifices
* speed increaser assembly
* tanks
* thermowells
* valve bodies 2-552.3.3.4.2  Staff EvaluationThe staff reviewed LRA Section 2.3.3.4 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.3.3.4.3  Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the CRD systemcomponents that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the CRD system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3.5  Demineralized Water System 2.3.3.5.1  Summary of Technical Information in the Application In LRA Section 2.3.3.5, the applicant described the demineralized water system (DWS). TheDWS provides for storage and distribution of high-quality, nonradioactive demineralized water for use as makeup to the CST system and other systems requiring high-quality demineralizedwater. The DWS is NSR and is not required during or following DBEs. The DWS includes the makeup demineralizer (MUD) subsystem. The MUD subsystem is a double-pass,reverse-osmosis system used to purify and demineralize well water. This demineralized water isused for various plant services which require quality water to (1) minimize damage to components because of chemical and corrosive attack, (2) minimize the fouling of heat transfer surfaces and mechanical parts, and (3) minimize impurities available for activation in neutron flux zones. The MUD subsystem is also NSR and is not required during or following DBEs. TheDWS provides for primary containment isolation.The DWS contains SR components that are relied upon to remain functional during andfollowing DBEs. The failure of NSR SSCs in the DWS could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal.The intended function, within the scope of license renewal, is to provide a pressure-retainingboundary.In LRA Table 2.3.3-5, the applicant identified the following DWS component types that arewithin the scope of license renewal and subject to an AMR:
2-56
* fasteners/bolting
* filters/housings
* flow element
* heat exchangers
* manifolds
* piping and fittings
* pump casings
* restricting orifices
* tanks
* thermowells
* ultraviolet light housings
* valve bodies2.3.3.5.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.5 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.3.3.5.3  Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the DWS components thatare within the scope of license renewal, as required by 10 CFR 54.4(a), and the DWS components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3.6  Emergency Diesel Generators System 2.3.3.6.1  Summary of Technical Information in the Application In LRA Section 2.3.3.6, the applicant described the EDG system (DGN). The DGN systemprovides a dependable, onsite power source capable of automatically starting and supplying the loads necessary to safely shut down the plant and maintain it in a safe-shutdown condition upon the loss of offsite power simultaneous with a DBA. The EDGs are normally in the standby mode of operation and remain in this mode unless called upon to start by receipt of appropriate automatic signals or by a manual start. The DGN system contains two identical electromotive,turbocharged, 20-cylinder EDGs, each supplying 4160 volts-alternating current (VAC) to its respective emergency bus. The following subsystems within the DGN system support operation 2-57of the EDGs-(1) an engine fuel oil system, (2) an engine lubricating oil system, (3) a startingair system, (4) a closed-cycle engine cooling water system, and (5) an air intake and exhaustsystem. The engine fuel oil system provides clean, water-free fuel oil to the diesel cylinders.The engine lubricating oil system provides filtered lubricating oil to the diesel engine to ensureadequate lubrication during engine startup and operation. The starting air system consists oftwo independent air-starting systems for each diesel that provide the motive force to initially putthe diesel engine in motion and begin the diesel cycle. The closed-cycle engine cooling watersystem provides cooling to the diesel cylinders and heads and the aftercooler of theturbocharger via two engine-driven centrifugal pumps. The EDG air intake and exhaust systemremoves exhaust gases from the diesel cylinders and supplies fresh air for the combustion process. The DGN system includes the diesel oil (DOL) system as a s ubsystem for licenserenewal purposes. The DOL subsystem provides for the storage and distribution of fuel oil usedin the operation of the plant EDGs, diesel fire pump, and heating boiler.The DGN system contains SR components that are relied upon to remain functional during andfollowing DBEs. The failure of NSR SSCs in the DGN system could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the DGN system performs functions that support FP.The intended functions within the scope of license renewal include the following:
* provide filtration
* provide for heat transfer
* provide a pressure-retaining boundaryIn LRA Table 2.3.3-6, the applicant identified the following DGN system com ponent types thatare within the scope of license renewal and subject to an AMR:
* fasteners/bolting
* filters/housings
* filters/strainers
* flame arrestors
* flow element
* gauges (flow, level, and sight)
* heat exchangers
* heaters/coolers
* manifolds
* piping and fittings
* pump casings
* silencer
* tanks
* thermowells
* valve bodies2.3.3.6.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.6 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.
2-58In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.3.3.6 identified an area for which it needed additionalinformation to complete its evaluation of the applicant's scoping and screening results. The applicant responded to the staff's RAI as discussed below.In RAI 2.3.3.6-1, dated September 16, 2005, the staff noted that the DGN system includes aDOL subsystem which stores and supplies diesel fuel oil for the operation of the plant dieselgenerators, diesel fire pump, and heating boiler. The DOL subsystem (except such portions asthe heating boiler oil storage tank and its day tank) is SR and within the scope of license renewal; however, license renewal drawing LR-36051 sheet 1 shows the truck f ill connection atlocation B-5 and the diesel oil receiving tank (T-83) subsystem (including pump, piping, andother components) at location A-7 as outside the scope of license renewal. Therefore, the staffrequested that the applicant clarify whether these components are within the scope of licenserenewal and subject to an AMR, in accordance with the applicable requirements of 10 CFR 54.4(a) and 10 CFR 54.21(a), respectively, or justify their exclusion.In its response, by letter dated October 14, 2005, the applicant stated that the diesel oilreceiving tank (T-83) and truck f ill connection are utilized for receiving, storing, and samplingdiesel fuel oil before transfer of the fuel oil to the diesel oil storage tank (T-44) and that these components are not SR. The applicant explained that failure of the truck f ill connection and thediesel oil receiving tank (T-83) and connecting piping outside the diesel fuel oil transfer house (pump house) would not impact the intended function of any SR SCs. The applicant, therefore, concluded that the NSR f ill connection, diesel oil receiving tank, and connectingpiping outside the pump house performed no license renewal function as defined by 10 CFR 54.4(a) and, therefore, were not within the scope of license renewal.Based on its review, the staff found the applicant's response to RAI 2.3.3.6-1 acceptablebecause the applicant provided a satisfactory explanation as to why the components are outside the scope of license renewal; therefore, the applicant resolved the staff concerndescribed in RAI 2.3.3.6-1.The staff's review of LRA Section 2.3.3.6 identified an area in which information provided in theLRA needed to be verified by the NRC Regional Inspection Team to complete the review of theapplicant's scoping and screening results.Inspection Item 2.3.3.6-1LRA Section 2.3.3.6 states that DGN air-starti ng subsystem components within the scope oflicense renewal are located between the air compressor discharge check valves and the diesel engine air start motors; however, license renewal drawing LR-36051 shows, at locations A-3, B-3, C-3, and D-3, that the license renewal boundaries terminate in the middle of those pipesconnected between the compressor air dryers and discharge check valves (GSA-32-2, 2-59GSA-32-1, GSA-32-4, and GSA-32-3). The actual locations of the license renewal scopeboundaries for these components are not clear. The NRC Regional Inspection Team performedan inspection to ensure that the license renewal scope boundaries for these components satisfy the 10 CFR 54.4(a)(2) criterion.The inspection team determined that the scope boundaries are just upstream of the respectivecheck valves, as indicated. The actual boundaries are where the carbon steel pipe connects to the copper alloy tubing at the nipple to the air dryers. Because of the relative flexibility betweenthe piping and tubing, the boundary is the tubing transition point. The boundary drawing depictsthis transition point between the check valve and the air dryer. The inspectors determined thatthe license renewal boundaries satisfy the 10 CFR 54.4(a)(2) criterion. Therefore, the staff'sconcern described in Inspection Item 2.3.3.6-1 is resolved.2.3.3.6.3  Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant had adequately identified the DGN systemcomponents that are within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant had adequately identified the DGN system components that are subject to anAMR, as required by 10 CFR 54.21(a)(1).2.3.3.7  Emergency Filtration Train System 2.3.3.7.1  Summary of Technical Information in the Application In LRA Section 2.3.3.7, the applicant described the emergency filtration train (EFT) system. TheMNGP licensing basis considers the EFT system as an ESF system. This section includes theEFT system, and the related aging management section, for consistency with the SRP-LR andGALL Report. The heating, ventilation, and air conditioning system that serves the main controlroom (MCR) and the EFT building is designed to provide cool air in the summer and warm air for heating in the winter. Ductwork is used to distribute air. The airflow in the MCR and portions of the EFT building is normally recirculated with return air arranged to pass back to the air conditioning unit, while supplemental outside air is drawn through filtration units. The EFT system will serve the MCR and EFT building during normal or emergency conditions. Anemergency condition is defined as a condition caused by a high radiation level or detection of toxic chemical vapors in the outside air. The air handling units are self-contained package units complete with electric coils for heating and cooling coils for air conditioning. In the normal operating mode, the MCR and EFT building's first and second floors, excluding the battery room, are served by one of the redundant seismic Class 1 air conditioning units. Filtered outside air from an EFT is available on demand. The EFT system operates in the recirculationmode from offsite AC power. If offsite power is not available, the diesel generators willautomatically supply the system.The EFT system contains SR components that are relied upon to remain functional during andfollowing DBEs. In addition, the EFT system performs functions that support FP.
2-60The intended functions within the scope of license renewal include the following:
* provide structural support to SR components (all other systems)
* provide for heat transfer
* provide a pressure-retaining boundaryIn LRA Table 2.3.3-7, the applicant identified the following EFT system com ponent types thatare within the scope of license renewal and subject to an AMR:
* chillers
* damper housings
* ductwork
* fan/blower/housings
* fasteners/bolting
* filters/housings
* heat exchangers
* piping and fittings
* valve bodies
* ventilation seal2.3.3.7.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.7 and USAR Section 6.7 using the evaluationmethodology described in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.3.3.7.3  Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the EFT system componentsthat are within the scope of license renewal, as required by 10 CFR 54.4(a), and the EFT system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2-612.3.3.8  Emergency Service Water System2.3.3.8.1  Summary of Technical Information in the Application In LRA Section 2.3.3.8, the applicant described the ESW system, which includes the followingthree plant subsystems-(1) EDG-ESW subsystem, (2) ESW subsystem, and (3) RHR servicewater subsystem. These subsystems are combined into the ESW system for license renewalpurposes. The EDG-ESW subsystem consists of two separate and independent emergencycooling water loops that provide cooling water to the EDGs. The loops are capable of providing cooling water during a loss of offsite power and during accident conditions. Each loop contains one full capacity pump that supplies strained cooling water to one of the EDGs. The ESW subsystem consists of two separate and independent emergency cooling water loops thatprovide cooling water to the ECCS pump motor coolers, ECCS room coolers, and the EFT.
Each loop is capable of providing cooling water during a loss of offsite power and/or a loss of normal service water. Each loop contains one full capacity pump that supplies strained cooling water to the cooling loads. The RHR service water subsystem (RSW) consists of two separateand independent emergency cooling water loops that provide cooling water to the RHR heatexchangers. Each loop is capable of providing cooling water during a loss of offsite power and during accident conditions. The RHR auxiliary air compressors are included in the RHR servicewater subsystem. The RHR auxiliary air compressors provide an SR backup air supply to the RHR heat exchanger residual heat removal service water (RSW) outlet control valves and theCGC system isolation valves upon occurrence of low pressure in the AIR system. The RHRauxiliary air compressors are normally in standby mode of operation.The ESW system contains SR components that are relied upon to remain functional during andfollowing DBEs. The failure of NSR SSCs in the ESW system could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the ESW system performs functions that support FP and EQ.The intended functions within the scope of license renewal include the following:
* provide filtration
* provide flow restriction
* provide for heat transfer
* provide a pressure-retaining boundaryIn LRA Table 2.3.3-8, the applicant identified the following ESW component types that arewithin the scope of license renewal and subject to an AMR:
* fasteners/bolting
* filters/housings
* filters/strainers
* flow element
* heat exchangers
* manifolds
* piping and fittings
* pump casings
* restricting orifices
* tanks 2-62
* thermowells
* valve bodies2.3.3.8.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.8 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.3.3.8 identified an area in which information provided in theLRA needed to be verified by the NRC Regional Inspection Team to complete the review of theapplicant's scoping and screening results.Inspection Item 2.3.3.8-1License renewal drawing LR-36665 at location C-5 shows a continuation of NSR ESW pipingwithin the scope of license renewal from the valve (ESW-12-4"-JBD-GT) to the desilting line on LR-36665 at location A-5; however, the continuation desilting line at location A-5 is designatedas SW28-4"-JF and not identified as within the scope of license renewal. Consequently, the actual location of the license renewal boundary for this pipe is not clear. The NRC Regi onalInspection Team performed an inspection to ensure that the license renewal scope boundary for this pipe satisfies the 10 CFR 54.4(a)(2) criterion.The inspection team determined that the continuation of NSR ESW piping from the valveESW-12 to the desilting line on LR-36665 at location A-5 should have been shown within the scope of license renewal. The applicant will revise license renewal drawing LR-36665 to showline SW28-4"-JF, the continuation to the desilting line, within the scope of license renewal, up towhere the line enters the column in the intake structure. The inspectors confirmed through walkdowns that the scoping boundary is where this line passes into the column shown at coordinates A-5 on the drawing. The inspectors determined that the license renewal boundarysatisfies the 10 CFR 54.4(a)(2) criterion. Therefore, the staff's concern described in Inspection Item 2.3.3.8-1 is resolved.2.3.3.8.3  Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the ESW systemcomponents that are within the scope of license renewal, as required by 10 CFR 54.4(a), and 2-63that the applicant adequately identified the ESW system components that are subject to anAMR, as required by 10 CFR 54.21(a)(1).2.3.3.9  Fire System 2.3.3.9.1  Summary of Technical Information in the Application In LRA Section 2.3.3.9, the applicant described the fire system. The fire system providesassurance, through defense-in-depth design, that a fire will not prevent the performance ofnecessary safe-shutdown functions or significantly increase the risk of radioactive release to the environment during a postulated fire. The fire system provides fire suppression by fixed waterspray and sprinkler systems, fixed gas (Halon 1301) systems, hose stations, and portableextinguishers located in various areas of the MNGP site. MNGP has a fire detection and alarm system that alarms locally in selected areas of the plant and transmits various alarm,supervisory, and trouble signals to the control room. The fire system ensures compliance withthe regulated event for FP. The Mississippi River supplies the water for the fire system. The firesystem also provides alternate sources of water to other plant systems.The failure of NSR SSCs in the fire system could potentially prevent the satisfactoryaccomplishment of an SR function of SSCs within the scope of license renewal. The fire systemalso performs functions that support FP.The intended functions within the scope of license renewal include the following:
* provide filtration
* provide flow restriction
* provide for heat transfer
* provide a pressure-retaining boundaryIn LRA Table 2.3.3-9, the applicant identified the following fire system component types that arewithin the scope of license renewal and subject to an AMR:
* fasteners/bolting
* filters/strainers
* fire hydrants
* flexible connections
* gauges (flow, level, and sight)
* heat exchangers
* manifolds
* nozzles
* piping and fittings
* pump casings
* restricting orifices
* sprinkler heads
* tanks
* valve bodies 2-642.3.3.9.2  Staff EvaluationThe staff reviewed LRA Section 2.3.3.9 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff also reviewed the approved FP SERs, dated August 29, 1979, February 12, 1981, and October 2, 1985. These reports are referenceddirectly in the MNGP FP CLB and summarize the FP program and commitments to 10 CFR 50.48 using the guidance of Appendix A to Branch Technical Position (BTP) Chemical and Mechanical Engineering Branch (CMEB) 9.5-1, "Guidelines for Fire Protection for Nuclear Power Plants."  The staff then reviewed those components that the applicant had identified asbeing within the scope of license renewal to verify that the applicant had not omitted anypassive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.3.3.9 identified areas for which it needed additionalinformation to complete its evaluation 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 18, 2005, the staff noted that license renewal drawing LR-36051highlights the diesel fire pump, diesel fire pump day tank, and interconnecting piping as within the scope of license renewal; however, the diesel fire pump day tank fill line is not highlighted.The staff requested that the applicant clarify whether the diesel fire pump day tank fill line iswithin 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), or justify its exclusion.In its response, by letter dated September 16, 2005, the applicant stated the following:The diesel fire pump day tank fill line is not within the scope of license renewaland is not subject to an AMR. The diesel fire pump day tank (T-100) is a 120-gallon capacity tank. The tank conservatively provides about ten hours of operation of the diesel-driven fire pump before makeup is required. This satisfies the requirements of NFPA-20, 'Standard for the Installation of Centrifugal Fire Pumps,' which states that the day tank capacity '...shall be sufficient to operate the engine for at least eight hours.' In accordance with the Operations Manual forthe diesel oil subsystem, the nominal fuel oil consumption of the diesel-driven fire pump is eight (8) gallons per hour. An alternate method of transferring fuel oil from the Diesel Oil Storage Tank (T-44) to the Diesel Fire Pump Day Tank is provided during emergencies and is governed by abnormal procedures in accordance with the MNGP Operations Manual. Under these situations, the Portable Gasoline Engine Powered Fuel Oil Pump (P-229) that is normally stored in Warehouse 2 is utilized. This portable pump is within the scope of licenserenewal and is subject to AMR. P-229 is evaluated in AMR-DGN, Emergency Diesel Generators System, since the diesel oil subsystem including fuel oil to thediesel-driven fire pump, is evaluated within this AMR. Under these emergency 2-65situations, P-229 is connected to the Diesel Oil Storage Tank using portablehoses. T-100 is filled by removing the 8" manhole cover from this tank andinserting the discharge hose from P-229. Consequently, utilizing the PortableGasoline Engine Powered Fuel Oil Pump provides an alternate method of fillingthe Diesel Fire Pump Day Tank and the Diesel Fire Pump Day Tank fill line isexcluded from the scope of license renewal and is not subject to AMR.Based on its review, the staff found the applicant's response to RAI 2.3.3.9-1 acceptablebecause the diesel fire pump day tank can be filled using an alternate method (i.e., the portablegasoline engine powered fuel oil pump) which is within the scope of license renewal and subject to an AMR; therefore, the staff's concern described in RAI 2.3.3.9-1 is resolved.In RAI 2.3.3.9-2, dated August 18, 2005, the staff identified that license renewaldrawing LR-36664 (coordinates C-7) shows the KB/GB boundary and the system boundarybreak (Fire Protection ESW) at opposite ends of valve RHRSW-46, which is the only valve onthe drawing at which they are at opposite ends. The staff requested that the applicant verifywhether this depiction is correct.In its response, by letter dated September 16, 2005, the applicant stated, "This is correct due tothe fact that valve RHRSW-46 is within scope in the Fire Protection (FIR) System. There istypically no correlation between License Renewal system boundary breaks and pipingclassifications."Based on its review, the staff found the applicant's response to RAI 2.3.3.9-2 acceptablebecause it adequately explains the scoping of valve RHRSW-46; therefore, the staff's concerndescribed in RAI 2.3.3.9-2 is resolved.In RAI 2.3.3.9-3, dated August 18, 2005, the staff identified that on license renewaldrawing LR-36664 the piping on the KB side (outlet) of valve RHRSW-46 (coordinates C-7) ishighlighted as within the scope of license renewal, in accordance with 10 CFR 54.4(a)(2). On the continuation license renewal drawing LR-36048, the same piping is shown highlighted aswithin the scope of license renewal pursuant to 10 CFR 54.4(a)(1) and (a)(3). The staff requested that the applicant clarify which paragraph of 10 CFR 54.4 applies to this piping forthe LRA.In its response, by letter dated September 16, 2005, the applicant stated the following:The piping on the 'KB' side of valve RHRSW-46 on LRA drawing LR-36664 ishighlighted in 'green' since it is in the scope of license renewal in accordance with 10 CFR 54.4(a)(2) for non-safety connected to safety (FIR to ESW) and, non-safety affecting safety (NSAS) with respect to potential leakage/spray. It is also in the scope of license renewal in accordance with 10 CFR 54.4(a)(3) for the fire protection regulated event. The continuation of this piping is highlighted on LRA drawing LR-36048 in 'red' and is in the scope of license renewal per 10 CFR 54.4(a)(3) due to the Fire Protection regulated event. The color-coding was performed in this manner to indicate these two separate criteria yet provide differentiation between the two criteria due to this particular piping segment in the FIR System being identified on two separate LR drawings.
2-66Based on its review, the staff found the applicant's response to RAI 2.3.3.9-3 acceptablebecause it adequately explains that the piping on the KB side of valve RHRSW-46 is within thescope of license renewal, pursuant to 10 CFR 54.4(a)(2) and 10 CFR 54.4(a)(3); therefore, the staff's concern described in RAI 2.3.3.9-3 is resolved.In RAI 2.3.3.9-4, dated August 18, 2005, the staff identified that GALL Report Section XI.27,"Fire Water System," describes the requirement for aging management of the FP water systemand recommends that an AMP be established to evaluate the aging effects of corrosion, microbiologically influenced corrosion (MIC), and biofouling of carbon steel and cast iron components in the FP systems exposed to water.LRA Section 2.3.3.9 addresses requirements for the Fire Detection and Protection Program, butdoes not mention trash racks and traveling screens for the fire pump suction water supply.Neither LRA Section 2.3.3.3, "Circulating Water System," nor Section 2.4.8, "Intake Structure,"mention trash racks and traveling screens.The USAR states, in part, the following:River water is turned through an angle of 81 to approach the plant along achannel excavated to elevation 898 feet. It enters the Intake Structure through a trash rack before dividing into two separate streams to the circulating water pump chambers. Each stream passes through two parallel automatically operated traveling screens, the service water pump bay and two parallel motor-operated sluice gates before reaching a circulating water pump. The center dividing wall permits dewatering of either pump bay. A normally closed gate in the wall can be manually opened during normal operation if a traveling screen is out of service for maintenance. Taking suction from the service pump bay are two 14,000 gpm make-up pumps and pumps for the station cooling, screen wash, and fire protection.Trash racks and traveling screens are necessary to remove debris and prevent clogging for theFP water supply system. Trash racks and traveling screens are typically considered passive,long-lived components. Trash racks are located in a freshwater environment. Traveling screensare located in a freshwater/air environment. Although not specifically addressed in the USAR or LRA, trash racks and traveling screens are typically constructed of carbon steel material.Carbon steel in a freshwater environment or a freshwater/air environment is subject to corrosion; therefore, the staff requested that the applicant explain the apparent exclusion of thetrash racks and traveling screens located upstream of the fire pump suctions from the scope oflicense renewal and an AMR.In its response, by letter dated September 16, 2005, the applicant stated the following:The trash racks are installed to remove large debris from entering the IntakeStructure. Since the trash racks are an integral part of the Intake Structure, they were included within the scope of license renewal and are subject to an AMR as part of the Intake Structure, for conservatism. They are identified in Table 3.5.2-8 (Structures and Component Supports-Intake Structure) of the LRA as carbon steel (Component Type) in both an atmosphere/weather and raw water environment and are subject to an AMR due to loss of material. The Structures 2-67Monitoring Program manages the aging effect of loss of material for thiscomponent. The traveling screens are part of the non-safety related Circulating Water System that supports normal plant operation. The traveling screens are provided for trash, fish, and vegetation removal to minimize the fouling and clogging of the Circulating Water System water box tube sheets and piping.
However, for both the trash racks and the traveling water screens, build-up ofdebris is considered event-driven and not age-related. Both the trash ra cks andtraveling screens are non-safety related, non-QA, and non-seismic components.During normal plant operation, the Circulating Water pumps (two pumps inoperation) draw a significant flow of cooling water (292,000 gpm) through the bays of the Intake Structure to support the main condenser cooling requirements. This high flow rate (not including the normal Service Water flow rate that equates to an additional 10,000 gpm with two pumps in operation) creates the potential for debris and sediment to enter the bays. Duringemergency operation, when the Circulating Water pumps are not in operation, the Fire Pumps draw a small flow (1500 gpm/pump) of water through the bays with a corresponding low velocity. The low flow velocity creates an insignificant amount of debris and sediment to accumulate and the traveling water screens are able to pass a sufficient amount of water to support operation of the Fire Pumps. Additionally, the Fire Pumps themselves are equipped with suction strainers. Basket strainers are provided in the main fire pump discharge headers.
Any significant degradation or failure of the traveling screens during normal power operation would be evident and detected by plant operators far in advanceof a complete failure. Even in the case of total failure, floating or heavy debris would not affect the operation of the Fire pumps due to the low velocities at the suction of these pumps. The screens are subject to periodic maintenance and replacement and are continuously monitored through main control room annunciation. Additionally, the river and atmospheric environments for these components are relatively non-aggressive. The traveling screens and trash racks are not required to perform a function during or following a design basis event, and therefore do not meet the scoping criteria of 10 CFR 54.4(a)(1)(I), (ii), or (iii).There is no credible failure mode of the traveling screens and trash racks thatcould prevent satisfactory accomplishment of any of the functions identified in paragraphs 10 CFR 54.4(a)(1)(I), (ii), or (iii). Therefore, the traveling screens andtrash racks do not meet the scoping criteria of 10 CFR 54.4(a)(2). The traveling screens and trash racks are not required to perform a function in support of theregulated events of 10 CFR 54.4(a)(3).
Based on the above, the traveling screens and trash racks are not considered tomeet the scoping criteria of 10 CFR 54.4(a) and do not perform a license renewal intended function per 10 CFR 54.4(b). Consequently, although the trash racks are within the scope of license renewal and are subject to AMR since theyare an integral part of the Intake Structure and were included for conservatism, the traveling screens are not within the scope of license renewal and are not subject to AMR.Based on its review, the staff found the applicant's response to RAI 2.3.3.9-4 acceptablebecause the trash racks are integral parts of the intake structure and were included within the 2-68scope of license renewal and are subject to an AMR for conservatism. The traveling screensare subject to periodic maintenance and replacement and are continuously monitored through main control room annunciation. Even in the case of total failure, floating or heavy debris would not affect the operation of the fire pumps because of the low velocities (compared to the velocities of the flow for the CWT pumps) at the suction of these pumps; therefore, the staff'sconcern described in RAI 2.3.3.9-4 is resolved.In RAI 2.3.3.9-5, dated August 18, 2005, the staff noted that Section 3.1.2(3) of the NRC "FireProtection Safety Evaluation Report," dated August 29, 1979, states that "a sprinkler system willbe installed to provide a means to cool hot gases that enter the cable tray area in the water treatment and ESF motor control center area." This sprinkler system is not shown on thelicense renewal boundary drawings; therefore, the staff requested that the applicant verify thatthis sprinkler system is within the scope of license renewal pursuant to 10 CFR 54.4(a)(3).In its response, by letter dated September 16, 2005, the applicant stated the following:The sprinkler system installed to provide a means to cool the hot gases thatenter the cable tray area in the water treatment and ESF motor control centerareas as addressed in the Fire Protection Safety Evaluation Report dated August 29, 1979, Section 3.1.2(3), is not shown in the Fire System LR boundary drawings (P&lDs). However, the isolation valves to this sprinkler system are shown on License Renewal Boundary Drawing LR-36048, Fire Protection System (coordinates C, 7). Valve FP-142 is located at the Turbine Building 951' elevation and valve FP-145 is located at the Turbine Building 911' elevation.These locked-open valves are noted on the drawing as 'FIREWALL SPRINKLER ABOVE LUBE OIL STORAGE TANKS.' These two valves and the remainder of this sprinkler system (water curtain) are in the scope of license renewal per10 CFR 54.4(a)(3) and are subject to AMR. These components are addressed in Table 3.3.2-9, Auxiliary Systems - Fire System - Summary of Aging ManagementEvaluation, of the MNGP LRA. The aging effects associated with these components are managed by both the Fire Water System and System Condition Monitoring (external environment) AMPs. However, in addition to the installation of this sprinkler system and in compliance with Appendix R of 10 CFR 50,Section IlI.G.2(c), the cable, equipment and associated non-safety circuits of the redundant trains are separated by a fire barrier (wall) having a minimum one-hour rating (two-hour barrier actually installed). This fire barrier (Walls T324 and T331) is addressed in Table 3.5.2-17, Structures and Component Supports -
Turbine Building - Summary of Aging Management Evaluation, of the MNGP LRA. Both the Fire Protection and Structures Monitoring AMPs manage the aging effects associated with this component.Based on its review, the staff found the applicant's response to RAI 2.3.3.9-5 acceptablebecause it adequately explains that the sprinkler system, installed as a means to cool the hotgases that enter the cable tray area in the water treatment and ESF motor control center (MCC)areas, is within the scope of license renewal, pursuant to 10 CFR 54.4(a)(3) and subject to an AMR; therefore, the staff's concern described in RAI 2.3.3.9-5 is resolved.In RAI 2.3.3.9-6, dated August 18, 2005, the staff noted that Section 4.3.1(17) of the NRC's"Fire Protection Safety Evaluation Report," dated August 29, 1979, states that, "The licensee 2-69will provide foam application equipment for use in fighting potential lube oil fires in the turbinebuilding."  The license renewal drawings do not show this foam application equipment; therefore, the staff requested that the applicant clarify whether this foam application equipmentis within the scope of license renewal, pursuant to 10 CFR 54.4(a)(3).In its response, dated September 16, 2005, the applicant stated the following:The foam application equipment addressed in the Fire Protection SafetyEvaluation Report dated August 29, 1979, Section 4.3.1(7) concerns the two (2)sets of portable foam applicators for use in fighting potential lube oil fires in the Turbine Building. This portable equipment is not shown in the Fire System LR boundary drawings (P&lDs) since it is portable equipment. This equipment is within the scope of license renewal per 10 CFR 54.4(a)(3) and is stored in the Fire Brigade Room in the Plant Administration Building basement at MNGP. This equipment is not subject to AMR since it is inspected periodically (quarterly) under the Fire Protection Program procedures for fire brigade equipment and replaced on condition.This issue is also addressed in Section 2.1.4.2.4, Fire Protection, of the MNGPLRA that states:Items such as fire extinguishers, fire hoses, portable lighting, and airpacks were subjected to the MNGP's scoping and screening process.This process is consistent with the NRC Staff's guidance on consumablesprovided in NUREG-1800, Table 2.1-3.This issue is further defined in Section 2.1.5.3, Component Classification(Passive, long-lived), of the MNGP LRA that states:C.Fire Extinguishers, Fire Hoses, and Air Packs Components such as fire hoses, fire extinguishers, self-containedbreathing apparatus (SCBA), and SCBA cylinders are consumables that are routinely tested or inspected. The Fire Protection Program complies with the applicable NFPA safety standards, which specify performance and condition monitoring programs for these specific components. They are replaced as necessary. Therefore, while these consumables are in the scope of license renewal, they do not require an AMR.A component (or component commodity group) that was determined tobe active or short-lived is not subject to an AMR, and is screened out by the process.Consequently, this foam application equipment is within the scope of licenserenewal per 10 CFR 54.4(a)(3) but is not subject to an AMR.Based on its review, the staff found the applicant's response to RAI 2.3.3.9-6 acceptablebecause it adequately explains that the foam application equipment is within the scope oflicense renewal, pursuant to 10 CFR 54.4(a)(3), but is not subject to an AMR because it is 2-70inspected periodically (quarterly) under the Fire Protection Program's procedures for firebrigade equipment and replaced as necessary. Therefore, the staff's concern described in RAI 2.3.3.9-6 is resolved.In RAI 2.3.3.9-7, dated August 18, 2005, the staff noted that Section 5.2.6 of the NRC's "FireProtection Safety Evaluation Report," dated August 29, 1979, states that the cable spreadingroom "will be provided with an automatic gas suppression system."  The license renewaldrawings do not show this automatic gas suppressi on system; therefore, the staff requestedthat the applicant clarify whether this automatic gas suppressi on system is within the scope oflicense renewal, pursuant to 10 CFR 54.4(a)(3).In its response, dated September 16, 2005, the applicant stated the following:The Cable Spreading Room, addressed in the Fire Protection Safety EvaluationReport dated August 29, 1979, Section 5.2.6.3, is provided with a total floodingautomatic gas suppression system consisting of cylinder storage unitspressurized with Halon 1301. Halon is discharged into the room through wide-angle nozzles. As stated in Section 2.1.4.4 (Evaluation Boundaries -
License Renewal Boundary Drawings) of the MNGP LRA, the in-scope boundaries are depicted in the License Renewal Boundary Drawings. 'The drawings consist of simplified process and instrumentation drawings (for the mechanical systems)' or P&lDs. The Halon gas suppression system does notappear in any of the MNGP P&lDs for the Fire System but rather in individual vendor drawings which are not included as part of the license renewal boundary drawing submittal package. The Cable Spreading Room Halon automatic gas suppression system is in the scope of license renewal. This is confirmed by anddiscussed in Section 2.3.3.9 (Fire System), Table 3.0-1 Mechanical and Civil Service Environments, Table 3.3.2-9, (Auxiliary Systems - Fire System -
Summary of Aging Management Evaluation), Appendix A2.1.17 (Fire Protection) and Appendix B2.1.17 (Fire Protection) of the MNGP LRA. Therefore, the CableSpreading Room automatic gas suppression system is in the scope of licenserenewal per 10 CFR 54.4(a)(3) and is subject to AMR.Based on its review, the staff found the applicant's response to RAI 2.3.3.9-7 acceptablebecause it adequately explains that the automatic gas suppression system is within the scopeof license renewal, pursuant to 10 CFR 54.4(a)(3), and is subject to an AMR; therefore, the staff's concern described in RAI 2.3.3.9-7 is resolved.2.3.3.9.3  Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the fire system componentsthat are within the scope of license renewal, as required by 10 CFR 54.4(a), and the fire systemcomponents that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2-712.3.3.10  Fuel Pool Cooling and Cleanup System2.3.3.10.1  Summary of Technical Information in the Application In LRA Section 2.3.3.10, the applicant described the fuel pool cooling and cleanup (FPC)system. The FPC system is designed to handle the spent fuel cooling load and to maintain poolwater purity and clarity. T he system provides sufficient filtering capacity to filter the entire spentfuel pool water volume every 12 hours. The fuel pool temperature is normally maintained at
 
125 F or less to ensure a reasonable working environment in the pool area, to keep thedemineralizer at an operable temperature, and to maintain visual clarity of the air above the pool; however, operation at temperatures up to 140 F is acceptable to remove decay heat fromthe spent fuel. The fuel pool cooling and cl eanup system consists of circulating pumps, heatexchangers, filter/demineralizers, piping, valves, and instrumentation. The pumps take suction from the skimmer surge tank, located at the top of the spent fuel storage pool water level, whichcontinuously skims the water from the surface and circulates the water to the heat exchangersand filter/demineralizers before discharging the water through the diffusers at the bottom of the spent fuel pool. This arrangement of taking suction from the top and discharging to the bottom of the pool provides a crossflow which tends to sweep the pool and to carry off dirt and small particles. This system may also be used to drain the steam-separator storage pool and thereactor well after refueling.The failure of NSR SSCs in the FPC system could potentially prevent the satisfactoryaccomplishment of an SR function of SSCs within the scope of license renewal.The intended function, within the scope of license renewal, is to provide a pressure-retainingboundary.In LRA Table 2.3.3-10, the applicant identified the following FPC system com ponent types thatare within the scope of license renewal and subject to an AMR:
* fasteners/bolting
* heat exchangers
* manifolds
* piping and fittings
* pump casings
* tanks
* thermowells
* valve bodies2.3.3.10.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.10 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant 2-72had identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).In reviewing LRA Section 2.3.3.10, the staff identified areas for which it needed additionalinformation to complete its evaluation of the applicant's scoping and screening results. The applicant responded to the staff's RAIs as discussed below.In RAI 2.3.3.10-1, dated September 16, 2005, the staff noted that LRA Section 2.3.3.10 statesthat components in the FPC system are NSR and that their failure could affect the capability ofSR SSCs to perform their safety function; therefore, they are within the scope of license renewal, in accordance with 10 CFR 54.4(a)(2). License renewal drawing LR-36256, Note 2, also states that the spent fuel pool liner is within the scope of license renewal as part of the reactor building structure. This spent fuel pool liner interfaces with the weirs and their associated connecting surface, FPC system, and fuel pool drains. License renewal drawingLR-36256 at location D-2 shows the adjustable weir and associated connecting surfaces to the south skimmer surge tank, T-48B, to be within the scope of license renewal. License renewal drawing LR-36256 at location D-4 shows similar components, the adjustable weir and connecting surfaces to the north skimmer surge tank, T-48A, as not within the scope of license renewal. Therefore, the staff requested that the applicant clarify whether the adjustable weirand associated connecting surfaces to the north skimmer surge tank, T-48A, at location D-4 are within the scope of license renewal and subject to an AMR, in accordance with the applicable requirements of 10 CFR 54.4(a) and 10 CFR 54.21(a), respectively, or justify their exclusion.In its response, by letter dated October 14, 2005, the applicant stated that only those portionsof skimmer surge tanks T-48A and T-48B not embedded in concrete are within the scope of license renewal. The adjustable weir is an NSR component located inside the concrete wall adjacent to the spent fuel pool. Its failure could not affect the intended function of SR SSCs.
The adjustable weir for the south skimmer surge tank T-48B was shown incorrectly as within the scope of license renewal. In addition, the adjustable weir for the south skimmer surge tankT-48B is not within the scope of license renewal; however, the connecting portion of skimmer tank T-48A at location D-3 is within the scope of license renewal from the skimmer tank up to the concrete wall.Based on its review, the staff found the applicant's response to RAI 2.3.3.10-1 acceptablebecause failure of the components embedded in concrete could not affect the intended function of SR SSCs and therefore are outside the scope of license renewal. In addition, the applicant added the connecting portion of skimmer tank T-48A from the skimmer tank up to the concrete wall to the scope of license renewal; therefore, the staff's concern described in RAI 2.3.3.10-1is resolved.In RAI 2.3.3.10-2, dated September 16, 2005, the staff noted, as shown on license renewaldrawing LR-36256 at location D-4, that diffusers A and B serve as a distribution point for returning cooling water for the FPC system to the fuel storage pool. Their failure could affectthe capability of SR SSCs to perform their safety function; therefore, the staff requested thatthe applicant justify why these diffusers are not within the scope of license renewal.In its response, by letter dated October 14, 2005, the applicant stated that the FPC system iswithin the scope of license renewal only because it contains NSR components which must 2-73maintain sufficient integrity to prevent spray, leakage, or spatial interaction from affectingintended functions of the SR SSCs adversely. The diffusers are located underwater (spent fuel pool) and the failure of these NSR diffusers would not affect SR SSC intended functions. The diffusers are, therefore, not within the scope of license renewal.Based on its review, the staff found the applicant's response to RAI 2.3.3.10-2 acceptablebecause the diffusers are not FPC system components that could affect the capability of SRSSCs to perform their safety function and, therefore, are not within the scope of license renewal; therefore, the staff's concern described in RAI 2.3.3.10-2 is resolved.In RAI 2.3.3.10-3, dated September 16, 2005, the staff determined that license renewal drawingLR-36256 shows an unisolable pipe (FPW17B-3"-MR) between the fuel storage pool and the skimmer surge tank, T-48B, as not within the scope of license renewal. All other piping and components entering the skimmer tank within the same apparent area of the plant are shownas within the scope of license renewal. Failure of this unisolable section of pipe could affect the intended license renewal pressure boundary function for the skimmer tank; therefore, the staffrequested that the applicant justify why this pipe is not included within the scope of licenserenewal.In its response, by letter dated October 14, 2005, the applicant stated that only the connectingportions of both of the skimmer surge tanks, T-48A and T-48B, not embedded in concrete are within the scope of license renewal. Pipe FPW17B-3"-MR is located along side the spent fuel pool and is embedded in concrete. It drains the wave suppression scupper into the portion of the skimmer surge tank embedded in concrete. This NSR component could not impact the intended function of SR SSCs and, therefore, is not within the scope of license renewal.Based on its review, the staff found the applicant's response to RAI 2.3.3.10-3 acceptablebecause pipe FPW17B-3"-MR is embedded in concrete and the failure of this NSR component could not impact the intended function of SR SSCs; therefore, the staff's concern described in RAI 2.3.3.10-3 is resolved.The staff's review of LRA Section 2.3.3.10 identified areas in which information provided in theLRA needed to be verified by the NRC Regional Inspection Team to complete the review of theapplicant's scoping and screening results.Inspection Item 2.3.3.10-1License renewal drawing LR-36256 at locations D-4 and D-2 does not clearly defi ne the systemboundaries between the fuel storage pool and the FPC system and between the fuel storagepool and the fuel pool drains and associated piping. The NRC Regional Inspection Teamperformed an inspection to ensure that the license renewal scope boundaries for the above cited systems satisfy the 10 CFR 54.4(a)(2) criterion.The inspection team found that this item addresses the wave suppression scupper, which isembedded in concrete. Detailed drawings for the reactor building and spent fuel pool provided further definition. The applicant recently revised license renewal drawing LR-36256 as a result of RAI 2.3.3.10-3 to better illustrate the wave suppression scupper drain piping. The inspectorsdetermined that the license renewal boundary satisfies the 10 CFR 54.4(a)(2) criterion.Therefore, the staff's concern described in Inspection Item 2.3.3.10-1 is resolved.
2-74Inspection Item 2.3.3.10-2License renewal drawing LR-36256 at location B-3 shows the license renewal scope boundaryfor the pipe FPW13-4"-HB terminating at a nonspecific location on the piping run (between the pipe FPW13-6"-HB and the valve AO-4"-HB). The actual location of the license renewal scope boundary for this pipe is not clear. The NRC Regional Inspection Team performed an inspectionto ensure that the license renewal scope boundary of this pipe satisfies the 10 CFR 54.4(a)(2) criterion.The inspection team confirmed that the license renewal boundary ends as the line enters the985' pump room. There are no SR components within the 985' pump room. P&IDs do not typically show walls and floors. The inspectors determined that the license renewal boundary satisfies the 10 CFR 54.4(a)(2) criteria. Therefore, the staff's concern described in Inspection Item 2.3.3.10-2 is resolved.2.3.3.10.3  Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the FPC system componentsthat are within the scope of license renewal, as required by 10 CFR 54.4(a), and the FPC system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3.11  Heating and Ventilation System 2.3.3.11.1  Summary of Technical Information in the Application In LRA Section 2.3.3.11, the applicant described the heating and ventilation (HTV) system. TheHTV system consists of the equipment required to affect and control the following space-airprocesses-supply and exhaust, distribution and recirculation (where applicable), differential and static pressure control, filtration, and cooling and heating. It also includes sampling and fume hood exhausting and process tank venting. The applicant scoped the reactor building isolation under the secondary containment system. The portion of the HTV system serving theHPCI building and the RHR/CSP corner rooms is within the scope of license renewal; theequipment is designed to provide cool air during normal operation and DBEs. General plant heating is provided by a network of carbon steel pipes originating at the plant heating boiler andextending throughout most of the plant to supply heated water and/or steam to various unit heaters. Three notable locations not directly served are the drywell, offgas storage building, and portions of the plant serviced by the EFT system.The HTV system contains SR components that are relied upon to remain functional during andfollowing DBEs. The failure of NSR SSCs in the HTV system could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the HTV system performs functions that support FP and EQ.The intended functions within the scope of license renewal include the following:
2-75
* provide filtration
* provide for heat transfer
* provide a pressure-retaining boundaryIn LRA Table 2.3.3-11, the applicant identified the following HTV system com ponent types thatare within the scope of license renewal and subject to an AMR:
* chillers
* damper/housings
* ductwork
* fan/blower/housings
* fasteners/bolting
* filters/strainers
* gauges (flow, level, and sight)
* heaters/coolers
* HVAC units
* instrumentation
* piping and fittings
* pump casings
* steam traps
* tanks
* valve bodies2.3.3.11.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.11 and USAR Sections 5.3.4 and 10.3.1.3.2 using theevaluation methodology described in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.3.3.11 identified an area for which it needed additionalinformation to complete its evaluation of the applicant's scoping and screening results. The applicant responded to the staff's RAI as discussed below.In RAI 2.3.3.11-1, dated September 15, 2005, the staff requested that the applicant clarifywhether all the associated components of "HVAC units," such as ductwork (equipment frames and housing), filters (housing and supports), ventilation seals, cooling coils, and I&C, are within the scope of license renewal, in accordance with 10 CFR 54.4(a), and subject to an AMR, in accordance with 10 CFR 54.21(a)(1).In its response, by letter dated October 14, 2005, the applicant stated the following:
2-76Certain components indicated on the LR boundary drawings for the HTV Systemare in scope to license renewal in accordance with 10 CFR 54.4(a)(1). Certain air conditioners and many of the unit heaters with their associated steam and/or hot water supply lines are in scope to license renewal in accordance with 10 CFR 54.4(a)(2). In addition, certain air handling units and exhaust fans are in scope to license renewal for the Fire Protection and Environmental Qualification regulated events in accordance with 10 CFR 54.4(a)(3). Other components within the HTV System are excluded from the scope of license renewal since they do not perform any license renewal intended function(s).Component groups such as ductwork, filters, instrumentation, etc, that are listedin Table 2.3.3-11 include those associated with the HVAC units within scope for license renewal in accordance with the scoping criteria listed above.Based on its review, the staff found the applicant's response to RAI 2.3.3.11-1 acceptablebecause all applicable associated components of "HVAC units" consisting of ductwork (equipment frames and housing), filters (housing and supports), and instrumentation are within the scope of license renewal, in accordance with 10 CFR 54.4(a), and subject to an AMR, in accordance with 10 CFR 54.21(a)(1); therefore, the staff's concern described in RAI 2.3.3.11-1is resolved.During the scoping inspection, the inspectors identified a 1-inch branch line from HS12-3"-JB toV-RF-1 (including BH-323, ST-9027, and BH-328) that was outside the scope of license renewal on license renewal drawing LR-36259-1. The applicant stated the line was contained under the steel deck plating of the EDG room foyer, effectively isolated from the SR equipment in the EDG room. However, the steam branch line entry point through the steel plating was not a grouted or robust penetration. A break in the line under the deck plating could cause heatingsteam to enter the EDG room, potentially challenging the room ambient temperature to staywithin the maximum allowable temperature for EDG operability. The applicant placed thisportion of piping, along with the two valves and the steam trap, within the scope of license renewal, pursuant to 10 CFR 54.4(a)(2).The inspectors also noted heating steamline HS5-6"-JB from valve BH-316-1 through BH-722on license renewal drawing LR-36664 as outside the scope of license renewal. The inspectors identified a seismic Class I support, SR-389, about 6 feet from BH-316-1 in the section of pipe outside the scope of license renewal. The applicant stated this portion of pipe was determined to be outside the scope of license renewal because it contained air/gas. However, guidance described in NEI 95-10 requires NSR piping attached to SR piping to be within scope up to and including the first equivalent anchor. Seismic Class I support SR-389 is the first equivalent anchor in this line. Therefore, the applicant placed the section of heating steamline HS5-6"-JBbetween valve BH-316-1 and up to and including support SR-389 within the scope of license renewal, pursuant to 10 CFR 54.4(a)(2).2.3.3.11.3  Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its 2-77review, the staff concluded that the applicant adequately identified the HTV system componentsthat are within the scope of license renewal, as required by 10 CFR 54.4(a), and the HTV system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3.12  Instrument and Service Air System 2.3.3.12.1  Summary of Technical Information in the Application In LRA Section 2.3.3.12, the applicant described the AIR system. The AIR system is designedto provide the plant with a continuous supply of oil-free compressed air. The instrument air portion of the system supplies dried compressed air for most of the pneumatic instruments andcontrols in the plant. The service air portion of the system supplies undried service air to plantcomponents that do not require dry air and to hose stations throughout the plant formiscellaneous use by maintenance and operations personnel. The AIR system includes threenonlubricated air compressors that discharge to air receivers through aftercoolers with moisture separator/traps. The AIR system is normally in continuous operation during normal plantoperation and shutdown. In addition to the AIR system, the plant includes other pneumaticsystems. The other pneumatic systems comprise an outboard main steam isolation valve airsupply which is part of the MST system, an AN2 system which is a separate mechanicalsystem, an instrument nitrogen supply to containment which is part of the primary containmentmechanical system, and the control room breathing air system which is part of the EFT system.The AN2 system interfaces with the AIR system through a check valve, with the nitrogen sideheld at a slightly lower pressure to allow the AIR system to be used during normal operation. Inthe event of an accident, which also disables the AIR system, the AN2 system would automatically pick up the required pneumatic loads.The AIR system contains SR components that are relied upon to remain functional during andfollowing DBEs. The failure of NSR SSCs in the AIR system could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the AIR system performs functions that support EQ.The intended function, within the scope of license renewal, is to provide a pressure-retainingboundary.In LRA Table 2.3.3-12, the applicant identified the following AIR system com ponent types thatare within the scope of license renewal and subject to an AMR:
* fasteners/bolting
* gauges (flow, level, and sight)
* piping and fittings
* pump casings
* tanks
* valve bodies2.3.3.12.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.12 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.
2-78In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.3.3.12 identified an area in which information provided inthe LRA needed to be verified by the NRC Regional Inspection Team to complete the review ofthe applicant's scoping and screening results.Inspection Item 2.3.3.12-1License renewal drawing LR-36049-10 at locations D-6 and B-6 have line continuations (airlines upstream of valves AI-704 and AI-715) outside the scope of license renewal to LR-36049-12 at location B-6. The actual locations of the license renewal scope boundaries of these components are not clear. The NRC Regional Inspection Team performed an inspectionto ensure that the license renewal scope boundaries of these components satisfy the 10 CFR 54.4(a)(2) criterion.License renewal drawing LR-36049-10 shows stainless steel instrument air lines at locationsD-6 and B-6 (air lines upstream of valves AI-704 and AI-715). These lines continue to LR-36049-12 at location B-6 where they join via a "T" to form one line and then continue to the vertical header shown on the drawing. Between the "T" joining these lines and the connection to the main vertical header, the line transitions from stainless steel to copper. This transition is the license renewal scoping boundary. The applicant will revise license renewal drawingLR-36049-12 to show the continuation text to license renewal drawing LR-36049-10 and the piping up to the stainless steel/copper transition point (located between the "T" and the verticalheader) as being within the scope of license renewal. In addition, license renewal drawing LR-36049-10 at locations D-6 and B-6 will be revised to show the continuation to licenserenewal drawing LR-36049-12 as being within the scope of license renewal. The inspectors determined that the license renewal boundary satisfies the 10 CFR 54.4(a)(2) criterion.Therefore, the staff's concern described in Inspection Item 2.3.3.12-1 is resolved.2.3.3.12.3  Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the AIR system componentsthat are within the scope of license renewal, as required by 10 CFR 54.4(a), and that theapplicant adequately identified the AIR system components that are subject to an AMR, asrequired by 10 CFR 54.21(a)(1).
2-792.3.3.13  Radwaste Solid and Liquid System2.3.3.13.1  Summary of Technical Information in the Application In LRA Section 2.3.3.13, the applicant described the radwaste solid and liquid (RAD) system.The RAD system contains the solid radwas te subsystem and the liquid radwaste subsystem.The solid radwaste system is designed to process, package, store, monitor, and provideshielded storage facilities for solid radioactive wastes to allow for radioactive decay and/ortemporary storage before shipment for offsite disposal. The liquid radwaste s ubsystem isdesigned to collect, process, and dispose of all radioactive liquid wastes generated during operation of the plant. The system is designed to accommodate the radioactive input resultingfrom the design-basis maximum fuel leakage condition. Either filtration or filtration followed by mixed deep-bed demineralization is used to remove the radioactive and chemical contaminants from the liquid waste streams. The filters remove insoluble particulate contaminants and the demineralizer is used to remove soluble materials. The filter and demineralizer sludge are backwashed into receiving tanks, dewatered, and packaged as solid waste for disposal off site at NRC-approved sites.The RAD system contains SR components that are relied upon to remain functional during andfollowing DBEs. The failure of NSR SSCs in the RAD system could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the RAD system performs functions that support EQ.The intended functions within the scope of license renewal include the following:
* provide flow restriction
* provide a pressure-retaining boundary
* provide structural support to NSR components (mechanical)In LRA Table 2.3.3-13, the applicant identified the following RAD system com ponent types thatare within the scope of license renewal and subject to an AMR:
* fasteners/bolting
* heat exchangers
* piping and fittings
* pump casings
* restricting orifices
* tanks
* valve bodies2.3.3.13.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.13 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions 2-80delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.3.3.13 identified areas for which it needed additionalinformation to complete its evaluation of the applicant's scoping and screening results. The applicant responded to the staff's RAIs as discussed below.In RAI 2.3.3.13-1, dated September 16, 2005, the staff noted that the following cases representunisolable piping defined as outside the scope of license renewal; however, the piping is attached or interfaces with components defined as within the scope of license renewal that perform a pressure-boundary function. Failure of these components outside the scope of license renewal could adversely impact the intended pressure-boundary function of components within the scope of license renewal; therefore, the staff requested that the applicant justify theexclusion of the following unisolable components from the scope of license renewal:
* License renewal drawing LR-36043 at location C-6 shows a 3-inch vent line on the topof machine shop drain tank T-103.
* License renewal drawing LR-36043 at location C-6 shows a 4-inch vent line on the topof reactor building floor drain sump S-37.
* License renewal drawing LR-36043 at location C-6 shows line RWN46-4"-MR enteringthe reactor building floor drain sump S-37 from the equipment drain sump S-42 overflow.
* License renewal drawing LR-36043 at location C-3 shows a 4-inch vent line on the topof drywell floor drain sump S-38.
* License renewal drawing LR-36044 at location C-2 shows a 4-inch vent line on the topof drywell equipment drain sump S-43.
* License renewal drawing LR-36044 at location C-2 shows a 4-inch vent line on the topof drywell equipment drain sump S-43.
* License renewal drawing LR-36044 at location A-3 shows a 4-inch vent line on the top ofturbine building normal waste sump S-45.
* License renewal drawing LR-36044 at location C-5 shows piping to an obsolete sensingline on the top of reactor building equipment drain tank T-56.
* License renewal drawing LR-36044 at location A-5 shows a 4-inch vent line and pipingto an obsolete sensing line on the top of the condensate drip tank T-22.
* License renewal drawing LR-36044 at location A-7 shows 4-inch vent line andRWN48-4"-MR exiting the turbine building equipment drain sump S-44.
* License renewal drawing LR-36044 at location C-7 shows 4-inch vent line andRWN46-4"-MR exiting the reactor building equipment drain sump S-42.In its response, by letter dated October 14, 2005, the applicant stated that the vent lines for thedrain tanks, floor drain sumps, equipment drain tanks, normal waste sumps, drip tanks, and 2-81equipment drain sumps are NSR, open to the atmosphere, and not relied upon for a pressureboundary. Their failure would not adversely affect the intended function of SR SSCs.
Piping RWN46-4"-MR and RWN48-4"-MR are embedded in concrete and act as overflows between sumps. This piping is NSR and its failure could not impact the intended function of SR SSCs. The sensing lines located on top of the tanks for level indication are filled with air. These sensing lines are NSR and their failure could not impact the intended function of SR SSCs.Based on its review, the staff found the applicant's response to RAI 2.3.3.13-1 acceptablebecause (1) the vent lines are open to the atmosphere and not relied upon for a pressure boundary, (2) piping RWN46-4"-MR and RWN48-4"-MR are embedded in concrete, and (3) the sensing lines located on top of the tanks for level indication are filled with air. The vent lines, piping RWN46-4"-MR and RWN48-4"-MR, and sensing lines are all NSR. Their failure could not impact the intended function of SR SSCs and, thus, are not within the scope of license renewal.
Therefore, the staff's concern described in RAI 2.3.3.13-1 is resolved.In RAI 2.3.3.13-2, dated September 16, 2005, the staff determined that license renewal drawingLR-36044 at location D-7 identified a 10 CFR 54.4(a)(2) boundary for the RAD system as thesection of piping before a normally open isolation valve, CRW-1, which is outside the scope of license renewal, from the CST overflow tank T-67. Failure of the unisolable piping could adversely impact the license renewal pressure-boundary function for the radwaste solid and liquid system; therefore, the staff requested that the applicant justify the location of the licenserenewal scope boundary at valve CRW-1, in accordance with the requirements of 10 CFR 54.4(a).In its response, by letter dated October 14, 2005, the applicant stated that NSR valve CRW-1 islocated outside the reactor building near the CST tanks. The piping connecting to valve CRW-1, which is shown within the scope of license renewal, is located inside the HPCl building, which houses SR components. Failure of this connecting piping could impact the intended function of SR SSCs. Failure of valve CRW-1 located outside the building could not impact the intended function of SR SSCs; therefore, valve CRW-1 and the connecting piping to the CST overflow tank T-67 are not within the scope of license renewal.Based on its review, the staff found the applicant's response to RAI 2.3.3.13-2 acceptablebecause CRW-1 and the connecting piping are located outside the building and could not impact the intended function of SR SSCs, and as such, are not within the scope of license renewal. Therefore, the staff's concern described in RAI 2.3.3.13-2 is resolved.In RAI 2.3.3.13-3, dated September 16, 2005, the staff noted that license renewal drawingsLR-36044 at locations A-7, C-7, C-3, and A-3 and LR-36043 at locations A-6, A-5, C-6, and C-3show the turbine building equipment drain sump (S-44), reactor building equipment drain sump (S-42), drywell equipment drain sump (S-43), turbine building normal waste sump (S-45),
condensate pump area sump (S-53), turbine building floor drain sump (S-40), reactor floor drain sump (S-37), and drywell floor drain sump (S-38) as not within the scope of license renewal.
LRA Section 2.3.3.13 states that all radwaste solid and liquid system components in either theturbine or reactor buildings, and constituting a liquid pressure boundary, are within the scope of license renewal. Failure of the liners for these sumps can negatively impact the intended liquid pressure-boundary functions of the components; therefore, the staff requested that theapplicant clarify whether the sumps and their associated liners are within the scope of license 2-82renewal and subject to an AMR, in accordance with the requirements of 10 CFR 54.4(a) and10 CFR 54.21(a), respectively, or justify their exclusion.In its response, by letter dated October 14, 2005, the applicant stated that the nonlined sumpsare NSR, embedded in concrete, and at the lowest elevations of the turbine and reactor buildings. Their failure could not impact the intended function of SR SSCs and they are not within the scope of license renewal.Based on its review, the staff found the applicant's response to RAI 2.3.3.13-3 acceptablebecause the nonlined sumps embedded in concrete are NSR, located at the lowest elevations of the turbine and reactor buildings, and their failure could not impact the intended function of SR SSCs. As such, they are not within the scope of license renewal; therefore, the staff's concern described in RAI 2.3.3.13-3 is resolved.The staff's review of LRA Section 2.3.3.13 identified areas in which information provided in theLRA needed to be verified by the NRC Regional Inspection Team to complete the review of theapplicant's scoping and screening results.Inspection Item 2.3.3.13-1License renewal drawing LR-36043 shows a 1.5-inch line at location B-1 within the scope oflicense renewal for the RAD system. The drawing specifies the line continues at location E-3,but license renewal drawing LR-36043 has no location E-3. Consequently, the actual location of the license renewal scope boundary for this line is not clear. The NRC Regional InspectionTeam performed an inspection to ensure that the license renewal scope boundary for this line satisfies the 10 CFR 54.4(a)(2) criterion.The applicant determined license renewal drawing LR-36043 requires revision to change thecontinuation of this line from coordinates E-3 to D-4. The NRC Regional Inspection Teamverified the accuracy of the corresponding plant P&ID (-137) as currently drawn. The inspectors determined that the license renewal boundary satisfies the 10 CFR 54.4(a)(2)criterion. Therefore, the staff's concern described in Inspection Item 2.3.3.13-1 is resolved.Inspection Item 2.3.3.13-2License renewal drawing LR-36043 shows piping RWN12-4"-HC at location C-4 as within thescope of license renewal continuing to an undefined location. The actual location of the license renewal scope boundary for this pipe is not clear. The NRC Regional Inspection Teamperformed an inspection to ensure that the license renewal scope boundary for this pipe satisfies the 10 CFR 54.4(a)(2) criterion.The applicant will revise license renewal drawing LR-36043 to show the continuation of thedrainline, RWN12-4"-HC, to license renewal drawing LR-36044, reactor building equipment drain sump, S-42. The applicant will revise license renewal drawing LR-36044 to show thedrains from the reactor building floor drain tank, T-55, as one of the lines discharging into the reactor building equipment drain sump, S-42. The drainline is within the scope of license renewal, pursuant to 10 CFR 54.4(a)(2). The inspectors determined that the license renewal boundary satisfies the 10 CFR 54.4(a)(2) criteria. Therefore, the staff's concern described in Inspection Item 2.3.3.13-2 is resolved.
2-83Inspection Item 2.3.3.13-3License renewal drawing LR-36044 at location B-1 shows the boundary for license renewalterminating at the unisolable junction of piping from the EDG room 11 floor drain to the flow controller just downstream of check valve NW-7. Failure of the unisolable piping can adversely impact the license renewal pressure-boundary function for the RAD system. The NRC Regi onalInspection Team performed an inspection to ensure that the license renewal scope boundary for this component satisfies the 10 CFR 54.4(a)(2) criterion.The inspection team determined that valves NW-7, 8, and 9 are FP-related, with each pipeconnection buried in concrete, although not shown on the drawing. The buried pipe acts as the anchor, therefore the boundary terminates at that point. The inspectors determined that thelicense renewal boundary satisfies the 10 CFR 54.4(a)(2) criterion. Therefore, the staff's concern described in Inspection Item 2.3.3.13-3 is resolved.Inspection Item 2.3.3.13-4License renewal drawing LR-36045 shows several lines entering the drawing from other sheets,RWN20-4"-HC (at location D-8), RWN5-3"-HC (at location D-8), RWN36-3"-HC (at location D-8), FPW13-4"-HP (at location B-8), TW37-4"-HC (at location B-8), SC15-3"-HB (at location D-7), and SC25-3"-HB (at location C-5) as within the scope of license renewal; however, for each of these lines, the boundary terminates at a nonspecific location on license renewal drawing LR-36045. The NRC Regional Inspection Team performed an inspection toensure that the license renewal scope boundaries for the cited components satisfy the10 CFR 54.4(a)(2) criterion.During walkdowns, the inspection team verified that the NSR piping enters the radwastebuilding or the 985' pump room and is, therefore, not within the scope of license renewal. Thereare no SR components in the radwaste building or the 985' pump room, and P&IDs do not typically depict walls. The applicant will revise license renewal drawing LR-36045 to change linenumbers RWN20-4"-HC (at location D-8), RWN5-3"-HC (at location D-8), FPW13-4"-HP (at location B-8), SC15-3"-HB (at location D-7), and SC25-2"-HB (at location C-5) from within the scope of license renewal to outside the scope of license renewal. The continuation drawings already show the transition into the radwaste building or the 985' pump room.The applicant will revise license renewal drawing LR-36044 to extend the wall at location B-1 toencompass line RWN5-3"-HC and to show the transition into the 985' pump room at the wall.
The license renewal boundary ends as the piping enters the 985' pump room.Line number TW37-4"-HC (at location B-8) on license renewal drawing LR-36045 has beenverified by walkdown and shows the transition to be where the line enters the radwaste building wall. The applicant will revise license renewal drawing LR-36045 to change the portion of thisline to outside the scope of license renewal. The applicant will also revise license renewaldrawing LR-36247 (at location C-4) to show the transition of this line through the radwaste building wall. The inspectors determined that the license renewal boundary satisfies the 10 CFR 54.4(a)(2) criteria. Therefore, the staff's concern described in Inspection Item 2.3.3.13-4 is resolved.Inspection Item 2.3.3.13-5 2-84License renewal drawing LR-36046 shows several lines entering the drawing from other sheets,turbine building floor sump drain (at location D-8), drywell and reactor building floor drain sump (at location D-8), machine shop drain (at location B-8), laboratory drain (at location B-8),
laundry drain waste (at location B-4), and machine shop drain (at location B-4), as within the scope of license renewal; however, for each of these lines, the license renewal scope boundary terminates at a nonspecific location on license renewal drawing LR-36046. The NRC Regi onalInspection Team performed an inspection to ensure that the license renewal scope boundaries for the cited components satisfy the 10 CFR 54.4(a)(2) criterion.The inspection team determined that the boundaries end as the lines enter the radwastebuilding wall (locations B-8 & D-8) or 985' pump room wall (location B-4). There are no SR components in the radwaste building or the 985' pump room. P&IDs at MNGP do not typically depict walls. The applicant will revise license renewal drawing LR-36046 (at location D-8) toshow lines RWN19-4"-HC and RWN8-3"-HC outside the scope of license renewal since the scoping boundary ends as the pipes enter the wall, which is already shown on LR-36043 (at location B-1). The inspectors determined that the license renewal boundary satisfies the 10 CFR 54.4(a)(2) criterion. Therefore, the staff's concern described in Inspection Item 2.3.3.13-5 is resolved.Inspection Item 2.3.3.13-6License renewal drawing LR-36241 at location D-7 shows a 1" line, V15-1"-HB, within the scopeof license renewal exiting to license renewal drawing LR-36049-12 at location D-5. Continuation of V15-1"-HB is not shown on license renewal drawing LR-36049-12 at the location specified.
The NRC Regional Inspection Team performed an inspection to ensure that the license renewalscope boundary for this line satisfies the 10 CFR 54.4(a)(2) criterion.The inspection team determined the continuation to license renewal drawing LR-36049-12,shown on license renewal drawing LR-36241, is for the instrument air system and should beshown as outside the scope of license renewal. The applicant will revise license renewaldrawing LR-36241 to change the continuation to license renewal drawing LR-36049-12 from within scope to outside the scope of license renewal.In addition, the applicant will revise license renewal drawing LR-36241 to show that lineV15-1"-HB discharges to the drywell equipment drain sump, S- 43, on license renewal drawing LR-36044. The applicant will also revise license renewal drawing LR-36044 to show the"Reactor Head Vent" as one of the drains discharging into the drywell equipment drain sump, S-43. The inspectors determined that the license renewal boundary satisfies the 10 CFR 54.4(a)(2) criterion. Therefore, the staff's concern described in Inspection Item 2.3.3.13-6 is resolved.Inspection Item 2.3.3.13-7Treated/processed and sampled liquid wastes collected in sumps and drain tanks in variousbuildings may be returned to the CSTs via the appropriate waste sample pump (P-36A or P-36B) and effluent transfer line C19-3"-HS. A portion of this line is shown as within the scope of license renewal on the license renewal drawings LR-36039 at location A-3 and LR-36045 at location B-1; however, the license renewal scope boundaries terminate in the middle of the pipe runs (at the junctions of lines C19-3"-HS and DW17-3"-HS and C19-3"-HS and SC16-10"-HB).
2-85The actual locations of the license renewal scope boundaries for these components are notclear. The NRC Regional Inspection Team performed an inspection to ensure that the licenserenewal scope boundaries for these components satisfy the 10 CFR 54.4(a)(2) criterion.The inspection team determined that this line is within the scope of license renewal, pursuant tothe 10 CFR 54.4(a)(2) criteria, as an equivalent anchor (buried piping). The in-scope boundary begins where the pipe connects to line SC16-10"-HK on LR-36039 (at location B-4) and extends to the radwaste building floor. There are no SR components in the radwaste building.
All P&IDs do not typically depict walls. The inspectors determined that the license renewal boundary satisfies the 10 CFR 54.4(a)(2) criterion. Therefore, the staff's concern described in Inspection Item 2.3.3.13-7 is resolved.2.3.3.13.3  Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the RAD systemcomponents that are within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant adequately identified the RAD system components that are subject to anAMR, as required by 10 CFR 54.21(a)(1).2.3.3.14  Reactor Building Closed Cooling Water System 2.3.3.14.1  Summary of Technical Information in the Application In LRA Section 2.3.3.14, the applicant described the reactor building closed coolingwater (RBC) system. The RBC system is a treated water system designed to remove heat fromthe reactor auxiliary systems' equipment. The RBC system consists of a closed cooling waterloop containing two pumps and three heat exchangers in parallel, and the associated piping, valves, and instrumentation. The system temperature is maintained by heat rejection from theRBC system heat exchangers to the service and seal water system. The RBC system ismonitored continuously for radioactivity by a process radiation monitor (PRM). An increase in the radiation level would indicate leakage of contaminated water into the RBC system. Leakagemay also be indicated by a level change in the RBC system surge tank with no associatedreactor power change, equipment change, or makeup water addition. Any potential leakage from the reactor auxiliary systems' equipment is to the RBC system closed loop where it isconfined or isolated.The RBC system contains SR components that are relied upon to remain functional during andfollowing DBEs. The failure of NSR SSCs in the RBC system could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the RBC system performs functions that support EQ.The intended function, within the scope of license renewal, is to provide a pressure-retainingboundary.
2-86In LRA Table 2.3.3-14, the applicant identified the following RBC system com ponent types thatare within the scope of license renewal and subject to an AMR:
* fasteners/bolting
* flexible connections
* flow element
* gauges (flow, level, and sight)
* heat exchangers
* manifolds
* piping and fittings
* pump casings
* tanks
* thermowells
* valve bodies2.3.3.14.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.14 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.3.3.14.3  Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs thatshould be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the RBC systemcomponents that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the RBC system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3.15  Reactor Water Cleanup System 2.3.3.15.1  Summary of Technical Information in the Application In LRA Section 2.3.3.15, the applicant described the reactor water cleanup (RWC) system. TheRWC system is a filtering and ion e xchange system that maintains water purity in the reactorand recirculation lines during all modes of plant operation. This minimizes changes in the core heat transfer characteristics by reducing the deposition of impurities on fuel surfaces by reducing the amount of waterborne impurities in the reactor primary system. It also reducessources of beta and gamma radiation by removing corrosion products, fission products, and 2-87impurities in the reactor primary system. The RWC system provides for primary containmentisolation and is also isolated on initiation of the SLC system. The RWC system provides forcontinuous purification of a portion of the REC system flow with a minimum of heat loss andwater loss from the cycle.The RWC system contains SR components that are relied upon to remain functional during andfollowing DBEs. The failure of NSR SSCs in the RWC system could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the RWC system performs functions that support EQ and ATWS.The intended function, within the scope of license renewal, is to provide a pressure-retainingboundary.In LRA Table 2.3.3-15, the applicant identified the following RWC system com ponent types thatare within the scope of license renewal and subject to an AMR:
* fasteners/bolting
* flow element
* heat exchangers
* manifolds
* piping and fittings
* pump casings
* restricting orifices
* thermowells
* valve bodies2.3.3.15.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.15 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.3.3.13 identified an area for which it needed additionalinformation to complete its evaluation of the applicant's scoping and screening results. The applicant responded to the staff's RAI as discussed below.In RAI 2.3.3.15-1, dated September 16, 2005, the staff noted that license renewal drawingLR-36254 at location C-8 contained two references (line REW3-4" EBD from REC  loop B and line REW31-2"-ED from reactor vessel drain) to license renewal drawing LR-36243 at location C-5; however, license renewal drawing LR-36243 only shows one reference (line REW31-2"-ED which is also capped) to license renewal drawing LR-36254. Therefore, the staff requested that 2-88the applicant clarify this discrepancy and confirm which portions of the piping are within thescope of license renewal and subject to an AMR, in accordance with the requirements of 10 CFR 54.4(a) and 10 CFR 54.21(a), respectively, or justify their exclusion.In its response, by letter dated October 14, 2005, the applicant clarified the drawing annotationsshowing the convergence of the two lines REW3-4"-EBD and REW31-2"-ED on license renewal drawing LR-36243 grid location C-6. The extension of line REW3-4"-EBD is shown as a dashed line on license renewal drawing LR-36243, instructing the reviewer to look at license renewal drawing LR-36254 for the details on that pipe. The applicant confirmed that the drawings werecorrect and that both lines are within the scope of license renewal and subject to an AMR, in accordance with the requirements of 10 CFR 54.4(a) and 10 CFR 54.21(a), respectively.Based on its review, the staff found the applicant's response to RAI 2.3.3.15-1 acceptablebecause the applicant confirmed that the lines are within the scope of license renewal;therefore, the staff's concern discussed in RAI 2.3.3.15-1 is resolved.The staff's review of LRA Section 2.3.3.15 identified an area in which information in the LRAneeded to be verified by the NRC Regional Inspection Team to complete the review of theapplicant's scoping and screening results.Inspection Item 2.3.3.15-1License renewal drawing LR-36254 at location B-8 shows two RWN36-3"-HC lines as within thescope of license renewal. One continues to waste collector tank, T-24, shown in license renewal drawing LR-36045, and one continues to waste surge tank, T-23, also shown in license renewal drawing LR-36045; however, the license renewal scope boundaries for these lines terminate in the middle of the pipe runs. The actual locations of the license renewal scope boundaries for these lines are not clear. The NRC Regional Inspection Team performed an inspection toensure that the license renewal scope boundaries for these lines satisfy the 10 CFR 54.4(a)(2)criterion.The inspection team conducted walkdowns, which confirmed that the two RWN36-3"-HC linespass into the 985' pump room and the radwaste building. There are no SR components in the 985' pump room or the radwaste building. The applicant will revise license renewal drawingLR-36045 to change the two RWN36-3"-HC lines (at location D-8) to outside the scope of license renewal. The continuation license renewal drawing LR-36254 will show the transitioninto the 985' pump room. The inspectors determined that the license renewal boundaries satisfy the 10 CFR 54.4(a)(2) criterion. Therefore, the staff's concern described in Inspection Item 2.3.3.15-1 is resolved.2.3.3.15.3  Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs thatshould be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the RWC system components that arewithin the scope of license renewal, as required by 10 CFR 54.4(a), and  the RWC systemcomponents that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2-892.3.3.16  Service and Seal Water System2.3.3.16.1  Summary of Technical Information in the Application In LRA Section 2.3.3.16, the applicant described the service and seal water (SSW) system. TheSSW system supplies screened and strained cooling water (raw water from the MississippiRiver) to various nonessential plant heat loads and services during all modes of operation. The service water portion of the SSW system consists of three 50-percent capacity service waterpumps, an auto strainer, a bypass basket strainer and associated valves, piping, and instrumentation. Normally two service water pumps are in operation and one service water pump is in auto-standby; however, during cold winter months, only one service water pump is required. The seal water portion of the SSW system provides filtered well water (service waterserves as backup to the well water) to the shaft seals for various pumps, including the service water pumps, RSW pumps, and the CWT pumps. The seal water portion consists of two pumps, two filters, and associated valves, piping, and instrumentation. The service water pumps take suction from the pump suction bay in the intake structure and discharge to the turbine building through the intake structure access tunnel. Service water is used to remove heat from various heat exchangers and coolers located in the reactor building and turbine building. The SSW system also supplies water to the sodium hypochlorite s ubsystem (part ofthe CWT system) and the fire system jockey pump. Service water flow is returned to the river.The SSW system is normally in service during plant operation and shutdown.The failure of NSR SSCs in the SSW system could potentially prevent the satisfactoryaccomplishment of an SR function of SSCs within the scope of license renewal. The SSW system also performs functions that support FP.The intended functions within the scope of license renewal include the following:
* provide flow restriction
* provide a pressure-retaining boundaryIn LRA Table 2.3.3-16, the applicant identified the following SSW system com ponent types thatare within the scope of license renewal and subject to an AMR:
* expansion joints
* fasteners/bolting
* filters/strainers
* gauges (flow, level, and sight)
* heat exchangers
* manifolds
* piping and fittings
* pump casings
* restricting orifices
* thermowells
* valve bodies 2-902.3.3.16.2  Staff EvaluationThe staff reviewed LRA Section 2.3.3.16 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.3.3.16 identified an area in which information in the LRAneeded to be verified by the NRC Regional Inspection Team to complete the review of theapplicant's scoping and screening results.Inspection Item 2.3.3.16-1License renewal drawing LR-36665 at location D-7 shows the line SW21-6"-JF, which continuesto the sodium hypochlorite system shown in license renewal drawing LR-36666, as within thescope of license renewal with the license renewal scope boundary terminating in the middle of the pipe run (downstream of the valve SW-10-6"-54); however, license renewal drawing LR-36666 at location C-6 shows the continuation of the line SW21-6"-JF as within the scope of license renewal and defines the boundary for license renewal at check valve SHC-26.
The actual location of the license renewal scope boundary for this pipe is not clear. The NRC Regional Inspection Team performed an inspection to ensure that the license renewal scope boundary for this pipe satisfies the 10 CFR 54.4(a)(2) criterion.The inspection team confirmed through a walkdown that the line SW21-6"-JF passes through aconcrete ceiling in the intake structure, which acts as the scoping boundary. All P&IDs do not typically depict ceilings. The inspectors determined that the license renewal boundary satisfiesthe 10 CFR 54.4(a)(2) criterion. Therefore, the staff's concern described in Inspection Item 2.3.3.16-1 is resolved.2.3.3.16.3  Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the SSW systemcomponents that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the SSW system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2-912.3.3.17  Standby Liquid Control System2.3.3.17.1  Summary of Technical Information in the Application In LRA Section 2.3.3.17, the applicant described the SLC system. The MNGP licensing basisincludes the SLC system as an ESF system. This section, as well as the related agingmanagement section, includes the SLC system for consistency with the SRP-LR and GALLReport. The SLC system provides a means of inserting negative reactivity into the reactor coreby the injection of neutron-absorbing boron in the form of liquid sodium pentaborate. A key lockswitch that starts the SLC system pumps and opens the squib-operated valves provides controlof injection. The boron solution is capable of shutting down the reactor and providing a sufficient shutdown margin to overcome void and temperature coefficients, as well as the effects of xenon, assuming that none of the withdrawn control rods can be inserted. Service airand demineralized water are provided to the SLC tank for mixing of the boron solution, as well as instrument air to various instrumentation.The SLC system contains SR components that are relied upon to remain functional during andfollowing DBEs. The failure of NSR SSCs in the SLC system could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the SLC system performs functions that support ATWS.The intended function, within the scope of license renewal, is to provide a pressure-retainingboundary.In LRA Table 2.3.3-17, the applicant identified the following SLC system com ponent types thatare within the scope of license renewal and subject to an AMR:
* accumulators
* fasteners/bolting
* manifolds
* piping and fittings
* pump casings
* tanks
* thermowells
* valve bodies2.3.3.17.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.17 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).
2-922.3.3.17.3  ConclusionThe staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the SLC system componentsthat are within the scope of license renewal, as required by 10 CFR 54.4(a), and the SLC system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3.18  Wells and Domestic Water System 2.3.3.18.1  Summary of Technical Information in the Application In LRA Section 2.3.3.18, the applicant described the wells and domestic water (WDW) system.The WDW system includes the domestic water, sanitary sewer, acid drain, storm drain, andturbine building normal drain subsystems as described below. The domestic water subsystemsupplies well water to the demineralized water system, the service and seal water system, hotand/or cold water to lavatories, the laundry, and showers throughout the plant's protected area.The sanitary sewer subsystem removes wastewater from lavatories, showers, and sinks in theprotected area, site administration building, and warehouse No. 5. It carries the wastewater tothe city of Monticello sew age system. The acid drain subsystem removes water from suchthings as the demineralized water system area drain and heating boiler blowdown, which is unfitfor direct discharge to the river. Drainage from these sources is carried to the discharge retention basin where it is treated and monitored before release to the river. The storm drain subsystem carries water from building roofs and normal surface drainage to the river. Theturbine building normal drain subsystem removes water from areas in the turbine building wherethere is no potential for radioactive contamination and transports it to the river.The failure of NSR SSCs in the WDW system could potentially prevent the satisfactoryaccomplishment of an SR function of SSCs within the scope of license renewal. The WDW system also performs functions that support FP.The intended function, within the scope of license renewal, is to provide a pressure-retainingboundary.In LRA Table 2.3.3-18, the applicant identified the following WDW system component typesthat are within the scope of license renewal and subject to an AMR:
* fasteners/bolting
* piping and fittings
* pump casings
* valve bodies2.3.3.18.2  Staff Evaluation The staff reviewed LRA Section 2.3.3.18 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.
2-93In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.3.3.18.3  Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the WDW systemcomponents that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the WDW system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.4  Steam and Power Conversion System In LRA Section 2.3.4, the applicant identified the SCs of the steam and power conversionsystem that are subject to an AMR for license renewal.The applicant described the supporting SCs of the steam and power conversi on system in thefollowing sections of the LRA:
* 2.3.4.1c ondensate storage system
* 2.3.4.2condensate and feedwater system
* 2.3.4.3main condenser system
* 2.3.4.4main steam system
* 2.3.4.5turbine generator systemSER Section 2.3.4.1-2.3.4.5 present the staff's review findings regarding LRASections 2.3.4.1-2.3.4.5, respectively.2.3.4.1  Condensate Storage System 2.3.4.1.1  Summary of Technical Information in the Application In LRA Section 2.3.4.1, the applicant described the condensate storage (CST) system. Thecondensate storage system provides a large storage capacity of reactor quality water. Thenormal plant uses for condensate storage water include (1) hotwell makeup and reject, (2) CRD supply, (3) fuel storage pool makeup, (4) demineralizer and radwaste processing, (5) filling therefueling wells, (6) miscellaneous plant flushing and decontamination services, (7) pressurizing
 
RHR and CSP piping, and (8) normal suction supply for HPC and RCI systems. In addition to the above, the condensate storage system provides storage for reclaimed water from theradwaste system. The suppression pool is the SR source of water for HPCI.
2-94The condensate stor age system contains SR components that are relied upon to remainfunctional during and following DBEs. The failure of NSR SSCs in the condensate storage system could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the condensate storage system performsfunctions that support EQ and SBO.The intended function, within the scope of license renewal, is to provide a pressure-retainingboundary.In LRA Table 2.3.4-1, the applicant identified the following condensate storage systemcomponent types that are within the scope of license renewal and subject to an AMR:
* fasteners/bolting
* filters/housings
* flow element
* gauges (flow, level, and sight)
* heat exchangers
* instrumentation
* manifolds
* piping and fittings
* pump casings
* restricting orifices
* thermowells
* valve bodies2.3.4.1.2  Staff Evaluation The staff reviewed LRA Section 2.3.4.1 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.3.4.1 identified an area for which it needed additionalinformation to complete its evaluation of the applicant's scoping and screening results. The applicant responded to the staff's RAI as discussed below.In RAI 2.3.4.1-1, dated September 16, 2005, the staff noted that the HPCI pump normally islined up to the CSTs and the suction is switched to the suppression pool when the level in either CST falls to the TS low level or when a high water level is sensed in the suppression pool. LRA Section 2.3.4.1 states that the portion of the condensate stor age system within the scope oflicense renewal consists of piping and valves which supply the fuel storage pool, HPCI, RCI, RHR, CRD, condensate, FW, CSP, main condenser, and radwaste systems. In addition, the 2-95instrumentation associated with the automatic transfer from the CST to the suppression pool isSR and the components are within the scope of license renewal, in accordance with 10 CFR 54.4(a)(1). LRA Table 2.3.4-1 shows that the intended function of all condensatestorage system component groups is "pressure boundary."License renewal drawing LR-36039 shows the piping within the scope of license renewal,associated with the SR level instrumentation for the north and south CSTs, at locations B-3 andB-6. For each CST, the portion within the scope of license renewal includes the portion of the CST connection piping C22-4"-HJ and C23-4"-HJ between the reactor building and the CST-level instruments. This license renewal drawing does not show the remaining portion of these lines from the reactor building to the CST as within the scope of license renewal. Failure of the piping outside the scope of license renewal would have the same effect as a pressure boundary failure of the portion within the scope of license renewal. Therefore, the staff requested that theapplicant justify why it did not include the portion of lines C22-4"-HJ and C23-4"-HJ between the reactor building and the CST within the scope of license renewal.In its response, by letter dated October 14, 2005, the applicant stated the following:Line segments C22-4"-HJ and C23-4"-HJ, shown on license renewal boundarydrawing LR-36039, include the level switches for the north and south condensate storage tanks (CSTs). The level instrumentation is safety-related because of the automatic transfer feature from the nonsafety-related condensate storage tanksto the safety-related suppression pool.Portions of the line segments connecting to lines C22-4"-HJ and C23-4"-HJlocated between the Reactor Building wall and just prior to valves CST-1-1 and CST-1-2 on LR drawing LR-36039 are buried and are in scope for license renewal. The buried piping is in scope for the reason that it serves as an equivalent anchor for the attached safety related piping. For the purposes of clarification of LR drawing LR-36039, this in scope buried piping is now included in the highlighted segments for C22-4"-HJ/HK and C23-4"-HJ/HK.The remaining line segments which include valves CST-1-1 and CST-1-2 andcontinue to the CSTs between the Reactor Building and the CSTs are above ground and outside the Reactor Building. This piping is considered non-safety related and its failure would only cause the level instrumentation to fail in a safe position by switching suction to the safety-related suppression pool. Therefore, this portion of the CST piping is not in the scope of license renewal.Based on its review, the staff found the applicant's response acceptable because it addressesequivalent seismic restraint and identifies the portions of t he system within the scope of licenserenewal and subject to an AMR, in accordance with the requirements of 10 CFR 54.4(a) and 10 CFR 54.21(a), respectively. The staff reviewed the applicant's use of underground piping as a seismic restraint in SER Section 2.1.3.1.2. Therefore, the staff's concern described inRAI 2.3.4.1-1 is resolved.
2-962.3.4.1.3  ConclusionThe staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the CST system componentsthat are within the scope of license renewal, as required by 10 CFR 54.4(a), and the CST system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.4.2  Condensate and Feedwater System 2.3.4.2.1  Summary of Technical Information in the Application In LRA Section 2.3.4.2, the applicant described the condensate and feedwater (CFW) system.The CFW system supplies condensate from the main condenser to the reactor vessel at anelevated temperature and pressure. The CFW system includes the condensate demineralizer,the reactor FW pump seal, and zinc injection passivation subsystems. Two motor-drivencondensate pumps pump condensate through the SJAE intercondensers and the steam-packing exhauster. After leaving the steam-packing exhauster, condensate passes through the full-flow condensate demineralizer subsystem to ensure a supply of high-purity water to thereactor. Demineralizer effluent is then split into two parallel paths, each with three stages of low-pressure FW heating, to the suction of the reactor FW pumps. The condensate demineralizer subsystem consists of five demineralizer vessels operating in parallel and sizedfor full-condensate flow at reactor-rated conditions. The demineralizer vessels are located inshielded cells. Wastes from an exhausted unit are transferred to the RAD system for disposal.The zinc injection passivation s ubsystem provides a zinc oxide suspension from a continuouslystirred supply tank, which is diluted with demineralized water, and fed to one of two zinc injection pumps. The diluted suspension is continuously injected into the suction of the reactor feed pump just downstream of the reactor feed pump suction valves. Small concentrations of zinc in the reactor water result in a reduction in the amount of cobalt incorporated into the oxide film established on stainless steel piping. This reduction in cobalt-60 incorporation provides substantial reductions in dose rates, particularly in primary containment.The CFW system contains SR components that are relied upon to remain functional during andfollowing DBEs. The failure of NSR SSCs in the CFW system could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the CFW system performs functions that support SBO.The intended functions within the scope of license renewal include the following:
* provide flow restriction
* provide a pressure-retaining boundaryIn LRA Table 2.3.4-2, the applicant identified the following CFW system com ponent types thatare within the scope of license renewal and subject to an AMR:
* expansion joints 2-97
* fasteners/bolting
* filters/strainers
* flow element
* gauges (flow, level, and sight)
* heat exchangers
* manifolds
* piping and fittings
* pump casings
* restricting orifices
* tanks
* thermowells
* valve bodies2.3.4.2.2  Staff Evaluation The staff reviewed LRA Section 2.3.4.2 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.3.4.2 identified areas for which it needed additionalinformation to complete its evaluation of the applicant's scoping and screening results. The applicant responded to the staff's RAIs as discussed below.In RAI 2.3.4.2-1, dated September 16, 2005, the staff noted that LRA Table 2.3.4-2 identifies"Pressure Boundary" as the intended function of all the heat exchangers within the scope of license renewal in the CFW system. License renewal drawings LR-36034 and LR-36035 showthat the shells for FW heaters E-11A, E-11B, E-12A, and E-12B are NSR and included within the scope of license renewal, in accordance with the 10 CFR 54.4(a)(2) criterion; however, several turbine and extraction steamlines connected to the heat exchanger shell pressure boundary are not shown within the scope of license renewal. These lines include the following:
* lines E9-26"-HCD, E10-26"-HCD, E11-26"-HCD, and E12-26"-HCD for L.P.
heaterE-11A on LR-36034 (quadrant B4)
* lines E1-20"-HCD and E2-20"-HCD for L.I.P. heater E-12A on LR-36034 (quadrant B4)
* lines E13-26"-HCD, E14-26"-HCD, E15-26"-HCD, and E16-26"-HCD for L.P.
heaterE-11B on LR-36035 (quadrant B-6)
* lines E2-20"-HCD and E4-20"-HCD for L.I.P. heater E-12B on LR-36035 (quadrant C-6) 2-98Therefore, the staff requested that the applicant justify why it did not include the turbinegenerator system piping connected to the CFW system heaters within the scope of licenserenewal, considering the component's intended function as defined in LRA Table 2.3.4-2 and the scoping criterion specified in 10 CFR 54.4(a)(2).In its response, by letter dated October 14, 2005, the applicant stated the following:The shells for feedwater heaters E-11A, E-11B, E-12A and E-12B are non-safetyrelated and are included within the scope of license renewal in accordance with 10 CFR 54.4(a)(2). These heaters are mounted in the 'neck' of the condenser with only a portion of the heater protruding from the condenser. It is only the ends of the feedwater heater shells which protrude outside of the condenser andhave the capability of impacting the intended function of safety-related SSCs dueto potential leakage or spray that are of concern. The turbine extraction steam lines connected to these heat exchanger shells are located inside the condenser and, therefore, do not pose a potential leak or spray hazard. The failure of thesenon-safety related components could not impact safety-related SSCs per the criteria specified in 10 CFR 54.4(a)(2) and, therefore, are not included in the scope of license renewal.Based on its review, the staff found the applicant's response to RAI 2.3.4.2-1 acceptablebecause the main condenser shell should preclude leakage or spray impacts on SR SSCs from the failure of NSR extraction steamlines inside the main condenser; therefore, the staff's concern described in RAI 2.3.4.2-1 is resolved.In RAI 2.3.4.2-2, dated September 16, 2005, the staff noted that license renewal drawingLR-36036 at locations C-5, C-6, D-5, and D-6 identifies the shells for FW heaters E-11A,E-11B, E-12A, and E-12B as NSR and within the scope of license renewal, in accordance with the 10 CFR 54.4(a)(2) criteria; however, the drawing also shows a connecting steamline to each heater shell as being outside the scope of license renewal with references to license renewal drawings LR-36035 (C-5), LR-36035 (B-5), LR-36034 (B-4), and LR-36034 (C-4),
which could not be found on the indicated license renewal drawings. Therefore, the staff requested that the applicant identify the correct drawings and locations for these references. Inaddition, the staff requested that the applicant justify the determination that the steam pipingconnected to the CFW system heaters is not within the scope of license renewal, consideringthe component's intended function as defined in LRA Table 2.3.4-2 and the scoping criteriaspecified in 10 CFR 54.4(a)(2).In its response, by letter dated October 14, 2005, the applicant stated that, for the FW heaters,license renewal drawings LR-36034 and LR-36035 show the extraction steam details and license renewal drawing LR-36036 shows the condensate and FW details. The applicant stated that the continuation between the drawings is shown only for information and refers to thegeneral area where the extraction steam piping connects to the heaters. Consistent with the extraction steamline noted in RAI 2.3.4.2-1, the applicant stated that the turbine extractionsteamlines identified in RAI 2.3.4.2-2 are inside the condenser and pose no potential leak orspray hazard. The applicant concluded that failure of these NSR extraction steamlines would not impact SR SSCs pursuant to the 10 CFR 54.4(a)(2) criteria and, therefore, are not includedwithin the scope of license renewal.
2-99Based on its review, the staff found the applicant's response to RAI 2.3.4.2-2 acceptable,because the main condenser shell should prevent leakage or spray impacts on SR SSCs from the failure of NSR extraction steamlines inside the main condenser; therefore, the applicant resolved the staff concern described in RAI 2.3.4.2-2.The staff's review of LRA Section 2.3.4.2 identified areas in which information in the LRAneeded to be verified by the NRC Regional Inspection Team to complete the review of theapplicant's scoping and screening results.Inspection Item 2.3.4.2-1LRA Section 2.3.4.2 states that the portion of the CFW system within the scope of licenserenewal consists of pumps, condensate demineralizers, heat exchangers, tanks, and associated piping, valves, and instrumentation from the condensate pump suction to the FWinjection nozzles. LRA Table 2.3.4-2 identifies "Pressure Boundary" as the intended function for all piping and fittings in the CFW system within the scope of license renewal. License renewaldrawing LR-36038-2 shows the CFW system piping associated with the condensatedemineralizer subsystem as NSR and included within the scope of license renewal, inaccordance with the 10 CFR 54.4(a)(2) criterion. Accordingly, license renewal drawing LR-36038-2 at location A-6 identifies a portion of line CH5-3"-HC to the chemical waste tank as within the scope of license renewal. Because the license renewal scope boundary for this line terminates in the middle of the pipe run, the actual location of the license renewal scopeboundary for this pipe is not clear. The NRC Regional Inspection Team performed an inspectionto ensure that the license renewal scope boundary for this pipe satisfies the 10 CFR 54.4(a)(2) criterion.The inspection team conducted a walkdown and confirmed that the license renewal boundaryends as line CH5-3"-HC enters the 985' pump room. There are no SR components in the 985' pump room. All P&IDs do not typically show walls and floors. The inspectors determined that the license renewal boundary satisfies the 10 CFR 54.4(a)(2) criterion. Therefore, the staff'sconcern described in Inspection Item 2.3.4.2-1 is resolved.2.3.4.2.3  Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the CFW systemcomponents that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the CFW system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.4.3  Main Condenser System 2.3.4.3.1  Summary of Technical Information in the Application In LRA Section 2.3.4.3, the applicant described the main condenser (CDR) system. The CDRsystem provides a heat sink for the steam cycle, removes noncondensable gases, and servesas a central collection point for system drains. The system is NSR, but is credited for post-2-100accident plateout and holdup of radioactive iodine in the LOCA and control rod dropaccident analyses conducted pursuant to USAR Sections 14.7.2.4.1 and 14.7.1.6, respectively.Also included in the nonsafety affecting safety function is the automatic closure of mechanical vacuum pump suction valves that isolate the condenser lines to the mechanical vacuum pump on primary containment isolati on system (PCIS) Division 1 logic, which includes detection ofhigh activity in the main steamlines. The CDR system consists principally of the CDR, which condenses steam exhausted from the turbine and turbine bypass system (TGS system). TheCDR is a twin-shell, dual-pressure surface condenser. Each of the two low-pressure turbinesexhausts into a condenser shell. Condenser structural integrity is continuously demonstrated during normal operation when the condenser is required to maintain vacuum. Following a DBA, when the condenser is required to perform its intended function, the main steam isolation valves will be closed and vacuum will be lost. The condenser will not be required to perform apressure-boundary function because atmospheric conditions will exist inside the condenser.The failure of NSR SSCs in the CDR system could potentially prevent the satisfactoryaccomplishment of an SR function of SSCs within the scope of license renewal.The intended functions within the scope of license renewal include the following:
* provide plateout and holdup of radioactive material
* provide a pressure-retaining boundaryIn LRA Table 2.3.4-3, the applicant identified the following CDR system component types thatare within the scope of license renewal and subject to an AMR:
* condenser complex
* expansion joints
* fasteners/bolting
* filters/strainers
* gauges (flow, level, and sight)
* heat exchangers
* LP turbine hood
* piping and fittings
* pump casings
* tanks
* thermowells
* valve bodies2.3.4.3.2  Staff Evaluation The staff reviewed LRA Section 2.3.4.3 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had not 2-101omitted any passive and long-lived components that should be subject to an AMR, inaccordance with the requirements of 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.3.4.3 identified areas for which it needed additionalinformation to complete its evaluation of the applicant's scoping and screening results. The applicant responded to the staff's RAIs as discussed below.In RAI 2.3.4.3-1, dated September 16, 2005, the staff noted that on license renewal drawingLR-36035-2 at location B-2, pipe section line number OG6-8"-HC at separator T-72 and downstream piping are not within the scope of license renewal. All other piping and components within the apparent plant area are within the scope of license renewal. Failure of this unisolable section of pipe could affect the license renewal intended pressure-boundary function for the CDR system; therefore, the staff requested that the applicant justify why it did not include thesesections of unisolable piping and components within the scope of license renewal.In its response, by letter dated October 14, 2005, the applicant stated that pipe line numberOG6-8-HC at separator T-72 and the downstream piping have an internal environment of air.
The failure of these NSR components could not impact the intended function of SR SSCs and therefore, are not included within the scope of license renewal. All other piping and componentswithin the plant area are within the scope of license renewal because they contain water and have the ability to impact the intended function of SR SSCs because of the potential for leakageor spray.Based on its review, the staff found the applicant's response to RAI 2.3.4.3-1 acceptable,because pipe line number OG6-8-HC and the downstream piping have an internal environment of air, which does not have the ability to impact the intended function of SR SSCs, and as such,are not within the scope of license renewal; therefore, the staff's concern described in RAI 2.3.4.3-1 is resolved.In RAI 2.3.4.3-2, dated September 16, 2005, the staff noted that license renewal drawingLR-54817-4 at location A-7 is not listed in LRA Section 2.3.4.3 as a license renewal drawing for the CDR system; therefore, the staff requested that the applicant clarify why it did not includeLR-54817-4 in LRA Section 2.3.4.3 as a license renewal drawing for the CDR system.In its response, by letter dated October 14, 2005, the applicant stated that license renewaldrawing LR-54817-4 shows the flow diagram for the recombiner building. There are no CDR components within the scope of license renewal inside the recombiner building. Consequently, license renewal drawing LR-54817-4 is not included in LRA Section 2.3.4.3 as a license renewal drawing for the CDR system.Based on its review, the staff found the applicant's response to RAI 2.3.4.3-2 acceptablebecause license renewal drawing LR-54817-4 shows no CDR components within the scope oflicense renewal; therefore, the staff's concern described in RAI 2.3.4.3-2 is resolved.The staff's review of LRA Section 2.3.4.3 identified areas in which information in the LRAneeded to be verified by the NRC Regional Inspection Team to complete the review of theapplicant's scoping and screening results.
2-102Inspection Item 2.3.4.3-1The CDR system is NSR, but is credited for post-accident plateout and holdup of radioactiveiodine in the LOCA and control rod drop accident analyses, per USAR Sections 14.7.2.4.1 and14.7.1.6, respectively. License renewal drawing LR-36035-2 at locations C-6 and B-6 has piping outside the scope of license renewal with continuations to condenser E-1B connection 29 on license renewal drawing LR-36035 at location D-6. The portion of piping on LR-36035 is within the scope of license renewal. Consequently, the actual locations of the license renewal boundary for these pipes are not clear. The NRC Regional Inspection Team performed aninspection to ensure that the license renewal scope boundary for these pipes satisfies the 10 CFR 54.4(a)(2) criterion.Lines RV34-6"-HB and RV33-6"-HB connect to condenser E-1B at connection 29 on LR-36035.The intended function of the piping is not for post-accident plateout and holdup of radioactive iodine, but for pressure boundary for NSR affecting SR components, as shown in LRA Table 2.3.4-3, "Main Condenser System." Lines RV34-6"-HB and RV33-6"-HB shown on LR-36035-2 are in the SJAE room. There are no SR components in the SJAE room and, therefore, this piping is not required to be within the scope of license renewal.Piping PS9-2"-ED, shown on LR-36035-2, is also in the SJAE room; however, this piping is anHELB line and, therefore, is within the scope of license renewal. The boundary for the HELB line ends at the valves, as stated in USAR Appendix I, Table I.2-1, page 8.The applicant will revise license renewal drawing LR-36035-2 to depict a wall that linesRV34-6"-HB and RV33-6"-HB pass through into the SJAE room. The lines will be shown withinthe scope of license renewal as they continue from license renewal drawing LR-36035 and condenser E-1B connection 29, and outside the scope of license renewal after they pass through the wall into the SJAE room. The inspectors determined that the license renewal boundary satisfies the 10 CFR 54.4(a)(2) criterion. Therefore, the staff's concern described in Inspection Item 2.3.4.3-1 is resolved.Inspection Item 2.3.4.3-2License renewal drawing LR-36035 at location A-8 has a piping continuation, pipe line numberCN-125-4"-EN1C, from the recombiner, license renewal drawing LR-54817-4 at location A-7, that is within the scope of license renewal. The continuation on license renewal drawing LR-54817-4 at location A-7 is outside the scope of license renewal. Consequently, the actuallocation of the license renewal boundary for this pipe is not clear. The NRC Regional InspectionTeam performed an inspection to ensure that the license renewal scope boundary for this pipe satisfies the 10 CFR 54.4(a)(2) criterion.The inspection team confirmed through walkdown that the license renewal boundary ends asthe line, CN-125-4"-EN1C, enters the recombiner building on license renewal drawing LR-54817-4. There are no SR components in the recombiner building; therefore, licenserenewal drawing LR-54817-4 does not depict any components within the scope of license renewal in that building.The applicant will revise license renewal drawing LR-54817-4 (at location A-7) to show thecontinuation of line CN-125-4"-EN1C to license renewal drawing LR-36035 as being within the 2-103scope of license renewal, with the scoping boundary at the wall labeled turbine building. Nocomponents shown to the right of the turbine building wall are within scope, as these are all inthe recombiner building. The inspectors determined that the license renewal boundary satisfies the 10 CFR 54.4(a)(2) criterion. Therefore, the staff's concern described in Inspection Item 2.3.4.3-2 is resolved.2.3.4.3.3  Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the CDR systemcomponents that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the CDR system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.4.4  Main Steam System 2.3.4.4.1  Summary of Technical Information in the Application In LRA Section 2.3.4.4, the applicant described the main steam (MST) system. The MSTsystem transports steam produced in the reactor to the main turbine for the production ofelectricity. This steam is supplied to the high-pressure section of the turbine. Steam leaving the high-pressure turbine is divided, the bulk of it passing through moisture separators before its admission to the low-pressure sections. A portion of the steam is extracted and is condensed as it is cascaded through FW heaters en route to the CDR. Normally, the turbine uses all thesteam being generated by the reactor; however, automatic, pressure-controlled, bypass valves are supplied, which can discharge excess steam directly to the condenser. The MST systemalso supplies steam to the HPCI and RCI turbines. The MST system includes an inline flowrestrictor for each of the four main steamlines. These flow restrictors minimize water losses and protect the fuel barrier before main steam isolation valve closure for steamline ruptures outside of primary containment. Drains are provided to remove condensate from the steamlines. The majority of the components for the MST system are located in the turbine building and reactorbuilding steam chase, with additional piping and valves located in the primary containment. The majority of the system components are made of stainless steel and carbon steel, althoughsome cast austenitic stainless steel and copper alloy material is used.The MST system contains SR components that are relied upon to remain functional during andfollowing DBEs. The failure of NSR SSCs in the MST system could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the MST system performs functions that support FP and EQ.The intended functions within the scope of license renewal include the following:
* provide filtration
* provide flow restriction
* provide a pressure-retaining boundary 2-104In LRA Table 2.3.4-4, the applicant identified the following MST system com ponent types thatare within the scope of license renewal and subject to an AMR:
* fasteners/bolting
* filters/strainers
* flow element
* manifolds
* piping and fittings
* restricting orifices
* thermowells
* valve bodies2.3.4.4.2  Staff Evaluation The staff reviewed LRA Section 2.3.4.4 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.3.4.4 identified an area for which it needed additionalinformation to complete its evaluation of the applicant's scoping and screening results. The applicant responded to the staff's RAI as discussed below.In RAI 2.3.4.4-1, dated September 16, 2005, the staff noted that license renewal drawingLR-36035-2 at locations D-7 and B-7 indicates that pipe line numbers D109-1"-EF and D108-1"-EF (steam supply lines to Air Ejectors E-2B and E-2A) are not within the scope of license renewal. Table 2.3.4-4 states that piping, fittings, and valves are within the scope oflicense renewal with intended pressure-boundary function. Failure of this section of pipe could affect the license renewal intended pressure-boundary function for the MST system piping;therefore, the staff requested that the applicant justify why it did not include these sections ofunisolable piping and components within the scope of license renewal.In its response, by letter dated October 14, 2005, the applicant stated that lines D109-1"-EFand D 108-1"-EF are inside the SJAE room. These 1-inch pipes are not considered high-energy lines and there are no SR components inside the SJAE room whose intended function could be impacted by this NSR piping; therefore, line numbers D109-1"-EF and D108-1"-EF are not within the scope of license renewal.Based on its review, the staff found the applicant's response to RAI 2.3.4.4-1 acceptablebecause NSR lines D109-1"-EF and D l08-1"-EF are inside the SJAE, are not considered high-energy lines, and as such, are not within the scope of license renewal; therefore, the staff's concern described in RAI 2.3.4.4-1 is resolved.
2-1052.3.4.4.3  ConclusionThe staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the MST systemcomponents that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the MST system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.4.5  Turbine Generator System 2.3.4.5.1  Summary of Technical Information in the Application In LRA Section 2.3.4.5, the applicant described the turbine generator system. The turbinegenerator system includes the turbine generator unit and the steam sealing, turbine lube oil,hydrogen cooling, hydrogen seal oil, and stator cooling subsystems. The function of the turbineis to convert the thermodynamic energy of the steam from the nuclear reactor into mechanical energy that drives the generator. The generator in turn converts that energy to an electricaloutput to the power grid. The turbine consists of one single-flow, high-pressure section with two double-flow, low-pressure sections of the non-reheat design on a single shaft. The generator consists of three major parts-the rotor, stator, and exciter. The rotor is turned by the turbine shaft and is the source of the moving magnetic field. The stator consists of windings which form a conductive path for the current induced by the rotating magnetic field of the rotor. The exciter is a separate and smaller generator driven by the turbine to provide power for the main generator rotor magnetic field. The steam sealing subsystem prevents steam leakage past theturbine shaft seals into the turbine building and limits air in-leakage to the turbine casings. The turbine generator shaft is supported by 10 journal bearings. All bearing oil is supplied by the turbine lube oil subsystem, which also provides high-pressure oil to the hydraulic turbine controlmechanisms. The hydrogen gas of the hydrogen cooling subsystem is contained within thegenerator casing. The hydrogen cooling subsystem is designed to reduce the heat generatedfrom windage resistance and provide a good heat transfer medium for generator cooling. The hydrogen seal oil subsystem supplies vacuum treated oil between the rotor shaft and thegenerator end housing hydrogen seals to prevent hydrogen from escaping into the turbine building. The stator cooling subsystem removes heat from the generator stator by circulatinglow-conductivity water through the hollow metal bars forming the stator windings. The subsystem also supplies cooling water to the generator exciter rectifier banks. The statorcooling subsystem consists of a storage tank feeding two parallel pumps, two heat exchangers,a filter, and connecting piping with the generator stator.The failure of NSR SSCs in the turbine generator system could potentially prevent thesatisfactory accomplishment of an SR function of SSCs within the scope of license renewal.The intended function, within the scope of license renewal, is to provide a pressure-retainingboundary.In LRA Table 2.3.4-5, the applicant identified the following turbine generator system componenttypes that are within the scope of license renewal and subject to an AMR:
2-106
* expansion joints
* fasteners/bolting
* filters/housings
* filters/strainers
* gauges (flow, level and sight)
* heat exchangers
* manifolds
* piping and fittings
* pump casings
* restricting orifices
* steam traps
* tanks
* thermowells
* turbines
* valve bodies2.3.4.5.2  Staff Evaluation The staff reviewed LRA Section 2.3.4.5 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.3.4.5 identified areas for which it needed additionalinformation to complete its evaluation of the applicant's scoping and screening results. The applicant responded to the staff's RAIs as discussed below.In RAI 2.3.4.5-1, dated September 16, 2005, the staff noted that license renewal drawingLR-36034 at location B-4 shows a portion of the sensing line to PT-1217 attached to pipe E2-20"-HCD as within the scope of license renewal; however, the remaining portion of thesensing line and pressure transmitter is shown as outside the scope of license renewal. In addition, license renewal drawing LR-36035 at location D-7 shows pressure transmitters PT-1222 and PT-1223 and portions of the sensing lines to these transmitters as within the scope of license renewal; however, the remaining portions of the sensing line to pipes E3-20"-HCD and E16-26"-HCD are shown as outside the scope of license renewal. LRASection 2.3.4.5 states that the license renewal function for turbine generator piping and gaugesis to maintain a pressure boundary and that NSR structures and/or components of the turbine generator system that could affect SR SSCs must maintain sufficient integrity so that theintended function of the SR SSCs is not adversely affected. Failure of the sensing lines noted above could affect the license renewal intended pressure-boundary function of this turbine generator piping and have a negative impact on the SR SSCs; therefore, the staff requested 2-107that the applicant justify why it did not include portions of the sensing lines and associatedpressure transmitters within the scope of license renewal.In its response, by letter dated October 14, 2005, the applicant stated that the portion of thesensing line to PT-1217 attached to pipe E2-20"-HCD is inside the condenser and should nothave been shown as within the scope of license renewal. PT-1222 and PT-1223 and portions of the sensing lines to these transmitters are within the scope of license renewal because they are on the exterior of the condenser. The sensing lines inside the condenser to pipes E3-20"-HCD and E16-26"-HCD are not within the scope of license renewal. The failure of these NSR linescould not impact the intended function of SR SSCs, and therefore, the applicant did not includethem within the scope of license renewal. During its review, the applicant found that it should have shown the portions of the sensing lines from condenser penetration No. 60 to PT-1216 and PT-1217 on the exterior of the condenser as within the scope of license renewal.Based on its review, the staff found the applicant's response to RAI 2.3.4.5-1 acceptablebecause failure of those NSR portions of sensing lines within the condenser could not impact the intended function of SR SSCs, and consequently, those portions are not within the scope of license renewal; therefore, the staff's concern described in RAI 2.3.4.5-1 is resolved.In RAI 2.3.4.5-2, dated September 16, 2005, the staff noted that LRA Section 2.3.4.5 statesthat the license renewal function for turbine generator piping is to maintain a pressure boundary and that NSR structures and/or components of the turbine generator system that could affectSR SSCs must maintain sufficient integrity so that the intended function of the SR SSCs is not adversely affected.License renewal drawings LR-36034 at location B-4 and LR-36035 at locations B-6, B-7, andC-7 show piping to LIP Heater 12-A&B and LP Heater 11-A & B (E9-26"-HCD, E10-26"-HCD,E11-26"-HCD, E12-26"-HCD, E1-20"-HCD, E2-20"-HCD, E14-26"-HCD, E13-26"-HCD, E15-26"-HCD, E16-26"-HCD, E4-20"-HCD, E3-20"-HCD) as outside the scope of licenserenewal; however, the sensing lines to pressure transmitters attached to these pipes are shown as within the scope of license renewal. Failure of the cited pipes could affect the license renewal intended function of pressure boundary for the turbine generator piping and have a negative impact on the SR SSCs. Therefore, the staff requested that the applicant justify why itdid not include the above cited pipes within the scope of license renewal.In its response, dated October 14, 2005, the applicant stated that portions of the sensing linesto these transmitters are within the scope of license renewal because they are on the exterior of the condenser and could impact the intended function of SR SSCs. The remaining portions of the sensing lines and heater piping to which they are attached are located in the condenser and are not within the scope of license renewal. The failure of this NSR piping could not impact the intended function of SR SSCs. During its review, the applicant found that the portions of the sensing lines from condenser penetration No. 25 to piping E4-20"-
HCD and E3-20"-HCD onlicense renewal drawing LR-36035 (at location C-7) and condenser penetration No. 31 to piping E1-20"-HCD and E2-20"-
HCD should not have been shown within the scope of license renewalbecause they are within the condenser.Based on its review, the staff found the applicant's response to RAI 2.3.4.5-2 acceptable,because those portions of sensing lines within the condenser are not within the scope of license 2-108renewal. The failure of these NSR lines could not impact the intended function of SR SSCs;therefore, the staff's concern described in RAI 2.3.4.5-2 is resolved.2.3.4.5.3  Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the turbine generator systemcomponents that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the turbine generator system components that are subject to an AMR, as required by10 CFR 54.21(a)(1).2.4Scoping and Screening Results:  Containments, Structures, and ComponentSupportsThis section documents the staff's review of the applicant's scoping and screening results forcontainments, structures, and component supports. Specifically, this section discusses the following containments, structures, and component supports:
* cranes, heavy loads, rigging
* diesel fuel oil transfer house
* emergency diesel generator building
* emergency filtration train building
* fire protection barriers commodity group
* hangers and supports commodity group
* HPCI building
* intake structure
* miscellaneous SBO yard structures
* offgas stack
* offgas storage and compressor building
* plant control and cable spreading structure
* primary containment
* radioactive waste building
* reactor building
* structures affecting safety
* turbine building
* underground duct bankIn accordance with the requirements of 10 CFR 54.21(a)(1), the applicant must identify and listpassive, long-lived SCs that are within the scope of license renewal and subject to an AMR. To verify that the applicant properly implemented its methodology, the staff focused its review onthe implementation results. This approach allowed the staff to confirm that there were noomissions of containments, structures, and component supports components that meet thescoping criteria and are subject to an AMR.
2-109Staff Evaluation Methodology. The staff performed its evaluation of the information in the LRAin the same manner for all containments, structures, and component supports. The objective of the review was to determine whether the applicant had identified the components andsupporting structures for a specific containment, structure, or component support, that appeared to meet the scoping criteria specified in the Rule, as within the scope of license renewal, in accordance with 10 CFR 54.4. Similarly, the staff evaluated the applicant'sscreening results to verify that all long-lived, passive components were subject to an AMR in accordance with 10 CFR 54.21(a)(1).Scoping. To perform its evaluation, the staff reviewed the applicable LRA section andassociated component drawings, focusing its review on components that had not been identified as within the scope of license renewal. The staff reviewed relevant licensing-basis documents, including the USAR, for each containment, structure, and component support to determine whether the applicant had omitted components with intended functions delineatedunder 10 CFR 54.4(a) from the scope of license renewal. The staff also reviewed the licensing-basis documents to determine whether the LRA specified all intended functions delineatedunder 10 CFR 54.4(a). If omissions were identified, the staff requested additional information to resolve the discrepancies.Screening. Once the staff completed its review of the scoping results, it evaluated theapplicant's screening results. For those containments, structures, and components supports with intended functions, the staff sought to determine (1) if the functions are performed with moving parts or a change in configuration or properties or (2) if they are subject to replacement based on a qualified life or specified time period, as described in 10 CFR 54.21(a)(1). For those that did not meet either of these criteria, the staff sought to confirm that these containments,structures, and components supports and components were subject to an AMR, as required by 10 CFR 54.21(a)(1). If discrepancies were identified, the staff requested additional information to resolve them.2.4.1  Cranes, Heavy Loads, Rigging 2.4.1.1  Summary of Technical Information in the ApplicationIn LRA Section 2.4.1, the applicant described the cranes, heavy loads, and riggi ng system. Thecranes, heavy loads, and rigging system consists of the reactor building and turbine buildingcranes, numerous hoists, lifting fixtures and devices, and other miscellaneous smaller cranes.
Included in this system are the reactor components' handling equipment, such as the refuelingbridge, various tools, controls, lifting devices, and fixtures. The refueling rod block interlocks arealso included under the reactor manual control system.The failure of NSR SSCs in the cranes, heavy loads, and rigging system could potentiallyprevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal.The intended function, within the scope of license renewal, is to provide structural support toNSR components (civil and structural).
2-110In LRA Table 2.4.1-1, the applicant identified the following cranes, heavy loads, and riggingsystem com ponent types that are within the scope of license renewal and subject to an AMR:
* aluminum in air/gas (fuel preparation machine aluminum frame)
* aluminum in treated water (fuel preparation machine aluminum frame)
* carbon steel, low-alloy steel in air/gas (reactor building crane rails, turbine building cranerails, refueling platform rails)
* carbon steel, low-alloy steel in air/gas (reactor building crane, turbine building crane,refueling platform, reactor vessel head lifting device, dryer and steam separator sling lifting device, and hook box)2.4.1.2  Staff Evaluation The staff reviewed LRA Section 2.4.1 and the USAR using the evaluation methodologydescribed in SER Section 2.4. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.4.In conducting its review, the staff evaluated the structural component functions described in theLRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had not omitted from the scope of license renewal any components with intendedfunctions delineated under 10 CFR 54.4(a). The staff then reviewed those components that theapplicant had identified as being within the scope of license renewal to verify that the applicanthad not omitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.4.1.3  Conclusion The staff reviewed the LRA and related structural components to determine whether theapplicant had failed to identify any SSCs that should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequatelyidentified the cranes, heavy loads, and rigging system components that are within the scope oflicense renewal, as required by 10 CFR 54.4(a), and the cranes, heavy loads, and rigging system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.4.2  Diesel Fuel Oil Transfer House2.4.2.1  Summary of Technical Information in the Application In LRA Section 2.4.2, the applicant described the diesel fuel oil transfer house. The diesel fueloil transfer house, located north of the diesel generator building and west of the intake structure, is a reinforced concrete building on a mat foundation that provides protective enclosure to the SR diesel oil transfer pump and the diesel oil service pump.The diesel fuel oil transfer house contains SR components that are relied upon to remainfunctional during and following DBEs. The failure of NSR SSCs in the diesel fuel oil transfer 2-111house could potentially prevent the satisfactory accomplishment of an SR function of SSCswithin the scope of license renewal. In addition, the diesel fuel oil transfer house performs functions that support FP.The intended functions within the scope of license renewal include the following:
* provide flood protection barrier
* provide missile barrier
* provide structural support to NSR components (civil and structural)
* provide structural support to SR components (civil and structural)
* provide shelter/protection to SR componentsIn LRA Table 2.4.2-1, the applicant identified the following diesel fuel oil transfer housecomponent types that are within the scope of license renewal and subject to an AMR:
* carbon steel, low-alloy steel in air/gas (structural steel, steel embeds, etc.)
* carbon steel, low-alloy steel in air/gas (supports for miscellaneous structures (i.e.,members, welds, bolted connections, support anchorage for platforms, stairs, etc.))
* carbon steel, low-alloy steel in atmosphere/weather (door)
* concrete in air/gas (foundation, walls, slabs)
* concrete in air/gas (foundation, walls, slabs, grout)
* concrete in atmosphere/weather (walls, slab)
* concrete in below grade (foundation, walls)2.4.2.2  Staff Evaluation The staff reviewed LRA Section 2.4.2 and the USAR using the evaluation methodologydescribed in SER Section 2.4. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.4.In conducting its review, the staff evaluated the structural component functions described in theLRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had not omitted from the scope of license renewal any components with intendedfunctions delineated under 10 CFR 54.4(a). The staff then reviewed those components that theapplicant had identified as being within the scope of license renewal to verify that the applicanthad not omitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.4.2 identified an area for which it needed additionalinformation to complete its evaluation of the applicant's scoping and screening results. The applicant responded to the staff's RAI as discussed below.In RAI 2.4.2-1, dated September 28, 2005, the staff noted that two component groups, (1)concrete in air/gas (foundation, walls, slabs) and (2) concrete in air/gas (foundation, walls, slabs, grout), have identical intended functions in Tables 2.4.2-1, 2.4.3-1, 2.4.4-1, 2.4.7-1,2.4.8-1, 2.4.11-1, 2.4.12-1, 2.4.14-1, 2.4.15-1, 2.4.16-1, and 2.4.17-1. Therefore, the staff 2-112requested that the applicant explain the need for the first component group since it appeared tobe contained in the second component group. The staff also noted that, in addition to those twocomponent groups, concrete in air/gas (walls, slabs) is listed in Tables 2.4.3-1, 2.4.4-1, 2.4.8-1,2.4.12-1, and 2.4.17-1 as a component group with the same intended function for which thestaff requested a similar explanation.In its response, by letter dated October 28, 2005, the applicant stated the following:To explain the difference between component groups, first an explanation of howTable 2.4.x-1 was assembled is needed. Tables in Section 2.4 of the License Renewal Application (LRA) were assembled by copying the component group and intended functions for each 3.5.2-x Table line entry into the 2.4.x-1 Table.This format was consistently used throughout the LRA. Many line entry component group descriptions appear similar but there are subtle differences that are evident upon review of the 3.5.2-x Table aging managementprogram (AMP), aging effects/mechanisms, material, etc.For this specific question, Table 2.4.x-1 component groups, 'concrete in air/gas(foundation, walls, slabs)' and 'concrete in air/gas (foundation, walls, slabs, grout)' have different component group descriptions (one component group includes grout and the other did not). Review of Table 3.5.2-x reveals that thecomponent group without grout is evaluated for the aging effect, 'cracking, loss of bond, loss of material due to corrosion of embedded steel.' The mechanism of corrosion of embedded steel is not applicable to grout but is applicable to reinforced concrete.For part two of this question, the Table 2.4.x-1 component groups, 'concrete inair/gas (walls, slabs),' 'concrete in air/gas (foundation, walls, slabs),' and
'concrete in air/gas (foundation, walls, slabs, grout)' have different component group descriptions. The same rationale discussed above is applicable here as well.Based on its review, the staff found the applicant's response to RAI 2.4.2-1 acceptable. Theapplicant explained that (1) tables in Section 2.4 were copied from the component group andintended function from tables in Section 3.5, (2) one component group includes grout and the other does not, and (3) the mechanism of corrosion of embedded steel is applicable to reinforced concrete but not to grout. Because of these minor differences, tables in Section 2.4 appear repetitious. Therefore, the staff's concern described in RAI 2.4.2-1 is resolved.2.4.2.3  Conclusion The staff reviewed the LRA and related structural components to determine whether any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the diesel fuel oil transferhouse components that are within the scope of license renewal, as required by 10 CFR 54.4(a),
and the diesel fuel oil transfer house components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2-1132.4.3  Emergency Diesel Generator Building2.4.3.1  Summary of Technical Information in the ApplicationIn LRA Section 2.4.3, the applicant described the EDG building. The principal function of theEDG building is to provide a safe enclosure and protection for the standby diesel generators and portions of the power distribution systems enclosed therein. The building is primarily asingle-story structure of reinforced concrete construction. A partial second story extends over a portion of the structure. The ground floor consists of a concrete slab which is independent of the building structure and placed on compacted select fill. Exterior walls are of reinforcedconcrete and support the lower roof and second story framing. The roof over the single-story portion of the structure and over the penthouse consists of a thick, reinforced concrete slab supported by structural steel framing. A north-south interior wall of reinforced concrete extends the full height of the structure providing physical separation of the diesel generator systems.The exterior and interior walls extend 6 feet below grade to form a continuous wall footing supported on select fill. The standby diesel generators are located at grade and are supportedon a 3-foot thick reinforced concrete mat which is physically independent of the ground floor slab and building structure.The EDG building contains SR components that are relied upon to remain functional during andfollowing DBEs. The failure of NSR SSCs in the EDG building could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the EDG building performs functions that support FP.The intended functions within the scope of license renewal include the following:
* provide rated fire barrier
* provide flood protection barrier
* provide missile barrier
* provide structural support to NSR components (civil and structural)
* provide structural support to SR components (civil and structural)
* provide shelter/protection to SR componentsIn LRA Table 2.4.3-1, the applicant identified the following EDG building component types thatare within the scope of license renewal and subject to an AMR:
* carbon steel, low-alloy steel in air/gas (fire-rated doors)
* carbon steel, low-alloy steel in air/gas (structural steel, steel embeds, etc.)
* carbon steel, low-alloy steel in air/gas (supports for miscellaneous structures (i.e.,members, welds, bolted connections, support anchorage for platforms, stairs, etc.))
* carbon steel, low-alloy steel in atmosphere/weather (doors, ventilation assemblies)
* concrete in air/gas (foundation, walls, slabs)
* concrete in air/gas (foundation, walls, slabs, grout)
* concrete in air/gas (walls, slabs)
* concrete in atmosphere/weather (walls, slab) 2-114
* concrete in below grade (foundation, walls)
* masonry walls in air/gas2.4.3.2  Staff Evaluation The staff reviewed LRA Section 2.4.3 and the USAR using the evaluation methodologydescribed in SER Section 2.4. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.4.In conducting its review, the staff evaluated the structural component functions described in theLRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had not omitted from the scope of license renewal any components with intendedfunctions delineated under 10 CFR 54.4(a). The staff then reviewed those components that theapplicant had identified as being within the scope of license renewal to verify that the applicanthad not omitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.4.3.3  Conclusion The staff reviewed the LRA and related structural components to determine whether theapplicant had failed to identify any SSCs that should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequatelyidentified the EDG building components that are within the scope of license renewal, asrequired by 10 CFR 54.4(a), and the EDG building components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.4.4  Emergency Filtration Train Building2.4.4.1  Summary of Technical Information in the Application In LRA Section 2.4.4, the applicant described the EFT building. The function of the EFT buildingis to provide safe enclosure and protection for the main components of the MCR air conditioning system (including the EFT units for the MCR air conditioning system) and for otherSR equipment as necessary. The EFT building is an L-shaped reinforced concrete structure supported by a mat foundation. The west section is supported by two reinforced concrete caissons. The east section is three stories high, and the west section is two stories high.The EFT building contains SR components that are relied upon to remain functional during andfollowing DBEs. The failure of NSR SSCs in the EFT building could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the EFT building performs functions that support FP, ATWS, and SBO.The intended functions within the scope of license renewal include the following:
* provide rated fire barrier
* provide flood protection barrier 2-115
* provide missile barrier
* provide structural support to NSR components (civil and structural)
* provide structural support to SR components (civil and structural)
* provide shelter/protection to SR componentsIn LRA Table 2.4.4-1, the applicant identified the following EFT building component types thatare within the scope of license renewal and subject to an AMR:
* carbon steel, low-alloy steel in air/gas (fire-rated doors)
* carbon steel, low-alloy steel in air/gas (structural steel, steel embeds, etc.)
* carbon steel, low-alloy steel in air/gas (supports for miscellaneous structures (i.e.,members, welds, bolted connections, support anchorage for platforms, stairs, etc.))
* concrete in air/gas (foundation, walls, slabs)
* concrete in air/gas (foundation, walls, slabs, grout)
* concrete in air/gas (walls, slabs)
* concrete in atmosphere/weather (walls, slab)
* concrete in below grade (foundation, walls)
* elastomer sealants (rubber, neoprene, s ilicone, etc.) in air/gas (EFT control volumeseals)2.4.4.2  Staff Evaluation The staff reviewed LRA Section 2.4.4 and the USAR using the evaluation methodologydescribed in SER Section 2.4. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.4.In conducting its review, the staff evaluated the structural component functions described in theLRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had not omitted from the scope of license renewal any components with intendedfunctions delineated under 10 CFR 54.4(a). The staff then reviewed those components that theapplicant had identified as being within the scope of license renewal to verify that the applicanthad not omitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.4.4 identified an area for which it needed additionalinformation to complete its evaluation of the applicant's scoping and screening results. The applicant responded to the staff's RAI as discussed below.In RAI 2.4.4-1, dated September 28, 2005, the staff noted that Table 2.4.4-1 lists two identicalcomponent groups, "concrete in atmosphere/weather (walls, slab)," with identical intended functions; therefore, the staff requested that the applicant explain the need to list the samecomponent group twice.In its response, by letter dated October 28, 2005, the applicant stated the following:
2-116Due to page format/spacing limitations, Table 3.5.2-4 was unable to include allthe component information on the same page, and therefore it became necessary to repeat the component group, intended functions, etc. on the following page. Table 2.4.4-1 could have omitted this duplication but a decisionwas made not to interfere with the process used to assemble the 2.4.x-1 Table.Based on its review, the staff found the applicant's response to RAI 2.4.4-1 acceptable.Although repetitious, the duplicate component groups have no effect on scoping or screening.
Therefore, the staff's concern described in RAI 2.4.4-1 is resolved2.4.4.3  Conclusion The staff reviewed the LRA and related structural components to determine whether theapplicant had failed to identify any SSCs that should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequatelyidentified the EFT building components that are within the scope of license renewal, as requiredby 10 CFR 54.4(a), and the EFT building components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.4.5  Fire Protection Barriers Commodity Group 2.4.5.1  Summary of Technical Information in the ApplicationIn LRA Section 2.4.5, the applicant described the FP barriers commodity group. The FP barrierscommodity group includes fire stop sealants, fireproofing, and metallics such as aluminum andcarbon steel credited in the FP evaluation report. Fire stop sealants, fireproofing, and meta llicscan be used as FP barriers to stop the spread of fire to adjacent fire areas and can also be used to encapsulate structural steel or other metallic and nonmetallic components locatedwithin a fire area to protect them from the effects of a fire. Fire stop sealants, fireproofing, metallics, and combinations thereof provide a fire resistance equivalent to the rating of the primary fire barrier to prevent the spread of fire to adjacent areas. Fire stop sealants, fireproofing, and metallics are used to close openings in ceilings, floors, and walls. Theseopenings may be for penetrating electrical (e.g., cables, cable trays, conduits) or mechanical (e.g., pipes, instrument lines, ventilation ducts) components. Cable tray FP barriers are a type of barrier that prevents the propagation of fire along the length of the cables. Ventilation ductfire barrier housings, located between adjacent fire areas, are an integral part of the FP barrier and therefore are included with the FP barriers. Fire doors, curbs, dikes, concrete, and masonry block walls are evaluated as part of the structure where they are located. Fire and alarm (e.g.,
smoke detectors), and fire suppression (e.g., automatic sprinklers, automatic halon systems)are evaluated in the FIR system. The diesel-driven fire pump is evaluated in both the FIR and the ESW systems.The FP barriers commodity group performs functions that support FP.
The intended function, within the scope of license renewal, is to provide a rated fire barrier.
2-117In LRA Table 2.4.5-1, the applicant identified the following FP barriers commodity groupcomponent types that are within the scope of license renewal and subject to an AMR:
* aluminum in air/gas (cable tray cover)
* carbon steel, low-alloy steel in air/gas (access tunnel FP guard pipe, fire damperhousings)
* nonmetallic fireproofing in air/gas (cementitious fireproofing for coating structural steeland miscellaneous components)
* nonmetallic fireproofing in air/gas (fibrous fire wraps, cementitious fireproofing (i.e.,pyrocrete, etc.))
* nonmetallic fire proofing in air/gas (fibrous fire wraps, cementitious fireproofing (i.e.,pyrocrete, etc.), rigid board (i.e., gypsum board, etc.))
* nonmetallic fire stop sealants in air/gas (fire stop sealants for EDG building)
* nonmetallic fire stop sealants in air/gas (fire stop sealants for intake structure)
* nonmetallic fire stop sealants in air/gas (fire stop sealants for reactor building, EFTbuilding, plant control, and cable spreading structure)
* nonmetallic fire stop sealants in air/gas (fire stop sealants for turbine building)2.4.5.2  Staff Evaluation The staff reviewed LRA Section 2.4.5 and the USAR using the evaluation methodologydescribed in SER Section 2.4. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.4.In conducting its review, the staff evaluated the structural component functions described in theLRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had not omitted from the scope of license renewal any components with intendedfunctions delineated under 10 CFR 54.4(a). The staff then reviewed those components that theapplicant had identified as being within the scope of license renewal to verify that the applicanthad not omitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.4.5 identified an area for which it needed additionalinformation to complete its evaluation of the applicant's scoping and screening results. The applicant responded to the staff's RAI as discussed below.In RAI 2.4.5-1, dated September 28, 2005, the staff noted that Table 2.4.5-1 lists three identicalcomponent groups, "Non-metallic fire proofing in air/gas (...cementitious fireproofing, ...)," withidentical intended functions; therefore, the staff requested that the applicant explain the need tolist the same component group three times.In its response, by letter dated October 28, 2005, the applicant stated the following:To explain the difference between component groups, first an explanation of howTable 2.4.x-1 was assembled is needed. Tables in Section 2.4 of the LRA were 2-118assembled by copying the component group and intended functions for each3.5.2-x Table line entry into the 2.4.x-1 Table. This format was consistently usedthroughout the LRA. Many line entry component group descriptions appear similar but there are subtle differences that are evident upon review of the 3.5.2-x Table AMP, aging effects/mechanisms, material, etc.Table 2.4.5-1 component groups, 'non-metallic fire proofing in air/gas(cementitious fireproofing for coating structural steel and miscellaneous components),' 'non-metallic fire proofing in air/gas (fibrous fire wraps,cementitious fireproofing (i.e., pyrocrete, etc.)),' and 'non-metallic fire proofing inair/gas (fibrous fire wraps, cementitious fireproofing (i.e., pyrocrete, etc.), rigid board (i.e., gypsum board, etc.))' have different component group descriptions.
Review of Table 3.5.2-5 reveals that component groups were evaluated for agingeffects/mechanisms that were not applicable to all component groups.Based on its review, the staff found the applicant's response to RAI 2.4.5-1 acceptable. Theapplicant explained that (1) the component groups and intended functions in Section 2.4 tableswere copied from tables in Section 3.5 and (2) the aging effects/mechanisms listed in Table 3.5.2-5 were not applicable to all three components groups; therefore, the staff's concerndescribed 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 theapplicant had failed to identify any SSCs that should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequatelyidentified the FP barriers commodity group components that are within the scope of licenserenewal, as required by 10 CFR 54.4(a), and the FP barriers commodity group components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.4.6  Hangers and Supports Commodity Group 2.4.6.1  Summary of Technical Information in the ApplicationIn LRA Section 2.4.6, the applicant described the hangers and supports commodity group. Thehangers and supports commodity group contains component and equipment supports, pipe restraints, junction boxes, control panels, electrical raceways, and electrical conduit associated with plant systems and equipment that are within the scope of license renewal or are locatedwithin structures containing SR components. This commodity group includes the grout under the baseplate and fasteners used with the support or equipment anchorage. Generally,supports provide the connection betw een a system's equipment or component and a plantstructural member (e.g., wall, floor, ceiling, column, beam). They provide support for distributed loads (e.g., piping, tubing, HVAC ducting, conduit, cable trays) and localized loads (e.g.,
individual equipment). Specific types of equipment and components evaluated as part of this commodity group include: (1) pipe supports/restraints-includes all items used to support and/or restrain piping, (2) equipment supports-includes structural steel, fasteners (e.g., bolts, 2-119studs, nuts), and vibration mounts that secure equipment to structures, (3) HVAC ductsupports-includes structural steel and fasteners (e.g., bolts, studs, nuts) that support/attach ventilation duct to structures, (4) raceways-generic component type that is designed specifically for holding electrical wires and cables (e.g., cable trays, exposed and concealed metallic conduit or wireways), and (5) electrical enclosures-generic component type thatcontains electrical components (e.g., conduit, panels, boxes, cabinets, consoles, and bus ducts).The hangers and supports commodity group contains SR components that are relied upon toremain functional during and following DBEs. The failure of NSR SSCs in the hangers and supports commodity group could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the hangers and supports commodity group performs functions that support FP, ATWS, and SBO.The intended functions within the scope of license renewal include the following:
* provide structural support to NSR components (civil and structural)
* provide structural support to SR components (civil and structural)In LRA Table 2.4.6-1, the applicant identified the following hangers and supports commoditygroup component types that are within the scope of license renewal and subject to an AMR:
* aluminum in air/gas (electrical junction boxes)
* carbon steel, low-alloy steel in air/gas (anchorages of lighting fixtures and junctionboxes inside torus, includes support members, welds, bolted connections)
* carbon steel, low-alloy steel in air/gas (anchorages of racks, panels, cabinets, andenclosures for electrical equipment and instrumentation; includes lighting fixtures, junction boxes, racks, panels, and cabinets outside torus, includes support members,welds, bolted connections, and support anchorage)
* carbon steel, low-alloy steel in air/gas (cable trays, conduit, tube track outside torus)
* carbon steel, low-alloy steel in air/gas (conduit, located inside torus)
* carbon steel, low-alloy steel in air/gas (lighting fixtures and junction boxes inside torus)
* carbon steel, low-alloy steel in air/gas (racks, panels, cabinets, lighting fixtures, junctionboxes outside torus)
* carbon steel, low-alloy steel in air/gas (supports for American Society of MechanicalEngineers (ASME) Class 1 piping and components including RPV stabilizers (i.e.,constant and variable spring hangers, guides, stops, etc.))
* carbon steel, low-alloy steel in air/gas (supports for ASME Class 1 piping andcomponents including RPV stabilizers, includes support members, welds, boltedconnections, and support anchorage)
* carbon steel, low-alloy steel in air/gas (supports for ASME Class 2 and 3 piping andcomponents (i.e., constant and variable spring hangers, guides, stops, etc.))
2-120
* carbon steel, low-alloy steel in air/gas (supports for ASME Class 2 and 3 piping andcomponents, includes support members, welds, bolted connections, and support anchorage)
* carbon steel, low-alloy steel in air/gas (supports for ASME Class MC components,includes torus seismic restraints, drywell male and female stabilizers, shield stabilizers,torus columns, torus saddles, vent system supports, downcomer bracing, includessupport members, welds, bolted connections and anchorages)
* carbon steel, low-alloy steel in air/gas (supports for cable trays, conduit, HVAC ducts,tube track, instrument tubing, and non-ASME piping outside torus, includes support members, welds, bolted connections, and support anchorage)
* carbon steel, low-alloy steel in air/gas (supports for mechanical equipment such as theEDG, HVAC components, pumps, fans, motors, turbines, etc., includes the splash hoods for the ESW pumps and the gas bottle racks, includes support members, welds,bolted connections, and support anchorage)
* carbon steel, low-alloy steel in air/gas (supports for non-ASME piping, conduit, andcomponents located inside the torus, includes support members, welds, bolted connections)
* carbon steel, low-alloy steel in atmosphere/weather (conduit for miscellaneous SBOyard structures, etc.)
* carbon steel, low-alloy steel in atmosphere/weather (supports for conduit formiscellaneous SBO yard structures, etc., includes support members, welds, bolted connections, and support anchorage)
* carbon steel, low-alloy steel in atmosphere/weather (supports for EFT tornado dampersand other miscellaneous mechanical equipment, includes support members, welds, bolted connections, and anchorage)
* carbon steel, low-alloy steel in atmosphere/weather (supports for non-ASME piping,includes support members, welds, bolted connections, and support anchorage)
* carbon steel, low-alloy steel in below grade (conduit for miscellaneous SBO yardstructures, etc.)
* carbon steel, low-alloy steel in below grade (diesel fuel oil storage tank flood tie-downs)
* carbon steel, low-alloy steel embedded in concrete (drywell support skirt anchorage,RPV female stabilizers)
* carbon steel, low-alloy steel embedded in concrete (embedded conduit)
* carbon steel, low-alloy steel in treated water (supports for ASME Class MC components(i.e., vent system supports, downcomer bracing) includes support members, welds)
* carbon steel, low-alloy steel in treated water (supports for non-ASME piping andcomponents (i.e., HPC, RCI sparger supports, SRV T-quencher support, ECCS suction strainer supports, etc.) includes support members, welds, bolted connections)
* concrete in air/gas (anchorage of racks, panels, cabinets, enclosures for electricalequipment and instrumentation, building concrete, grout pads) 2-121
* concrete in air/gas (supports for ASME Class 1 piping and components, buildingconcrete, and grout pads)
* concrete in air/gas (supports for ASME Class 2 and 3 piping and components, buildingconcrete, grout pads)
* concrete in air/gas (supports for ASME Class MC components, building concrete, groutpads)
* concrete in air/gas (supports for cable trays, conduit, HVAC ducts, tube track,instrument tubing, non-ASME piping and components, building concrete, grout pads)
* concrete in air/gas (supports for EDG, HVAC system com ponents, and othermiscellaneous mechanical equipment, building concrete, grout pads)
* concrete in atmosphere/weather (supports for conduit for miscellaneous SBO yardstructures, etc.; building concrete, grout pads)
* concrete in atmosphere/weather (supports for EFT tornado dampers and othermiscellaneous mechanical equipment, building concrete, grout pads)
* concrete in atmosphere/weather (supports for non-ASME piping and components,building concrete, grout pads)
* concrete in below grade (diesel fuel oil storage tank deadmen)
* elastomer sealants (rubber, neoprene, s ilicone, etc.) in air/gas (vibration isolationelements for ASME Class 1 piping and components)
* elastomer sealants (rubber, neoprene, s ilicone, etc.) in air/gas (vibration isolationelements for ASME Class 2 and 3 piping and components)
* elastomer sealants (rubber, neoprene, s ilicone, etc.) in air/gas (vibration isolationelements for ASME Class MC components)
* elastomer sealants (rubber, neoprene, s ilicone, etc.) in air/gas (vibration isolationelements for EDG, HVAC system components, and other miscellaneous mechanicalequipment)
* fiberglass in air/gas (electrical junction boxes)
* lubrite in air/gas (sliding surfaces for ASME Class 1 piping and components)
* lubrite in air/gas (sliding surfaces for ASME Class 2 and 3 piping and components)
* lubrite in air/gas (sliding surfaces for torus saddles)
* plastic in air/gas (electrical junction boxes)
* stainless steel in air/gas (supports for ASME Class 1 piping and components includingRPV stabilizers, clamps etc.)
* stainless steel in air/gas (supports for ASME Class 2 and 3 piping and components,clamps, etc.)
* stainless steel in air/gas (supports for ASME Class MC components (i.e., vent headercolumn support pins))
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* stainless steel in air/gas (supports for tube track, instrument tubing, non-ASME pipingand components; clamps, etc.)
* stainless steel in treated water (supports for ASME Class MC components (i.e., ventheader column support pins))2.4.6.2  Staff Evaluation The staff reviewed LRA Section 2.4.6 and the USAR using the evaluation methodologydescribed in SER Section 2.4. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.4.In conducting its review, the staff evaluated the structural component functions described in theLRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had not omitted from the scope of license renewal any components with intendedfunctions delineated under 10 CFR 54.4(a). The staff then reviewed those components that theapplicant had identified as being within the scope of license renewal to verify that the applicanthad not omitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.4.6 identified areas for which it needed additionalinformation to complete its evaluation of the applicant's scoping and screening results. The applicant responded to the staff's RAIs as discussed below.In RAI 2.4.6-1, dated September 28, 2005, the staff noted that after the "System FunctionListing," the applicant referred to Sections 12.2.1.2 and 12.2.1.3 of the USAR for additionalhangers and supports commodity group details. The staff's review of the USAR sections indicates that the SSCs are classified as Class I and Class II with definitions noticeably different from Criteria 1, 2, and 3 in 10 CFR 54.4(a); therefore, the staff requested that the applicantclarify how it reconciled the CLB classification in the system function listing in LRASection 2.4.6.In its response, dated October 28, 2005, the applicant stated that LRA Section 2.1.4.2 and theadditional comment clarify how the CLB classification of SSCs was reconciled. LRA Section 2.1.4.2 states the following:Numerous sources, including the MNGP USAR, docketed correspondence withthe NRC, Maintenance Rule documents, and DBDs provi ded system andstructure-level function information. Documentation of references used in this process was included for eac h system function as appropriate.The process used at the MNGP identified all system-level and structure-levelfunctions. If the functions met any of the criteria specified in 10 CFR Part 54.4(a)(1), (2), or (3), t hen the system or structure was in-scope forLR...The applicant further stated that even though USAR Class I and II designations are significantlydifferent from 10 CFR 54.4 designations, SSCs were still within the scope of license renewal, inaccordance with the criteria in 10 CFR 54.4(a).
2-123Based on its review, the staff found the applicant's response to RAI 2.4.6-1 acceptable. Withthe applicant's clarification, the staff recognized the methods used to reconcile SR SSCs andfound the applicant's method of compliance with the requirements of 10 CFR 50.54 acceptable;therefore, the staff's concern described in RAI 2.4.6-1 is resolved.In RAI 2.4.6-2, dated September 28, 2005, the staff noted that Table 2.4.6-1 line item "carbonsteel, low-alloy steel in air/gas," identifies a number of supports/anchorages as ASME Class MC supports and some are identified as non-ASME support components; therefore, the staff requested that the applicant clarify the classification of component supports inside and outsidethe torus (some may be non-ASME) and specifically, the classification of the support system forthe torus. The staff assumed that the torus support system is classified as Class MC supportsand that all its components are inspected by the requirements of ASME Section XI, Subsection IWF. After reviewing LRA Table 3.5.2-6, it was not obvious how the applicant had treated these supports; therefore, the staff requested that the applicant provide clarifications.In its response, by letter dated October 28, 2005, the applicant stated that the torus supportsinclude torus columns, torus saddles, and torus seismic restraints and pointed out that LRA Table 3.5.2-6, page 3-675, indicates that these supports located on the outside of the torus areclassified as ASME Class MC and will be managed by the ASME Section XI, Subsection IWFProgram. For the remaining torus system support components, the applicant provided anabridged list extracted from Table 3.5.2-6 which provided classifications and locations of these supports.Based on its review, the staff found the applicant's response to RAI 2.4.6-2 acceptable. Theresponse asserted the staff's assumption that all torus supports on the outside of the torus are classified as Class MC supports and are inspected in accordance with the requirements of Section XI, Subsection IWF, of the ASME code. The applicant also clarified that  either the Primary Containment In-Service Inspection Program (i.e., ASME Code Section XI, Subsection IWE) or ASME Code Section XI, Subsection NF provides aging management of the remaining supports. The staff considered the applicant's approach logical and acceptable; therefore, the staff's concern described in RAI 2.6.4-2 is resolved.In RAI 2.4.6-3, dated September 28, 2005, the staff noted that Table 2.4.6-1 lists "Carbon steel,low-alloy steel in atmosphere/weather (bolted connections and anchorage)" as a component group and "Carbon steel, low-alloy steel in atmosphere/weather (bolted connections and support anchorage)" as another. The only difference between the two component groups is that one group lists "anchorage" and the other "support anchorage." Therefore, the staff requested that the applicant explain the difference between "anchorage" and "support anchorage" andprovide examples of each.In its response, by letter dated October 28, 2005, the applicant explained that the line entry inLRA Table 2.4.6-1 containing the word "anchorage" also could have included the word "support" before "anchorage" in the description to be consistent with similar entries. The word, "anchorage" alone, however, is sufficient to convey the intent. The applicant further explained that "anchorage" and "support anchorage" refer to components used to secure (i.e., anchor) the support to the concrete surface and include concrete anchors of various types and associated components like nuts and washers.
2-124Based on its review, the staff found the applicant's response to RAI 2.4.6-3 acceptable becausethe applicant adequately explained that the two terms are defined the same and their intendedfunctions are the same. Therefore, the staff's concern described in RAI 2.4.6-3 is resolved.2.4.6.3  Conclusion The staff reviewed the LRA and related structural components to determine whether theapplicant had failed to identify any SSCs that should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequatelyidentified the hangers and supports commodity group components that are within the scope oflicense renewal, as required by 10 CFR 54.4(a), and the hangers and supports commodity group components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.4.7  HPCI Building 2.4.7.1  Summary of Technical Information in the ApplicationIn LRA Section 2.4.7, the applicant described the HPCI building. The principal functions of theHPCI building are to enclose the HPCI turbine and pumps and protect the equipment from weather, tornado, and seismic effects. The building is a Class 1 structure and is part of the secondary containment of the reactor building. The HPCI building is a reinforced concrete structure constructed monolithically with the reactor building. The structure is supported by a reinforced concrete mat which is an extension of the reactor building mat.The HPCI building contains SR components that are relied upon to remain functional duringand following DBEs. The failure of NSR SSCs in the HPCI building could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the HPCI building performs functions that support SBO.The intended functions within the scope of license renewal include the following:
* provide flood protection barrier
* provide missile barrier
* provide structural support to NSR components (civil and structural)
* provide pressure boundary of essentially leaktight barrier (civil and structural)
* provide shielding against radiation
* provide structural support to SR components (civil and structural)
* provide shelter/protection to SR componentsIn LRA Table 2.4.7-1, the applicant identified the following HPCI building component types thatare within the scope of license renewal and subject to an AMR:
* aluminum in air/gas (platforms)
* carbon steel, low-alloy steel in air/gas (structural steel, steel embeds, etc.)
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* carbon steel, low-alloy steel in air/gas (supports for miscellaneous structures (i.e.,members, welds, bolted connections, support anchorage for platforms, stairs, etc.))
* carbon steel, low-alloy steel in atmosphere/weather (roof hatch)
* carbon steel, low-alloy steel in below grade (piping penetration seal plates)
* concrete in air/gas (foundation, walls, slab)
* concrete in air/gas (foundation, walls, slab, grout)
* concrete in atmosphere/weather (slab, roof hatch)
* concrete in below grade (foundation, walls)
* elastomer sealants (rubber, neoprene, s ilicone, etc.) in air/gas (roof hatch seals)
* elastomer sealants (rubber, neoprene, s ilicone, etc.) in atmosphere/weather (roof hatchseals)2.4.7.2  Staff Evaluation The staff reviewed LRA Section 2.4.7 and the USAR using the evaluation methodologydescribed in SER Section 2.4. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.4.In conducting its review, the staff evaluated the structural component functions described in theLRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had not omitted from the scope of license renewal any components with intendedfunctions delineated under 10 CFR 54.4(a). The staff then reviewed those components that theapplicant had identified as being within the scope of license renewal to verify that the applicanthad not omitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.4.7.3  Conclusion The staff reviewed the LRA and related structural components to determine whether theapplicant failed to identify any SSCs that should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequatelyidentified the HPCI building components that are within the scope of license renewal, asrequired by 10 CFR 54.4(a), and the HPCI building components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.4.8  Intake Structure 2.4.8.1  Summary of Technical Information in the ApplicationIn LRA Section 2.4.8, the applicant described the intake structure. The intake structure isbasically a chambered box of reinforced concrete construction. Essentially, the intake structure consists of four 13-foot 8-inch bays with an invert at the intake end which converges to a two-2-126section suction chamber at the discharge end. A CWT pump is mounted over each suctionchamber. The roof of the structure is approximately 4 feet 3 inches above grade and consists of reinforced concrete beam and slab framing. The intake structure contains an operating floor on which the EDG-ESW, ESW, and RHR service water subsystem pumps are mounted. Exteriorand interior walls and slabs are constructed of reinforced concrete and provide support for the operating floor and roof framing. The structure is supported on a mat foundation 3 feet 6 inches in thickness that was placed on a lean concrete fill which overlays a layer of cementedsandstone. The intake structure also includes the access tunnel between the turbine building and the intake structure, as well as the diesel fire pump house which sits on top of the intake structure at the east end. The diesel fire pump house contains the diesel fire pump and the diesel fire pump day tank. The diesel fire pump house is constructed of concrete masonry block walls with an insulated steel deck roof supported by structural steel beams.The intake structure contains SR components that are relied upon to remain functional duringand following DBEs. The failure of NSR SSCs in the intake structure could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal.
In addition, the intake structure performs functions that support FP.The intended functions within the scope of license renewal include the following:
* provide source of cooling water for plant shutdown
* provide rated fire barrier
* provide flood protection barrier
* provide missile barrier
* provide structural support to NSR components (civil and structural)
* provide structural support to SR components (civil and structural)
* provide shelter/protection to SR componentsIn LRA Table 2.4.8-1, the applicant identified the following intake structure component typesthat are within the scope of license renewal and subject to an AMR:
* carbon steel, low-alloy steel in air/gas (doors, structural steel, steel embeds, etc.)
* carbon steel, low-alloy steel in air/gas (supports for miscellaneous structures (i.e.,members, welds, bolted connections, support anchorage for platforms, stairs, etc.))
* carbon steel, low-alloy steel in atmosphere/weather (structural steel, sheet piles,ventilation assemblies)
* carbon steel, low-alloy steel in below grade (sheet piles)
* carbon steel, low-alloy steel in raw water (structural steel, sheet piles)
* carbon steel, low-alloy steel in raw water (supports for miscellaneous structures (i.e.,members, welds, bolted connections, support anchorage for platforms, stairs, etc.))
* concrete in air/gas (foundation, walls, slabs)
* concrete in air/gas (foundation, walls, slabs, grout)
* concrete in air/gas (walls, slabs)
* concrete in atmosphere/weather (intake structure and access tunnel roof slabs) 2-127
* concrete in atmosphere/weather (walls, slabs)
* concrete in below grade (foundation, walls, lean concrete)
* concrete in raw water (foundation, walls, slabs)
* masonry walls in air/gas
* masonry walls in atmosphere/weather2.4.8.2  Staff Evaluation The staff reviewed LRA Section 2.4.8 and the USAR using the evaluation methodologydescribed in SER Section 2.4. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.4.In conducting its review, the staff evaluated the structural component functions described in theLRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had not omitted from the scope of license renewal any components with intendedfunctions delineated under 10 CFR 54.4(a). The staff then reviewed those components that theapplicant had identified as being within the scope of license renewal to verify that the applicanthad not omitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.4.8.3  Conclusion The staff reviewed the LRA and related structural components to determine whether theapplicant had failed to identify any SSCs that should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequatelyidentified the intake structure components that are within the scope of license renewal, asrequired by 10 CFR 54.4(a), and the intake structure components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.4.9  Miscellaneous SBO Yard Structures 2.4.9.1  Summary of Technical Information in the ApplicationIn LRA Section 2.4.9, the applicant described the miscellaneous SBO yard structures. Themiscellaneous SBO yard structures are those yard structures that provide support for equipment relied upon for recovery from an SBO. These structures are listed below:
* the foundations and transformer structures for 1R, 2R, 1AR, and 2RS transformers
* the 345-kV control house
* the towers/foundation for the 1N2, 1N6, 5N5, 5N7, 8N4, and 8N11 breakers
* the towers/foundations for the bus bars between the 2RS transformer and the 8N4 and8N11 breakers, this includes the tower/foundation for the 3N4 breaker, 3N5 fused 2-128disconnect, the current limiting protector, and the towers/foundations to the 1ARSmotor-operated disconnect
* the towers/foundations for the bus bars for the 5N5 and 5N7 breakers, including thewest four rows of columns and the beams that connect them together.
* the Trenwa trenches connecting the control house to the 115-kV ring bus
* the Trenwa trenches connecting the control house to the 345-kV ring bus
* the electrical duct bank from the 1N2 breaker to the 1AR transformer
* the tower/foundation for the bus 1, 115-kV potential transformer
* the three 115- kV transmission towers along the west owner-controlled area fencebetween the switchyard and the 1R transformer and the first transmission tower northwest of the plant
* the block walls surrounding the 1R and 2R transformersThe miscellaneous SBO yard structures perform functions that support SBO.
The intended function, within the scope of license renewal, is to provide structural support toNSR components (civil and structural).In LRA Table 2.4.9-1, the applicant identified the following miscellaneous SBO yard structurescomponent types that are within the scope of license renewal and subject to an AMR:
* carbon steel, low-alloy steel in air/gas (345-kV house structural steel)
* carbon steel, low-alloy steel in air/gas (supports for 345-kV house miscellaneous steel(i.e., members, welds, bolted connections, support anchorage))
* carbon steel, low-alloy steel in atmosphere/weather (anchorages)
* carbon steel, low-alloy steel in atmosphere/weather (structural steel for 345-kV house,switchyard, and transmission towers, etc.)
* concrete in air/gas (345-kV house concrete)
* concrete in atmosphere/weather (345-kV house concrete, foundations)
* concrete in atmosphere/weather (345-kV house, foundations, trenches, duct bank,grout)
* concrete in below grade (345-kV house, foundations, trenches, duct bank)
* masonry walls in atmosphere/weather2.4.9.2  Staff Evaluation The staff reviewed LRA Section 2.4.9 and the USAR using the evaluation methodologydescribed in SER Section 2.4. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.4.
2-129In conducting its review, the staff evaluated the structural component functions described in theLRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had not omitted from the scope of license renewal any components with intendedfunctions delineated under 10 CFR 54.4(a). The staff then reviewed those components that theapplicant had identified as being within the scope of license renewal to verify that the applicanthad not omitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.4.9.3  Conclusion The staff reviewed the LRA and related structural components to determine whether theapplicant had failed to identify any SSCs that should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequatelyidentified the miscellaneous SBO yard structures components that are within the scope oflicense renewal, as required by 10 CFR 54.4(a), and the miscellaneous SBO yard structures components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.4.10  Offgas Stack 2.4.10.1  Summary of Technical Information in the ApplicationIn LRA Section 2.4.10, the applicant described the offgas stack. The function of the offgasstack is to provide for controlled release and dispersal of gaseous radioactive wastes. The stack is a free-standing, tapered, reinforced concrete structure which encloses and supports an independent gas flue. The overall height of the stack above adjacent grade is 328 feet. The internal diameter of the concrete shell is 7 feet at the top and 32 feet at the 946-foot 6-inchelevation, with thickness varying from 7 inches at the top to 10 inches at the 946-foot 6-inchelevation. Below the 946-foot 6-inch elevation to the top of the foundation at the 932-foot 6-inchelevation, the stack shell is a polygon having a maximum inscribed diameter of 34 feet. The wall thickness varies in accordance with radiation shielding requirements. The stack shell is supported on a 4-foot-thick octagonal spread footing with a 1-foot 6-inch pedestal. The independent gas flue is 18 inches in diameter reducing to 14 inches in diameter at the top.The offgas stack contains SR components that are relied upon to remain functional during andfollowing DBEs. The failure of NSR SSCs in the offgas stack could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal.The intended functions within the scope of license renewal include the following:
* provide flood protection barrier
* provide path for release of filtered and unfiltered gaseous discharge
* provide structural support to NSR components (civil and structural)
* provide shielding against radiation
* provide structural support to SR components (civil and structural)
* provide shelter/protection to SR components 2-130In LRA Table 2.4.10-1, the applicant identified the following offgas stack component types thatare within the scope of license renewal and subject to an AMR:
* carbon steel, low-alloy steel in air/gas (structural steel, steel embeds, etc.)
* carbon steel, low-alloy steel in air/gas (supports for miscellaneous structures (i.e.,members, welds, bolted connections, support anchorage for platforms, stairs, etc.))
* carbon steel, low-alloy steel in atmosphere/weather (doors)
* concrete in air/gas (pedestal, walls, slabs)
* concrete in air/gas (pedestal, walls, slabs, grout)
* concrete in atmosphere/weather (pedestal, walls)
* concrete in below grade (pedestal)
* masonry walls in air/gas
* stainless steel in air/gas (cap)
* stainless steel in atmosphere/weather (cap)2.4.10.2  Staff Evaluation The staff reviewed LRA Section 2.4.10 and the USAR using the evaluation methodologydescribed in SER Section 2.4. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.4.In conducting its review, the staff evaluated the structural component functions described in theLRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had not omitted from the scope of license renewal any components with intendedfunctions delineated under 10 CFR 54.4(a). The staff then reviewed those components that theapplicant had identified as being within the scope of license renewal to verify that the applicanthad not omitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.4.10.3  Conclusion The staff reviewed the LRA and related structural components to determine whether theapplicant had failed to identify any SSCs that should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequatelyidentified the offgas stack components that are within the scope of license renewal, as requiredby 10 CFR 54.4(a), and the offgas stack components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2-1312.4.11  Offgas Storage and Compressor Building2.4.11.1  Summary of Technical Information in the ApplicationIn LRA Section 2.4.11, the applicant described the offgas storage and compressor building. Theoffgas storage building, except for the fan and foyer room portions, was designed for Class 1 seismic conditions and flood conditions, as well as for tornado wind loads and missiles. The only portion of the offgas stor age system which currently has seismic design requirements arethe storage tanks and the attached piping up to the first isolation valve. The building meets allFederal, State, and local codes applicable to industrial process buildings. The building is constructed of reinforced concrete on a suitable foundation and is situated near the base of the offgas stack. The fan and foyer room portions of the offgas storage building provide Class 1-level protection for all external events in which the enclosed equipment is required to perform an SR function. This includes Class 1 dead, live (snow and floor), and wind loads. It does not include seismic or tornado loads or tornado-generated missiles.The offgas storage and compressor building contains SR components that are relied upon toremain functional during and following DBEs. The failure of NSR SSCs in the offgas storage and compressor building could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal.The intended functions within the scope of license renewal include the following:
* provide structural support to NSR components (civil and structural)
* provide structural support to SR components (civil and structural)In LRA Table 2.4.11-1, the applicant identified the following offgas storage and compressorbuilding component types that are within the scope of license renewal and subject to an AMR:
* carbon steel, low-alloy steel in air/gas (structural steel)
* concrete in air/gas (foundation, walls, slabs)
* concrete in air/gas (foundation, walls, slabs, grout)
* concrete in atmosphere/weather (walls, slabs)
* concrete in below grade (foundation, walls)2.4.11.2  Staff Evaluation The staff reviewed LRA Section 2.4.11 and the USAR using the evaluation methodologydescribed in SER Section 2.4. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.4.In conducting its review, the staff evaluated the structural component functions described in theLRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had not omitted from the scope of license renewal any components with intendedfunctions delineated under 10 CFR 54.4(a). The staff then reviewed those components that theapplicant had identified as being within the scope of license renewal to verify that the applicanthad not omitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).
2-1322.4.11.3  ConclusionThe staff reviewed the LRA and related structural components to determine whether theapplicant had failed to identify any SSCs that should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequatelyidentified the offgas storage and compressor building components that are within the scope oflicense renewal, as required by 10 CFR 54.4(a), and the offgas storage and compressor building components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.4.12  Plant Control and Cable Spreading Structure 2.4.12.1  Summary of Technical Information in the ApplicationIn LRA Section 2.4.12, the applicant described the plant control and cable spreading structure.The primary functions of this structure are to provide, under all operating or postulated accident conditions, safe enclosure for those portions of the standby electrical power systems and I&Csystems vital to overall plant operation and safety which are located therein, as well as anenvironment satisfactory for continuous occupancy by operating personnel. The plant control and cable spreading structure is located at the north end of the original office and control building and includes the MCR, cable spreading room, and battery room. The administration building is located adjacent to the east side of the original office and control building. The original office and control building, as well as the administration building, constitute the plant control and cable spreading structure. The administration building provides a records storage area to meet the requirements of American National Standards Institute (ANSI) N45.2.9,training space, lockers and restroom facilities, an instrument shop, library space, a meetingroom, shift supervisor's office, open office space, and private offices. Modifications to the shift supervisor's office have been made so that the office is part of the MCR for the purpose of meeting the NRC's requirement for the presence of a senior licensed operator in the controlroom at all times. The shift supervisor's office is located immediately adjacent to the MCR, but outside the previously defined control room boundary.The plant control and cable spreading structure contains SR components that are relied upon toremain functional during and following DBEs. The failure of NSR SSCs in the plant control and cable spreading structure could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the plant control and cable spreading structure performs functions that support FP, ATWS, and SBO.The intended functions within the scope of license renewal include the following:
* provide rated fire barrier
* provide flood protection barrier
* provide missile barrier
* provide structural support to NSR components (civil and structural)
* provide structural support to SR components (civil and structural)
* provide shelter/protection to SR components 2-133In LRA Table 2.4.12-1, the applicant identified the following plant control and cable spreadingstructure component types that are within the scope of license renewal and subject to an AMR:
* carbon steel, low-alloy steel in air/gas (fire-rated doors)
* carbon steel, low-alloy steel in air/gas (structural steel, steel embeds, etc.)
* carbon steel, low-alloy steel in air/gas (supports for miscellaneous structures (i.e.,members, welds, bolted connections, support anchorage for platforms, stairs, etc.))
* concrete in air/gas (foundation, walls, slabs)
* concrete in air/gas (foundation, walls, slabs, grout)
* concrete in air/gas (walls, slabs)
* concrete in atmosphere/weather (walls, slabs)
* concrete in below grade (foundation, walls)
* elastomer sealants (rubber, neoprene, s ilicone, etc.) in air/gas (control room seals)
* masonry walls in air/gas2.4.12.2  Staff Evaluation The staff reviewed LRA Section 2.4.12 and the USAR using the evaluation methodologydescribed in SER Section 2.4. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.4.In conducting its review, the staff evaluated the structural component functions described in theLRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had not omitted from the scope of license renewal any components with intendedfunctions delineated under 10 CFR 54.4(a). The staff then reviewed those components that theapplicant had identified as being within the scope of license renewal to verify that the applicanthad not omitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.4.12.3  Conclusion The staff reviewed the LRA and related structural components to determine whether theapplicant had failed to identify any SSCs that should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant had adequatelyidentified the plant control and cable spreading structure components that are within the scopeof license renewal, as required by 10 CFR 54.4(a), and the plant control and cable spreading structure components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2-1342.4.13  Primary Containment2.4.13.1  Summary of Technical Information in the ApplicationIn LRA Section 2.4.13, the applicant described the primary containment (PCT) system. ThePCT system includes the drywell, the wetwell (torus), the primary containment penetrations, thebioshield wall, the RPV support pedestal, the drywell/torus internal platforms, and the torus external catwalk. The mechanical portion of the primary containment system is included in thePCM system. The PCT system provides a barrier to the release of fission products to the SCTand rapidly reduces the pressure in primary containment after a  LOCA. The  system consistsof a light-bulb-shaped drywell, a torus-shaped wetwell, and a connecti ng vent system betweenthe drywell and the wetwell. The system encloses the reactor vessel, the reactor coolantrecirculation loops, and various branch connections of the reactor primary system. The drywellis a steel pressure vessel with a spherical lower portion and a cylindrical upper portion. The personnel airlock provides an entrance to the drywell measuring 6 feet by 2.5 feet. The wetwell is a steel pressure vessel in the shape of a torus located below and encircling the drywell.
Penetrations through the drywell and wetwell walls provide for passage of fluid piping and electrical cables. These penetrations are designed to withstand environmental conditions present during a LOCA and to maintain primary containment integrity for extended periods oftime in a post-accident environment. Piping penetrations consist of pipe segments welded into structurally enhanced containment shell plates. Piping penetrations are of two general types-sleeved, those for which the process flow is not in contact with the original penetrationpipe segments, and unsleeved, those for which the process flow is in contact with the originalpenetration pipe segments.The PCT system contains SR components that are relied upon to remain functional during andfollowing DBEs. The failure of NSR SSCs in the PCT system could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the PCT system performs functions that support FP, ATWS, and SBO.The intended functions within the scope of license renewal include the following:
* provide source of cooling water for plant shutdown
* provide flood protection barrier
* provide heat sink during DBAs
* provide shielding against HELBs
* provide missile barrier
* provide structural support to NSR components (civil and structural)
* provide pressure boundary of essentially leaktight barrier (civil and structural)
* provide shielding against radiation
* provide structural support to SR components (civil and structural)
* provide pipe whip restraintIn LRA Table 2.4.13-1, the applicant identified the following PCT system com ponent types thatare within the scope of license renewal and subject to an AMR:
* carbon steel, low-alloy steel in air/gas (drywell penetration sleeves, drywell penetrationbellows assemblies, drywell penetrations, torus penetrations) 2-135
* carbon steel, low-alloy steel in air/gas (drywell, torus, drywell head, drywell head bolts,torus ring girder, downcomers, vent lines, vent header, bellows assemblies, vent header deflectors, ECCS suction header)
* carbon steel, low-alloy steel in air/gas (personnel airlock, equipment hatch, CRD hatch,seismic restraint, inspection ports)
* carbon steel, low-alloy steel in air/gas (personnel airlock, equipment hatch, CRD hatch,seismic restraint, inspection ports, including locks, hinges, and closure mechanisms)
* carbon steel, low-alloy steel in air/gas (structural steel (i.e., torus external catwalk,drywell interior platforms, bioshield wall liners, etc.))
* carbon steel, low-alloy steel in air/gas (structural steel inside torus (i.e., torus internalcatwalk, etc.))
* carbon steel, low-alloy steel in air/gas (supports for miscellaneous structures, includingplatforms, stairs, and whip restraints, etc.  (i.e., members, welds, bolted connections, support anchorage to building structure))
* carbon steel, low-alloy steel embedded in concrete (drywell support skirt, embeddedshell)
* carbon steel, low-alloy steel in treated water (structural steel)
* carbon steel, low-alloy steel in treated water (support members, welds, boltedconnections (i.e., torus internal catwalk support columns))
* carbon steel, low-alloy steel in treated water (torus penetrations)
* carbon steel, low-alloy steel in treated water (torus, torus ring girder, downcomers,ECCS suction header)
* carbon steel, low-alloy steel, stainless steel in air/gas (drywell penetration sleeves,drywell penetrations)
* concrete in air/gas (bioshield wall, drywell equipment foundation, RPV pedestal)
* elastomer sealants (rubber, neoprene, s ilicone, etc.) in air/gas (moisture barriers)
* elastomer sealants (rubber, neoprene, s ilicone, etc.) in air/gas (seals and gaskets)
* inconel in air/gas (drywell penetration X-16B bellows)
* lubrite in air/gas (drywell head, downcomers)
* lubrite in air/gas (drywell interior platform sliding plates)
* lubrite in treated water (downcomers)
* stainless steel in air/gas (drywell penetration sleeves, drywell penetration bellows)
* stainless steel in air/gas (RPV to drywell refueling seal)
* stainless steel in air/gas (vent line bellows)
* stainless steel in treated water (thermowells) 2-1362.4.13.2  Staff EvaluationThe staff reviewed LRA Section 2.4.13 and the USAR using the evaluation methodologydescribed in SER Section 2.4. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.4.In conducting its review, the staff evaluated the structural component functions described in theLRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had not omitted from the scope of license renewal any components with intendedfunctions delineated under 10 CFR 54.4(a). The staff then reviewed those components that theapplicant had identified as being within the scope of license renewal to verify that the applicanthad not omitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.4.13 identified areas for which it needed additionalinformation to complete its evaluation of the applicant's scoping and screening results. The applicant responded to the staff's RAIs as discussed below.In RAI 2.4.13-1, dated September 28, 2005, the staff requested that the applicant clarifywhether the supports and components included in Code PCT-04 of the system function listingare within the scope of license renewal. The staff requested that the applicant provide asummary listing of these supports and components and a confirmation that their failure under earthquake-induced loads would not affect the functioning of SR SSCs.In its response, by letter dated October 28, 2005, the applicant explained the following:System function Primary Containment (PCT)-04 referred only to non-safetyrelated components that could not affect safety related SSCs. Components associated with this function are not in scope of license renewal. The function for non-safety related components that could affect safety related components is Primary Containment-Non-Safety Affecting Safety (PCT-NSAS), evaluated on page 2-225 of the LRA. Functions associated with component supports are further addressed in Section 2.4.6, 'Hangers and Supports Commodity Group.'
The PCT-04 function was evaluated against the criteria of 10 CFR 54.4(a) and found not to meet any of its requirements. Consequently, the function was provided for information and completeness only, since it did not form a basis for including the primary containment structure within the scope of the Rule. This scoping methodology was consistently used through Section 2 of the LRA.Based on its review, the staff found the applicant's response to RAI 2.4.13-1 acceptable. Theclarification asserts that the components included in the PCT-04 group are not SR and wouldnot affect the integrity of SR SSCs under postulated seismic events; therefore, the staff'sconcern described in RAI 2.4.13-1 is resolved.In RAI 2.4.13-2, dated September 28, 2005, the staff noted that the second and thirdcomponent groups in Table 2.4.13-1 list almost identical components (drywell, torus, drywell head, drywell head bolts, torus ring girder, downcomers, vent lines, vent header, bellows assembly, ECCS suction header) with the same material-environment combination (carbon steel/low-alloy steel in air/gas) and intended functions. A similar redundancy was noted on the 2-137first two component groups on page 2-257 (personnel airlock, equipment hatch, CRD hatch,seismic restraint, and inspection ports). Therefore, the staff requested that the applicant clarifythese redundancies.In its response, by letter dated October 28, 2005, the applicant stated the following:To explain the apparent redundancies between components, first an explanationof how Table 2.4.13-1 was assembled is needed to explain the apparent redundancies between components. Tables in Section 2.4 of the LRA were assembled by copying the component group and intended functions for each 3.5.2-x Table line entry into the 2.4.x-1 Table. This format was consistently usedthroughout the LRA. Many line entry component group descriptions appear similar but there are subtle differences that are evident upon review of the 3.5.2-x Table AMP, aging effects/mechanisms, material, etc.For this specific question, Table 2.4.13-1 component groups, 'carbon steel, lowalloy steel in air/gas (drywell, torus, drywell head, drywell head bolts, torus ring girder, downcomers, vent lines, vent header, bellows assemblies, ECCS suction header)' and 'carbon steel, low alloy steel in air/gas (drywell, torus, drywell head, drywell head bolts, torus ring girder, downcomers, vent lines, vent header, bellows assemblies, vent header deflectors, ECCS suction header)' have different component group descriptions (one component group includes vent header deflectors and the other does not). Review of Table 3.5.2-13 reveals thatthe component group without vent header deflectors is managed by 10 CFR 50, Appendix J while the group with vent header deflectors is managed by the Primary Containment In-Service Inspection Program. This is because the vent header deflectors do not perform a pressure retaining function associated with an Appendix J test.For part two of this question, Table 2.4.13-1 component groups, 'carbon steel,low alloy steel in air/gas (personnel airlock, equipment hatch, [Control Rod Drive]
CRD hatch, seismic restraint inspection ports)' and 'carbon steel, low alloy steelin air/gas (personnel airlock, equipment hatch, CRD hatch, seismic restraintinspection ports, including locks, hinges and closure mechanisms)' have differentcomponent group descriptions. Review of Table 3.5.2-13 reveals that the component group with locks, hinges, and closure mechanisms is managed for adifferent aging effect, 'loss of leak tightness in closed position' in accordance with NUREG-1801 line item II.B4.2-b.Based on its review, the staff found the applicant's response to RAI 2.4.13-2 acceptable. Thepurpose of scoping is to ensure that all SSCs that are within the scope of license renewal pursuant to 10 CFR 54.4 first be identified clearly and then, while performing an AMR, the applicant identifies the relevant material and environment. In this application, the applicant usedthe reverse method; however, the explanation ensures that the applicant has not missed anyimportant SSCs from the scope of license renewal. After reviewing the applicant's approach, the staff understood the reason for the redundancies and found the approach acceptable; therefore, the staff's concern described in RAI 2.4.13-2 is resolved.
2-138In RAI 2.4.13-3, dated September 28, 2005, the staff also noted that Table 2.4.13-1 lists thecomponent group, "lubrite in air/gas," with the drywell head included as a component. In the description of drywell head, the applicant stated, "The head is held in place by bolts and sealed with a double gasket arrangement." Therefore, the staff requested that the applicant clarifywhere the lubrite bearings are used in the drywell head.In its response, by letter dated October 28, 2005, the applicant provided the followinginformation:Lubrite type material is not used for the drywell head or downcomers.Table 2.4.13-1, page 2-260 included this component group, 'lubrite in air/gas (drywell head and downcomers)' because tables in Section 2.4 of the LRA were assembled by copying the component group and intended functions for each Table 3.5.2-13 line entry into Table 2.4.13-1. Table 3.5.2-13 included this entryto demonstrate that NUREG-1801 line item II.B1.1.1-e was evaluated forapplicability. The evaluation provided in Table 3.5.2-13 stated that, 'The drywellhead and downcomer pipes are carbon steel material. Graphite plate material is not used for these components and therefore the aging effect is not applicable'(see LRA note 556). Therefore the description of the drywell head in the LRA, page 2-251 is consistent with note 556 in Table 3.5.2-13.Based on its review, the staff found the applicant's response to RAI 2.4.13-3 acceptable. Thestaff found that the applicant's approach covers all the components subject to AMR; therefore,the staff's concern described in RAI 2.4.13-3 is resolved.2.4.13.3  Conclusion The staff reviewed the LRA and related structural components to determine whether theapplicant had failed to identify any SSCs that should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequatelyidentified the PCT system components that are within the scope of license renewal, as requiredby 10 CFR 54.4(a), and the PCT system components that are subject to an AMR, as requiredby 10 CFR 54.21(a)(1).2.4.14  Radioactive Waste Building 2.4.14.1  Summary of Technical Information in the ApplicationIn LRA Section 2.4.14, the applicant described the radioactive waste building. The radioactivewaste building is located adjacent to the south side of the reactor building. The building is usedfor storage of contaminated materials, such as spent ion exchange resins, filters, anti-C clothing, and contaminated materials. The railroad car airlock and the airlock between thereactor building and the radioactive waste building are part of secondary containment. The radioactive waste building is a reinforced concrete structure supported on a concrete slab. The radioactive waste building was designed such that it would not fail during an earthquake. It is also designed to protect the reactor building from external floods.
2-139The radioactive waste building contains SR components that are relied upon to remainfunctional during and following DBEs. The failure of NSR SSCs in the radioactive waste building could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal.The intended functions within the scope of license renewal include the following:
* provide flood protection barrier
* provide shielding against HELBs
* provide structural support to NSR components (civil and structural)
* provide pressure boundary of essentially leaktight barrier (civil and structural)
* provide shielding against radiation
* provide structural support to SR components (civil and structural)
* provide shelter/protection to SR componentsIn LRA Table 2.4.14-1, the applicant identified the following radioactive waste buildingcomponent types that are within the scope of license renewal and subject to an AMR:
* carbon steel, low-alloy steel in air/gas (air lock and railroad doors)
* carbon steel, low-alloy steel in air/gas (structural steel)
* carbon steel, low-alloy steel in atmosphere/weather (railroad door)
* concrete in air/gas (foundation, walls, slabs)
* concrete in air/gas (foundation, walls, slabs, grout)
* concrete in atmosphere/weather (walls, slabs)
* concrete in below grade (foundation, walls)
* elastomer sealants (rubber, neoprene, s ilicone, etc.) in air/gas (secondary containmentseals)
* elastomer sealants (rubber, neoprene, s ilicone, etc.) in atmosphere/weather (secondarycontainment seals)
* glass in air/gas (railroad bay door view port)
* glass in atmosphere/weather (railroad bay door view port)
* masonry walls in air/gas
* roofing in atmosphere/weather (railroad bay built-up roofing)2.4.14.2  Staff Evaluation The staff reviewed LRA Section 2.4.14 and the USAR using the evaluation methodologydescribed in SER Section 2.4. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.4.In conducting its review, the staff evaluated the structural component functions described in theLRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had not omitted from the scope of license renewal any components with intended 2-140functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that theapplicant had identified as being within the scope of license renewal to verify that the applicanthad not omitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.4.14.3  Conclusion The staff reviewed the LRA and related structural components to determine whether theapplicant had failed to identify any SSCs that should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequatelyidentified the radioactive waste building components that are within the scope of licenserenewal, as required by 10 CFR 54.4(a), and the radioactive waste building components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.4.15  Reactor Building 2.4.15.1  Summary of Technical Information in the ApplicationIn LRA Section 2.4.15, the applicant described the reactor building. The principal functions ofthe reactor building are to support and protect enclo sed systems and components and toprovide secondary containment limiting the offsite radiological consequences of accidents. The building provides necessary space for the equipment in a planned arrangement and provides for layout space for the equipment to be removed and replaced if necessary. Reactor internals and fuel can be moved and conveniently stored within the building. The reactor building serves as the secondary containment. The secondary containment, in conjunction with other engineered safeguards and nuclear safety systems, limits the release of radioactive materialsfrom a postulated DBA. The reactor building also provides secondary containment when the primary containment is in service and provides primary containment during reactor refueling and maintenance operations when the primary containment system is open. A majorsubstructure within the reactor building is a reinforced concrete biological shield that surrounds the reactor and drywell portion of the primary containment.The reactor building contains SR components that are relied upon to remain functional duringand following DBEs. The failure of NSR SSCs in the reactor building could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal.
In addition, the reactor building performs functions that support FP, ATWS, and SBO.The intended functions within the scope of license renewal include the following:
* provide shielding against neutron radiation
* provide rated fire barrier
* provide flood protection barrier
* provide shielding against HELBs
* provide missile barrier
* provide structural support to NSR components (civil and structural)
* provide pressure boundary of essentially leaktight barrier (civil and structural) 2-141
* provide shielding against radiation
* provide structural support to SR components (civil and structural)
* provide shelter/protection to SR components
* provide pipe whip restraintIn LRA Table 2.4.15-1, the applicant identified the following reactor building component typesthat are within the scope of license renewal and subject to an AMR:
* aluminum in air/gas (new fuel storage racks)
* aluminum in air/gas (siding)
* aluminum in atmosphere/weather (siding, ventilation assemblies)
* aluminum in treated water (spent fuel storage racks)
* boral in treated water (spent fuel storage racks neutron-absorbing sheets)
* carbon steel, low-alloy steel in air/gas (drywell to reactor building refueling seal plates)
* carbon steel, low-alloy steel in air/gas (fire-rated doors)
* carbon steel, low-alloy steel in air/gas (fire-rated, HELB, and secondary containmentdoors)
* carbon steel, low-alloy steel in air/gas (structural steel, steel embeds, blowout panels,etc.)
* carbon steel, low-alloy steel in air/gas (supports for miscellaneous structures (i.e.,members, welds, bolted connections, support anchorage for platforms, stairs, whip restraints, masonry wall supports, etc.))
* carbon steel, low-alloy steel in atmosphere/weather (structural steel, ventilationassemblies)
* carbon steel, low-alloy steel in treated water (drywell to reactor building refueling sealplates)
* concrete in air/gas (foundation, walls, slabs)
* concrete in air/gas (foundation, walls, slabs, grout)
* concrete in air/gas (walls, slabs)
* concrete in atmosphere/weather (walls, slabs)
* concrete in below grade (foundation, walls)
* elastomer sealants (rubber, neoprene, s ilicone, etc.) in air/gas (secondary containmentseals, spent fuel pool gate seals, and hatch seals)
* elastomer sealants (rubber, neoprene, s ilicone, etc.) in atmosphere/weather (secondarycontainment seals)
* elastomer sealants (rubber, neoprene, s ilicone, etc.) in treated water (spent fuel poolgate seals)
* glass in air/gas (railroad door view port) 2-142
* masonry walls in air/gas
* nonmetallic fireproofing in air/gas (gypsum board walls)
* roofing in atmosphere/weather
* stainless steel in air/gas (metal siding screws, upper portion of spent fuel pool,dryer/separator storage pool, reactor well liners, and drywell to reactor building refueling seal bellows)
* stainless steel in atmosphere/weather (metal siding screws)
* stainless steel in treated water (dryer/separator storage pool and reactor well liners)
* stainless steel in treated water (drywell to reactor building refueling seal bellows)
* stainless steel in treated water (spent fuel pool, dryer/separator storage pool, andreactor well liners)
* stainless steel in treated water (spent fuel pool liner)
* stainless steel in treated water (spent fuel storage racks)2.4.15.2  Staff Evaluation The staff reviewed LRA Section 2.4.15 and the USAR using the evaluation methodologydescribed in SER Section 2.4. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.4.In conducting its review, the staff evaluated the structural component functions described in theLRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had not omitted from the scope of license renewal any components with intendedfunctions delineated under 10 CFR 54.4(a). The staff then reviewed those components that theapplicant had identified as being within the scope of license renewal to verify that the applicanthad not omitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.4.15.3  Conclusion The staff reviewed the LRA and related structural components to determine whether theapplicant had failed to identify any SSCs that should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequatelyidentified the reactor building components that are within the scope of license renewal, asrequired by 10 CFR 54.4(a), and the reactor building components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2-1432.4.16  Structures Affecting Safety2.4.16.1  Summary of Technical Information in the ApplicationIn LRA Section 2.4.16, the applicant described the structures affecting safety system. Thestructures affecting safety system pertains to plant structures that perform no safety function or regulated event function (except for the heating boiler building), but could, under certain failurescenarios, adversely affect buildings or equipment having such functions. These structures are listed below:
* The heating boiler building is located along the east side of the turbine building. Theheating boiler building is a structural steel frame building with insulated metal siding and a steel deck roof. The structural steel columns sit on a reinforced concrete footing. The foundation walls are also of reinforced concrete. The floor consists of a reinforced concrete slab on grade.
* The non-1E electrical equipment room is located just east of the turbine building. Thestructure contains transformers and switchgear for NSR portions of the 480-VAC power system. In addition, the NSR No. 17 250-VDC battery is located in the non-1E electricalequipment room.
* The hot machine shop is located along side the turbine building at the east end of thenorth wall. The hot machine shop is a structural steel frame building with insulated metal siding with a steel deck roof. The structural steel columns sit on a reinforced concrete footing. The foundation walls are also of reinforced concrete. The floor consists of a reinforced concrete slab on grade.
* The turbine building addition is a Class 2 structure and does not contain any Class 1equipment. The structure was designed in accordance with the uniform building code.
The primary function of the turbine building addition is to provide a controlled environment for the condenser retubing effort.
* The recombiner building is a reinforced concrete structure utilizing heavy shear walls asa lateral force-resisting system resting on a mat foundation. The building consists of twoequipment bays, a shielded tunnel which houses the interconnecting piping, an instrument room, and a pump room. There is also an enclosed walkway and access areas constructed of structural steel with insulated metal siding and insulated builtup roofing.
* A radwaste storage building is provided for the solid radwaste truck-loading area. Thissheet metal building is provided with shield walls, floor drains, heating, and FP systems.An overhead crane is located in the building. The building is designed to enclose the radwaste shipping truck and to facilitate loading of the truck.The failure of NSR SSCs in the structures affecting safety system could potentially prevent thesatisfactory accomplishment of an SR function of SSCs within the scope of license renewal.
The structures affecting safety system also performs functions that support FP.The intended functions within the scope of license renewal include the following:
* provide rated fire barrier 2-144
* provide structural support to NSR components (civil and structural)In LRA Table 2.4.16-1, the applicant identified the following structures affecting safety systemcomponent types that are within the scope of license renewal and subject to an AMR:
* carbon steel, low-alloy steel in air/gas (fire-rated doors)
* carbon steel, low-alloy steel in air/gas (structural steel)
* concrete in air/gas (foundations, walls, slabs)
* concrete in air/gas (foundations, walls, slabs, grout)
* concrete in atmosphere/weather (foundations, walls, slabs)
* concrete in below grade (foundations, walls)2.4.16.2  Staff Evaluation The staff reviewed LRA Section 2.4.16 and the USAR using the evaluation methodologydescribed in SER Section 2.4. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.4.In conducting its review, the staff evaluated the structural component functions described in theLRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had not omitted from the scope of license renewal any components with intendedfunctions delineated under 10 CFR 54.4(a). The staff then reviewed those components that theapplicant had identified as being within the scope of license renewal to verify that the applicanthad not omitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.4.16.3  Conclusion The staff reviewed the LRA and related structural components to determine whether theapplicant had failed to identify any SSCs that should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequatelyidentified the structures affecting safety system components that are within the scope of licenserenewal, as required by 10 CFR 54.4(a), and the structures affecting safety system componentsthat are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.4.17  Turbine Building 2.4.17.1  Summary of Technical Information in the ApplicationIn LRA Section 2.4.17, the applicant described the turbine building (TGB). The TGB is aClass 2 structure; however, the portions that support and protect electrical controls and instrumentation for Class 1 equipment were designed in accordance with the criteria for the design of portions of Class 2 structures enclosing and/or supporting Class 1 equipment. The primary function of the TGB is to provide the necessary environment required for safe operation and maintenance of the turbine generator and other components of the power conversionsystem. The TGB is a combination of reinforced concrete and structural steel construction. The 2-145foundation is a reinforced concrete mat of variable thickness supported on undisturbed soil. Thefoundation supports the reinforced concrete turbine generator pedestal, as well as the building superstructure. The reinforced concrete portion of the superstructure extends from the top of the mat foundation to the turbine deck. Structural steel beam and girded framing support the reinforced concrete floor slabs. Interior reinforced concrete walls extending from the top of the mat up to the operating floor are oriented to protect personnel against radiation emanating fromthe turbine and auxiliary systems. A structural steel-framed superstructure is based at theturbine deck on reinforced concrete columns located within the exterior walls. The superstructure encloses the operating floor and also provides support and closure for a traveling bridge crane. A 5-ply tar and felt insulated roof is supported by a metal roof deck which also acts as a diaphragm to transmit lateral forces to vertically braced end walls or shear frames.The TGB contains SR components that are relied upon to remain functional during andfollowing DBEs. The failure of NSR SSCs in the TGB could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the TGB performs functions that support FP, ATWS, and SBO.The intended functions within the scope of license renewal include the following:
* provide rated fire barrier
* provide flood protection barrier
* provide shielding against HELBs
* provide missile barrier
* provide structural support to NSR components (civil and structural)
* provide shielding against radiation
* provide structural support to SR components (civil and structural)
* provide shelter/protection to SR components
* provide pipe whip restraintIn LRA Table 2.4.17-1, the applicant identified the following TGB component types that arewithin the scope of license renewal and subject to an AMR:
* carbon steel, low-alloy steel in air/gas (fire-rated doors)
* carbon steel, low-alloy steel in air/gas (structural steel, steel embeds, doors, etc.)
* carbon steel, low-alloy steel in air/gas (supports for miscellaneous structures (i.e.,members, welds, bolted connections, support anchorage for platforms, stairs, whip restraints, masonry wall supports, etc.))
* carbon steel, low-alloy steel in atmosphere/weather (doors)
* concrete in air/gas (foundation, walls, slabs)
* concrete in air/gas (foundation, walls, slabs, grout)
* concrete in air/gas (walls, slabs)
* concrete in atmosphere/weather (walls near recombiner building)
* concrete in atmosphere/weather (walls, slabs) 2-146
* concrete in below grade (foundation, walls)
* masonry walls in air/gas
* nonmetallic fireproofing in air/gas (cementitious fireproofing, pyrocrete walls)
* nonmetallic fireproofing in air/gas (gypsum board walls)2.4.17.2  Staff Evaluation The staff reviewed LRA Section 2.4.17 and the USAR using the evaluation methodologydescribed in SER Section 2.4. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.4.In conducting its review, the staff evaluated the structural component functions described in theLRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had not omitted from the scope of license renewal any components with intendedfunctions delineated under 10 CFR 54.4(a). The staff then reviewed those components that theapplicant had identified as being within the scope of license renewal to verify that the applicanthad not omitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.4.17 identified an area for which it needed additionalinformation to complete its evaluation of the applicant's scoping and screening results. The applicant responded to the staff's RAI as discussed below.In RAI 2.4.17-1, dated September 28, 2005, the staff noted that Table 2.4.17-1 lists "Carbonsteel, low-alloy steel in air/gas (fire rated doors)" as a component group with the intended function being fire barrier, and "Carbon steel, low-alloy steel in air/gas (...doors,...)" as another component group with one of the intended functions also being fire barrier. Therefore, the staff requested that the applicant explain the difference between the doors listed in the twocomponent groups.In its response, by letter dated October 28, 2005, the applicant provided the following response:Table 2.4.17-1 component group, 'carbon steel, low alloy steel in air/gas (firerated doors)' refers to doors that provide a fire barrier intended function and are managed for aging by the Fire Protection Program. Table 2.4.17-1 component group, 'carbon steel, low alloy steel in air/gas (structural steel, steel embeds, doors, etc.)' refers to those doors that were assigned a fire barrier function as discussed above, but also perform at least one other intended function such as high energy line break (HELB) barrier and/or flood barrier. Consequently doors with a fire barrier intended function that also perform additional functions are managed by the Structures Monitoring Program in addition to the Fire Protection Program in accordance with NUREG-1801.Based on its review, the staff found the applicant's response to RAI 2.4.17-1 acceptable,because the applicant adequately explained that the doors have different intended functions.Therefore, the staff's concern described in RAI 2.4.17-1 is resolved.
2-1472.4.17.3  ConclusionThe staff reviewed the LRA and related structural components to determine whether theapplicant had failed to identify any SSCs that should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequatelyidentified the TGB components that are within the scope of license renewal, as required by10 CFR 54.4(a), and the TGB components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.4.18  Underground Duct Bank 2.4.18.1  Summary of Technical Information in the ApplicationIn LRA Section 2.4.18, the applicant described the underground duct bank. The undergroundduct bank runs between the third floor of the EFT building and the reactor building. The primary function of the duct bank is to carry Division 2 safe-shutdown cables outside of areas where fire damage could occur. The duct bank includes risers at each end with an underground section in between. The underground portion of the duct bank is 700 feet in length and is rectangular in cross section. It is constructed of reinforced concrete and contains sixteen 4-inch diameter raceways. Access to the duct bank is provided by four reinforced concrete manholes. Seismic joints occur at the manhole to duct bank interface and the riser to duct bank interface.The underground duct bank contains SR components that are relied upon to remain functionalduring and following DBEs. In addition, the underground duct bank performs functions that support FP and SBO.The intended functions within the scope of license renewal include the following:
* provide flood protection barrier
* provide structural support to NSR components (civil and structural)
* provide structural support to SR components (civil and structural)
* provide shelter/protection to SR componentsIn LRA Table 2.4.18-1, the applicant identified the following underground duct bank componenttypes that are within the scope of license renewal and subject to an AMR:
* carbon steel, low-alloy steel in air/gas (structural steel, steel embeds, etc.)
* carbon steel, low-alloy steel in air/gas (supports for miscellaneous structures (i.e.,members, welds, bolted connections, support anchorage for platforms, stairs, etc.))
* carbon steel, low-alloy steel in atmosphere/weather (manhole covers/supports)
* carbon steel, low-alloy steel in below grade (manhole covers/supports)
* concrete in air/gas (foundation, walls, slabs)
* concrete in atmosphere/weather (walls, slabs) 2-148
* concrete in below grade (foundation, walls, slabs, grout)2.4.18.2  Staff Evaluation The staff reviewed LRA Section 2.4.18 and the USAR using the evaluation methodologydescribed in SER Section 2.4. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.4.In conducting its review, the staff evaluated the structural component functions described in theLRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had not omitted from the scope of license renewal any components with intendedfunctions delineated under 10 CFR 54.4(a). The staff then reviewed those components that theapplicant had identified as being within the scope of license renewal to verify that the applicanthad not omitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.4.18.3  Conclusion The staff reviewed the LRA and related structural components to determine whether theapplicant had failed to identify any SSCs that should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequatelyidentified the underground duct bank components that are within the scope of license renewal,as required by 10 CFR 54.4(a), and the underground duct bank components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.5  Scoping and Screening Results:  Electrical and Instrumentation and ControlsThis section documents the staff's review of the applicant's scoping and screening results forelectrical and I&C systems. Specifically, this section discusses the following:
* electrical and I&C systems
* electrical commoditiesIn accordance with the requirements of 10 CFR 54.21(a)(1), the applicant must identify and listpassive, long-lived SCs that are within the scope of license renewal and subject to an AMR. To verify that the applicant properly implemented its methodology, the staff focused its review onthe implementation results. This approach allowed the staff to confirm that there were noomissions of electrical and I&C system components that meet the scoping criteria and aresubject to an AMR.Staff Evaluation Methodology. The staff performed its evaluation of the information in the LRAin the same manner for all electrical and I&C systems. The objective of the review was todetermine whether the applicant had identified the components and supporting structures for aspecific electrical and I&C system, that appeared to meet the scoping criteria specified in theRule, as within the scope of license renewal, in accordance with 10 CFR 54.4. Similarly, the 2-149staff evaluated the applicant's screening results to verify that all long-lived, passive componentswere subject to an AMR, in accordance with 10 CFR 54.21(a)(1).Scoping. To perform its evaluation, the staff reviewed the applicable LRA section andassociated component drawings, focusing its review on components that had not been identified as within the scope of license renewal. The staff reviewed relevant licensing-basis documents, including the USAR, for each electrical and I&C system component to determinewhether the applicant had omitted components with intended functions delineated under10 CFR 54.4(a) from the scope of license renewal. The staff also reviewed the licensing-basis documents to determine whether the LRA specified all intended functions delineated under10 CFR 54.4(a). If omissions were identified, the staff requested additional information to resolve the discrepancies.Screening. Once the staff completed its review of the scoping results, the staff evaluated theapplicant's screening results. For those systems and components with intended functions, thestaff sought to determine (1) if the functions are performed with moving parts or a change in configuration or properties or (2) if they are subject to replacement based on a qualified life or specified time period, as described in 10 CFR 54.21(a)(1). For those electrical and I&C systemsand components that did not meet either of these criteria, the staff sought to confirm that theywere subject to an AMR, as required by 10 CFR 54.21(a)(1). If discrepancies were identified, the staff requested additional information to resolve them.2.5.1  Electrical and Instrumentation and Controls Systems In LRA Section 2.5.1, the applicant identified the SCs of the electrical and I&C systems that aresubject to an AMR for license renewal.The applicant described the supporting SCs of the electrical and I&C systems in the followingsections of the LRA:
* 2.5.1.1480-V station auxiliary system
* 2.5.1.24.16-kV station auxiliary
* 2.5.1.3alternate shutdown
* 2.5.1.4annunciators
* 2.5.1.5communications
* 2.5.1.6DC battery
* 2.5.1.7lighting
* 2.5.1.8neutron monitoring
* 2.5.1.9offsite power
* 2.5.1.10plant protection
* 2.5.1.11radiation monitoring
* 2.5.1.12reactor level control (RLC)
* 2.5.1.13uninterruptible ACSER Sections 2.5.1.1-2.5.1.13 present the staff's review findings regarding LRASections 2.5.1.1-2.5.1.13, respectively.
2-1502.5.1.1  480-V Station Auxiliary2.5.1.1.1  Summary of Technical Information in the Application In LRA Section 2.5.1.1, the applicant described the 480-V station auxiliary system. The 480-Vstation auxiliary system consists of transformers, breakers, load centers, and MCCs. Power istypically supplied to motors less than 250 horsepower (HP) and lighting transformers. The system receives power from the 4.16-kV station auxiliary system through load centertransformers. It distributes power through load center buses and MCCs.The 480-V station auxiliary system contains SR components that are relied upon to remainfunctional during and following DBEs. The failure of NSR SSCs in the 480-V station auxiliarysystem could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the 480-V station auxiliary system performsfunctions that support FP, ATWS, and SBO.The applicant identified the 480-V station auxiliary system SCs that are within the sc ope oflicense renewal. LRA Section 2.5.2 evaluates electrical commodities for this system that aresubject to AMR. LRA Section 2.4.6 evaluates supports for electrical components.2.5.1.1.2  Staff Evaluation The staff reviewed LRA Section 2.5.1.1 and the USAR using the evaluation methodologydescribed in SER Section 2.5. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.5.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.5.1.1 identified an area for which it needed additionalinformation to complete its evaluation of the applicant's results. The applicant responded to the staff's RAI as discussed below.In RAI 2.5.1-1, the staff noted that LRA Section 2.5.1.1, under the system function listing 480-V station auxiliary, states that MCCs 132, 133A, and 142A are credited with supporting anATWS event; however, license renewal drawing LR-36298, does not include MCC 132 as within the scope of license renewal; therefore, the staff requested that the applicant resolve thediscrepancy.In its response, by letter dated September 16, 2005, the applicant provided the followingresponse:MCC 132 Breaker B3230 supplies power to the tank heater for Standby LiquidControl (SLC) Tank T-200. The SLC System mitigates an ATWS event. The 2-151drawing is in error. Drawing LR-36298 will be revised to show MCC 132 as beingwithin the scope of License Renewal.Based on its review, the staff found the applicant's response to RAI 2.5.1-1 acceptable becausethe applicant will revise its boundary drawing to indicate MCC 132 as being within the scope oflicense renewal. Therefore, the staff's concern described in RAI 2.5.1-1 is resolved.During the scoping inspection, the inspectors identified discrepancies between the scoping andscreening report and license renewal drawing LR-36298. Specifically, the license renewal classification of breakers fed from several 480-V load centers was not consistent with the license renewal scoping and screening document. The applicant also identified several other load center cubicles which were not previously shown as being within the scope of license renewal, but which should have been included. The applicant determined that the additionalcomponents brought into scope of license renewal were all active components, and therefore, screened out and did not require aging management. On the basis of its review, the staff concluded that the breakers are active components, and therefore not subject to an AMR.2.5.1.1.3  Conclusion On the basis of its review, the staff concluded that the applicant adequately identified the 480-Vstation auxiliary system components that are within the scope of license renewal, as required by10 CFR 54.4(a), and the 480-V station auxiliary system components that are subject to anAMR, as required by 10 CFR 54.21(a)(1).2.5.1.2  4.16-kV Station Auxiliary 2.5.1.2.1  Summary of Technical Information in the Application In LRA Section 2.5.1.2, the applicant described the 4.16-kV station auxiliary system. All stationpower is supplied from the 4.16-kV station auxiliary system (4 kV) through distribution buses tovarious motors and stepdown transformers. The 4.16-kV system is a three-phase, groundedneutral distribution system. The system uses eight 4.16-kV bus sections, each housed in metalclad assemblies. Six buses, 11, 12, 13, 14, 15, and 16, are located in the turbine building.Buses 17 and 18 are located at the discharge structure to serve the cooling tower pumps. The plant's 4.16-kV buses may be supplied from either of two sources. The normal source is the 2R transformer supplied from the 345-kV substation. The alternate source is the 1R transformer supplied from the 115-kV substation. Protective relaying, if activated, deenergizes the 2Rtransformer and initiates an open circuit transfer to the 1R transformer. Air circuit breakers (ACBs) connect sources and loads to the buses. Two 125-V station batteries supply control power to control the opening and closing of the plant breakers in the 4.16-kV system.The 4.16-kV station auxiliary system contains SR components that are relied upon to remainfunctional during and following DBEs. In addition, the 4.16-kV station auxiliary system performsfunctions that support FP, ATWS, and SBO.The applicant identified the 4.16-kV station auxiliary system component types that are within thescope of license renewal. Section 2.5.2 evaluates electrical commodities for this system thatare subject to AMR. Section 2.4.6 evaluates supports for electrical components.
2-1522.5.1.2.2  Staff EvaluationThe staff reviewed LRA Section 2.5.1.2 and the USAR using the evaluation methodologydescribed in SER Section 2.5. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.5.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.5.1.2.3  Conclusion On the basis of its review, the staff concluded that the applicant adequately identified the 4.16-kV station auxiliary system components that are within the scope of license renewal, asrequired by 10 CFR 54.4(a), and the 4.16-kV station auxiliary system components that aresubject to an AMR, as required by 10 CFR 54.21(a)(1).2.5.1.3  Alternate Shutdown 2.5.1.3.1  Summary of Technical Information in the Application In LRA Section 2.5.1.3, the applicant described the ASD system, which is designed to providealternative shutdown capability, as required by 10 CFR 50.48 and Appendix R to 10 CFRPart 50. This system assures safe shutdown in the event of a fire in the control room, cable spreading room, or both. The ASD system performs the above by providing for a remotecentralized location at which existing plant systems can be manually controlled. T he syst emuses existing Division II systems and equipment. The ASD control panel is located on the thirdfloor of the emergency filtration building. This area is adjacent to the turbine building and the control room.The ASD system contains SR components that are relied upon to remain functional during andfollowing DBEs. In addition, the ASD system performs functions that support FP and SBO.The applicant identified the ASD system com ponent types that are within the scope of licenserenewal. Section 2.5.2 evaluates electrical commodities for this system that are subject to anAMR. Section 2.4.6 evaluates supports for electrical components.2.5.1.3.2  Staff Evaluation The staff reviewed LRA Section 2.5.1.3 and the USAR using the evaluation methodologydescribed in SER Section 2.5. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.5.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had 2-153not omitted from the scope of license renewal any components with intended functionsdelineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.5.1.3.3  Conclusion On the basis of its review, the staff concluded that the applicant adequately identified the ASDsystem components that are within the scope of license renewal, as required by10 CFR 54.4(a), and the ASD system components that are subject to an AMR, as required by10 CFR 54.21(a)(1).2.5.1.4  Annunciators 2.5.1.4.1  Summary of Technical Information in the Application In LRA Section 2.5.1.4, the applicant described the plant annunciators. The plant annunciatorsconsist of MCC panels and local panels for selected systems and associated plantinstrumentation. They alert operators to off-normal conditions for monitored variables.The failure of NSR SCs in the plant annunciators could potentially prevent the satisfactoryaccomplishment of an SR function of SSCs within the scope of license renewal. The plant annunciators also perform functions that support FP and SBO.The applicant identified the plant annunciators component types that are within the scope oflicense renewal. Section 2.5.2 evaluates electrical commodities for this system that are subjectto an AMR. Section 2.4.6 evaluates supports for electrical components.2.5.1.4.2  Staff Evaluation The staff reviewed LRA Section 2.5.1.4 and the USAR using the evaluation methodologydescribed in SER Section 2.5. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.5.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.5.1.4.3  Conclusion On the basis of its review, the staff concluded that the applicant adequately identified the plantannunciators components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the plant annunciators components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2-1542.5.1.5  Communications2.5.1.5.1  Summary of Technical Information in the Application In LRA Section 2.5.1.5, the applicant described the communications system. Thecommunications system consists of the following five subsystems-(1) telephone system, (2)site public address (PA) system, (3) sound-powered system, (4) intercom system, and (5) plantradio system. The plant telephone system is the most widely used method of communication atMNGP and is centered around an AT&T programmable solid-state private branch exchange (PBX) switch. There is also a set of telephones located in the control room, technical support center, and training center which are used solely to perform NRC notification. This system iscalled the FTS 2000 and uses dedicated circuits leased from commercial carriers to make direct connections to various branches/offices of the NRC. The design of this system providesindependence from the normal tel ephone system and guarantees availability of commercialcircuits in the event of heavy telephone use by the local community. The site PA system isdesigned to provide general plant paging capability and also provides a single-party linechannel between paging stations. The sound powered system is a series of hard-wiredtelephone jacks located at various places throughout the plant that can be used formaintenance and calibration activities. The intercom system is a multichannel system withpush-button channel selection at the master stations located in the control room and cablespreading room. The plant radio system is a Motorola repeater-based system with six separatechannels.The communications system performs functions that support FP.The applicant identified the communications system component types that are within the scopeof license renewal. Section 2.5.2 evaluates electrical commodities for this system that aresubject to an AMR. Section 2.4.6 evaluates supports for electrical components.2.5.1.5.2  Staff Evaluation The staff reviewed LRA Section 2.5.1.5 and the USAR using the evaluation methodologydescribed in SER Section 2.5. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.5.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.5.1.5.3  Conclusion On the basis of its review, the staff concluded that the applicant adequately identified thecommunications system components that are within the scope of license renewal, as requiredby 10 CFR 54.4(a), and the communications system components that are subject to an AMR,as required by 10 CFR 54.21(a)(1).
2-1552.5.1.6  DC Battery2.5.1.6.1  Summary of Technical Information in the Application In LRA Section 2.5.1.6, the applicant described the DC battery. Two independent divisions of24-VDC batteries are provided. They include two battery systems which feed separate DCbuses and two battery chargers per division fed from different AC feeders and distribution panels. These 24-VDC batteries provide power for the nuclear instrumentation, PRMs, and
 
H 2/O 2 analyzer isolation valve position indication. Two independent divisions of 125-VDCbatteries are provided. They include two battery systems which feed separate DC buses anddistribution panels. The 250-VDC system consists of essential and nonessential subsystems.The essential system consists of two independent divisions of 250-VDC batteries with centertaps for 125 VDC. The 250-VDC system supplies highly reliable power to large loads, such asmotor-driven pumps, valves, and uninterruptible power supplies (UPSs). The nonessential system consists of one division of 250-VDC batteries. It includes one battery system which ischarged by rectifiers in the UPS and distribution panels.The DC battery contains SR components that are relied upon to remain functional during andfollowing DBEs. In addition, the DC battery performs functions that support FP, ATWS, and SBO. This system contains equipment that is required to be qualified in accordance with10 CFR 50.49.The applicant identified the DC battery component types that are within the scope of licenserenewal. Section 2.5.2 evaluates electrical commodities for this system that are subject to anAMR. Section 2.4.6 evaluates supports for electrical components.2.5.1.6.2  Staff Evaluation The staff reviewed LRA Section 2.5.1.6 and the USAR using the evaluation methodologydescribed in SER Section 2.5. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.5.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.5.1.6 identified an area for which it needed additionalinformation to complete its evaluation of the applicant's results. The applicant responded to the staff's RAI as discussed below.In RAI 2.5.1-2, the staff noted that LRA Section 2.5.1.6, under the description of DC battery,states that the 24-VDC batteries provide power for the nuclear instrumentation, PRMs, and H 2/0 2 analyzer isolation valve position indication, this section further states, under the systemfunction listing, that the 24-VDC system continuously provides DC electrical power to the SRand NSR loads. However, the 24-VDC system is not considered SR bec ause the system is not 2-156required to provide the SR function of these loads; therefore, the staff requested that theapplicant indicate specific safety loads powered by the 24-VDC system and explain how theseloads would perform the SR function if the 24-VDC NSR power supply were to fail.In its response, by letter dated September 16, 2005, the applicant responded:The 24 VDC system provides power to the Source Range Monitors (SRMs) andthe Intermediate Range Monitors (IRMs) in the Neutron Monitoring System (NMS). With the mode switch in SHUTDOWN and RUN, SRMs andIRMs are not required to be operable. Per the Technical Specifications, the SRMs and IRMs are only required to be operable when the mode switch is in REFUEL and STARTUP. The 24 VDC system provides power to the SRMs andIRMs, but is not required for them to provide their Safety Related function.
Failure of 24 VDC power will initiate the safety functions (rod block and scram).The Division I 24 VDC system provides power for the output trip relaying (not theradiation monitors) for the Off-Gas Pretreatments monitors. In the event of a 24VDC failure for this relaying, offgas trip timers will conservatively trip the operating recombiner train after a 30-minute delay. Operability of the monitorsthemselves is not affected.The Division I 24 VDC system also provides power for the Flux-Tilt monitor. Thismonitor is classified as non-safety related and is not required for normal operation.The Division II 24 VDC system provides power for the Discharge Canal, ServiceWater, Radwaste Effluent, and Reactor Building Closed Cooling Water process liquid radiation monitors. These monitors are all classified as non-safety related.
In the event of loss of Division II 24 VDC, compensatory measures would be implemented for these radiation monitors in accordance with the applicable MNGP site procedures.Finally, each divisions of 24 VDC supplies power for the corresponding divisionof containment atmosphere monitori ng system isolation valve position indication.Control power for the valves is provided by other sources. The valve position indication function does not meet the criteria of 10 CFR 54.4(a)(I), (ii), or (iii) forbeing within the scope of license renewal.Based on its review, the staff found the applicant's response to RAI 2.5.1-2 acceptable becausethe applicant adequately described the safety loads power ed by the system and how thoseloads perform if the power supply were to fail. Therefore, the staff's concern described in RAI 2.5.1-2 is resolved.2.5.1.6.3  Conclusion On the basis of its review, the staff concluded that the applicant adequately identified the DCbattery components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the DC battery components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2-1572.5.1.7  Lighting2.5.1.7.1  Summary of Technical Information in the Application In LRA Section 2.5.1.7, the applicant described the lighting system. The lighting systemprovides light in all areas for safe, efficient operation of the plant. Normal lighting is supplied by normal AC power. Several locations in the plant are supplied by normal lighting which is supplied from an essential lighting source. Essential lighting is supplied by a normal AC source, or by the diesel generators, or by the 1AR transformer during a loss of the normal AC source.
The emergency lighting system is independent of the AC system. 8-hour, battery-poweredemergency lighting units are also located throughout the plant. These units have individual batteries that are continuously charged from normal AC power sources. In the event normal AC power is lost, these units will illuminate. Appendix R to 10 CFR Part 50 requires 8-hour lightingunits to be located in the MCR, at the ASD panel, along the pathway in between, in the 11diesel generator room, and in the warehouse/cold shop equipment bay.The lighting system contains SR components that are relied upon to remain functional duringand following DBEs. In addition, the lighting system performs functions that support FP and SBO.The applicant identified the lighting system component types that are within the scope of licenserenewal. Section 2.5.2 evaluates electrical commodities for this system that are subject to anAMR. Section 2.4.6 evaluates supports for electrical components.2.5.1.7.2  Staff Evaluation The staff reviewed LRA Section 2.5.1.7 and the USAR using the evaluation methodologydescribed in SER Section 2.5. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.5.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.5.1.7.3  Conclusion On the basis of its review, the staff concluded that the applicant adequately identified thelighting system components that are within the scope of license renewal, as required by10 CFR 54.4(a), and the lighting system components that are subject to an AMR, as requiredby 10 CFR 54.21(a)(1).
2-1582.5.1.8  Neutron Monitoring2.5.1.8.1  Summary of Technical Information in the Application In LRA Section 2.5.1.8, the applicant described neutron monitoring systems. The local powerrange monitor (LPRM) s ubsystem is designed to continuously monitor the neutron flux level inthe reactor while in the power range. The LPRM subsystem signals must be available to permitdemonstration of compliance with the critical power ratio limits. The individual LPRM output signals serve as input signals to the average power range monitors (APRMs) and rod block monitor (RBM). The APRM subsystem is designed to provide a continuous, accurate indicationof the average core power. The RBM is an operational aid designed to prevent violation of the fuel integrity safety criteria during withdrawal of a single control blade. The RBM also provides a local relative power signal for operator evaluation during control blade movement. The startup range monitors consist of 12 neutron flux monitoring channels. They include four SRMs and eight IRMs. The source range monitoring system is used to provide neutron flux informationfrom subcritical to an intermediate flux level. The intermediate range monitoring system is usedto provide neutron flux information from the upper limit of the source range monitors to the lower limit of the power range monitors.The neutron monitoring systems contain SR components that are relied upon to remainfunctional during and following DBEs.The applicant identified the neutron monitoring component types that are within the scope oflicense renewal. Section 2.5.2 evaluates the electrical commodities for this system that aresubject to an AMR. Section 2.4.6 evaluates the supports for electrical components.2.5.1.8.2  Staff Evaluation The staff reviewed LRA Section 2.5.1.8 and the USAR using the evaluation methodologydescribed in SER Section 2.5. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.5.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.5.1.8.3  Conclusion On the basis of its review, the staff concluded that the applicant adequately identified theneutron monitoring components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the neutron monitoring components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2-1592.5.1.9  Offsite Power2.5.1.9.1  Summary of Technical Information in the Application In LRA Section 2.5.1.9, the applicant described the offsite power system. The 115-kVsubstation contains buses, breakers, transformers, and associated equipment necessary to connect the MNGP 345-kV system to the Xcel Energy 115-kV transmission system. The 115-kVsubstation supplies power to the 1R and 1AR transformers. The 230-kV substation contains buses, breakers, transformers, and associated equipment. It connects the Xcel 345-kV transmission system to the Great River Energy 230-kV transmission system. The 230-kVsubstation system includes the No. 6 transformer. The 345-kV substation contains t he buses,breakers, and associated equipment necessary to connect the Xcel 345-kV transmission system to the 2RS and 1ARS transformers.The offsite power system performs functions that support SBO.The applicant identified the offsite power system com ponent types that are within the scope oflicense renewal. Section 2.5.2 evaluates electrical commodities for this system that are subjectto an AMR. Section 2.4.6 evaluates supports for electrical components.2.5.1.9.2  Staff Evaluation The staff reviewed LRA Section 2.5.1.9 and the USAR using the evaluation methodologydescribed in SER Section 2.5. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.5.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.5.1.9.3  Conclusion On the basis of its review, the staff concluded that the applicant adequately identified the offsitepower components that are within the scope of license renewal, as required by 10 CFR 54.4(a),
and the offsite power components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.5.1.10  Plant Protection 2.5.1.10.1  Summary of Technical Information in the Application In LRA Section 2.5.1.10, the applicant described the PPS. The PPS consists of the  reactorprotection system, the ATWS system, and the primary containment isolati on system (PCIS).The reactor protection system includes the motor-generator power supplies' associated controland indicating equipment, sensors, relays, bypass circuitry, and switches that cause rapid 2-160insertion of control rods (scram) to shutdown the reactor. The ATWS system consists of twoseparately powered trip systems, each made up of two subchannels. Each subchannel receivesan input from an independent sensor monitoring each of the ATWS trip parameters. A trip occurring in both subchannels will cause an ATWS trip which opens both recirculating motorgenerator set generator field breakers and causes control rod insertion by venting the scram air header. The PCIS provides protection against the onset and consequences of accidents involving the gross release of radioactive materials from the primary containment. This protection is the automatic isolation of appropriate pipelines which penetrate the primarycontainment whenever certain monitored variables exceed their preselected operational limit.The PPS contains SR components that are relied upon to remain functional during andfollowing DBEs. In addition, the PPS performs functions that support FP, ATWS, and SBO. This system contains components required to be qualified in accordance with 10 CFR 50.49.The applicant identified the PPS component types that are within the scope of license renewal.Section 2.5.2 evaluates electrical commodities for this system that are subject to an AMR.
Section 2.4.6 evaluates supports for electrical components.2.5.1.10.2  Staff Evaluation The staff reviewed LRA Section 2.5.1.10 and the USAR using the evaluation methodologydescribed in SER Section 2.5. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.5.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.5.1.10.3  Conclusion On the basis of its review, the staff concluded that the applicant adequately identified the PPScomponents that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the PPS components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.5.1.11  Radiation Monitoring 2.5.1.11.1  Summary of Technical Information in the Application In LRA Section 2.5.1.11, the applicant described the area radiation monitors (ARMs). There arenumerous ARMs located throughout the plant, recombiner building, and offgas storage building.
Each consists of a detector coupled to an indicator located either on control room panels C-11 or C-252D. The indicators for the containment high-range monitors are located on panels C-257 and C-258 in the control room. The PAS system indicators are on PAS system panel C-261.Two multipoint recorders, NR-18-55 and RR-7573, located on panel C-02 and panel C-252D, respectively, record the readings of all channels, except the high-range channel (RI-7774) from 2-161the offgas storage building, the drywell monitors, and the PAS system monitor. All of the ARMsuse Geiger-Mueller detectors, except for the containment high-range monitors which are ion chambers. These units are X-ray and gamma sensing devices. The PRM system consists ofseveral subsystems that provide continuous monitoring of the radiation levels of liquid andgaseous processes throughout the plant which can release activity directly to the environment.
These subsystems assist in controlling the release of radioactive byproducts within the legallyprescribed limits as set forth in the TSs. They also help provide for personnel safety by warning of abnormal radiation release levels and, in some cases, automatically terminating these releases.The ARMs contain SR components that are relied upon to remain functional during andfollowing DBEs. In addition, the ARMs contain components which are part of the Environmental Qualification Program.The applicant identified the ARMs component types that are within the scope of licenserenewal. Section 2.5.2 evaluates electrical commodities for this system that are subject to anAMR. Section 2.4.6 evaluates supports for electrical components.2.5.1.11.2  Staff Evaluation The staff reviewed LRA Section 2.5.1.11 and the USAR using the evaluation methodologydescribed in SER Section 2.5. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.5.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.5.1.11.3  Conclusion On the basis of its review, the staff concluded that the applicant adequately identified the ARMcomponents that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the ARM components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.5.1.12  Reactor Level Control 2.5.1.12.1  Summary of Technical Information in the Application In LRA Section 2.5.1.12, the applicant described the RLC system. The FW system consists oftwo constant-speed, motor-driven FW pumps with throttling flow control that have a combinedcapacity of the total required flow to the reactor. The RLC system automatically controls theflow of FW into the reactor vessel to maintain the water level in the vessel within a predetermined range during all modes of plant operations. The RLC system employs waterlevel, steam flow, and FW flow as a three-element control. Single-element control, which employs water level only, is also available.
2-162The RLC system performs functions that support FP and SBO.The applicant identified the RLC component types that are within the scope of license renewal.Section 2.5.2 evaluates electrical commodities for this system that are subject to an AMR. Section 2.4.6 evaluates supports for electrical components.2.5.1.12.2  Staff Evaluation The staff reviewed LRA Section 2.5.1.12 and the USAR using the evaluation methodologydescribed in SER Section 2.5. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.5.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.5.1.12.3  Conclusion On the basis of its review, the staff concluded that the applicant adequately identified the RLCsystem components that are within the scope of license renewal, as required by10 CFR 54.4(a), and the RLC system components that are subject to an AMR, as required by10 CFR 54.21(a)(1).2.5.1.13  Uninterruptible AC 2.5.1.13.1  Summary of Technical Information in the Application In LRA Section 2.5.1.13, the applicant described the uninterruptible AC (UAC) system. TheUAC system is composed of two Class 1E inverters that provide a Division 1 and a Division 2120-VAC UPS. The Division 1 inverter (Y-71) is supplied by Division 1 250-VDC distribution panel D-31, with an alternate AC source to the static switch from essential MCC-134 through a stepdown transformer. The Division 2 inverter (Y-81) is supplied by Division 2 250-VDC distribution panel D-100 with an alternate AC source to the static switch from essential MCC-144 through a step-down transformer. The 480-Volt AC system is composed of one UPSY-91 which provides a reliable source of 480-Volt AC power. This system is not a Class 1Esystem. The normal source for Y-91 is from LC-108 through circuit breaker 52-804. Thealternate source is through circuit breaker 52-704 on LC-107. The backup DC source is 250-VDC battery No. 17 via circuit breaker No. 1 on panel D-71. Y-91 rectifier section provides the charging for No. 17 battery, as well as being the normal supply for Y-91 inverter section. The instrument and control AC power provides AC power to plant AC instrument loads.The UAC system contains SR components that are relied upon to remain functional during andfollowing DBEs. In addition, the UAC system performs functions that support FP, ATWS, and SBO.
2-163The applicant identified the UAC system com ponent types that are within the scope of licenserenewal. Section 2.5.2 evaluates electrical commodities for this system that are subject to anAMR. Section 2.4.6 evaluates supports for electrical components.2.5.1.13.2  Staff Evaluation The staff reviewed LRA Section 2.5.1.13 and the USAR using the evaluation methodologydescribed in SER Section 2.5. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.5.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.5.1.13.3  Conclusion On the basis of its review, the staff concluded that the applicant adequately identified the UACsystem components that are within the scope of license renewal, as required by10 CFR 54.4(a), and the UAC system components that are subject to an AMR, as required by10 CFR 54.21(a)(1).2.5.2  Electrical Commodities In LRA Section 2.5.2, the applicant presented the results of the screening process for electricalcomponents evaluated as commodities subject to an AMR for license renewal. The applicant explained in LRA Section 2.1.5.4 that the scoping and screening process for electricalequipment was unique in several aspects. All electrical systems were evaluated to determinewhether the system intended functions met 10 CFR 54.4(a)(1) through (a)(3) requirements.SSCs supporting intended functions were considered within the scope of license renewal. The applicant performed component-level screening for electrical and mechanical systems withinthe scope of license renewal. Most component-level screening was performed and documented in the license renewal database on a commodity basis. Components were either screened out as active or included in a commodity group.The applicant described electrical commodity groups and their intended function in the followingsections of the LRA:
* 2.5.2.1electrical penetrations
* 2.5.2.2fuse holders
* 2.5.2.3non-EQ cables and connections
* 2.5.2.4offsite power/SBO recovery pathSections 2.5.2.1-2.5.2.4 present the staff's review findings regarding LRASections 2.5.2.1-2.5.2.4, respectively.
2-1642.5.2.1  Electrical Penetrations2.5.2.1.1  Summary of Technical Information in the Application In LRA Section 2.5.2.1, the applicant described the electrical penetrations. The electricalpenetrations assemblies consist of one or more electrical conductors and materials, which provide a pressure boundary between the inboard and outboard sides of the penetration. Thepenetration must be capable of maintaining the license renewal intended function of "electrical continuity" through the boundary. The cable and material associated with maintaining the license renewal intended function is the focus of this review. Section 2.4.13 of the LRA contains portions and materials of the penetration assembly associated with the license renewal intended function "pressure boundary" (or essentially leaktight containment barrier). For an electrical penetration to be within the scope of license renewal, it must support an intended function of one of the systems or components identified as within the scope of license renewal.MNGP uses penetrations manufactured by GE and D.G. O'Brien. There are 24 electrical penetrations at MNGP. Nineteen of these are in use and five are spares. There are six penetrations designated as requiring EQ and are addressed in SER Section 4.7. Of the remaining 13 penetrations, only 4 are within the scope of license renewal. The other nine penetrations do not contain cables which provide a license renewal SR intended function or are credited for any of the regulated events.The intended function of electrical penetrations is to provide electrical connections to specifiedsections of an electrical circuitIn LRA Table 2.5.2-1, the applicant identified the following commodity groups that are within thescope of license renewal and subject to an AMR:
* non-EQ insulated cables and connections
* non-EQ electrical and I&C penetration assemblies except cable and connections(electrical components only-potting compound, vapor barrier, and support)
* non-EQ electrical cables used in instrumentation circuits not subject to 10 CFR 50.49EQ requirements that are sensitive to reduction in conductor insulation resistance2.5.2.1.2  Staff Evaluation The staff reviewed LRA Section 2.5.2.1 and the USAR using the evaluation methodologydescribed in SER Section 2.5. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.5.2.5.2.1.3  Conclusion On the basis of its review, the staff concluded that the applicant adequately identified theelectrical penetrations components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the commodity groups for electrical penetrations components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).
2-1652.5.2.2  Fuse Holders2.5.2.2.1  Summary of Technical Information in the Application In LRA Section 2.5.2.2, the applicant described the fuse holders. For a fuse holder (block, clips,and connection points) to be within scope, it must support an intended function of one of the systems or components identified as within the scope of license renewal. In addition, the reviewof fuse holders applies only to those that are not part of a larger assembly, but support SR and NSR functions in which the failure of a fuse precludes a safety function from being accomplished. Fuse holders inside an enclosure of an active component, such as the switchgear, load center, MCC, distribution panel, power supply, power inverter, charger, converter, inverter, or circuit board, are parts of the larger assembly. Since the applicant regularly inspects and maintains piece parts and subcomponents in such an enclosure as part of the plant's normal maintenance and surveillance activities, they are not subject to an AMR.Since there is no all-inclusive fuse database at MNGP, the applicant used various databases,analysis/calculations, and plant walkdowns to identify those fuse holders meeting the abovecriteria. Based on the above reviews of databases, analysis/calculations, and in-plant walkdowns, the applicant determined that the majority of the fuse holders at MNGP are locatedinside an active device enclosure. For those fuse holders not located inside an active device enclosure, the applicant performed further evaluation to determine whether the fuse holdersupported an intended function of systems or components identified as within the scope oflicense renewal. Those fuse holders not supporting an intended function were scoped out and no further evaluations were performed. Those fuse holders that do support an intended function were scoped in and are subject to AMR.The intended function of fuse holders is to provide electrical connections to specified sectionsof an electrical circuit.In LRA Table 2.5.2-2, the applicant identified the fuse holders as a commodity group that iswithin the scope of license renewal and subject to an AMR.2.5.2.2.2  Staff Evaluation The staff reviewed LRA Section 2.5.2.2 and the USAR using the evaluation methodologydescribed in SER Section 2.5. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.5.2.5.2.2.3  Conclusion On the basis of its review, the staff concluded that the applicant adequately identified the fuseholders that are within the scope of license renewal, as required by 10 CFR 54.4(a), and  the fuse holders as a commodity group that is subject to an AMR, as required by 10 CFR 54.21(a)(1).
2-1662.5.2.3  Non-EQ Cables and Connections2.5.2.3.1  Summary of Technical Information in the Application In LRA Section 2.5.2.3, the applicant described the non-EQ cables and connections. Thecomponents evaluated are non-EQ power, I&C insulated cables and connections (connections include connectors, splices, and terminal blocks), and uninsulated (bare) ground conductors.SER Section 4.7 evaluates components that are part of the Environmental QualificationProgram. In accordance with the Department of Energy's cable aging management guideline presented in SAND96-0344, "Aging Management Guideline for Commercial Nuclear Power Plants-Electrical Cable and Terminations," issued September 1996, an insulated cable is an assembly of a single electrical conductor (wire) with an insulation covering or a combination of conductors insulated from one another with overall coverings. Connections (or terminations) are used to connect the cable conductors to other cables or electrical devices. The applicant evaluated several types of connections. Plug-in connectors are one or more electrical contacts that plug or screw into a mating receptacle. Splice insulation systems (heat shrink and tape) areinsulation material generally applied over compression (i.e., bolted) or fusion connections and are used to seal and insulate cable or splice terminations or junctions from the surrounding environment. Terminal blocks are an insulating base with fixed points for landing of wiring orconnection of terminal (ring) lugs. Terminal blocks are installed in enclosures such as controlboards, MCCs, motors, terminal boxes, or power panel boards for protection from both physical and environmental damage. Uninsulated ground conductors are electrical conductors (e.g.,
bare copper cable, bare copper bar) that are used to make electrical equipment ground connections.Uninsulated ground cables are neither classified as SR nor relied upon for SR equipment toperform their intended function, as identified in 10 CFR 54.4(a); therefore, the applicant hasdetermined that uninsulated ground cables are outside the scope of license renewal.The intended function of non-EQ cable and connections is to provide electrical connections tospecified sections of an electrical circuit.In LRA Table 2.5.2-3, the applicant identified the non-EQ cables and connections as commoditygroups that are within the scope of license renewal and subject to an AMR as follows:
* electrical cables and connections not subject to 10 CFR 50.49 EQ requirements
* electrical cables used in instrumentation circuits not subject to 10 CFR 50.49 EQrequirements that are sensitive to reduction in conductor insulation resistance
* inaccessible medium voltage (2 kV to 34.5 kV) cable and connections (e.g., installed inconduit or direct buried) not subject to 10 CFR 50.49 EQ requirements2.5.2.3.2  Staff Evaluation The staff reviewed LRA Section 2.5.2.3 and the USAR using the evaluation methodologydescribed in SER Section 2.5. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.5.
2-1672.5.2.3.3  ConclusionOn the basis of its review, the staff concluded that the applicant adequately identified thenon-EQ cables and connections that are within the scope of license renewal, as required by 10 CFR 54.4(a), and  the non-EQ cables and connections as commodity groups that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.5.2.4  Offsite Power/SBO Recovery Path 2.5.2.4.1  Summary of Technical Information in the Application In LRA Section 2.5.2.4, the applicant described the offsite power/SBO recovery path. Thepassive, long-lived, in-scope components comprising the offsite power/SBO recovery path subject to an AMR include phase bus, switchyard bus, high-voltage insulators, transmission conductors, non-EQ cables and connections, and non-EQ buried cable. The hardware used to secure or attach switchyard bus and transmission conductors to high-voltage insulators is also included. Phase bus is a bus that is enclosed (either within its own enclosure or inside a vault) and is not part of an active component, such as switchgear, load center, or MCC. There are four types of phase bus-isolated-phase bus, nonsegregated phase bus, phase bus enclosed in a vault, and segregated phase bus. MNGP has two of the types of phase buses mentioned above. A switchyard bus is an uninsulated, unenclosed, rigid electrical conductor used in switchyards to connect two or more elements of an electrical power circuit, such as active disconnect (gang) switches and passive transmission conductors. Included with the switchyard bus is the hardware used to secure the bus to a high-voltage insulator or transmission conductor. Switchyard bus connections to an active component (e.g., disconnect (gang) switch, transformer) are inspected and maintained along with the active components (e.g., disconnect (gang) switch, transformer) and are not included here. In accordance with the Institute of Electrical and Electronics Engineers, an insulator is an insulating material in a form designed to support a conductor physically and separate the conductor electrically from another conductor or object. Transmission conductors are uninsulated, stranded electrical cables used to electrically connect two or more elements of an electrical power circuit. The offsite power system/recovery path boundary includes the 345-kV, 115-kV, and 13.8-kV system componentsfrom the plant 4.16-kV buses out to the first switchyard breaker, which disconnects the plant from the 345-kV or 115-kV ring bus or the 13.8-kV system fed from the No. 10 transformer.In LRA Table 2.5.2-4, the applicant identified the following commodity groups for offsitepower/SBO recovery path that are within the scope of license renewal and subject to an AMR:
* nonsegregated phase bus
* high-voltage insulators
* high-voltage switchyard bus
* high-voltage transmission conductors
* electrical cables and connections not subject to 10 CFR 50.49 EQ requirements
* inaccessible medium voltage (2 kV to 34.5 kV) cable (e.g., installed in conduit or directburied) not subject to 10 CFR 50.49 EQ requirements 2-168The intended functions of the above commodity groups include the following:
* insulate and support an electrical conductor
* provide electrical connections to specified sections of an electrical circuit2.5.2.4.2  Staff Evaluation The staff reviewed LRA Section 2.5.2.4 and the USAR using the evaluation methodologydescribed in SER Section 2.5. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.5.The staff's review of LRA Section 2.5.2.4 identified an area for which it needed additionalinformation to complete its evaluation of the applicant's results. The applicant responded to the staff's RAI as discussed below.In RAI 2.5.2-1, dated August 18, 2005, the staff noted that LRA Section 2.5.2.4, under thedescription of Offsite Power/SBO Recovery Path, states that the path boundary includes the 345-kV, 115-kV, and 13.8-kV system components from the plant 4.16-kV buses out to the firstswitchyard breaker, which disconnects the plant from the 345-kV or 115-kV ring bus or the 13.8-kV system fed from the No. 10 transformer in the switchyard. The staff requested that theapplicant confirm that the path boundary also includes the associated control circuits subject toan AMR.In its response, by letter dated September 16, 2005, the applicant confirmed that the controlcircuits for the offsite power/SBO recovery path components within the scope of license renewalare included within the AMR scope.Based on its review, the staff found the applicant's response to RAI 2.5.2-1 acceptable becausethe applicant verified that the associated control circuits are subject to an AMR. Therefore, thestaff's concern described in RAI 2.5.2-1 is resolved.2.5.2.4.3  Conclusion On the basis of its review, the staff concluded that the applicant adequately identified the offsitepower/SBO recovery path components that are within the scope of license renewal, as requiredby 10 CFR 54.4(a), and adequately identified the commodity group for the offsite power/SBOrecovery path components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.6  Conclusion for Scoping and ScreeningThe staff reviewed the information in LRA Section 2, "Scoping and Screening Methodology forIdentifying Structures and Components Subject to Aging Management Review, and Implementation Results." The staff determined that the applicant's scoping and screeningmethodology was consistent with the requirements of 10 CFR 54.21(a)(1) and the SRP-LR onthe treatment of SR and NSR SSCs within the scope of license renewal and that the SCsidentified as requiring an AMR are consistent with the requirements of 10 CFR 54.4 and10 CFR 54.21(a)(1).
2-169On the basis of its review, the staff concluded that the applicant adequately identified thosesystems and components that are within the scope of license renewal, as required by10 CFR 54.4(a), and those systems and components that are subject to an AMR, as requiredby 10 CFR 54.21(a)(1).
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3-1SECTION 3AGING MANAGEMENT REVIEW RESULTSThis section of the safety evaluation report (SER) contains the staff's evaluation of theapplicant's aging management programs (AMPs) and aging management reviews (AMRs). In Appendix B to its license renewal application (LRA), the applicant described the 35 AMPs that itrelies on to manage or monitor the aging of long-lived, passive structures and components (SCs).In LRA Section 3, the applicant provided the results of the AMRs for those SCs that it identifiedin LRA Section 2 as being within the scope of license renewal and subject to an AMR.3.0  Applicant's Use of the Generic Aging Lessons Learned ReportIn preparing its LRA, Nuclear Management Company, LLC (NMC or the applicant), creditedNUREG-1801, "Generic Aging Lessons Learned (GALL) Report," issued July 2001. The GALLReport contains the staff's generic evaluation of the existing plant programs, and it documentsthe technical basis for determining when existing programs are adequate without modification, and when existing programs should be augmented for the extended period of operation. The evaluation results documented in the GALL Report indicate that many of the existing programsare adequate to manage the aging effects for particular SCs for license renewal without change. The GALL Report also contains recommendations on specific areas for which existing programs should be augmented for license renewal. An applicant may reference the GALL Report in its LRA to demonstrate that the programs at its facility correspond to those reviewedand approved in the report.The GALL Report provides a summary of staff-approved AMPs to manage or monitor the agingof SCs that are subject to an AMR. If an applicant commits to implementing these staff-approved AMPs, the time, effort, and resources used to review an applicant's LRA willlikely be reduced, thereby improving the efficiency and effectiveness of the license renewal review process. The GALL Report also serves as a reference for applicants and staff reviewers to quickly identify those AMPs and activities that the staff has determined will adequatelymanage or monitor aging during the period of extended operation.The GALL Report identifies (1) systems, structures, and components (SSCs), (2) SC materials,(3) the environments to which the SCs are exposed, (4) the aging effects associated with thegiven materials and environments, (5) the AMPs that are credited with managing or monitoring the aging effects, and (6) recommendations for further applicant evaluations of aging management for certain component types.The staff performed its review in accordance with the requirements of Title 10, Part 54,"Requirements for Renewal of Operating Licenses for Nuclear Power Plants," of the Code ofFederal Regulations (10 CFR Part 54), the guidance provided in NUREG-1800, "StandardReview Plan for Review of License Renewal Applications for Nuclear Power Plants" (SRP-LR),
issued July 2001, and the guidance provided in the GALL Report.
3-2In addition to its review of the LRA, the staff conducted an onsite audit of selected AMRs andassociated AMPs, as described in the "Audit and Review Plan for Plant Aging Management Reviews and Programs for Monticello Nuclear Generating Plant," dated June 2, 2005. The staff designed its onsite audits and reviews to maximize the efficiency of its review of the LRA. This helps reduce the need for formal correspondence between the staff and the applicant, thereby improving the review's efficiency. In addition, the applicant could respond to questions and the staff could readily evaluate the applicant's responses.3.0.1  Format of the License Renewal Application The applicant submitted an application that followed the standard LRA format, which wasagreed to by the U.S. Nuclear Regulatory Commission (NRC) staff and the Nuclear EnergyInstitute (NEI) (see letter dated April 7, 2003, ADAMS Accession No. ML030990052). This revised LRA format incorporates lessons learned from the staff's reviews of the previous five LRAs. These previous applications used a format developed from information gained during an NRC staff and NEI demonstration project that was conducted to evaluate the use of the GALLReport in the staff's review process.The organization of LRA Section 3 parallels Chapter 3 of the SRP-LR. Two types of tablespresent the AMR results information in LRA Section 3:(1)Table 1-Table 3.x.1, where "3" indicates the LRA section number, "x" indicates thesubsection number from the GALL Report, and "1" indicates that this is the first table type in LRA Section 3.(2)Table 2-Table 3.x.2-y, where "3" indicates the LRA section number, "x" indicates thesubsection number from the GALL Report, "2" indicates that this is the second table type in LRA Section 3, and "y" indi cates the system table number.The content of previous applications for other plants' renewals and the Monticello NuclearGenerating Plant (MNGP) application is essentially the same. The revised format used for the MNGP application was intended to modify the tables in Section 3 to provide additional information that will assist the staff in its review. In Table 1, the applicant summarized theportions of the application that it considered to be consistent with the GALL Report. In Table 2,the applicant identified the linkage between the scoping and screening results in Section 2 ofthe LRA and the AMRs in Section 3.3.0.1.1  Overview of Table 1 Table 3.x.1 (Table 1) provides a summary comparison of how the facility aligns with thecorresponding tables in the GALL Report, Volume 1. The table is essentially the same as Tables 1 through 6 provided in the GALL Report, Volume 1, except that the "Type" column has been replaced by an "Item Number" column and the "Item Number in GALL" column has been replaced by a "Discussion" column. The "Item Number" column provides the reviewer with a means to cross-reference from Table 2 to Table 1. The applicant used the "Discussion" column to provide clarifying and amplifying information. This column might contain the following types of information:
3-3
* further evaluation recommended (information or reference to the location of thatinformation)
* the name of a plant-specific program being used
* exceptions to the GALL Report assumptions
* a discussion of how the line is consistent with the corresponding line item in the GALLReport when this may not be intuitively obvious
* a discussion of how the item is different from the corresponding line item in the GALLReport (e.g., when an exception is taken to an AMP that is listed in the GALL Report)The format of Table 1 allows the staff to align a specific Table 1 row with the correspondingGALL Report, Volume 1, table row so that the consistency can be easily verified.3.0.1.2  Overview of Table 2 Table 3.x.2-y (Table 2) provides the detailed results of the AMRs for those componentsidentified in LRA Section 2 as subject to an AMR. The LRA contains a Table 2 for each of the systems or components within a system grouping (e.g., reactor coolant system (RCS),engineered safety features (ESFs), and auxiliary systems). For example, the ESF groupcontains tables specific to the core spray (CSP) system, high-pressure coolant injection (HPC) system, and residual heat removal (RHR) system,. Table 2 consists of the following ninecolumns:  (941)Component Type-The first column identifies the component types from LRASection 2 that are subject to an AMR. The table lists the component types in alphabetical order.  (942)Intended Function-The second column contains the license renewal intendedfunctions for the listed component types. LRA Table 2.1-1 contains definitions of intended functions.  (943)Material-The third column lists the particular materials of construction for thecomponent type.  (944)Environment-The fourth column lists the environment to which the componenttypes are exposed. The column indicates the internal and external service environments; LRA Table 3.0-1 lists these environments.  (945)Aging Effect Requiring Management (AERM)-The fifth column lists aging effectsrequiring management. As part of the AMR process, the applicant determined any AERMs for each combination of material and environment.  (946)AMPs-The sixth column lists the AMPs that the applicant used to manage theidentified aging effects.  (947)NUREG-1801 Volume 2 Line Item-The seventh column lists the GALL Reportitem(s) that the applicant identified as being similar to the AMR results in the LRA.The applicant compared each combination of component type, material, environment, AERM, and AMP in LRA Table 2 to the items in the GALL Report. If the GALL Report contained no corresponding items, the applicant left the column 3-4blank. In this way, the applicant identified the AMR results in the LRA tables thatcorrespond to the items in the GALL Report tables.  (948)Table 1 Item-The eighth column lists the corresponding summary item numberfrom Table 1. If the applicant identified AMR results in Table 2 that are consistentwith the GALL Report, then Table 2 should list the associated Table 3.x.1 line summary item number. If the GALL Report contains no corresponding item, then the applicant left the eighth column blank. In this way, the information from the two tables can be correlated.  (949)Notes-The ninth column lists the corresponding notes that the applicant used toidentify how the information in Table 2 aligns with that in the GALL Report. An NEI working group developed the notes identified by letters, which will be used in futureLRAs. Any plant-specific notes are identified by a number and provide additional information concerning the consistency of the line item with the GALL Report.3.0.2  Staff's Review Process The staff conducted the following three types of evaluations of the AMRs and associated AMPs:  (1)For items that the applicant stated were consistent with the GALL Report, the staffconducted either an audit or a technical review to determine consistency with the GALL Report.  (2)For items that the applicant stated were consistent with the GALL Report withexceptions and/or enhancements, the staff conducted either an audit or a technicalreview of the item to determine consistency with the GALL Report. In addition, the staff conducted either an audit or a technical review of the applicant's technical justification for the exceptions and the adequacy of the enhancements.  (3)For other items, the staff conducted a technical review per 10 CFR 54.21(a)(3).The staff performed audits and technical reviews of the applicant's AMPs and AMRs. Theseaudits and technical reviews determine whether the effects of aging on SCs can be adequately managed so that their intended functions can be maintained consistent with the plant's currentlicensing basis (CLB) for the period of extended operation, as required by 10 CFR Part 54.3.0.2.1  Review of AMPs For those AMPs for which the applicant claimed consistency with the GALL Report AMPs, thestaff conducted either an audit or a technical review to verify that the applicant's AMPs were consistent with the AMPs in the GALL Report. For each AMP that had one or more deviations, the staff evaluated each deviation to determine (1) whether the deviation is acceptable and (2)whether the AMP, as modified, will adequately manage the aging effect(s) for which it iscredited. For AMPs that the GALL Report, the staff performed a full review to determine theadequacy of the AMPs. 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 toan AMR for license renewal.
3-5  (2)Preventive Actions-Preventive actions should prevent or mitigate aging degradation.  (3)Parameters Monitored or Inspected-Parameters monitored or inspected should belinked to the degradation of the particular SC intended function(s).  (4)Detection of Aging Effects-Detection of aging effects should occur before there is aloss of SC intended function(s). This element 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 the timely detection of aging effects.  (5)Monitoring and Trending-Monitoring and trending should provide predictability of theextent of degradation, as well as timely corrective or mitigative actions.  (6)Acceptance Criteria-Acceptance criteria, against which the need for corrective actionwill be evaluated, should ensure that the SC intended function(s) are maintained underall CLB design conditions during the period of extended operation.  (7)Corrective Actions-Corrective actions, including root cause determination andprevention of recurrence, should be timely.  (8)Confirmation Process-The confirmation process should ensure that preventive actionsare adequate and that appropriate corrective actions have been completed and are effective.  (9)Administrative Controls-Administrative controls should provide a formal review andapproval process.  (10)Operating Experience-Operating experience of the AMP, including past correctiveactions resulting in program enhancements or additional programs, should provide objective evidence to support the conclusion that the effects of aging will be m anagedadequately so that the SC intended function(s) will be maintained during the period ofextended operation.The "Audit and Review Report for Plant Aging Management Reviews and Programs MonticelloNuclear Generating Plant," dated October 12, 2005 (hereafter referred to as the MNGP audit and review report), details the staff's audit evaluation of program elements (1) through (6), as summarized in SER Section 3.0.3.The staff reviewed the applicant's Corrective Action Program (CAP) and documented itsevaluations in SER Section 3.0.4. The staff's evaluation of the CAP included assessment of theCorrective Actions, Confirmation Process, and Administrative Controls program elements.The staff reviewed the information concerning the Operating Experience program element anddocumented its evaluation in the MNGP audit and review report. The staff also included a summary of the program in SER Section 3.0.3.The staff reviewed the Updated Safety Analysis Report (USAR) supplement for each AMP todetermine if it adequately describes the program or activity, as required by 10 CFR 54.21(d).
3-63.0.2.2  Review of AMR ResultsLRA Table 2 contains information concerning whether the applicant's AMRs align with theAMRs identified in the GALL Report. For a given AMR in Table 2, the staff reviewed the intended function, material, environment, AERM, and AMP combination for a particular component type within a system. The applicant identified the AMRs that correlate between acombination in Table 2 and a combination in the GALL Report using a referenced item number in the seventh column, "NUREG-1801 Volume 2 Line Item." The staff also conducted onsiteaudits to verify the correlation. A blank seventh column indicates that the applicant could not locate an appropriate corresponding combination in the GALL Report. The staff conducted a technical review of these combinations that were not consistent with the GALL Report. The nextcolumn, "Table 1 Item," provides a reference number that indicates the corresponding row in Table 1.3.0.2.3  USAR Supplement Consistent with the SRP-LR, for the AMRs and associated AMPs that it reviewed, the staff alsoreviewed the USAR supplement that summarizes the applicant's programs and activities for managing the effects of aging for the period of extended operation, as required by 10 CFR 54.21(d).3.0.2.4  Documentation and Documents Reviewed In performing its review, the staff relied heavily on the LRA, the LRA supplements, the SRP-LR,and the GALL Report.In addition, during the onsite audit, the staff examined the applicant's justification, asdocumented in the staff's MNGP audit and review report, to verify that the applicant's activities and programs will adequately manage the effects of aging on SCs. The staff also conducteddetailed discussions and interviews with the applicant's license renewal project personnel and others with technical expertise relevant to aging management.3.0.3  Aging Management Programs Table 3.0.3-1 presents the AMPs credited by the applicant and described in LRA Appendix B.The table also indicates the GALL Report program that the applicant claimed its AMP wasconsistent with (if applicable) and the SSCs for managing or monitoring aging. Finally, the tableprovides the section of the SER that documents the staff's evaluation of the program.Table 3.0.3-1  MNGP's Aging Management ProgramsMNGP AMP(LRA Section)
GALLComparison GALLAMP(s)LRA Systems or StructuresThat Credit the AMPStaff'sSER SectionExisting AMPs10 CFR 50, Appendix JProgram(B2.1.1)Consistent withexceptionsXI.S4containments, structures,and component supports 3.0.3.2.1 MNGP AMP(LRA Section)
GALLComparison GALLAMP(s)LRA Systems or StructuresThat Credit the AMPStaff'sSER Section3-7ASME Section XIIn-Service Inspection,Subsections IWB,IWC, and IWDProgram(B2.1.2)Consistent withexceptionXI.M1reactor coolant system,engineered safety features 3.0.3.2.2ASME Section XI,Subsection IWFProgram(B2.1.3)Consistent withenhancementXI.S3containments, structures,and component supports 3.0.3.2.3Bolting IntegrityProgram(B2.1.4)Consistent withenhancementsXI.M18reactor coolant system,engineered safety features,auxiliary systems, steam andpower conversion system,containment, structures, andcomponent supports3.0.3.2.4Buried Piping & TanksInspection Program(B2.1.5)Consistent withenhancementsXI.M34engineered safety features;auxiliary systems;containments, structures,and component supports 3.0.3.2.5BWR Control RodDrive Return LineNozzle Program(B2.1.7)Consistent withexceptionsXI.M6reactor coolant system 3.0.3.2.6BWR FeedwaterNozzle Program(B2.1.8)Consistent withenhancementsXI.M5reactor coolant system 3.0.3.2.7BWR PenetrationsProgram(B2.1.9)Consistent withexceptionsXI.M8reactor coolant system 3.0.3.2.8BWR Stress CorrosionCracking Program(B2.1.10)Consistent withexceptionXI.M7reactor coolant system,engineered safety features,auxiliary systems 3.0.3.2.9BWR Vessel IDAttachment WeldsProgram(B2.1.11)Consistent withexceptionXI.M4reactor coolant system 3.0.3.2.10BWR Vessel InternalsProgram(B2.1.12)Consistent withexception andenhancementXI.M9reactor coolant system 3.0.3.2.11Closed-Cycle CoolingWater System Program(B2.1.13)Consistent withexceptions andenhancementXI.M21reactor coolant system,engineered safety features,auxiliary systems 3.0.3.2.12Compressed AirMonitoring Program(B2.1.14)Consistent withexceptions andenhancementsXI.M24auxiliary systems 3.0.3.2.13 MNGP AMP(LRA Section)
GALLComparison GALLAMP(s)LRA Systems or StructuresThat Credit the AMPStaff'sSER Section3-8Fire ProtectionProgram(B2.1.17)Consistent withexception andenhancementXI.M26auxiliary systems;containments, structures,and component supports 3.0.3.2.15Fire Water SystemProgram(B2.1.18)Consistent withenhancementXI.M27auxiliary systems 3.0.3.2.16Flow-AcceleratedCorrosion Program(B2.1.19)ConsistentXI.M17reactor coolant system,engineered safety features,auxiliary systems, steam andpower conversion system 3.0.3.1.2Fuel Oil ChemistryProgram(B2.1.20)Consistent withexceptions andenhancementsXI.M30auxiliary systems 3.0.3.2.17Inspection of OverheadHeavy Load and LightLoad (Related toRefueling) HandlingSystems Program(B2.1.22)Consistent withexception andenhancementsXI.M23containments, structures,and component supports 3.0.3.2.18Open-Cycle CoolingWater System Program(B2.1.24)ConsistentXI.M20engineered safety features,auxiliary systems, steam andpower conversion system 3.0.3.1.5Plant ChemistryProgram(B2.1.25)Consistent withexceptionsXI.M2reactor coolant system,engineered safety features,auxiliary systems, steam andpower conversion system 3.0.3.2.19Primary ContainmentIn-Service InspectionProgram(B2.1.26)ConsistentXI.S1containments, structures,and component supports 3.0.3.1.6Protective CoatingMonitoring &Maintenance Program(B2.1.27)Consistent withenhancementXI.S8containments, structures,and component supports3.0.3.2.20Reactor Head ClosureStuds Program(B2.1.28)Consistent withexceptionsXI.M3reactor coolant system 3.0.3.1.7Reactor VesselSurveillance Program(B2.1.29)Consistent withenhancementXI.M31reactor coolant system 3.0.3.2.21Structures MonitoringProgram(B2.1.31)Consistent withenhancementsXI.S6containments, structures,and component supports 3.0.3.2.23 MNGP AMP(LRA Section)
GALLComparison GALLAMP(s)LRA Systems or StructuresThat Credit the AMPStaff'sSER Section3-9System ConditionMonitoring Program(B2.1.32)Plant-specificNAreactor coolant system;engineered safety features;auxiliary systems; steam andpower conversion system;containments, structures,and component supports 3.0.3.3.2Thermal Aging &Neutron IrradiationEmbrittlement of CastAustenitic StainlessSteel (CASS) Program(B2.1.33)ConsistentXI.M13reactor coolant system 3.0.3.1.8Electrical EquipmentSubject to10 CFR 50.49EnvironmentalQualification (EQ)Requirements Program(B3.1)ConsistentX.E1electrical and instrumentationand controls3.0.3.1.9Metal Fatigue of theReactor CoolantPressure BoundaryProgram(B3.2)Consistent withenhancementX.M1reactor coolant system,engineered safety features3.0.3.2.24 New AMPsBus Duct InspectionProgram(B2.1.6)Plant specificNAelectrical and instrumentationand controls 3.0.3.3.1Electrical Cables &Connections NotSubject to10 CFR 50.49EnvironmentalQualificationRequirements Program(B2.1.15)ConsistentXI.E1electrical and instrumentationand controls 3.0.3.1.1Electrical Cables NotSubject to10 CFR 50.49EnvironmentalQualificationRequirements Used inInstrumentationCircuits Program(B2.1.16)Consistent withexceptionsXI.E2electrical and instrumentationand controls 3.0.3.2.14 MNGP AMP(LRA Section)
GALLComparison GALLAMP(s)LRA Systems or StructuresThat Credit the AMPStaff'sSER Section3-10Inaccessible MediumVoltage (2kV to34.5kV) Cables NotSubject to10 CFR 50.49 EQRequirements Program(B2.1.21)ConsistentXI.E3electrical and instrumentationand controls 3.0.3.1.3One-Time InspectionProgram(B2.1.23)ConsistentXI.M32reactor coolant system,engineered safety features,auxiliary systems, steam andpower conversion system 3.0.3.1.4Selective Leaching ofMaterials Program(B2.1.30)Consistent withexceptionXI.M33engineered safety features,auxiliary systems, steam andpower conversion system 3.0.3.2.223.0.3.1  AMPs That Are Consistent with the GALL ReportIn LRA Appendix B, the applicant identified the following AMPs as consistent with the GALLReport:
* Electrical Cables & Connections Not Subject to 10 CFR 50.49 EnvironmentalQualification (EQ) Requirements Program (B2.1.15)
* Flow-Accelerated Corrosion (FAC) Program (B2.1.19)
* Inaccessible Medium Voltage (2kV to 34.5kV) Cables Not Subject to 10 CFR 50.49 EQRequirements Program (B2.1.21)
* One-Time Inspection Program (B2.1.23)
* Open-Cycle Cooling Water (OCCW) System Program (B2.1.24)
* Primary Containment In-Service Inspection Program (B2.1.26)
* Reactor Head Closure Studs Program (B2.1.28)
* Thermal Aging & Neutron Irradiation Embrittlement of Cast Austenitic StainlessSteel (CASS) Program (B2.1.33)
* Electrical Equipment Subject to 10 CFR 50.49 EQ Requirements Program (B3.1)3.0.3.1.1Electrical Cables & Connections Not Subject to 10 CFR 50.49 EnvironmentalQualification Requirements ProgramSummary of Technical Information in the Application. In LRA Section B2.1.15, the applicantdescribed the Electrical Cables & Connections Not Subject to 10 CFR 50.49 EQ Requirements Program, stating that this new program is consistent with GALL AMP XI.E1, "Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements." An adverse localized environment is a condition in a limited plant area that is significantly more severe than the specified service environment for the component. An adverse variation in environment is significant if it could appreciably increase the rate of aging of a component or 3-11have an immediate adverse effect on operability. In most areas of the plant, the actual ambientenvironments (e.g., temperature, radiation, or moisture) are less severe than the plant designenvironment. However, in a limited number of localized areas, the actual environments may be more severe than the plant design environment for those areas. Cable and connection insulation materials may degrade more rapidly than expected in these adverse localized environments. Since they are not subject to the EQ requirements of 10 CFR 50.49,"Environmental Qualification of Electric Equipment Important to Safety for Nuclear Power Plants," the electrical cables and connections covered by this AMP are either not exposed to harsh accident conditions or not required to remain functional during or following an accident to which they are exposed. The scope of this program includes accessible non-EQ electrical cables and connections, including control and instrumentation circuits, within the scope of license renewal.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report documents the details of the staff's evaluation of this AMP. The staff determined that this AMP is consistent with theAMP described in the GALL Report, including the associated operating experience attribute.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.E1.The staff reviewed those portions of AMP B2.1.15, "Electrical Cables & Connections NotSubject to 10 CFR 50.49 Environmental Qualification Requirements Program," which the applicant claims are consistent with GALL AMP XI.E1, "Electrical Cables & Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program," and found themconsistent with the GALL Report AMP. Because it is consistent with the GALL Report, the AMPensures that the effects of aging will be adequately managed. The staff found the applicant'sLRA AMP acceptable because it conforms to the recommended GALL Report AMP.Operating Experience. In LRA Section B2.1.15, the applicant explained that the ElectricalCables & Connections Not Subject to 10 CFR 50.49 EQ Requirements Program is a new site-specific program and therefore does not have any operating experience. However, as noted in the GALL Report, industry operating experience shows that adverse local environments caused by heat or radiation for electrical cables and connections have been shown to exist and produce degradation of insulating material degradation that can be detected visually.During the audit and review, the staff asked the applicant how it captures operating experience.The applicant stated that the site's CAP identifies, tracks, and trends site operating experiencerelated to all site components. It documents any site component identified as degraded, failed, or potentially unable to fulfill its intended functions in the site CAP database. The plantengineering staff then evaluates these components for the extent of the condition and takesappropriate followup actions. The plant engineering staff also trends related CAPs to identify generic issues and addresses trended site issues in program health reports presented to site management on a scheduled basis. The CAP also addresses issues related to 10 CFR 54.21, "Contents of Application-Technical Information," and external operating events reported by theNRC, Institute of Nuclear Power Operations (INPO), Licensing Information Service (LIS), and NMC Fleet. The staff reviewed the applicant's response and found it acceptable.
3-12The staff recognized that the CAP, which captures internal and external operating experienceissues, will ensure that the licensee reviews and incorporates operating experience in thefuture.On the basis of its review of the above industry and plant-specific operating experience anddiscussions with the applicant's technical personnel, the staff concluded that the applicant'sElectrical Cables & Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program will adequately manage the aging effects identified in the LRA for whichthis AMP is credited.USAR Supplement. In LRA Section A2.1.15, the applicant provided the USAR supplement forthe Electrical Cables & Connections Not Subject to 10 CFR 50.49 EQ Requirements Program.Subsequently, by letter dated June 10, 2005, the applicant revised its USAR supplement toinclude the following commitment, documented as commitment 26 in Table A.5:Prior to the period of extended operation, the MNGP Electrical Cables &Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program will be implemented as a new program consistent withthe recommendations of NUREG-1801 Chapter XI Program XI.E1. The program will manage the aging of conductor insulation material on cables, connectors,and other electrical insulation materials that are installed in an adverse localized environment caused by heat, radiation, or moisture.The staff reviewed this section and determined that the information in the USAR supplement asaugmented by the commitment adequately describes the program as required by 10 CFR 54.21(d).Conclusion. On the basis of its review and audit of the applicant's Electrical Cables &Connections Not Subject to 10 CFR 50.49 EQ Requirements Program, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report areconsistent with the GALL Report. The staff concluded that the applicant demonstrated that theeffects of aging will be adequately managed so that intended functions will be maintainedconsistent with the CLB for the period of extended operation, as required by10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.1.2  Flow-Accelerated Corrosion Program Summary of Technical Information in the Application. In LRA Section B2.1.19, the applicantdescribed the Flow-Accelerated Corrosion (FAC) Program, stating that this existing program is consistent with GALL AMP XI.M17, "Flow-Accelerated Corrosion." The program implements the Electric Power Research Institute (EPRI) guidelines in NSAC-202L-R2, "Recommendations for an Effective Flow-Accelerated Corrosion Program."  This program also requires the use of CHECWORKS as a predictive tool. The program includes (1) an analysis to determine locations susceptible to flow-accelerated corrosion (FAC), (2) performance of limited baseline inspections, (3) followup inspections to confirm the predictions, and (4) repairing or replacing 3-13components, as necessary. The MNGP FAC Program includes the response made to GenericLetter (GL) 89-08, "Erosion/Corrosion Induced Pipe Wall Thinning, dated May 2, 1989."Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's evaluation of this AMP. The staff determined that this AMP is consistent with the AMPdescribed in the GALL Report, including the associated operating experience attribute.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.M17.During the audit and review, the staff asked the applicant to clarify the minimum allowable wallthickness defined in the MNGP FAC program. The applicant stated that if degradation isdetected such that the measured wall thickness is less than 87.5 percent of nominal wallthickness for safety-related (SR) piping or 60 percent of nominal wall thickness for nonsafety-related (NSR) piping, it will perform an engineering evaluation to determine whetherthe degraded component is acceptable for continued use. If the component requires repair orreplacement during the inspection outage, the applicant will initiate a conditionreport (CR)/action request (AR) in accordance with the site-specific CAP. If a replacement is planned for the next refueling outage, the applicant will initiate a work request in accordancewith the site-specific process for work requests/work orders (WOs). In addition to the engineering evaluation, the applicant will examine adjacent areas to bound the thinning andassure that the actual minimum wall thickness is measured.The applicant further evaluated the adequacy of using 60 percent of pipe nominal wall thicknessas a trigger point for an engineering evaluation of NSR piping. The applicant determined thatthe 60-percent criterion has technical merit in statistical analysis, but lacks rigorous justificationbecause the applicant has not performed any plant-specific analysis to ensure its validity for all cases at MNGP. By letter dated August 11, 2005, the applicant provided responses to questions raised during the AMP and AMR audits. In this letter, the applicant committed to revise its FAC Inspection Program to use the industry-accepted 87.5 percent of nominal pipe wall thickness for NSR piping as a trigger point for an engineering evaluation. The applicant identified this as commitment 53 in Table A.5 of the USAR supplement provided in its letter dated March 15, 2006. On the basis of its review, the staff found the applicant's responseacceptable because it adequately addressed the minimum wall thickness evaluation.The staff reviewed those portions of the MNGP AMP B2.1.19, "Flow-Accelerated CorrosionProgram," that the applicant claimed are consistent with GALL AMP XI.M17, "Flow-AcceleratedCorrosion," and found them consistent with the GALL Report AMP. Because it is consistent withthe GALL Report, the AMP ensures that the effects of aging will be adequately managed. Thestaff found the applicant's AMP acceptable because it conforms to the recommended GALL Report AMP.Operating Experience. In LRA Section B2.1.19, the applicant explained that the FAC wallthinning problems in single-phase systems have occurred throughout the industry infeedwater (FW) and c ondensate systems, and in two-phase piping in extraction steamlines andmoisture separator reheater and FW heater drains. Application of the program at MNGP hasresulted in the identification and replacement of susceptible piping sections with materials more 3-14resistant to FAC (e.g., extraction steam system piping and piping downstream of the moistureseparators). The NRC originally outlined the FAC program in NUREG-1344,"Erosion/Corrosion-Induced Pipe Wall Thinning in U.S. Nuclear Power Plants," issued 1989, and implemented it through GL 89-08. The MNGP program has evolved through industry experience and is now implemented using the guidelines of NSAC-202L-R2 and CHECWORKS as a predictive tool. Monitoring locations and inspection methods have improved over time based on industry and plant experience and through the development of new techniques.On the basis of its review of the above operating experience and discussions with theapplicant's technical personnel, the staff concluded that the applicant's FAC Program willadequately manage the aging effects at the applicant's plant.USAR Supplement. In LRA Section A2.1.19, the applicant provided the USAR supplement forthe FAC Program. The staff reviewed this section and determined that the information in the USAR supplement provides an adequate summary description of the program, as required by 10 CFR 54.21(d).Conclusion. On the basis of its review and audit of the applicant's FAC Program, the staffdetermined that those program elements for which the applicant claimed consistency with theGALL Report are consistent with the GALL Report. The staff concluded that the applicantdemonstrated that the effects of aging will be adequately managed so that intended functionswill be maintained consistent with the CLB for the period of extended operation, as required by10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.1.3Inaccessible Medium Voltage (2kV to 34.5kV) Cables Not Subject to 10 CFR 50.49EQ Requirements ProgramSummary of Technical Information in the Application. In LRA Section B2.1.21, the applicantdescribed the Inaccessible Medium Voltage (2kV to 34.5kV) Cables Not Subject to 10 CFR 50.49 EQ Requirements Program, stating that this new program is consistent withGALL AMP XI.E3, "Inaccessible Medium-Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements." The intended function of insulated cables andconnections is to provide electrical connections to specified sections of an electrical circuit to deliver voltage, current, or signals. Most electrical cables at MNGP are located in dry environments. However, some cables may be exposed to condensation and wetting in inaccessible locations, such as conduits, cable trenches, cable troughs, duct banks, underground vaults, or direct buried installations. When an energized medium-voltage cable is exposed to wet conditions for which it was not designed, water treeing or a decrease in the dielectric strength of the conductor insulation can occur. This can potentially lead to electrical failure. In this AMP, the applicant takes periodic actions to prevent the exposure of cables to significant moisture, such as inspecting for water collection in cable manholes and conduit, and draining water, as needed. In-scope, medium-voltage cables exposed to significant moisture and significant voltage are tested to provide an indication of the condition of the conductor insulation. The specific type of test performed will be determined before the initial test, and it willbe a proven test for detecting deterioration of the insulation system as a result of wetting, suchas power factor, partial discharge, polarization index, or other testing that is state-of-the-art at the time the test is performed.
3-15Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's evaluation of this AMP. The staff determined that this AMP is consistent with the AMPdescribed in the GALL Report, including the associated operating experience attribute.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.E3.During the audit and review, the staff asked that the applicant explain the process for assuringthat cables in conduit are not subject to significant moisture and, thus, are not subject to testing. The applicant indicated that it is impossible to assure that cables in undergroundconduit are not exposed to significant moisture. The applicant further noted that the majority ofits underground cables are buried without the use of conduit and are thus subject to significant moisture and required to be tested. Cables located in underground conduit are also subject to significant moisture from condensation and required to be tested. In addition, under the Parameters Monitored or Inspected program element, included as part of MNGP AMP B2.1.21, "Inaccessible Medium Voltage (2kV to 34.5kV) Cables Not Subject to 10 CFR 50.49 EQ Requirements," the MNGP program will test medium-voltage cables (2 kilovolt (kV) to 34.5 kV)within the scope of license renewal exposed to moisture (direct buried or in underground conduit) and energized more than 25 percent of the time. The staff reviewed this response and found it acceptable.In the course of its review, the staff noted the applicant's statement that, in the PreventiveActions program element, it takes periodic actions, like inspecting for water collection in cable manholes and conduit and draining water as needed, to prevent prolonged exposure of medium-voltage cables to significant moisture. In the LRA, the applicant stated the following:Medium voltage cables, for which such actions are taken, are not required to betested since operating experience indicates that prolonged exposure to significant moisture and being energized for significant periods of time are required to induce this aging effect.In Request for Additional Information (RAI) B2.1.21-1, dated November 7, 2005, the staff notedits position that inaccessible medium-voltage cables be tested and inspected. Therefore, thestaff requested that the applicant remove the line from the LRA indicating that medium-voltagecables are not required to be tested. In addition, the staff requested that the applicant state theinspection frequency and its basis.In its response, by letter dated December 7, 2005, the applicant stated that it will revise thePreventive Action program element in LRA Section B2.1.21 to delete the following text:Medium-voltage cables, for which such actions are taken, are not required to betested since operating experience indicates that prolonged exposure to significant moisture and being energized for significant periods of time are required to induce this effect.
3-16In its letter dated March 15, 2006, the applicant amended the Detection of Aging Effectsprogram element by adding the following statement:In addition, the underground electrical vaults (manholes, handholes, etc)containing cable at MNGP are designed and installed without a concrete bottom.
The electrical vaults are set on natural soil which is porous river sand.
Historically, water accumulation in electrical vaults has not been an issue due to the natural draining of the porous soil. The inspection frequency for water collection will be based on actual plant experience. For those electrical vaults within the scope of license renewal, the initial inspection frequency for water accumulation will be at least once every two years. The first inspection for license renewal is to be completed before the period of extended operation.Based on its review, the staff found the applicant's response to RAI B2.1.21-1 acceptable. Thestaff found that the applicant's response addresses the staff's concern regarding testing and inspection of water in manholes for inaccessible medium-voltage cables. Therefore, the staff's concern described in RAI B2.1.21-1 is resolved.The staff reviewed those portions of MNGP AMP B2.1.21 that the applicant claimed areconsistent with GALL AMP XI.E3 and found them consistent with the GALL Report AMP.Because it is consistent with the GALL Report, the AMP ensures that the effects of aging will beadequately managed. The staff found the applicant's LRA AMP acceptable because it conforms to the recommended GALL Report AMP.Operating Experience. In LRA Section B2.1.21, the applicant explained that the InaccessibleMedium Voltage (2kV to 34.5kV) Cables Not Subject to 10 CFR 50.49 EQ Requirements Program is a new program with no operating experience. However, as noted in the GALL Report, industry operating experience shows 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 vary directly with operating voltage. Treeing is much less prevalent in 4-kV cables than those operated at 13-kV or 33-kV. Minimizing exposure to moisture also lessens the potential for the development of water treeing.During the audit and review, the staff asked the applicant how it captures operating experience.The applicant indicated that the site's CAP identifies, tr acks, and trends site operatingexperience related to all site components. The applicant documents any site component identified as degraded, failed, or potentially unable to fulfill its intended functions in the site CAPdatabase. The plant engineering staff then evaluates these components for the extent of the condition and takes appropriate followup actions. The plant engineering staff also trends related CAPs to identify generic issues and addresses trended site issues in program health reports presented to site management on a scheduled basis. The CAP also addresses issues related to 10 CFR 54.21 and external operating events from the NRC, INPO, LIS, and NMC Fleet. Thestaff reviewed the applicant's response and found it acceptable.The staff recognized that the CAP, which captures internal and external operating experienceissues, will ensure that operating experience is reviewed and incorporated in the future.On the basis of its review of the above industry and plant-specific operating experience anddiscussions with the applicant's technical personnel, the staff concluded that the applicant's 3-17Inaccessible Medium Voltage (2kV to 34.5kV) Cables Not Subject to 10 CFR 50.49 EQRequirements Program will adequately manage the aging effects identified in the LRA for whichthis AMP is credited.USAR Supplement. In LRA Section A2.1.21, the applicant provided the USAR supplement forthe Inaccessible Medium Voltage (2kV to 34.5kV) Cables Not Subject to 10 CFR 50.49 EQ Requirements Program.Subsequently, by letter dated June 10, 2005, the applicant revised its USAR supplement toinclude the following commitment, documented as commitment 36 in Table A.5:Prior to the period of extended operation, the MNGP InaccessibleMedium-Voltage (2kV to 34.5kV) Cables Not Subject to 10 CFR 50.49 EQ Requirements Program will be implemented as a new program consistent withthe recommendations of NUREG-1801 Chapter XI, Program XI.E3.The staff reviewed this section and determined that the information in the USAR supplement asaugmented by the commitment adequately describes the program, as required by 10 CFR 54.21(d).Conclusion. On the basis of its review and audit of the applicant's Inaccessible Medium Voltage(2kV to 34.5kV) Cables Not Subject to 10 CFR 50.49 EQ Requirements Program, the staff determined that those program elements for which the applicant claimed consistency with theGALL Report are consistent with the GALL Report. The staff concluded that the applicantdemonstrated that the effects of aging will be adequately managed so that intended functionswill be maintained consistent with the CLB for the period of extended operation, as required by10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.1.4  One-Time Inspection Program Summary of Technical Information in the Application. In LRA Section B2.1.23, the applicantdescribed the One-Time Inspection Program, stating that this new program is consistent withGALL AMP XI.M32, "One-Time Inspection." The MNGP One-Time Inspection Program addresses concerns with and confirmation for the potential long incubation period for certain aging effects on SCs. In some cases, (1) an aging effect is not expected to occur but data are not sufficient to completely rule it out, or (2) an aging effect is expected to progress very slowly.
The activities of the One-Time Inspection Program include (1) determination of the sample size based on an assessment of materials of fabrication, environment, plausible aging effects, and operating experience, (2) identification of the inspection locations in the system or componentbased on the aging effect, (3) determination of the examination technique, including acceptancecriteria that will be effective in managing the aging effect for which the component is examined,and (4) evaluation of the need for followup examinations to monitor the progression of any identified aging degradation. The program will manage the aging effects caused by corrosion,cracking, erosion, fouling, fretting, or thermal exposure. The program will also verify the absence of reduction of neutron absorption capacity of boral in the spent fuel pool.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's 3-18evaluation of this AMP. The staff determined that this AMP is consistent with the AMPdescribed in the GALL Report, including the associated operating experience attribute.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.M32.The staff reviewed those portions of the MNGP AMP B2.1.23, "One-Time Inspection Program,"that the applicant claimed are consistent with GALL AMP XI.M32 and found them consistentwith the GALL Report AMP. Because it is consistent with the GALL Report, the AMP ensures that the effects of aging will be adequately managed. The staff found the applicant's AMPacceptable because it conforms to the recommended GALL Report AMP.Operating Experience. In LRA Section B2.1.23, the applicant explained that the One-TimeInspection Program is a new program with no operating experience.During the audit and review, the staff asked the applicant how it captures operating experience.The applicant indicated that the MNGP CAP identifies, tr acks, and trends site operatingexperience related to all site components. The applicant documents any site component identified as degraded, as failed, or as potentially unable to fulfill its intended functions in thesite CAP database. The plant engineering staff then evaluates these components for the extentof the condition and takes appropriate followup actions. The plant engineering staff also trends related CAPs to identify generic issues and addresses trended site issues in program health reports presented to site management on a scheduled basis. The CAP also addresses issues related to 10 CFR 54.21 and external operating events from the NRC, INPO, LIS, and NMCFleet. The staff reviewed the applicant's response and found it acceptable.The staff recognized that the CAP, which captures the internal and external operatingexperience issues, will ensure evaluation and incorporation of operating experience forobjective evidence of the adequate management of aging effects.USAR Supplement. In LRA Section A2.1.23, the applicant provided the USAR supplement forthe One-Time Inspection Program.Subsequently, by letter dated June 10, 2005, the applicant revised its USAR supplement toinclude the following commitment, documented as commitment 38 in Table A.5:Prior to the period of extended operation, the MNGP One-Time InspectionProgram will be implemented as a new program consistent with the recommendations of NUREG-1801 Chapter Xl Program XI.M32, "One-TimeInspection." This program will include measures to verify the effectiveness of thefollowing aging management programs: Plant Chemistry Program and Fuel Oil Chemistry Program. This program will also confirm the absence of age relateddegradation in selected components (e.g., flow restrictors, venturis) within License Renewal scope.The staff reviewed this section and determined that the information in the USAR supplement asaugmented by the commitment adequately describes the program, as required by 10 CFR 54.21(d).
3-19Conclusion. On the basis of its review and audit of the applicant's One-Time InspectionProgram, the staff determined that those program elements for which the applicant claimedconsistency with the GALL Report are consistent with the GALL Report. The staff concluded that the applicant demonstrated that the effects of aging will be adequately managed so thatintended functions will be maintained consistent with the CLB for the period of extendedoperation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.1.5  Open-Cycle Cooling Water System Program Summary of Technical Information in the Application. In LRA Section B2.1.24, the applicantdescribed the Open-Cycle Cooling Water (OCCW) System Program, stating that this existing program is consistent with GALL AMP XI.M20, "Open-Cycle Cooling Water System." The MNGP OCCW System Program relies on the implementation of the recommendations of NRC GL 89-13, "Service Water System Problems Affecting Safety-Related Equipment," dated July 18, 1989, to ensure that the effects of aging on the raw water service water systems will bemanaged for the period of extended operation. This program manages the aging effects of metallic components in water systems (e.g., piping and heat exchangers) exposed to raw,untreated (e.g., service) water. Corrosion, erosion, and biofouling in SSCs serviced by the OCCW system cause these aging effects. The program includes (1) surveillance and control ofbiofouling, (2) tests to verify heat transfer, and (3) routine inspection and maintenance. The MNGP OCCW System Program complies with the MNGP response to NRC GL 89-13. Theapplicant has incorporated the commitments it made to comply with GL 89-13 into plant procedures and programs.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's evaluation of this AMP. The staff determined that this AMP is consistent with the AMPdescribed in the GALL Report, including the associated operating experience attribute.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.M20.The staff reviewed those portions of the MNGP AMP B2.1.24, "Open-Cycle Cooling WaterSystem Program," that the applicant claimed are consistent with GALL AMP XI.M20, "Open-Cycle Cooling Water System," and found them consistent with the GALL Report AMP. Because it is consistent with the GALL Report, the AMP ensures that the effects of aging will beadequately managed. The staff found the applicant's AMP acceptable because it conforms to the recommended GALL Report AMP.Operating Experience. In LRA Section B2.1.24, the applicant explained that the OCCW SystemProgram has been effective in managing loss of material and heat transfer degradation aging effects for systems within the scope of the program. Various self-assessments and NuclearOversight Department reviews have demonstrated program effectiveness and have shown that MNGP has implemented the requirements of GL 89-13. The applicant has documented andevaluated corrosion and material condition issues in the site CAP.
3-20The staff reviewed the operating experience provided in the LRA and interviewed theapplicant's technical personnel to confirm that the plant-specific operating experience revealedno degradation not bounded by industry experience.On the basis of its review of the above industry and plant-specific operating experience, thestaff concluded that applicant's OCCW System Program will adequately manage the agingeffects identified in the LRA for which this AMP is credited.USAR Supplement. In LRA Section A2.1.24, the applicant provided the USAR supplement forthe OCCW System Program. The staff reviewed this section and determined that the information in the USAR supplement adequately describes the program, as required by 10 CFR 54.21(d).Conclusion. On the basis of its review and audit of the applicant's OCCW System Program, thestaff determined that those program elements for which the applicant claimed consistency withthe GALL Report are consistent with the GALL Report. The staff concluded that the applicantdemonstrated that the effects of aging will be adequately managed so that intended functionswill be maintained consistent with the CLB for the period of extended operation, as required by10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.1.6  Primary Containment In-Service Inspection Program Summary of Technical Information in the Application. In LRA Section B2.1.26, the applicantdescribed the Primary Containment In-Service Inspection Program, stating that this existing program is consistent with GALL AMP XI.S1, "ASME Section XI, Subsection IWE." The MNGP Primary Containment In-Service Inspection Program requires visual examinations of the accessible surfaces (base metal and welds) of the drywell, torus, vent lines, internal vent system, penetration assemblies, and associated integral attachments. The program alsorequires examination of pressure-retaining bolting and the drywell interior slab moisture barrier.
The program conforms to the applicable requirements of 10 CFR 50.55a, "Codes and Standards," and the 1992 Edition with 1992 Addenda of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code (ASME Code), Subsection IWE. The applicant performs a detailed visual examination (VT)-3 and VT-1 examination once during each 10-year inservice inspection (ISI) interval. This examination occurs either at the end of the interval or is spread across the three periods that comprise the interval. The applicant performs general visual examinations that assess the overall structural condition once during each period. Surface and/or volumetric examination augments visual examination as required to define the extent of observed conditions or to identify deterioration at inaccessible locations.
Limited scope examinations are performed as required to evaluate disassembled bolting and the condition of the normally submerged torus surface when the suppression pool is drained.
The applicant periodically updates the program as required by 10 CFR 50.55a.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's evaluation of this AMP. The staff determined that this AMP is consistent with the AMPdescribed in the GALL Report, including the associated operating experience attribute.
3-21The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.S1.The applicant stated in MNGP AMP B2.1.26, "Primary Containment In-Service InspectionProgram," that exceptions to ASME Code requirements granted by approved code cases or relief requests are not considered exceptions to the GALL Report criteria. In addition, the discussions of some program elements cite a number of relief requests. In all cases, the applicant reiterated that these are not considered exceptions since the NRC reviewed the MNGP IWE program and the program is in accordance with 10 CFR 50.55a with
 
NRC-approved relief requests.The staff noted that 10 CFR 54.21 requires the LRA to contain information for each SC withinthe scope of license renewal demonstrating that the applicant will adequately manage agingeffects so that intended functions will be maintained consistent with the CLB for the period ofextended operation. The staff questioned the applicant's position that exceptions to ASMECode requirements granted by code cases or relief requests are not considered exceptions to the GALL Report.In its letter dated August 31, 2005, the applicant stated the following:The statement under the 'NUREG-1801 Consistency' regarding 'Exceptions toASME Code requirements that have been granted by approved Code Cases or relief requests are not considered to be exceptions to NUREG-1801 criteria'should be removed. The statement is not required. ASME Section XI, Subsection IWE alternatives expire prior to the period of extended operation.The statement under the 'Scope of Program' regarding 'These are notconsidered exceptions since the MNGP program has been reviewed by the NRC and is in accordance with 10 CFR 50.55a with NRC approved relief requests'should be removed. The statement is not required. ASME Section XI, Subsection IWE alternatives expire prior to the period of extended operation.The statement under the 'Parameters Monitored or Inspected' regarding 'Theseare not considered exceptions since the MNGP program has been reviewed by the NRC and is in accordance with 10 CFR 50.55a with NRC approved reliefrequests' should be removed. The statement is not required. ASME Section XI, Subsection IWE alternatives expire prior to the period of extended operation.The statement under the 'Detection of Aging Effects' regarding 'This is notconsidered an exception since the MNGP program has been reviewed by the
 
NRC and is in accordance with 10 CFR 50.55a with NRC approved reliefrequests' should be removed. The statement is not required. ASME Section XI, Subsection IWE alternatives expire prior to the period of extended operation.The statement under the 'Monitor and Trending' regarding 'This is notconsidered an exception since the MNGP program has been reviewed by the
 
NRC and is in accordance with 10 CFR 50.55a with NRC approved relief 3-22requests' should be removed. The statement is not required. ASME Section XI,Subsection IWE alternatives expire prior to the period of extended operation.The statement under the 'Corrective Actions' regarding 'This is not consideredan exception since the MNGP program has been reviewed by the NRC and is inaccordance with 10 CFR 50.55a with NRC approved relief requests' should beremoved. The statement is not required. ASME Section XI, Subsection IWE alternatives expire prior to the period of extended operation.The statement under the 'Confirmation Process' regarding 'This is notconsidered an exception since the MNGP program has been reviewed by the
 
NRC and is in accordance with 10 CFR 50.55a with NRC approved reliefrequests' should be removed. The statement is not required. ASME Section XI, Subsection IWE alternatives expire prior to the period of extended operation.The staff found the applicant's position acceptable, because the applicant removed referencesstating that relief requests were not considered exceptions to the GALL Report and the reliefrequests will not be credited for aging management.The staff reviewed those portions of the MNGP AMP B2.1.26 that the applicant claimed areconsistent with GALL AMP XI.S1 and found them consistent with the GALL Report AMP.Because it is consistent with the GALL Report, the AMP ensures that the effects of aging will beadequately managed. The staff found the applicant's AMP acceptable because it conforms to the recommended GALL Report AMP.Operating Experience. In LRA Section B2.1.26, the applicant explained that the PrimaryContainment In-Service Inspection Program, when implemented in conjunction with the 10 CFR 50, Appendix J Program and special examinations conducted to address specific industry issues, has demonstrated that aging of the primary containment, the internal vent system, and steel components within the torus is managed in an effective manner. Specialexaminations have verified the absence of significant corrosion in the drywell sand pocket region and on the normally submerged surfaces of the torus. The applicant also stated that leakage testing has been effective in early detection of passive isolation barrier deterioration (active barriers are outside the scope of the AMP). Examinations under the ISI program have shown that there is no significant corrosion on, or other deterioration of, accessible containmentshell, vent system, and penetration assembly surfaces.On the basis of its review of the above operating experience and discussions with theapplicant's technical personnel, the staff concluded that the Primary Containment In-ServiceInspection Program will adequately manage the aging effects identified in the LRA for which theAMP is credited.USAR Supplement. In LRA Section A2.1.26, the applicant provided the USAR supplement forthe Primary Containment In-Service Inspection Program. The staff reviewed this section and determined that the information in the USAR supplement adequately describes the program, asrequired by 10 CFR 54.21(d).Conclusion. On the basis of its review and audit of the applicant's Primary ContainmentIn-Service Inspection Program, the staff determined that those program elements for which the 3-23applicant claimed consistency with the GALL Report are consistent with the GALL Report. Thestaff concluded that the applicant demonstrated that the effects of aging will be adequatelymanaged so that intended functions will be maintained consistent with the CLB for the period ofextended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.1.7  Reactor Head Closure Studs ProgramSummary of Technical Information in the Application. In LRA Section B2.1.28, the applicantdescribed the Reactor Head Closure Studs Program, stating that this existing program is consistent with GALL AMP XI.M3, "Reactor Head Closure Studs." The MNGP Reactor Head Closure Studs Program is part of the MNGP ASME Section XI In-Service Inspection Program.
The Reactor Head Closure Studs Program is in accordance with the ASME Code, Section XI, 1995 Edition through the 1996 Addenda, and provides for condition monitoring of the reactor head closure stud bolting. Replacement reactor head studs available for use at MNGP include preventive measures described in Regulatory Guide (RG) 1.65, "Material and Inspection for Reactor Vessel Closure Studs," issued October 1973. The applicant updates the program periodically as required by 10 CFR 50.55a.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's evaluation of this AMP. The staff determined that this AMP is consistent with the AMPdescribed in the GALL Report, including the associated operating experience attribute.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.M3.During the audit and review, the staff noted that the applicant stated the following in LRASection B2.1.28:Exceptions to ASME requirements that have been granted by approved CodeCases or relief requests are not considered to be exceptions to NUREG-1801criteria.The staff asked that the applicant clarify this statement. The applicant responded that it usedCode Case -307-2, "Revised Ultrasonic Examination Volume for Class 1 Bolting, Table IWB-2500-1, Examination Category B-G-1, When the Examinations Are Conducted Fromthe End of the Bolt or Stud or From the Center-Drilled Hole," dated September 24, 1999, thatapplied to the reactor head closure studs. The applicant also used the ASME Code, Section XI, 2001 Edition, in lieu of the 1995 edition with addenda through 1996, for repair and replacement activities; the staff discusses this second exception below. Code users employ code cases when they cannot or do not want to perform a particular code requirement. This is an allowed exception to the application of the code by the user and thus is an exception to GALL Reportrecommendations. The staff determined that the code case used affected the GALL Reportrecommendation and that its use constituted an exception. In its letter dated August 11, 2005, 3-24supplemented by its letter dated August 31, 2005, the applicant stated that it will change itsapplication to identify the use of the code case as an exception to this AMP. The following provides the staff evaluation of these exceptions.Exception 1:  The GALL Report identifies the following recommendation for the ParametersMonitored or Inspected program element associated with the exception:The ASME Section XI ISI program detects and sizes cracks, detects loss ofmaterial, and detects coolant leakage by following the examination and inspection requirements specified in Table IWB-2500-1.In its letter dated August 11, 2005, the applicant stated that when conducting ultrasonic testing(UT) examinations from the end of the stud to satisfy ASME Code, Section XI, examination requirements, the examination volume may be limited to a cylinder of 1/4-inch thickness measured from the minor diameter and the length of the threaded portion of the stud.The staff confirmed that Table 1 of RG 1.147, Revision 13, "In-Service Inspection Code CaseAcceptability, ASME Section XI, Division 1," issued January 2004, lists Code Case -307-2.Based on this listing, the NRC staff has reviewed this code case and accepted it for generalindustry use.The staff then reviewed both the applicable ASME Code, Section XI ISI requirements for thereactor head closure studs and the alternative requirements of Code Case -307-2. ASME Code, Section XI, requires a visual examination of the surfaces of the reactor head closure nuts, washers, and bushings; a volumetric examination of the vessel flange threads and reactor head closure stud when examined in place; and a surface and volumetric examination of the reactor head closure stud when removed. In lieu of the volumetric examination required by ASME Code, Section XI, of essentially the entire volume of the reactor head closure stud, Code Case -307-2 allows examination of a cylindrical region of 1/4-inch thickness measured from the minor diameter of the reactor head closure stud and the length of the threaded portion of the stud. The staff noted that the use of this code case reduces the required examination volume tothe higher stress area of the bolting. The roots of the threads are stress risers and, hence, likelysites for crack initiation. Cracks at the roots of threads will be perpendicular to straight beam UTexamination from the end of the stud and will create a corner trap for angle beam UTexamination from the center hole. The staff reviewed the difference between the tworequirements and noted that the use of the code case alters the portion of the stud examinedbut continues to identify relevant aging effects (i.e., cracking and general corrosion) as the high-stress portion of the stud continues to be examined. Thus, the staff determined that theapplicant's use of the code case has no impact on the aging effect being managed.On the basis of a review of the above exception and of operating experience for AMP B2.1.28,"Reactor Head Closure Studs Program," the staff found this exception acceptable.Exception 2:  The GALL Report identified the following recommendation for the CorrectiveActions program element associated with the exception:Repair and replacement are in conformance with the requirements of IWB-4000and IWB-7000, respectively, and the material and inspection guidance of RG
 
1.65.
3-25In its letter dated August 11, 2005, the applicant stated that the staff has already genericallyreviewed and approved the use of the ASME Code, Section XI, 2001 edition, as an alternative to the 1995 edition with 1996 addenda, for repair and replacement  for aging management of systems and components within the scope of license renewal. Therefore, this alternative will notaffect the aging management of components crediting ISI performed in accordance with ASME Code, Section XI. The applicant provided the following justification, published in Volume 69 of
 
the Federal Register, pages 58804 and 58816 on October 1, 2004, accompanying the NRC'samendments to its regulations that incorporated, by reference, certain updated editions andaddenda of the ASME Code for use by NRC licensees:Accordingly, an applicant may use Subsections IWB, IWC, IWD, IWE, IWF, andIWL of Section XI of the ASME BPV Code (2001 Edition and the 2002 and 2003 Addenda) as acceptable alternatives to the requirements of the 1995 Edition up to and including the 1996 Addenda of the ASME Code, Section XI referenced in the GALL AMPs without the need to submit these alternatives for NRC review inits plant-specific license renewal application.Because the NRC staff has already reviewed and approved this alternative, related to repairand replacement, generically for aging management of systems and components within thescope of license renewal, the staff concluded that it does not need to be classified as an exception and that the affected program element is consistent with the GALL Report.Exception 3:  The GALL Report identified the following recommendations for the Scope ofProgram element associated with the exception:The program includes preventive measures of NRC Regulatory Guide 1.65 tomitigate cracking. The program is applicable to closure studs and nuts constructed from materials with a maximum tensile strength limited to less than 1172 MPa (170 ksi) (Nuclear Regulatory Commission [NRC] Regulatory Guide[RG] 1.65).The inspectors noted that RG 1.65 recommends that reactor head closure stud materialmeasured ultimate tensile strength not exceed 170 kilo-pounds per square inch (ksi) to minimize the likelihood of stress-corrosion cracking (SCC). Hardness tests conducted on the installed reactor head studs showed that most studs have greater than 170 ksi tensile stress.
The applicant committed to document this exception to NUREG-1801 in the LRA. In its letterdated March 15, 2006, the applicant stated the following:The Reactor Head Closure Studs Program does not incorporate the ultimatetensile strength requirement of NRC Regulatory Guide 1.65 for the existingreactor head closure studs. NMC considers this an acceptable exception to NUREG-1801, since these studs are considered susceptible to cracking atMNGP and NMC continues to manage them through the preventative measures recommended by Regulatory Guide 1.65 regardless of the tensile strength.The inspectors found this exception to the GALL Report acceptable because the applicantconsiders these studs to be susceptible to cracking, continues to manage the studs using the other preventive measures of RG 1.65, continues to conduct UT and surface examinations on a 10- year interval, and, to date, has identified no apparent discontinuities.
3-26The staff reviewed those portions of AMP B2.1.28 that the applicant claimed are consistent withGALL AMP XI.M3 and found them consistent. The staff found the applicant's AMP acceptable because it conforms to the recommended GALL Report AMP with the exceptions described.Operating Experience. In LRA Section B2.1.28, the applicant explained that the Reactor HeadClosure Studs Program has been effective in managing the aging effects of reactor pressure vessel (RPV) closure studs. The applicant has considered plant operating experience in the evaluation of stud performance. The MNGP inspection and testing methodologies have detected no cracking, nondestructive examination (NDE) indications, or aging effects for the RPV studs. Intergranular SCC (IGSCC) was seen in two RPV head studs at another plant. In response to this incident, MNGP performed field hardness testing and UT examination of the reactor head studs removed from the reactor cavity during the 1991 outage, evaluated the testresults, and evaluated the original certified material test reports. It found no evidence of RPV head stud cracking.The staff reviewed the operating experience provided in the LRA and interviewed theapplicant's technical personnel to confirm that plant-specific operating experience revealed no degradation not bounded by industry experience.On the basis of its review of the above industry and plant-specific operating experience anddiscussions with the applicant's technical personnel, the staff concluded that the applicant'sReactor Head Closure Stud Program will adequately manage the aging effects identified in theLRA for which this AMP is credited.USAR Supplement. In LRA Section A2.1.28, the applicant provided the USAR supplement forthe Reactor Head Closure Studs Program. The staff reviewed this section and determined that the information in the USAR supplement adequately describes the program, as required by 10 CFR 54.21(d).Conclusion. On the basis of its review and audit of the applicant's Reactor Head Closure StudsProgram, the staff determined that those program elements for which the applicant claimedconsistency with the GALL Report are consistent with the GALL Report. The staff concluded that the applicant demonstrated that the effects of aging will be adequately managed so thatintended functions will be maintained consistent with the CLB for the period of extendedoperation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.1.8Thermal Aging & Neutron Irradiation Embrittlement of Cast Austenitic StainlessSteel (CASS) ProgramSummary of Technical Information in the Application. In LRA Section B2.1.33, the applicantdescribed the Thermal Aging & Neutron Irradiation Embrittlement of CASS Program, stating that this existing program is consistent with GALL AMP XI.M13, "Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel (CASS)." The MNGP Thermal Aging and Neutron Irradiation Embrittlement of CASS Program monitors the aging effects of loss of fracture toughness on the intended function of the component by performing examinations onCASS reactor vessel internal components as part of the MNGP ASME Section XI In-Service Inspection Program. The Thermal Aging and Neutron Irradiation Embrittlement of CASS 3-27Program is in accordance with ASME Code, Section XI, Subsection IWB, Category B--1 andB--2 requirements, and provides for condition monitoring of the CASS components. The applicant performs additional enhanced visual inspections that incorporate the requirements of the Boiling Water Reactor Vessel and Internals Project (BWRVIP) to detect the effects of loss of fracture toughness due to thermal aging and neutron irradiation embrittlement of CASS reactor vessel internals. The applicant updates the program periodically as required by 10 CFR 50.55a.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's evaluation of this AMP. The staff determined that this AMP is consistent with the AMPdescribed in the GALL Report, including the associated operating experience attribute.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.M13.During the audit and review, the staff questioned the applicant regarding the screening criteriafor determining the susceptibility of CASS components to thermal aging. The applicant statedthat it does not address this screening process; instead, the program includes all CASS reactor vessel internal components. These components consist of jet pump assembly castings, the orifice fuel support casting, and the guide tube base casting. The staff found this approach conservative and therefore acceptable.During the audit and review, the staff asked the applicant whether its current approved ISI reliefrequests or code cases affect any of its AMP program elements. In its letter dated August 31, 2005, the applicant identified the following exception to the GALL Report program element.Exception:  The GALL Report identifies the following recommendations for the CorrectiveActions program element associated with the exception taken:Repair is in conformance with IWA-4000 and IWB-4000, and replacement is inaccordance with IWA-7000 and IWB-7000.In its letter dated August 11, 2005, the applicant stated that an approved alternative allows theuse of the ASME Code, Section XI, 2001 edition in lieu of the 1995 edition with the 1996 addenda for repair/replacement activities. Section 3.0.3.1.7 of the SER provides the staff'sevaluation of this exception.Because the NRC has already reviewed and approved this alternative, relating to repair andreplacement, generically for aging management of systems and components within the scopeof license renewal, the staff concluded that it does not need to be classified as an exception and that, with regard to this item, the affected program element is consistent with the GALL Report.The staff reviewed those portions of AMP B2.1.33, "Thermal Aging & Neutron IrradiationEmbrittlement of Cast Austenitic Stainless Steel (CASS) Program," that the applicant claimed are consistent with GALL AMP XI.M13 and found them consistent. The staff found the 3-28applicant's AMP acceptable because it conforms to the recommended GALL Report AMP withthe exception described.Operating Experience. In LRA Section B2.1.33, the applicant explained that the Thermal Aging& Neutron Irradiation Embrittlement of CASS Program has been effective in managing aging effects due to thermal aging and neutron irradiation embrittlement. The applicant periodically examines materials within the scope of the program and evaluates them for corrective action as needed. In addition to ASME inspection requirements, the applicant follows vendor guidance (e.g., BWRVIP-03, "BWR Vessel and Internals Project, Reactor Pressure Vessel and Internals Examination Guidelines," and BWRVIP-41, "BWR Jet Pump Assembly Inspection and Flaw Evaluation Guidelines").In addition, the staff reviewed the operating experience provided in the LRA and interviewed theapplicant's technical personnel to confirm that plant-specific operating experience revealed no degradation not bounded by industry experience.On the basis of its review of the above operating experience and discussions with theapplicant's technical personnel, the staff concluded that the applicant's Thermal Aging &Neutron Irradiation Embrittlement of CASS Program will adequately manage the aging effectsidentified in the LRA for which this AMP is credited.USAR Supplement. In LRA Section A2.1.33, the applicant provided the USAR supplement forthe Thermal Aging & Neutron Irradiation Embrittlement of CASS Program. The staff reviewed this section and determined that the information in the USAR supplement adequately describesthe program, as required by 10 CFR 54.21(d).Conclusion. On the basis of its review and audit of the applicant's Thermal Aging & NeutronIrradiation Embrittlement of CASS Program, the staff determined that those program elementsfor which the applicant claimed consistency with the GALL Report are consistent with the GALLReport. The staff concluded that the applicant demonstrated that the effects of aging will beadequately managed so that intended functions will be maintained consistent with the CLB forthe period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.1.9Electrical Equipment Subject to 10 CFR 50.49 EQ Requirements ProgramSummary of Technical Information in the Application. In LRA Section B3.1, the applicantdescribed the Electrical Equipment Subject to 10 CFR 50.49 EQ Requirements Program, stating that this existing program that is consistent with GALL AMP X.E1, "EnvironmentalQualification (EQ) of Electric Components." The purpose of the MNGP EQ program is to ensure that SR electrical equipment is capable of performing its function in a harsh environment (effects of a loss-of-coolant accident (LOCA), high-energy line break (HELB), or post-LOCA radiation) and is qualified in accordance with the Equipment Qualification Final Rule, 10 CFR 50.49, dated February 22, 1983. This program describes EQ program attributes, andhow those attributes ensure that the EQ program remains effective throughout the licenserenewal period (60 years).
3-29Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's evaluation of this AMP. The staff determined that this AMP is consistent with the AMPdescribed in the GALL Report, including the associated operating experience attribute.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's MNGP audit and review report, which assesses the consistency of the AMP elements with GALL AMP X.E1.The staff reviewed those portions of AMP B3.1, "Electrical Equipment Subject to 10 CFR 50.49EQ Requirements Program," that the applicant claimed are consistent with GALL AMP X.E1and found them consistent. Because it is consistent with the GALL Report, the AMP ensures that the effects of aging will be adequately managed. The staff found the applicant's AMPacceptable because it conforms to the recommended GALL Report AMP.Operating Experience. In LRA Section B3.1, the applicant explained that the MNGP EQprogram includes monitoring and assessment of industry information in order to assess its impact on EQ components at MNGP. The EQ Coordinator is responsible for reviewing the disposition of such information, as well as subsequent assignment of actions to be taken, and confirming that completion of the actions has satisfactorily addressed potential MNGP EQ aging issues. The following examples provide objective evidence that the MNGP EQ program is responsive to externally identified operating experience items as well as proactive in self-identification activities:
* An NRC safety system design inspection, conducted in March 2003, resulted in twogreen findings and four corrective actions.
* A nuclear oversight quality assurance (QA) assessment in June 2003 resulted in nofindings.
* The 2001 internal self-assessment resulted in a determination of effectiveimplementation, but noted specific areas needing improvement and additionalrecommendations for continued improvement.
* The applicant periodically performs program health reviews to measure the acceptabilityof the program and identify improvements as applicable in accordance with MNGP and NMC Fleet procedures.
* The applicant conducts operating experience reviews of EQ issues identified at othersites and processes these items through the CAP.On the basis of its review of the above operating experience and discussions with theapplicant's technical personnel, the staff concluded that the Electrical Equipment Subject to10 CFR 50.49 EQ Requirements Program will adequately manage the aging effects observedat the applicant's plant.USAR Supplement. In LRA Section A4.1, the applicant provided the USAR supplement for theElectrical Equipment Subject to 10 CFR 50.49 EQ Requirements Program. The staff reviewed this section and determined that the information in the USAR supplement adequately describesthe program, as required by 10 CFR 54.21(d).
3-30Conclusion. On the basis of its review and audit of the applicant's Electrical Equipment Subjectto 10 CFR 50.49 EQ Requirements Program, the staff determined that those program elementsfor which the applicant claimed consistency with the GALL Report are consistent with the GALLReport. The staff concluded that the applicant demonstrated that the effects of aging will beadequately managed so that intended functions will be maintained consistent with the CLB forthe period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.2  AMPs That Are Consistent with the GALL Report with Exceptions or EnhancementsIn LRA Appendix B, the applicant identified the following AMPs that are, or will be, consistentwith the GALL Report, with exceptions or enhancements:
* 10 CFR 50, Appendix J Program (B2.1.1)
* ASME Section XI In-Service Inspection, Subsections IWB, IWC, and IWDProgram (B2.1.2)
* ASME Section XI, Subsection IWF Program (B2.1.3)
* Bolting Integrity Program (B2.1.4)
* Buried Piping & Tanks Inspection Program (B2.1.5)
* BWR Control Rod Drive (CRD) Return Line Nozzle Program (B2.1.7)
* BWR FW Nozzle Program (B2.1.8)
* BWR Penetrations Program (B2.1.9)
* BWR Stress Corrosion Cracking (SCC) Program (B2.1.10)
* BWR Vessel Inside Diameter (ID) Attachment Welds Program (B2.1.11)
* BWR Vessel Internals Program (B2.1.12)
* Closed-Cycle Cooling Water (CCCW) System Program (B2.1.13)
* Compressed Air Monitoring Program (B2.1.14)
* Electrical Cables Not Subject to 10 CFR 50.49 EQ Requirements Used inInstrumentation Circuits Program (B2.1.16)
* Fire Protection Program (B2.1.17)
* Fire Water System Program (B2.1.18)
* Fuel Oil Chemistry Program (B2.1.20)
* Inspection of Overhead Heavy Load and Light Load (Related to Refueling) HandlingSystems Program (B2.1.22)
* Plant Chemistry Program (B2.1.25)
* Protective Coating Monitoring & Maintenance Program (B2.1.27)
* Reactor Vessel Surveillance Program (B2.1.29) 3-31
* Selective Leaching of Materials Program (B2.1.30)
* Structures Monitoring Program (B2.1.31)
* Metal Fatigue of the Reactor Coolant Pressure Boundary Program (B3.2)For AMPs that the applicant claimed are consistent with the GALL Report, with exceptions orenhancements, the staff performed an audit to confirm that those attributes or features of theprogram for which the applicant claimed consistency with the GALL Report are indeed consistent. The staff also reviewed the exceptions and enhancements to the GALL Report to determine whether they are acceptable and adequate. The following sections document theresults of the staff's audit and reviews.3.0.3.2.1  10 CFR 50, Appendix J Program Summary of Technical Information in the Application. In LRA Section B2.1.1, the applicantdescribed the 10 CFR 50, Appendix J Program, stating that this existing program is consistent,with exceptions, with GALL AMP XI.S4, "10 CFR Part 50, Appendix J." The MNGP 10 CFR 50, Appendix J Program specifies pneumatic pressure tests and visual examinations to verify the structural and leak-tight integrity of the primary containment. An overall (Type A) pressure test assesses the capacity of the containment to retain design-basis accident (DBA) pressure. This test also measures total leakage through the containment pressure-retaining boundary. Local (Type B & C) tests measure leakage through individual penetration isolation barriers. These barriers are maintained as required to keep overall and local leakage under technical specification (TS) and plant administrative limits. The applicant performs tests at intervals determined by the risk and performance factors applicable to each tested item in accordance with governing regulations and standards. Visual examinations are performed before each Type A test. The applicant also performs these examinations at least once during each containment ISI period in which no Type A test is conducted. The examinations are performed to detect corrosion and other types of deterioration on the accessible surfaces of the containment.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's audit evaluation of this AMP. The staff reviewed the exceptions and the associated justifications todetermine whether the AMP, with the exceptions, remains adequate to manage the agingeffects for which it is credited.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.S4.In the LRA, the applicant stated the following exceptions to the program elements listed forAMP XI.S4 in the GALL Report.Exception 1: The GALL Report identifies the following recommendation for the Scope ofProgram element associated with the exception taken:The scope of the containment LRT program includes all pressure-retainingcomponents. Two types of tests are implemented. Type A tests are performed to measure the overall primary containment integrated leakage rate which is 3-32obtained by summing leakage through all potential leakage paths includingcontainment welds, valves, fittings, and components that penetrate containment.Type B tests are performed to measure local leakage rates across each pressure-containing or leakage-limiting boundary for containment penetrations.
Type A and B tests described in 10 CFR Part 50, Appendix J, are acceptable methods for performing these LRTs. Leakage testing for containment isolation valves (normally performed under Type C tests), if not included under this program, is included under LRT programs for systems containing the isolationvalves.In the LRA, the applicant stated that main steam isolation valves (MSIVs) are tested at25 pounds per square inch gauge (psig) instead of at an accident pressure of 42 psig. The applicant indicated that Section III.C.2 of Appendix J, "Primary Reactor Containment LeakageTesting for Water-Cooled Power Reactors," to 10 CFR Part 50, "Domestic Licensing of Production and Utilization Facilities," requires, in part, that Type C testing be performed at thepeak calculated accident pressure, which for MNGP is 42 psig. The outboard MSIVs are tested by pressurizing the volume between the inboard and outboard valves. The inboard MSIVs at MNGP are angled (Y-pattern globe) in the main steamlines for better closure characteristics. A test pressure at the peak calculated accident pressure (42 psig) acting under the inboard valve disc could lift the disc off its seat and cause excessive leakage into the vessel. The NRC hasapproved Type C testing of these valves at a reduced pressure of 25 psig as part of a request for relief (letter from Darrell G. Eisenhut, NRC, to D.M. Musolf, NMC, dated June 3, 1984). Thestaff determined that the inboard valves are the same design as the valves evaluated by the NRC and that a test pressure alternative in the leakage test will have no impact on agingmanagement. Therefore, the staff concluded that this exception is acceptable.Exception 2:  The GALL Report identifies the following recommendation for the Monitoring andTrending program element associated with the exception taken:Because the LRT program is repeated throughout the operating license period,the entire pressure boundary is monitored over time. The frequency of these tests depends on which option (A or B) is selected. With Option A, testing is performed on a regular fixed time interval as defined in 10 CFR Part 50, Appendix J. In the case of Option B, the interval for testing may be increased on the basis of acceptable performance in meeting leakage limits in prior tests.
Additional details for implementing Option B are provided in NRC RegulatoryGuide 1.163 and NEI 94-01, Rev. 0.In the LRA, the applicant stated that the Type A test interval is extended, on a one-time basis,to 15 years, exceeding the 10-year interval limit in NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J," issued March 1996.
The applicant stated that MNGP is currently under Option B, "Performance-Based Requirement," of Appendix J to perform the Type A containment integrated leakage rate test. In accordance with Option B provisions and acceptable Type A test performance history, the Type A testing will occur at a frequency of 10 years. The most recent Type A test was in March 1993;thus, the applicant will have to perform the subsequent test no later than March 2003. Followinggeneral industry practice, the applicant submitted a request for a one-time test interval extension to 15 years based on a plant-specific, risk-based evaluation. The staff approved this request in a letter from L.M. Padovan, NRC, to D.L. Wilson, NMC, dated March 31, 2003; 3-33therefore, MNGP will have to perform one Type A test no later than March 2008, before theperiod of extended operation. The frequency of future Type A tests will be determi ned on thebasis of the next Type A test results and the limit set forth in Appendix J, Option B.The staff found that, in addition to the integrated leakage test, Type A test requirements includevisual examination of the containment exterior and interior to detect conditions that mightadversely affect structural integrity or leak tightness. The applicant performs an examination before each Type A test and between tests at nominal intervals of 40 months. Because MNGP followed its CLB in having a Type A test interval extended once to 15 years ending before the period of extended operation and the additional visual examination requirements are in place, the staff found this exception acceptable.The staff reviewed those portions of the AMP B2.1.1, "10 CFR 50, Appendix J Program," thatthe applicant claimed are consistent with GALL AMP XI.S4 and found them consistent. Thestaff found the applicant's AMP acceptable because it conforms to the recommended GALL Report AMP with the exceptions as described above.Operating Experience. In LRA Section B2.1.1, the applicant explained that the 10 CFR 50,Appendix J Program tests conducted under the program have been effective principally in detecting developing leakage through containment isolation valves, which, as active components, are outside the scope of the AMP. Testing has also detected developing leakagein both an electrical penetration conductor seal and a hot piping penetration expansion bellows.
The applicant corrected both of these conditions while the leakage was still small. MNGP iscommitted to the risk- and performance-based program defined by Option B of Appendix J".
This approach uses plant- and industrywide operating experience as the bases for defining the performance and risk factors, which, in turn, are used to determine testing intervals. Using this approach enhances the effectiveness of the program as an aging management tool by concentrating testing and maintenance resources on components that have higher risk and/or ahistory of high leakage.The staff reviewed the operating experience provided in the LRA and interviewed theapplicant's technical personnel to confirm that plant-specific operating experience revealed no degradation not bounded by industry experience.On the basis of its review of the above operating experience and discussions with theapplicant's technical personnel, the staff concluded that the applicant's 10 CFR 50, Appendix JProgram will adequately manage the aging effects identified in the LRA for which this AMP iscredited.USAR Supplement. In LRA Section A2.1.1, the applicant provided the USAR supplement forthe 10 CFR 50, Appendix J Program. The staff reviewed this section and determined that the information in the USAR supplement adequately describes the program, as required by 10 CFR 54.21(d).Conclusion. On the basis of its review and audit of the applicant's 10 CFR 50, Appendix JProgram, the staff determined that those program elements for which the applicant claimedconsistency with the GALL Report are consistent with the GALL Report. In addition, the staffreviewed the exceptions and the associated justifications and determined that the AMP, with theexceptions, is adequate to manage the aging effects for which it is credited. The staff 3-34concluded that the applicant demonstrated that the effects of aging will be adequately managedso that intended functions will be maintained consistent with the CLB for the period of extendedoperation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.2.2  ASME Section XI In-Service Inspection, Subsections IWB, IWC, and IWD Program Summary of Technical Information in the Application. In LRA Section B2.1.2, the applicantdescribed the ASME Section XI In-Service Inspection, Subsections IWB, IWC, and IWD Program, stating that this existing program is consistent, with exception, with GALL AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD." The MNGP ASME Section XI In-Service Inspection, Subsections IWB, IWC, and IWD Program is part of the MNGP ASME Section XI In-Service Inspection Program. This program is in accordance with the ASME Code, Section XI, 1995 edition through the 1996 addenda and is subject to the limitations and modifications of 10 CFR 50.55a. The program provides for condition monitoring of Class 1, 2, and 3 pressure-retaining components and their integral attachments. The applicant inspects Class 1 and 2 piping in accordance with the risk informed ISI (RI-ISI) program as described in the EPRI Topical Report (TR)-112657, Revision B-A, "Revised Risk Informed In-Service Inspection Evaluation Procedure." The NRC has approved the use of RI-ISIin a safety evaluation (SE) documented in an NRC letter dated July 24, 2002, "MonticelloNuclear Generating Plant-Risk Informed In-Service Inspection Program (TAC No. MB3819)."
The applicant updates the program periodically as required by 10 CFR 50.55a. The Plant Chemistry Program augments this program where applicable.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's audit evaluation of this AMP. The staff reviewed the exceptions and the associated justifications todetermine whether the AMP, with the exceptions, remains adequate to manage the agingeffects for which it is credited.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.M1.In the LRA, the applicant stated the following exceptions to the program elements listed forAMP XI.M1 in the GALL Report.Exceptions 1 and 2:  The GALL Report recommends the following for the Scope of Programelement associated with the exception taken:The ASME Section XI program provides the requirements for ISI, repair, andreplacement. The components within the scope of the program are specified in Subsections IWB-1100, IWC-1100, and IWD-1100 for Class 1, 2, and 3 components, respectively, and include all pressure-retaining components and their integral attachments in light-water cooled power plants. The componentsdescribed in Subsection IWB-1220, IWC-1220 and IWD-1220 are exempt from the examination requirements of Subsections IWB-2500, IWC-2500, and IWD-2500.
3-35In the LRA, the applicant stated that, pursuant to 10 CFR 50.55a(b)(2)(xi), it uses therequirements of IWB-1220 in the 1989 edition of the ASME Code, Section XI, for Class 1 piping instead of the 1995 edition of the ASME Code, Section XI, with the 1996 addenda and that, pursuant to 10 CFR 50.55a(b)(2)(xxi)(B), reused CRD bolting must meet examinationrequirements for Table IWB-2500-1, Category B-G-2, Item B7.80, of the 1995 edition of theASME Code, Section XI.The staff determined that both of the items that the applicant identified as exceptions are, infact, requirements codified in 10 CFR 50.55a and that the Scope of Program program element in the GALL Report mentions no specific ASME Code, Section XI, edition or addenda. The staff asked the applicant why it considered these items exceptions to the GALL Report. The applicant stated that it "conservatively" identified these items as exceptions solely because theyare requirements not contained in the ASME Code, Section XI, 1995 edition through 1996 addenda identified in the GALL Report program description for this AMP. The applicant stated that these codified requirements result in inspections that otherwise will not be required by the1995 edition through 1996 addenda of the ASME Code, Section XI. Because the items identified by the applicant are requirements codified in 10 CFR 50.55a and necessitate more stringent examinations than the ASME Code, Section XI, 1995 edition through 1996 addenda would otherwise call for, the staff found these exceptions acceptable.During the audit and review, the staff asked the applicant whether its approved ISI reliefrequests or code cases affect any of the AMP elements. The applicant stated that code cases and relief requests for the MNGP ASME Section XI In-Service Inspection, Subsections IWB, IWC, IWD, and IWF Program are valid for approximately 21 months into the period of extended operation and that the current inspection interval ends on May 31, 2012. In addition, theapplicant provided results of its reevaluation of code cases and relief requests as documented in its letter dated August 31, 2005. That reevaluation identified six additional exceptions(Exceptions 3 through 8) to the GALL Report program elements. The following paragraphs describe and evaluate these additional exceptions to the GALL Report.Exception 3:  The GALL Report identifies the following recommendation for the Detection ofAging Effects program element associated with the exception taken:Category B-G-1 specifies volumetric examination of studs in place, from the top of thenut to the bottom of the flange hole; surface and volumetric examination of studs when removed; volumetric examination of flange threads; and visual VT-1 examination of the surfaces of nuts, washers, and bushings.In its letter dated August 11, 2005, the applicant stated that its ASME Section XI In-ServiceInspection, Subsections IWB, IWC, and IWD Program includes implementation of Code Case N-307-2, which revises the UT examination volume for Class 1 bolting.Table 1 of RG 1.147 lists Code Case N-307-2. The applicant categorized implementation ofthis code case as an exception to the GALL Report because the description of the Detection of Aging Effects program element in GALL Report AMP XI.M1 references ASME Code, Section XI, Table IWB-2500-1, Examination Category B-G-1. The applicant stated that the onlyClass 1 bolts at MNGP with center holes are the reactor head closure studs and the reactor recirculation (REC) pump bolts. The applicant also stated that provisions of this code case were added to Table IWB-2500-1, Figure IWB-2500-12, and Appendix VIII, Supplement 8, 1.1(c), to 3-36the 2000 addenda of the ASME Code, Section XI. The applicant stated that this code casechanges the portion of the bolt evaluated but will still detect the presence of the relevant agingeffect. Because this code case only changes the portion of the component examined and continues to examine all applicable components in a way that will detect relevant aging effects,the staff concluded that this exception to the GALL Report is acceptable.Exception 4:  The GALL Report identifies the following recommendation for the Monitoring andTrending program element associated with the exception taken:For Class 1, 2, or 3 components, the inspection schedule of IWB-2400,IWC-2400, or IWD-2400, respectively, and the extent and frequency of IWB-2500-1, IWC-2500-1, or IWD-2500-1, respectively, provides for timely detection of degradation.In its letter dated August 11, 2005, the applicant stated that its ASME Section XI In-ServiceInspection, Subsections IWB, IWC, and IWD Program includes implementation of Code Case N-526, Revision 13, "In-Service Inspection Code Case Acceptability, ASME Section XI,Division 1," issued January 2004, which provides alternative requirements for successive inspections mandated by IWB-2420 and IWC-2420 when areas of the vessel are found, by volumetric examinations, to contain subsurface flaws.Table 1 of RG 1.147 lists Code Case N-526. The applicant categorized implementation of thiscode case as an exception to the GALL Report because the successive inspections required by IWB-2420 and IWC-2420 may be waived when a flaw is found acceptable for continued service in accordance with IWB-3600. In its letter dated August 11, 2005, the applicant stated thatvessel aging effects are still managed and that any flaws for which successive inspections arewaived are required to be acceptable for continued service in accordance with IWB-3600. The applicant also stated that the ASME Code, Section XI, requires that the sequence ofcomponent examinations established during the first inspection interval be repeated during each successive inspection interval to the extent practical. Because any flaws are determined to be acceptable in accordance with IWB-3600 and component examinations are required to be repeated during successive inspection intervals (so that any flaw area will be reexami ned atleast once in each inspection interval), the staff concluded that this exception to the GALL Report is acceptable.Exception 5:  The GALL Report identifies the following recommendation for the Detection ofAging Effects program element associated with the exception taken:Class 1 Components, Table IWB-2500-1Examination Category B-D, for full penetration welds of nozzles in reactorvessels, pressurizers, steam generators (primary side), and heat exchangers (primary side):  This category specifies volumetric examination of all nozzle-to-vessel welds and the nozzle inside radius.In its letter dated August 11, 2005, the applicant stated that its ASME Section XI In-ServiceInspection, Subsections IWB, IWC, and IWD Program will deviate from the requirements of 3-37ASME Code, Section XI, Table IWB-2500-1 and Figure IWB-2500-7(b) with regard to theexamination volume for Category B-D components (full penetration welded nozzles in vessels).The applicant identified that, based on its implementation of ASME Code, Section XI, CodeCase N-613-1, "Ultrasonic Examination of Penetration Nozzles in Vessels, Examination Category B-D, Item Nos. B3.10 and B3.90, Reactor Nozzle to Vessel Welds, Figs. IWB-2500-7(a), (b), and (c), Section XI, Division 1," issued June 2001, examination of Category B-D components will deviate from the requirements of the 1995 edition through 1996 addenda ofASME Code, Section XI, Table IWB-2500-1, Item No B3.90 and from the requirements of ASME Code, Section XI, Figure IWB-2500-7(b). Specifically, Figure IWB-2500-7(b) requires that a minimum volume of material equal to a distance of one-half the reactor vessel shell thickness (i.e., a distance of approximately 2-1/2 inches for MNGP) be included in the examination volume on each side of the weld; however, the applicant's ASME Section XI In-Service Inspection, Subsections IWB, IWC, and IWD Program at MNGP, instead, includes a reduced examination volume of one-half inch of base metal on each side of the widest portion of the weld. The applicant provided the following technical justification for the reduction in examination volume:The required examination volume for the reactor vessel pressure retainingnozzle-to-vessel welds extends far beyond the weld into the base metal, and is unnecessarily large. The proposed alternative re-defined the examination volume boundary to 1/2 inch of base metal on each side of the widest portion of the weld, removing from examination the base metal that was extensively examined during prior inspections, and that is not in the high residual stress region associated with the weld.The creation of flaws during plant service in the volume excluded from theproposed reduced examination is unlikely because of the low stress in the base metal away from the weld. The stresses caused by welding are concentrated at or near the weld. Cracks, should they initiate, occur in the high-stressed areas ofthe weld. These high-stress areas are contained in the volume that is defined by Code Case N-613-1 and are thus subject to examination. During previous examinations, no indications exceeding the allowable limits of the preservice or Inservice criteria were found in the reactor vessel nozzle to shell examination volumes including the base metal areas proposed for exclusion from examination in this request.The staff reviewed the applicant's description and technical justification for this exceptionsummarized in the preceding paragraph. The staff also reviewed the applicant's request for relief, "Request for Authorization to Utilize Code Case N-613-1," dated February 27, 2004,which provides a similar technical justification and includes tables of previous examination results. Because the examination volume will still include the heat-affected regions of basemetal around the welds where new cracks are most likely to occur and previous examinations ofthe base metal beyond the heat-affected regions have detected no unacceptable conditions, thestaff concluded that this exception is acceptable.Exception 6:  The GALL Report identifies the following recommendation for the CorrectiveActions program element associated with the exception taken:
3-38For Class 1, 2, and 3, respectively, repair is in conformance with IWB-4000,IWC-4000, and IWD-4000, and replacement according to IWB-7000, IWC-7000, and IWD-7000. Approved BWRVIP-44 and BWRVIP-45 documents, respectively, provide guidelines for weld repair of nickel alloys and for weldabilityof irradiated structural components.In its letter dated August 11, 2005, the applicant stated that an approved alternative allows theuse of the 2001 edition of the ASME Code, Section XI, in lieu of the 1995 edition with the 1996 addenda for repair/replacement activities. Section 3.0.3.1.7 of this SER provides the staff's evaluation of this exception.On the basis that the NRC staff has already reviewed and approved this alternative related torepair and replacement generically for aging management of systems and components withinthe scope of license renewal, the staff concluded that it is not an exception and that the affectedprogram element is consistent with the GALL Report.Exception 7:  The GALL Report identifies the following recommendation for the Detection ofAging Effects program element associated with the exception taken:Components are examined and tested as specified in Tables IWB-2500-1,IWC-2500-1, and IWD-2500-1, respectively, for Class 1, 2, and 3 components.
The tables specify the extent and schedule of the inspection and examinationmethods for the components of the pressure-retaining boundaries. Alternative approved methods that meet the requirements of IWA-2240 are also specified inthese tables.In its letter dated August 11, 2005, the applicant stated that its ASME Section XI In-ServiceInspection, Subsections IWB, IWC, and IWD Program includes an RI-ISI methodology that provides an alternative to the ASME Code, Section XI, ISI requirements as to (1) the number of locations inspected, (2) the locations inspected, and (3) the method of inspection. Thisalternative applies to welds in ASME Code, Section XI, Categories B-F (Class 1 pressure retaining dissimilar metal welds in vessel nozzles), B-J (Class 1 pressure retaining welds in piping), C-F-1 (Class 2 pressure retaining welds in austenitic stainless steel or high-alloy piping), and C-F-2 (Class 2 pressure retaining welds in carbon or low-alloy steel piping).The applicant submitted a description of its RI-ISI program in its letter dated December 18,2001, "Alternative to the ASME Boiler and Pressure Vessel Code Section XI Requirements for Class 1 and 2 Piping Welds-Risk Informed In-Service Inspection Program."  In a letter, "Monticello Nuclear Generating Plant-Risk-Informed In-Service Inspection Program (TAC No.
MB3818)," dated July 24, 2002, the NRC documents authorization for the applicant's RI-ISIprogram during the current (fourth) 10-year ISI interval.In its letter dated August 11, 2005, supplemented by its August 31, 2005, letter, the applicantjustified continuation of its RI-ISI program into the period of extended operation:...The RI-ISI program maintains the fundamental requirements of ASMESection XI, such as the examination technique, examination frequency, and acceptance criteria. Although the RI-ISI program reduces the number of required examination locations, it maintains an acceptable level of quality and safety 3-39pursuant to 10 CFR 50.55a(a)3, by focusing inspections on the most safetysignificant welds with nondestructive examination techniques that are more focused towards finding the type of expected degradation as well as the types of flaws and degradation found during traditional inspections.A systematic approach was used to identify component susceptibility to commondegradation mechanisms and to categorize these degradation mechanisms into the appropriate degradation categories with respect to their potential to result in a postulated leak or rupture in the pressure boundary. An evaluation to determine the susceptibility of components to a particular degradationmechanism that may be a precursor to a leak or rupture in the pressure boundary, and an independent assessment of the consequences of a failure at that location were performed. Industry and plant-specific piping operating experience was used to identify piping degradation mechanisms and failure modes, and consequence evaluations performed used probabilistic riskassessment to establish safety ranking of piping segments for selecting new inspection locations. The degradation mechanisms identified in the RI-ISI Program include thermal fatigue including thermal stratification, cycling, and striping (TASCS) and thermal transients (TT); intergranular stress corrosion cracking (IGSCC); and flow-accelerated corrosion (FAC). The consequences of pressure boundary failures were evaluated and ranked on their impact on core damage and early release. Therefore, redistributing the welds to be inspected with consideration of the safety significance of the segments provides assurance that segments whose failure have a significant impact on plant risk receive an acceptable and improved level of inspection.The RI-ISI examinations result in improved detection of service-relateddegradations over those currently required by ASME Section XI. Therefore, the aging effect of cracking continues to be adequately managed for the piping welds.The staff reviewed the applicant's technical justification for this exception. In addition, the staffreviewed the applicant's detailed RI-ISI program description in its letter requesting relief, dated December 18, 2001, and NRC authorization to implement the RI-ISI program in a letter datedJuly 24, 2002. Based on its review of these documents, the staff determined the following:
* The letter from MNGP dated December 18, 2001, lists 15 systems that its RI-ISIprogram encompasses.
* For 10 of the 15 systems that the RI-ISI methodology characterizes in the high- ormedium-risk regions, the MNGP RI-ISI program will change the location and categoryand, typically, will reduce the number of inspected welds from the ASME Code,Section XI, numbers, locations, and categories. However, the applicant will conti nue toinspect a representative number of welds in each of these systems per ASME Code,Section XI, requirements.
* For 5 of t he 15 systems (component cooling water, control rod drive (CRD) hydraulic,fuel pool emergency cooling, primary containment and atmospheric control, and torus hard vent systems) where the RI-ISI methodology characterizes all pipe welds in the 3-40low-risk region, the MNGP RI-ISI program will eliminate inspection of welds previouslyinspected in accordance with ASME Code, Section XI, requirements.
* The NRC staff review of the applicant's RI-ISI program, documented in a letter datedJuly 24, 2002, concluded that the MNGP RI-ISI program will provide an acceptable levelof quality and safety pursuant to 10 CFR 50.55a with regard to the number of inspections, locations of inspections, and methods of inspections.Supported by its previous approval of the applicant's RI-ISI program, the staff concluded thatthe ASME Section XI In-Service Inspection, Subsections IWB, IWC, and IWD Program, as modified by the RI-ISI program approved by the NRC in a letter dated July 24, 2002, isacceptable for managing applicable component aging effects through the end of the applicant's current ISI inspection interval on May 31, 2012, approximately 21 months into the extendedoperating period. The staff based this conclusion on the fact that (1) the Class 1 and 2 weldsaffected by implementation of RI-ISI representative welds most susceptible to various age-related degradation mechanisms are still examined to ASME Code, Section XI,requirements, (2) any continuation of the RI-ISI program into the period of extended operationbeyond May 31, 2012, will require review and authorization pursuant to 10 CFR 50.55a, and (3)any subsequent authorization to continue the RI-ISI program into the next ISI inspection interval will include consideration of any adverse industry or plant-specific operating experience thatmight preclude the use or require modification of the RI-ISI program for affected component aging management through the period of extended operation. On the basis of theseconsiderations, the staff concluded that the applicant's implementation of RI-ISI is anacceptable exception to the Detection of Aging Effects program element as described in the GALL Report for AMP XI.M1.Exception 8:  The GALL Report recommends the following for the Detection of Aging Effectselement associated with the exception taken:Examination category B-H for integral attachments for vessels:  This categoryspecifies volumetric or surface examination of essentially 100% of the length of the attachment weld at each attachment subject to examination.In its letter dated August 11, 2005, the applicant stated that based on a relief request approvedpursuant to 10 CFR 50.55a, its ASME Section XI In-Service Inspection, Subsections IWB, IWC, and IWD Program excludes volumetric or surface examination of the reactor vessel stabilizerbracket welds to the exterior of the RPV. The 1995 edition of the ASME Code, Section XI, classifies the reactor vessel stabilizer bracket welds as Category B-H components (integralattachments for vessels) in the IWB-2500 examination category tabulation and, based on achange in ASME Code, Section XI, category nomenclature, the 1995 addenda classify them as Category B-K components (welded attachments for vessels, piping, pumps, and valves) in the IWB-2500 examination category tabulation.In its letter dated August 11, 2005, the applicant justified not performing a volumetric or surfaceexamination of the reactor vessel stabilizer bracket welds as specified by ASME C ode,Section XI, and described in the GALL Report:Four RPV (reactor pressure vessel) stabilizer brackets are attached to the Class1 RPV with full penetration fillet welds at 0, 90, 180, and 270 RPV azimuth 3-41at an elevation of 994'-2". The RPV stabilizers are connected with flexiblecouplings to the brackets on the RPV and also to the biological shield wall. The RPV stabilizers, brackets, and their attachment welds are designed to withstandand resist local loads (jet reaction forces) and seismic loads while allowing axial and radial movement due to normal thermal growth. The RPV stabilizer bracketsdo not provide structural support during normal operation. The MNGP RPV has never experienced jet reaction forces or seismic events, therefore the stabilizers, brackets, and attachment welds have not experienced the loads for which they are designed.The area around the stabilizers is extremely congested. The vessel stabilizerbrackets are surrounded by mirror insulation that is secured by cable hangers and buckles, ventilation ductwork with support bracing, and electrical installations such as thermocouples. All of this equipment must be relocated and restored to provide access to the stabilizers for examination of the welds. Additionally, dueto the location of the stabilizer brackets and the lack of a working platform at thestabilizer location, a complex scaffold installation is required to provide access tothe examination location.As an alternative to the requirements of Table IWB-2500-1, Category B-K, Item B10.10, inSection XI of the ASME Code, the applicant proposed a surface examination on the stabilizerbrackets if local (jet reaction forces) or seismic design loads are experienced. In addition, the applicant stated that a one-time VT-3 inspection of the accessible areas of all four welded attachments during the 2005 refueling outage noted no reportable conditions.The applicant also stated that relief from this inspection will have no effect on agingmanagement of the components within the scope of license renewal crediting these programs.
The welds are part of the external surface of the reactor vessel. LRA Table 3.1.2-2 discusses aging management for the vessel external surface". The staff reviewed the applicant's justification for this exception. In addition, the staff reviewed the NRC's letter, "MonticelloNuclear Generating Plant-Fourth 10-Year In-Service Inspection Interval Request for Relief No.
4 (TAC No. MC2222)," dated January 6, 2005, in which the staff approved the applicant's request for relief from the requirements of the ASME Code, Section XI, with regard to the requirements of Table IWB-2500-1, Category B-K, Item B10.10 for inspection of the reactorvessel stabilizer bracket welds.On the basis of the information reviewed and additional discussions with the applicant, the NRCissued RAI B2.1.2-1 on August 18, 2005, to obtain an additional technical basis for this exception. The staff asked the applicant to describe details of the weld used for the stabilizer bracket attachment, describe applicable examination requirements and any available results from the time of vessel manufacture, describe inspections since initial startup of the plant, identify and describe stressors that the welds experience during normal operation, statewhether the welds have experienced any stressors different from the normal operating stressors, and summarize any related industry experience with similar welds known to the applicant.In its response, dated September 16, 2005, the applicant provided additional information onweld type and examinations. The four 3-1/2-inch-thick stabilizer brackets are wel ded to theoutside of the RPV with a double-bevel groove weld (3/16-inch root opening, 1/8-inch root face, 3-42 and 30 groove angle) and a concave reinforcing fillet. At the time of vessel manufacture, a UTexamination was conducted of the vessel shell surface before the stabilizer brackets werewelded at the weld location to a depth at least equal to the thickness of the bracket and over the entire area of the subsequent connection, plus a band all around this area half as wide as the thickness of the bracket. After the stabilizer brackets were welded to the vessel, a magneticparticle examination was conducted of the welds. The only examination of the stabilizer bracketwelds since manufacture occurred in March 2005 and consisted of a VT-3 examination of the stabilizer brackets using a flashlight and mirror looking for cracks or linear indications, wear,corrosion, and contaminants. This examination did not identify any reportable indications on anyof the four stabilizer brackets.The applicant's response also provided the following bases to conclude that degradation of thestabilizer bracket welds is unlikely:  *Degradation of the stabilizer bracket welds is unlikely because the cumulative fatigueusage factor for the stabilizer brackets is extremely low, so cracking due to fatigue is notexpected to occur.  *The brackets and welds are made of carbon steel, and SCC is not applicable for thismaterial; furthermore, during reactor operation, the drywell is maintained in an inert atmosphere with the RPV at high temperatures, so loss of material due to general corrosion is not expected to occur.  *MNGP does not use boric acid or a borated solution as a moderator in the reactorcoolant system. Therefore, loss of material due to boric acid corrosion of externalsurfaces does not occur.  *Flexible couplings connect the RPV stabilizers to the brackets on the RPV and to thebiological shield wall. The RPV stabilizers, brackets, and their attachment welds aredesigned to withstand and resist local loads (jet reactor forces) and seismic loads while allowing axial and radial movement due to normal thermal growth. During normal operation, there is no loading on the stabilizer brackets; the stabilizers, brackets, andattachment welds have never experienced the loads for which they were designed.  *Because of design differences, the Duane Arnold plant was able to conduct surfaceexaminations on portions of its stabilizer bracket attachment welds in April 2005 andfound no reportable indications. In addition, the MNGP staff does not know of any failures or defects of these or similar welds at any other boiling-water reactors (BWRs).Based on the applicant's additional information that an appropriate original inspection of thestabilizer brackets and welds was performed, that there are no stressors to cause degradationof the brackets or welds during normal operation, that no operational events have subjected thebrackets or welds to abnormal stressors, that a recent VT-3 examination of the brackets found no indications of weld or bracket degradation, and that industry operating experience does not suggest occurrence of any age-related degradation of the stabilizer brackets or welds, the staffconcluded that this exception to the Detection of Aging Effects program element is acceptable.The staff reviewed those portions of AMP B2.1.1, "ASME Section XI In-Service Inspection,Subsections IWB, IWC, and IWD Program," that the applicant claimed are consistent withGALL AMP XI.M1 and found them consistent. The staff found the applicant's AMP acceptable 3-43because it conforms to the recommended GALL Report AMP with the exceptions as describedabove.Operating Experience. In LRA Section B2.1.2, the applicant stated that a review of operatingexperience for the ASME Section XI In-Service Inspection, Subsections IWB, IWC, and IWD Program identified no adverse trends or issues with program performance. The program identified and corrected problems before they caused any significant impact to safe operation or loss of intended functions. The applicant took corrective actions to prevent recurrence. The MNGP ASME Section XI In-Service Inspection, Subsections IWB, IWC, and IWD Program monitors the condition of the pressure-retaining components within the license renewal boundary. MNGP procedures contain guidance for indications of degradation requiring evaluation, repair, or replacement. The applicant performs periodic self-assessments and reviews of industry and plant experience to identify any areas needing improvement. Some examples include the following:  *The applicant modified its ASME Section XI In-Service Inspection, Subsections IWB,IWC, and IWD Program at the end of the third interval to incorporate an improved strategy for NDE as described in EPRI TR-112657 and in compliance with the requirements of RG 1.174, Revision 1, "An Approach for Using Probabilistic RiskAssessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis," issued November 2002, and RG 1.178, Revision 1, "An Approach for Plant-Specific Risk-Informed Decision-Making for In-Service Inspection of Piping,"
issued September 2003.  *Inspections in 1998 and 2001 of steam dryer jacking screws revealed a crack-likeindication in the screw tack weld at 325 degrees. Following the inspection in 1998, an evaluation indicated that the crack was acceptable. Reinspections of the jacking screwsin 2001 showed no crack growth in the 325 degree screw and no indications of cracking in the other screws.  *The applicant detected cracking in 34 tack welds on jet pump beam adjusting screws in1994 during the in-vessel visual inspection at the end of cycle 16. Cracking wasascribed to high cycle fatigue. Applicant staff restored tack welds so that each adjustingscrew had a minimum of one uncracked tack weld. Tack welds are and will conti nue tobe visually inspected.The staff reviewed the operating experience provided in the LRA and interviewed theapplicant's technical personnel to confirm that plant-specific operating experience revealed no degradation not bounded by industry experience.On the basis of its evaluation of the applicant's program against the program elementsdescribed in the GALL Report AMP, its review of the above industry and plant-specific operating experience, and its discussions with the applicant's technical personnel, the staff concluded that the applicant's ASME Section XI In-Service Inspection, Subsections IWB, IWC, and IWD Program will adequately manage the aging effects identified in the LRA for which this AMP iscredited.USAR Supplement. In LRA Section A2.1.2, the applicant provided the USAR supplement forthe ASME Section XI In-Service Inspection, Subsections IWB, IWC, and IWD Program. The 3-44staff reviewed this section and determined that the information in the USAR supplementadequately describes the program, as required by 10 CFR 54.21(d).Conclusion. On the basis of its review and audit of the applicant's ASME Section XI In-ServiceInspection, Subsections IWB, IWC, and IWD Program, the staff determined that those programelements for which the applicant claimed consistency with the GALL Report are consistent withthe GALL Report. In addition, the staff reviewed the exceptions and the associated justificationsand determined that the AMP, with the exceptions, is adequate to manage the aging effects forwhich it is credited. The staff concluded that the applicant demonstrated that the effects ofaging will be adequately managed so that intended functions will be maintained consistent withthe CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff alsoreviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.2.3  ASME Section XI, Subsection IWF Program Summary of Technical Information in the Application. In LRA Section B2.1.3, the applicantdescribed the ASME Section XI, Subsection IWF Program, stating that this existing program is consistent, with enhancement, with GALL AMP XI.S3, "ASME Section XI, Subsection IWF." The MNGP ASME Section XI, Subsection IWF Program is part of the MNGP ASME Section XI In-Service Inspection Program. The applicant performs the ASME Section XI, Subsection IWF Program in accordance with the ASME Code, Section XI, 1995 edition through the 1996 addenda and 10 CFR 50.55a. The program provides for condition monitoring of Class 1, 2, 3, and MC component supports. The applicant selects component supports for inspection in accordance with the ASME Code classification and increases the quantity of component supports selected for examination as a result of discovered support deficiencies. Visual inspection is the primary method for identifying deficiencies. The applicant periodically updates the program as required by 10 CFR 50.55a.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's audit evaluation of this AMP. The staff reviewed the enhancement and the associated justifications todetermine whether the AMP, with the enhancement, remains adequate to manage the agingeffects for which it is credited.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.S3.In the LRA, the applicant stated that, after enhancement of its current program, it will contain noexceptions to program elements of GALL AMP XI.S3; however, during the audit and review, the staff asked the applicant whether its approved ISI relief requests or code cases affect any of its AMP elements. In its letter dated August 11, 2005, supplemented by its letter dated August 31, 2005, the applicant identified for Code Case N-491-2,  "Rules for Examination of Class 1, 2, 3,and MC Component Supports of Light-Water Cooled Power Plants, Section XI, Division 1,"
issued March 2000, the following exception to the GALL Report program element.Exception:  The GALL Report recommends the following for the Corrective Actions programelement associated with the exception taken:
3-45In accordance with IWF-3122, supports containing unacceptable conditions areevaluated or tested, or corrected before returning to service. Corrective actions are delineated in IWF-3122.2. IWF-3122.3 provides an alternative for evaluationor testing to substantiate structural integrity and/or functionality.In its letter dated August 11, 2005, the applicant stated that it may perform corrective measureson a component support to return it to design condition after acceptance by evaluation or test without requiring additional examinations.The applicant explained that most of the provisions of the original code case were added to the1990 addenda to the ASME Code, Section XI, but that Code Case N-491-2 provisions were added to IWF-3112.3 and IWF-3122.3 in the 1997 addenda. Because some of the provisions were added by ASME Code, Section XI, addenda later than what the GALL Report references, the applicant has identified these provisions as an exception to the GALL Report description ofthe ASME Section XI, Subsection IWF Program.The applicant stated in its letter dated August 11, 2005, that this exception to the CorrectiveAction Program element of GALL Report AMP XI.S3 will have no impact on aging managementfor the component supports. The staff reviewed the applicant's description of this exception together with requirements specified in the ASME Code, Section XI, 1995 Edition through 1996 Addenda. Because the applicant's AMP provides inspections required by ASME Code, Section XI, Subsection IWF (involving requirements for Class 1, 2, 3, and MC component supports of light-water-cooled power plants) and requires reasonable and appropriate corrective actions before a defective component returns to service, the staff agreed that this exception willhave no detrimental impact on the adequacy of affected component aging management. For this reason, together with review of the ASME Section XI, Subsection IWF Program operating experience, the staff found this exception acceptable.In the LRA, the applicant stated that it will implement the following enhancement to make thisAMP consistent with the recommendation in the GALL Report.Enhancement:  The GALL Report recommends the following for the Scope of Program programelement associated with the enhancement made:Starting with the 1990 Addenda to the 1989 Edition, the scope of SubsectionIWF was revised. The required percentages of each type of nonexempt support subject to examination were incorporated into Table IWF-2500-1. The revised percentages are 25% of Class 1 nonexempt piping supports, 15% of Class 2 nonexempt piping supports, 10% of Class 3 nonexempt piping supports, and 100% of supports other than piping supports (Class 1, 2, 3, and MC). For pipe supports, the total sample consists of supports from each system (such as mainsteam, feedwater, residual heat removal), where the individual sample sizes are proportional to the total number of nonexempt supports of each type and function within each system. For multiple components other than piping withi n a systemof similar design, function, and service, the supports of only one of the multiple components are required to be examined. To the extent practical, the same supports selected for examination during the first inspection interval are examined during each successive inspection interval.
3-46In the LRA, the applicant stated that it will enhance its ASME Section XI, Subsection IWFProgram to inspect Class MC components supports consistent with the GALL Report, Chapter III, Section B1.3, "Supports for ASME Class MC Components."During the audit and review, the staff asked the applicant for more details about its current IWFprogram and to identify the inspections that the enhancement will add. In response, theapplicant provided the following information:  *The current MNGP IWF program does not include VT-3 examination of MC supports.  *The current MNGP IWE program includes general visual examinations of MCcomponents and their supports in accordance with ASME Code, Section XI, Table IWE-2500-1.The applicant stated that examinations conducted under the current IWE program include thefollowing MC supports:  *torus/ring header seismic restraints  *drywell male and female stabilizers  *shield stabilizers
  *torus columns
  *torus saddles
  *vent system supports  *downcomer bracingThe applicant further stated that for the period of extended operation, the ASME Section XI,Subsection IWF Program will perform VT-3 examinations of the MC supports listed above inaccordance with ASME Code, Section XI, Table IWF-2500-1 in compliance with the ASME Code, Section XI, 1995 edition and 1996 addenda ISI requirements. In addition, for the period of extended operation, the ASME Section XI, Subsection IWE Program will conti nue thegeneral visual examination of the MC components and their supports listed above in accordance with ASME Code, Section XI, Table IWE-2500-1.The staff reviewed the applicant's response together with the applicant's program-basisdocument (PBD) for the IWF program. The staff concluded that by adding a requirement for VT-3 inspection of MC component supports, the applicant's current program will be consistentwith GALL AMP XI.S3. On this basis, the staff found the applicant's response acceptable.The staff asked whether the applicant's program, when enhanced as described in the LRA, willprovide for inspection of all Class MC supports rolled up into applicable line items of the GALL Report, Chapter II, Section B1.3, which specifies ASME Code, Section XI, Subsection IWF as the AMP. In response, the applicant stated the following:When the ASME Section XI, Subsection IWF Program is enhanced, all MNGPMC supports will be rolled up into the applicable NUREG-1801 line items to theextent required by ASME Section XI, Table IWF-2500-1.The staff reviewed the applicant's response together with the applicant's proposed programenhancement as described in the LRA and evaluated in the applicant's PBDs. Based on this 3-47review, the staff concluded that the applicant's program includes appropriate components asrequired by ASME Code, Section XI, Table IWF-2500-1. On this basis, the staff found the applicant's response acceptable.Based on the applicant's responses to the staff's questions and review of associateddocuments provided by the applicant, the staff concluded that the existing program, enhancedas described in the LRA, will be fully consistent with the AMP elements described in GALLAMP XI.S3.The applicant stated, in the LRA, that the enhancement is required to satisfy the GALL ReportAMP recommendations and is scheduled for implementation before the period of extended operation. On the basis of its evaluations of the applicant's program against the programelements described in the GALL Report AMP, together with its review of AMP B2.1.3, "ASME Section XI, Subsection IWF," program operating experience, the staff found this enhancement acceptable, as such changes to the applicant's program provide assurance that the program will adequately manage the effects of aging.The staff reviewed those portions of AMP B2.1.3 that the applicant claimed are consistent withGALL AMP XI.S3 and found them consistent. The staff found the applicant's AMP acceptable because it conforms to the recommended GALL Report AMP with the exception and enhancement as described above.Operating Experience. In LRA Section B2.1.3, the applicant stated that the MNGP ASMESection XI, Subsection IWF Program addresses industry operating experience and prescribes the need for additional augmented requirements for Class 1, 2, 3, and MC component supportsas applicable. In addition, MNGP has been performing a general visual examination on accessible Class MC component supports in accordance with the ASME Section XI, Subsection IWE Program and has not identified any aging effects of concern.The staff reviewed the operating experience provided in the LRA and interviewed theapplicant's technical personnel to confirm that plant-specific operating experience revealed no degradation not bounded by industry experience.On the basis of its evaluation of the applicant's program against the program elementsdescribed in the GALL Report AMP, its review of the above industry and plant-specific operating experience, and discussions with the applicant's technical personnel, the staff concluded that the applicant's ASME Section XI, Subsection IWF program will adequately manage the agingeffects identified in the LRA for which this AMP is credited.USAR Supplement. In LRA Section A2.1.3, the applicant provided the USAR supplement forthe ASME Section XI, Subsection IWF Program.Subsequently, by letter dated June 10, 2005, the applicant revised its USAR supplement toinclude the following commitment, documented as commitment 9 in Table A.5:Prior to the period of extended operation, the MNGP ASME Section XI,Subsection IWF Program will be enhanced to provide inspections of Class MCcomponents supports consistent with NUREG-1801, Chapter III Section B1.3.
3-48The staff reviewed this section and determined that the information in the USAR supplement asaugmented by the commitment adequately describes the program, as required by 10 CFR 54.21(d).Conclusion. On the basis of its review and audit of the applicant's ASME Section XI, SubsectionIWF Program, the staff determined that those program elements for which the applicantclaimed consistency with the GALL Report are consistent with the GALL Report. In addition, thestaff reviewed the enhancement and confirmed that its implementation before the period ofextended operation will result in the existing AMP being consistent with the GALL Report AMPto which it was credited. The staff concluded that the applicant demonstrated that the effects ofaging will be adequately managed so that intended functions will be maintained consistent withthe CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff alsoreviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.2.4  Bolting Integrity Program Summary of Technical Information in the Application. In LRA Section B2.1.4, the applicantdescribed its Bolting Integrity Program, stating that this existing AMP is consistent, with enhancements, with GALL AMP XI.M18, "Bolting Integrity."The applicant stated that the Bolting Integrity Program manages the aging affects associatedwith bolting within the scope of license renewal through periodic inspection, material selection, thread lubricant control, assembly and torque requirements, and repair and replacement requirements. These activities are based on the applicable requirements of the ASME Code, Section XI, and plant operating experience and include consideration of the guidance contained in NUREG-1339, "Resolution of Generic Safety Issue 29:  Bolting Degradation or Failure inNuclear Power Plants," EPRI NP-5769, "Degradation and Failure of Bolting in Nuclear Power Plants," EPRI TR-104213, "Bolted Joint Maintenance & Application Guide," and EPRI NP-5067,Volumes 1 and 2, "Good Bolting Practices."The Bolting Integrity Program credits 11 AMPs for the inspection of installed bolts,namely(1) 10 CFR 50, Appendix J, (2) ASME Section XI In-Service Inspection, Subsections IWB, IWC and IWD, (3) Primary Containment In-Service Inspection, (4) Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems, (5) ASME Section XI, Subsection IWF, (6) Buried Piping and Tanks Inspection, (7) Bus Duct Inspection, (8) BWR Vessel Internals, (9) Reactor Head Closure Studs Monitoring, (10) System Condition Monitoring, and (11) Structures Monitoring Programs.The applicant stated that enhancements are required to satisfy the GALL Report AMPrecommendations. It will add the enhancements to the Parameters Monitored or Inspected andAcceptance Criteria elements of the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program, Structures Monitoring Program, and System Condition Monitoring Program. These enhancements will add guidance for visual boltinginspections found in EPRI TR-104213 and EPRI NP- 5067, Volumes 1 and 2.The LRA also states that inspection of bolting for ASME Code, Section XI, Class 1, 2, 3, andMC components is in accordance with the ASME Code, Section XI requirements. Because the scope of license renewal includes components besides those related to ASME Code, 3-49Section XI, the applicant relies upon other programs for additional inspections that includechecking the material condition of bolting for signs of corrosion, wear, and other problems, and associated pressure-retaining joints for signs of leakage. Upon detection of degraded conditions, the applicant performs followup inspections, repairs, replacements, or application of additional testing methods as required by the site CAP and applicable ASME Code, Section XI acceptance criteria.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's audit evaluation of this AMP. The staff reviewed the enhancements and the associated justificationsto determine whether the AMP, with the enhancements, remains adequate to manage the agingeffects for which it is credited.The staff reviewed the Bolting Integrity Program against the AMP elements in the GALL Report,SRP-LR Section A.1.2.3, and SRP-LR Table A.1-1 and focused on the program's managementof aging effects through the incorporation of the 10 program elements. The applicant indicated that the site-controlled Quality Assurance Program includes the Corrective Actions, Confirmation Process, and Administrative Controls elements. SER Section 3.0.4 discusses the staff's evaluation of the Quality Assurance Program.LRA Section B2.1.4 states that the Bolting Integrity Program is consistent with GALLAMP XI.M18 with enhancements added to the Parameters Monitored or Inspected and Acceptance Criteria elements of the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program, Structures Monitoring Program, and System Condition Monitoring Program. These enhancements will add guidance for visual boltinginspections found in EPRI TR-104213, and EPRI NP-5067, Volumes 1 and 2". The staff reviewed the Parameters Monitored or Inspected and Acceptance Criteria elements and concluded that the applicant has acceptable criteria for visual bolting inspections and acceptance criteria for the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program, Structures Monitoring Program, and System Condition Monitoring Program. The staff has reviewed and approved similar enhancements to bolting programs based on EPRI NP-5067 and EPRI TR-104213, as documented in NUREG-1743,"Safety Evaluation Report Related to the License Renewal of Arkansas Nuclear One, Unit 1,"issued April 2001. For these reasons, the staff found that the guidelines for enhancements tothe Bolting Integrity Program reflect industry practice and meet the recommendations of GALL AMP XI.M18.The staff's review of LRA Section B2.1.4 identified an area for which it needed additionalinformation to complete its evaluation of the applicant's program elements. The applicant responded to the staff's RAI as discussed below.In RAI B2.1.4-1, dated July 20, 2005, the staff noted that Table Items 3.3.1-18, 3.3.1-24, and3.4.1-08 in the LRA provide a general discussion of the Bolting Integrity Program as applied to the ESF, auxiliary, and steam and power conversion (SPC) systems. Therefore, the staffrequested that the applicant state whether the Bolting Integrity Program manages all closurebolting in the ESF, auxiliary, and SPC systems for loss of preload, even though the AMR tablescontain no specific line items for this aging effect.In its response, by letter dated August 16, 2005, the applicant stated the following:
3-50As discussed in Section B2.1.4 of the License Renewal Application, the BoltingIntegrity Program manages aging effects for bolting within the scope of license renewal. This includes closure bolting that is required to support a pressure boundary intended function for components of the systems listed in SectionB2.1.4, Scope of Program. Detection of aging effects includes visual inspection of pressure retaining joints for signs of leakage, which may be the result of loss of preload. With the exception of the Emergency Filtration (EFT) System, this includes all closure bolting of the Engineered Safety Features (ESF), Auxiliary,and Steam and Power Conversion (SPC) systems in the LRA. As noted in LRATable 3.3.2-7, bolting of the EFT System is not susceptible to aging effects due to is location in a controlled environment and is, therefore, not included in the Bolting Integrity Program.In a telephone conversation on November 4, 2005, the staff requested that the applicant explainwhy closure bolting of the EFT system is not susceptible to aging effects and not included in theBolting Integrity Program.In its response, by letter dated November 17, 2005, the applicant stated that bolting in the EFTsystem is not susceptible to aging effects (i.e., corrosion) because of its location in a controlled air environment; however, the Bolting Integrity Program is credited with managing the loss of preload aging effect for the EFT system. The applicant supplemented its response toRAI B2.1.4-1 as follows:Closure bolting of the EFT system is managed by the Bolting Integrity Programfor loss of preload. Section B.2.1.4, Scope of Program, of the LRA for the BoltingIntegrity Program is revised to include the EFT system.Based on its review, the staff found the applicant's response to RAI B2.1.4-1 acceptable. Theapplicant stated that the Bolting Integrity Program manages all closure bolting in the ESF,auxiliary, and SPC systems for loss of preload; therefore, the staff's concern described in RAIB2.1.4-1 is resolved.During the audit and review, the staff asked the applicant whether its current approved ISI reliefrequests or code cases affect any of its AMP program elements. In its letter dated August 31, 2005, the applicant identified the following exception to the GALL Report for the Bolting IntegrityProgram:Element: 7:  Corrective ActionsException:  An approved alternative allows the use of the 2001 Edition of ASME Section XI in lieu of the 1995 Edition with the 1996 Addenda for repair/replacement activities.SER Section 3.0.3.1.7 documents the staff's evaluation of this exception.Because the NRC has already reviewed and approved this alternative, as it relates to repair andreplacement, generically for aging management of systems and components within the scopeof license renewal, the staff concluded that the applicant need not classify it as an exceptionand that, with regard to this item, the affected program element is consistent with the GALL Report.
3-51Operating Experience. The applicant stated that both the industry and the NRC have revealed anumber of instances of bolting concerns, from material control and certification to bolting practices, use of lubrication, and the impact of aging mechanisms. The MNGP Bolting Integrity Program incorporates both plant and industry experience on bolting issues. For example, MNGP previously evaluated and addressed NRC information notices (INs), bulletins, circulars,and GLs listed in Section 3 of NUREG-1339. Some of these resulted in confirmatory analysesor inspections and others in modifications or the addition of special items to consider in the procurement and design processes. MNGP replaced all reactor vessel shroud head bolts with a new vendor recommended design, for example, when it identified cracking issues with the prior design.A review of plant operating experience identified issues with missing or loose bolts, inadequatethread engagement, and improper bolt applications. In all cases, MNGP corrected the identified concern; no significant safety event resulted; and the applicant implemented additional actions,such as procedural enhancements, as needed to minimize the potential for recurrence.In RAI B2.1.4-2, dated July 20, 2005, the staff noted that, after the applicant had submitted theLRA, failed bolts on tee-quencher supports were found at the Hatch Nuclear Plant Unit 2 (Hatch 2). Subsequent analysis revealed that high-strength bolts are susceptible to hydrogen-induced cracking and may fail after 20 to 25 years of service. Therefore, the staff requested that the applicant explain why the tee-quencher bolts at MNGP will not fail as a resultof hydrogen-induced cracking.In its response, by letter dated August 16, 2005, the applicant stated that the tee-quenchersupport design at MNGP differs from the design at Hatch 2. In addition, all bolts are 1-inch-diameter, 3.75-inch-long hex bolts procured to the requirements of American Society for Testing Materials (ASTM) A-325 Type 1 or A-193 Grade B7 material specification. These are not high-strength bolts, having ultimate strength of approximately 125 ksi or less, and are well below the ultimate strength of SA540 Grade B21 Class 1 bolts at Hatch 2. Further, analysis of the Hatch 2 event determined that the most likely cause of SCC of the high-strength bolts wasthe significant contribution of hydrogen embrittlement. One possible source of the hydrogenembrittlement was the use of a zinc primer inside the torus. MNGP does not use a zinc primer; instead, it uses a modified phenolic-based primer in the torus. Finally, MNGP performs underwater inspections of these bolts periodically, and the May 1993 inspection identified no problems or loose connections.Based on its review, the staff found the applicant's response to RAI B2.1.4-2 acceptable. Thestaff concurred with the applicant's conclusions that the Hatch 2 event does not apply to MNGPbecause the tee-quencher design differs from the design at Hatch 2. The bolts at MNGP arelower strength bolts not susceptible to SCC, and the application of phenolic-based instead of zinc-based primer inside the torus has minimized any source of hydrogen. In addition, the applicant performs periodic inspection of tee-quencher bolts in accordance with the requirements of its Primary Containment In-Service Inspection Program, providing added assurance that bolting materials inside the torus will be adequately managed during the periodof extended operation. Therefore, the staff's concern described in RAI B2.1.4-2 is resolved.On the basis of its review of the above industry and plant-specific operating experience, thestaff concluded that the Bolting Integrity Program will adequately manage the aging effects 3-52identified in the LRA for which this AMP is credited. The staff concluded that this programattribute is acceptable.USAR Supplement. In LRA Section A2.1.4, the applicant provided the USAR supplement forthe Bolting Integrity Program.Subsequently, by letter dated June 10, 2005, the applicant revised its USAR supplement toinclude the following commitment, documented as commitment 10 in Table A.5:Prior to the period of extended operation, the guidance for performing visualbolting inspections contained in EPRI TR-104213, Bolted Joint Maintenance &
Application Guide, and the Good Bolting Practices Handbook (EPRI NP-5067 Volumes 1 and 2) will be included in the Bus Duct Inspection Program,Inspection of Overhead Heavy Load and Light Load (Related to Refueling)
Handling Systems Program, Structures Monitoring Program and the System Condition Monitoring Program.The staff reviewed this section and determined that the information in the USAR supplement asaugmented by the commitment adequately describes the program, as required by 10 CFR 54.21(d).Conclusion. On the basis of its review and audit of the applicant's Bolting Integrity Program, thestaff determined that those program elements for which the applicant claimed consistency withthe GALL Report are consistent with the GALL Report. In addition, the staff reviewed the enhancements and confirmed that their implementation before the period of extended operationwill result in the existing AMP being consistent with the GALL Report AMP to which it wascredited. The staff concluded that the applicant demonstrated that the effects of aging will beadequately managed so that intended functions will be maintained consistent with the CLB forthe period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.2.5  Buried Piping & Tanks Inspection Program Summary of Technical Information in the Application. In LRA Section B2.1.5, the applicantdescribed the Buried Piping & Tanks Inspection Program, stating that this existing program is consistent, with enhancements, with GALL AMP XI.M34, "Buried Piping and Tanks Inspection."
The Buried Piping & Tanks Inspection Program consists of preventive and condition monitoring measures to manage the aging effects for buried piping, conduit, and tanks within the scope of license renewal. Buried components within the scope of license renewal include carbon steel piping, bolting, conduit, and tanks (loss of material due to general, crevice, galvanic, pitting, and microbiologically influenced corrosion (MIC)) and cast iron piping (loss of material due to general, crevice, galvanic, and pitting corrosion, MIC, and selective leaching). Preventive measures consist of protective coatings and/or wraps on buried components. Condition monitoring consists of periodic inspections of buried components. In addition, buried components are not routinely uncovered during maintenance activities. Therefore, other systemmonitoring and functional testing activities are relied upon to provide effective degradation aging management of buried piping and tanks. Some of these activities are neither preventive nor mitigative in nature, but they do provide indication of a leak. However, the potential problem 3-53(i.e., small leak) is detected at an early stage, such that repairs can be made before the loss ofcomponent intended function.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's audit evaluation of this AMP. The staff reviewed the enhancements and the associated justificationsto determine whether the AMP, with the enhancements, remains adequate to manage the agingeffects for which it is credited.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses consistency of the AMP elements with GALL AMP XI.M34.In the LRA, the applicant stated that the following enhancements will make this AMP consistentwith the recommendation in the GALL Report.Enhancement 1:  The GALL Report recommends the following for the Scope of Programprogram element associated with the enhancement made:The program relies on preventive measures such as coating and wrapping andperiodic inspection for loss of material caused by corrosion of the external surface of buried carbon steel piping and tanks. Loss of material in these components, which may be exposed to aggressive soil environment, is caused by general, pitting, and crevice corrosion, and microbiologically influenced corrosion (MIC). Periodic inspections are performed when the components are excavated for maintenance or for any other reason.The applicant stated in the LRA that it will update the scope of the Buried Piping & TanksInspection Program to implement procedures to include inspections of buried components when uncovered. In interviews with the applicant's technical personnel about the enhanced program, the applicant stated that the enhanced program will take inspection opportunities when buriedcomponents are uncovered at times other than scheduled buried piping inspections. In addition, it will update the excavating procedure to perform inspection(s), when buried components areuncovered. The staff reviewed the applicant's response and plant procedures and found this enhancement acceptable as such changes to the applicant's program provide assurance that the effects of aging will be adequately managed.During the aging management inspection, the inspectors noted that, although the PBDsindicate that the Buried Piping & Tanks Inspection Program would manage buried conduit, the existing inspections and related procedures were limited to buried piping and the diesel fuel oil storage tank. Since buried conduit is galvanized and not wrapped or coated, aging of conduit could be different from that of underground piping and tanks. In its letter dated March 15, 2006,the applicant amended the scope of the program to include conduit. The staff found this acceptable because it ensures that potential aging effects of buried conduit are managed.Enhancement 2:  The GALL Report recommends the following for the Parameters Monitored orInspected program element associated with the enhancement made:
3-54The program monitors parameters such as coating and wrapping integrity thatare directly related to corrosion damage of the external surface of buried carbon steel piping and tanks. Coatings and wrappings are inspected by visual techniques. Any evidence of damaged wrapping or coating defects, such as coating perforation, holidays, or other damage, is an indicator of possible corrosion damage to the external surface of piping and tanks.In the LRA, the applicant stated that it will add the Diesel Fuel Oil Storage Tank T-44 internalinspections to the list of scheduled inspections in the Buried Piping & Tanks Inspection Program.The staff noted that the applicant's buried diesel fuel oil storage tank inspection is an internalinspection. In RAI B2.1.5-1, dated October 31, 2005, the staff requested that the applicantclarify whether the diesel fuel oil storage tank internal inspection is in addition to or in lieu of the external inspection recommended in the GALL Report.In its response, by letter dated November 22, 2005, the applicant stated that the Buried Piping& Tanks Inspection Program and the 10-year diesel fuel oil storage tank internal inspection willsupplement the external inspection as recommended in the GALL Report and will incl ude bothvisual and UT inspections. External inspections of the diesel fuel oil storage tank will take placeas opportunities arise. Should the applicant excavate the tank during maintenance activities, itwill perform an external inspection consistent with the GALL Report for inspecting the externalsurfaces of buried piping and tanks.In the Detection of Aging Effects program element, the applicant stated, "An enhancement tothe underground piping inspections is to include a provision that if evaluations of pipe wall thickness show a susceptibility to corrosion, further evaluation as to the extent of susceptibility will be performed." The applicant restated in its RAI response that inspections of the externalsurfaces of other buried carbon steel components will also indicate the external surfacecondition of the diesel fuel oil storage tank.The applicant stated that the diesel fuel oil storage tank internal inspection supplements theexternal inspections recommended in the GALL Report and, therefore, is an acceptable AMP for the detection of aging effects consistent with the GALL Report. The staff reviewed the applicant's response and found this enhancement acceptable as it provides assurance that the effects of aging will be adequately managed.Enhancement 3:  The GALL Report recommends the following for the Detection of AgingEffects program element associated with the enhancement made:Periodic inspection of susceptible locations to confirm that coating and wrappingare intact is an effective method to ensure that corrosion of external surfaces has not occurred and the intended function is maintained. The inspections are performed in areas with the highest likelihood of corrosion problems, and in areas with a history of corrosion problems. Because the inspection frequency is plant-specific and also depends on the plant operating experience, the applicant's proposed inspection frequency is to be further evaluated for the extended period of operation.
3-55In the LRA, the applicant stated that it will revise the Buried Piping & Tanks Inspection Programto include a provision that if evaluations of pipe wall thickness show susceptibility to corrosion,further evaluation as to the extent of susceptibility will be performed. It will revise the Buried Piping & Tanks Inspection Program to specify a 10-year buried pipe inspection frequency and a 10-year Diesel Fuel Oil Storage Tank T-44 internal inspection frequency.During the audit and review, the staff asked the applicant about the types of inspections it willperform for this program before the period of extended operation. In response, the applicantstated that a visual and UT inspection of the buried Diesel Fuel Oil Storage Tank T-44 was performed in 2003 and showed no significant loss of material due to corrosion on the tank interior. Additionally, the applicant stated that a visual and UT inspection of the buried pipe nearthe offgas stack was performed in 1999 and no degradation due to aging effects was detected.
The applicant also stated that it regularly in spects the underground piping for the off gas systemgoing to the plant stack. The Offsite Safety Review Committee established this requirement to preclude leakage of offgas from the underground piping for any reason, including aging effects.The staff reviewed the applicant's response and plant procedures and found the enhancementacceptable by providing assurance that AMP B2.1.5, "Buried Piping & Tanks Inspection Program,"  is consistent with the AMP elements described in GALL AMP XI.M34.Enhancement 4:  The GALL Report recommends the following for the Monitoring and Trendingprogram element associated with the enhancement made:Results of previous inspections are used to identify susceptible locations.In the LRA, the applicant stated that the underground piping inspections will include review ofprevious buried piping issues to determine possibly susceptible locations.During the audit and review, the applicant provided technical information regarding thestatement that MNGP has mild soil conditions. In response to the staff's questions, the applicant provided technical data for pH, chloride, and sulfate concentrations, which verified this conclusion. The enhancement of the Monitoring and Trending program element will incl ude areview of previous buried piping issues to determine possibly susceptible locations. The staff reviewed the applicant's response and found AMP B2.1.5 consistent with the AMP elements described in GALL AMP XI.M34.The staff reviewed those portions of AMP B2.1.5 that the applicant claimed are consistent withGALL AMP XI.M34 and found them consistent. The staff found the applicant's AMP acceptable because it conforms to the recommended GALL Report AMP with the enhancements as described above.Operating Experience. In LRA Section B2.1.5, the applicant stated that the Buried Piping &Tanks Inspection Program relies on preventive measures, periodic inspections, and functional testing to manage the aging effects of buried components. MNGP operating experience has shown no buried component failures for systems within the scope of license renewal(emergency service water (ESW), diesel generator, hangars and supports, secondary containment system, fire system (FIR)). The only failures of buried components were on thewell water piping system and the instrument air system to the cooling towers. These are not SRsystems and they are outside the scope of license renewal. The failures are not located near 3-56any buried components within the scope of license renewal. The well water piping failure waspostulated to be caused by MIC and not a failure of the protective coating. The cause of the failure of the instrument air line is yet to be determined. Periodic visual and UT inspections of buried pipe have shown no significant loss of material due to pipe corrosion. Periodic UT inspections of the diesel fuel oil storage tank interior have also shown no significant loss of material due to corrosion. Periodic functional testing of the ESW and fire header systems hasshown no functional failures. Periodic vapor point monitoring and ground water monitoring near the diesel fuel oil storage tank have shown no functional failures of the storage tank or the diesel fuel oil lines.The staff reviewed the operating experience provided in the LRA and interviewed theapplicant's technical personnel to confirm that plant-specific operating experience revealed no degradation not bounded by industry experience.On the basis of its review, operating experience documentation, and discussions with theapplicant's technical personnel, the staff concluded that the applicant's Buried Piping & TanksInspection Program will adequately manage the aging effects identified in the LRA for whichthis AMP is credited.USAR Supplement. In LRA Section A2.1.5, the applicant provided the USAR supplement forthe Buried Piping & Tanks Inspection Program. The staff reviewed this section and determined that the information in the USAR supplement adequately describes the program, as required by10 CFR 54.21(d).In its letter dated June 10, 2005, the applicant supplemented LRA Section A2.1.5 by listing thefollowing commitments, documented as commitments 11-16 in Table A.5, to be performed before the period of extended operation:  (1)The Buried Piping and Tanks Inspection Program will update theimplementing procedures to include inspections of buried components when they are uncovered.  (2)The Diesel Fuel Oil Storage Tank, T-44, internal inspection will be addedto the list of scheduled inspections in the Buried Piping and Tanks Inspection Program.  (3)The Buried Piping and Tanks Inspection Program will be revised toinclude a provision that if evaluations of pipe wall thickness show a susceptibility to corrosion, further evaluation as to the extent of susceptibility will be performed.  (4)The Buried Piping and Tanks Inspection Program will be revised tospecify a 10-year buried pipe inspection frequency.  (5)The Buried Piping and Tanks Inspection Program will be revised tospecify a 10-year inspection frequency for Diesel Fuel Oil Storage Tank T-44.  (6)The Buried Piping and Tanks Inspection Program will be revised toinclude a review of previous buried piping issues to determine possible susceptible locations.
3-57Conclusion. On the basis of its review and audit of the applicant's Buried Piping & TanksInspection Program, the staff determined that those program elements for which the applicantclaimed consistency with the GALL Report are consistent with the GALL Report. In addition, thestaff reviewed the enhancements and confirmed that their implementation before the period ofextended operation will result in the existing AMP being consistent with the GALL Report AMPto which it was credited. The staff concluded that the applicant demonstrated that the effects ofaging will be adequately managed so that intended functions will be maintained consistent withthe CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff alsoreviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.2.6  BWR Control Rod Drive Return Line Nozzle Program Summary of Technical Information in the Application. In LRA Section B2.1.7, the applicantdescribed the BWR CRD Return Line Nozzle Program, stating that this existing program isconsistent, with exceptions, with GALL AMP XI.M6, "BWR Control Rod Drive Return Line Nozzle." The MNGP BWR CRD Return Line Nozzle Program is part of the MNGP ASME Section XI In-Service Inspection Program. The BWR CRD Return Line Nozzle Program is in accordance with the ASME Code, Section XI, 1995 edition through the 1996 addenda, and provides for condition monitoring of the BWR CRD return line (CRDRL) nozzle. In 1977, theCRDRL nozzle safe end was removed and the CRDRL nozzle was capped. In 1986, theCRDRL nozzle was modified again by removing the portion of the existing weld butter layersusceptible to IGSCC, by re-cladding the weld prep area with corrosion-resistant cladding, and by installing a new nozzle cap of non-IGSCC susceptible stainless steel. As a result of capping the CRDRL nozzle, the NUREG-0619, "BWR Feedwater Nozzle and Control Rod Drive ReturnLine Nozzle Cracking:  Resolution of Generic Technical Activity A-10," issued November 1980, augmented examinations are no longer required. Not performing the NUREG-0619 augmentedexaminations is considered an exception to GALL Report AMP XI.M6. The applicant updates the program periodically as required by 10 CFR 50.55a.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's audit evaluation of this AMP. The staff reviewed the exceptions and the associated justifications todetermine whether the AMP, with the exceptions, remains adequate to manage the agingeffects for which it is credited.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.M6.In the LRA, the applicant stated the following exceptions to the program elements listed forAMP XI.M6 in the GALL Report.Exception 1:  The GALL Report recommends the following for the Parameters Monitored orInspected, Detection of Aging Effects, and Monitoring and Trending program elements associated with the exception taken:
3-58The aging management program (AMP) monitors the effects of cracking on theintended function of the component by detecting and sizing cracks by ISI inaccordance with Table IWB 2500-1 and NUREG-0619.The extent and schedule of inspection, as delineated in NUREG 0619, assuresdetection of cr acks before the loss of intended function of the component.Inspection recommendations include liquid penetrant testing (PT) of the CRDRLnozzle blend radius and bore regions and the reactor vessel wall area beneath the nozzle, return-flow-capacity demonstration, CRD-system-performance testingand ultrasonic inspection of welded connections in the rerouted line. The inspection is to include base metal to a distance of one-pipe-wall thickness or 0.5 in., whichever is greater, on both sides of the weld.The inspection schedule of NUREG-0619 provides timely detection of cracks.In the LRA, the applicant stated that it does not perform the NUREG-0619 augmentedinspections; it removed the CRDRL nozzle safe end and capped the nozzle in 1977. Theapplicant also stated that it modified the nozzle again in 1986 to remove that portion of theexisting weld butter layer susceptible to IGSCC by re-cladding the weld prep area with corrosion-resistant cladding and by installing a new nozzle cap of 316 L nuclear-grade stainlesssteel. Because of these modifications, the applicant stated in its LRA that the requiredaugmented inspections on the CRDRL nozzle specified in NUREG-0619 through NRC GL80-95, "Generic Activity A-10," dated November 13, 1980, are no longer necessary. Although the applicant did not perform those augmented inspections specified in NUREG-0619, it didfollow the guidance in NUREG-0619, Section 8.2, for other inspections and maintenanceactivities related to the CRD system. The following summarizes the activities related to NUREG-0619, Section 8.2:  *Section 8.2(3)-The final PT inspection of the CRDRL nozzle showed no indications. Asystem flow and performance test had satisfactory results.  *Section 8.2(3a)-The welded connection joining the rerouted CRDRL to the reactorwater cleanup (RWCU) system is inspected every refueling outage with UT and includesbase metal to a distance of one pipe-wall thickness or 0.5 inches, whichever is greater, on both sides of the weld.  *Section 8.2(3b)-The remainder of the CRDRL does not meet the definition of Class 1,2, or 3 pipe and, therefore, NUREG-0313, Revision 2, "Technical Report on MaterialSelection and Processing Guidelines for BWR Coolant Pressure Boundary Piping,"
issued January 1988, does not require augmented inspections.  *Section 8.2(3c)-Since carbon steel piping was retained in the exhaust header,procedures were developed for (1) periodically performing a random sampling of hydraulic accumulator unit filters to determine if cleaning and flushing is required, and (2) periodically performing a flush of the CRD exhaust header.The applicant further stated that its commitment in response to GL 80-95 to implement therequirements for the CRDRL nozzle specified in NUREG-0619, Section 8, has been completed.The activities described above relating to NUREG-0619, Sections 8.2(3a) and 8.2(3c), areexisting NRC commitments and will continue through the period of extended operation.
3-59On the basis of its review of the completion of CRDRL nozzle-related modifications, thecompletion of commitments in response to GL 80-95, and operating experience for AMP B2.1.7, the staff found this exception acceptable.During the audit and review, the staff asked the applicant whether its current approved ISI reliefrequests or code cases affect any of its AMP program elements. In its letter dated August 31, 2005, the applicant identified the following additional exception to the GALL Report programelement:Exception 2:  The GALL Report recommends the following for the Corrective Actions programelement associated with the exception taken:Repair is in conformance with IWB-4000 and replacement in accordance withIWB-7000.In its letter dated August 11, 2005, the applicant stated that an approved alternative allows theuse of the ASME Code, Section XI, 2001 edition in lieu of the 1995 edition with the 1996 addenda for repair/replacement activities.The staff concluded that this item is not an exception and that with regard to this item, theaffected program element is consistent with the GALL Report. SER Section 3.0.3.1.7documents the staff's evaluation.The staff reviewed those portions of AMP B2.1.7, "BWR Control Rod Drive Return Line NozzleProgram," that the applicant claimed are consistent with GALL AMP XI.M6 and found themconsistent. The staff found the applicant's LRA AMP acceptable because it conforms to the recommended GALL Report AMP with the exceptions as described above.Operating Experience. In LRA Section B2.1.7, the applicant stated that it implements the BWRControl Rod Drive Return Line Nozzle Program inspections through the Inservice Inspection Program, which incorporates applicable requirements of the ASME Code. The inspection and testing methodologies have been effective in detecting aging effects due to cracking.
Engineering evaluations were performed based on plant and industry experience and component and programmatic corrective actions implemented as required. For example, in
 
1977 the CRDRL nozzle safe end was removed and the CRDRL nozzle was capped. In 1986,the CRDRL nozzle was modified again by removing the portion of the existing weld butter layersusceptible to IGSCC by re-cladding the weld prep area with corrosion-resistant cladding, and by installing a new nozzle cap. As a result of capping the CRDRL nozzle as discussed above,the NUREG-0619 augmented examinations are no longer required.The staff reviewed the operating experience provided in the LRA and interviewed theapplicant's technical personnel to confirm that plant-specific operating experience revealed no degradation not bounded by industry experience.On the basis of its review of the above operating experience and discussions with theapplicant's technical personnel, the staff concluded that the applicant's BWR CRDRL NozzleProgram will adequately manage the aging effects identified in the LRA for which this AMP iscredited.
3-60USAR Supplement. In LRA Section A2.1.7, the applicant provided the USAR supplement forthe BWR CRDRL Nozzle Program. The staff reviewed this section and determined that theinformation in the USAR supplement adequately describes the program, as required by 10 CFR 54.21(d).Conclusion. On the basis of its review and audit of the applicant's BWR CRDRL NozzleProgram, the staff determined that those program elements for which the applicant claimedconsistency with the GALL Report are consistent with the GALL Report. In addition, the staffreviewed the exceptions and the associated justifications and determined that the AMP, with theexceptions, is adequate to manage the aging effects for which it is credited. The staff concluded that the applicant demonstrated that the effects of aging will be adequately managedso that intended functions will be maintained consistent with the CLB for the period of extendedoperation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.2.7  BWR Feedwater Nozzle Program Summary of Technical Information in the Application. In LRA Section B2.1.8, the applicantdescribed the BWR Feedwater Nozzle Program, stating that this existing program is consistent,with enhancements, with GALL AMP XI.M5, "BWR Feedwater Nozzle." The MNGP BWR Feedwater Nozzle Program is part of the MNGP ASME Section XI In-Service Inspection Program. The BWR Feedwater Nozzle Program is in accordance with the ASME Code, Section XI, 1995 edition through the 1996 addenda, with Appendix VIII. The program providesfor condition monitoring of the BWR FW nozzles. The BWR FW nozzles were all repaired in 1977 and the safe ends were all replaced in 1981 with a tuning fork design with a welded-in thermal sleeve. The BWR Feedwater Nozzle Program is not currently augmented by the recommendations of General Electric (GE) Topical Report NE-523-A71-0594, Revision 1, "Alternate BWR Feedwater Nozzle Inspection Requirement." The applicant will enhance theprogram by including the recommendations of GE-NE-523-A71-0594-A, Revision 1. The applicant updates the program periodically as required by 10 CFR 50.55a.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's audit evaluation of this AMP. The staff reviewed the enhancements and the associated justificationsto determine whether the AMP, with the enhancements, remains adequate to manage the agingeffects for which it is credited.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses consistency of the AMP elements with GALL AMP XI.M5.During the audit and review, the staff asked the applicant whether its current approved ISI reliefrequests or code cases affect any of its AMP program elements.In its letter dated August 31, 2005, the applicant identified the following additional exception tothe GALL Report program element.
3-61Exception:  The GALL Report recommends for the Corrective Actions program elementassociated with the exception taken:Repair is in conformance with IWB-4000 and replacement in accordance withIWB-7000.In its letter dated August 11, 2005, the applicant stated that an approved alternative allows theuse of the ASME Code, Section XI, 2001 edition in lieu of the 1995 edition with the 1996 addenda for repair/replacement activities.The staff concluded that this item is not an exception and that with regard to this item, theaffected program element is consistent with the GALL Report. SER Section 3.0.3.1.7documents the staff's evaluation.In the LRA, the applicant described the following enhancement in meeting the GALL Reportelements.Enhancement:  The GALL Report recommends the following for the Parameters Monitored orInspected, Detection of Aging Effects, and Monitoring and Trending program elements associated with the enhancement made:The aging management program (AMP) monitors the effects of cracking on theintended function of the component by detection and sizing of cracks by ISI inaccordance with ASME Section XI, Subsection IWB and the recommendation of GE NE-523-A71-0594, as described below.The extent and schedule of the inspection prescribed by the program aredesigned to ensure that aging effects will be discovered and repaired before theloss of intended function of the component. Inspection can reveal crack initiation and growth. GE NE-523-A71-0594 specifies ultrasonic testing (UT) of specific regions of the blend radius and bore. The UT examination techniques and personnel qualifications are in accordance with the guidelines of GE NE-523-A71-0594. Based on the inspection method and techniques and plant-specific fracture mechanics assessments, the inspection schedule is in accordance with Table 6-1 of GE NE-523-A71-0594. Leakage monitoring may be used to modify the inspection interval.Inspections scheduled in accordance with GE NE-523-A71-0594 provide timelydetection of cracks.In the LRA, the applicant stated that it will enhance the BWR Feedwater Nozzle Program byincluding the recommendations of GE-NE-523-A71-0594-A, Revision 1.By letter dated September 24, 1999, the BWR Owners Group (BWROG) submitted for staffreview Topical Report GE-NE-523-A71-0594-A, Revision 1". This report proposed an alternative to the recommendations of NUREG-0619". The topical report proposed to (1) accept the UT asthe basis to eliminate supplemental liquid PT of inside radii of the RPV nozzles, (2) lengthen the time interval between routine UT of inside radii of the RPV nozzles, and (3) reduce the inspection area of inside radii of the RPV nozzles. In its review of the topical report, the staff 3-62focused on the quality and reliability of the UT examinations. In its letter to BWROG, datedMarch 10, 2000, the staff approved the proposed inspection program and schedule as described in the BWROG topical report; therefore, GE-NE-523-A71-0594-A, Revision 1, is an acceptable alternative to the NUREG-0619 inspection guidelines.The applicant stated that it had made four long-term inspection commitments based onNUREG-0619 in 1989, as follows:  (1)Review online FW nozzle thermal sleeve leak detection system data monthly.  (2)Perform external UT examinations on two of the four FW nozzles each refueling outage.  (3)Perform visual inspections of the spargers and the nozzle blend radius areas of all fourFW nozzles each refueling outage.  (4)Perform PT examinations of nozzles at the next appropriate opportunity in the event that(a) UT examinations indicate a flaw or (b) online leakage monitoring systems identifyexcessive leakage (greater than 0.3 gallons per minute).In the corresponding SER, the staff stated that MNGP will continue inspections for "9 inspectioninterval-refueling cycles or 135 startup/shutdown cycles" as stated in NUREG-0619. Theinspection interval began with the installation of welded thermal sleeves during the 1981 refueling outage. With the completion of inspections during the 1998 refueling outage, the applicant had completed the required nine inspection interval-refueling cycles with no observeddegradation of the FW nozzles. The most recent FW nozzle inspections during the third 10-year ASME Section XI In-Service Inspection Program (ending on May 1, 2003) also revealed no cracking on these nozzles.During the audit and review, the staff asked the applicant to clarify plans to update its currentBWR Feedwater Nozzle Program to meet the recommendations in GE-NE-523-A71-0594, Revision 1. The applicant stated that (1) the requirement specified in ASME Code, Section XI,Table IWB-2500-1, Examination Category B-D, for full-penetration welded nozzles has been incorporated into the BWR Feedwater Nozzle Program, (2) the region inspected, examinationtechniques, and personnel qualifications will be consistent with the recommendations of GE-NE-523-A71-0594, Revision 1, Section 4.0, and (3) the requirement of Appendix VIII to ASMECode, Section XI, including IWB-2400 schedule requirements has been incorporated into the BWR Feedwater Nozzle Program, which will be enhanced for consistency with therecommendations of GE-NE-523-A71-0594, Revision 1, Sections 6.2 and 6.3. If defects are detected, the applicant will expand the scope of examinations pursuant to the requirements ofIWB-2430. The staff found this enhancement acceptable because the associated recommendations are based on (1) the availability of the proven improved UT techniques, (2)meeting the inspection commitments made in 1989, (3) acceptable performance history of the FW nozzles with the new thermal sleeves, and (4) the staff's approval of use of GE-NE-523-A71-0594, Revision 1.On the basis of its review of the above enhancement and discussions with the applicant'stechnical personnel, the staff found this enhancement acceptable as such changes to the applicant's program provide assurance that the effects of aging will be adequately managed.
3-63The staff reviewed those portions of AMP B2.1.8, "BWR Feedwater Nozzle Program," that theapplicant claimed are consistent with GALL AMP XI.M5 and found them consistent. The staff found the applicant's AMP acceptable because it conforms to the recommended GALL Report AMP with the exception and enhancement as described above.Operating Experience. In LRA Section B2.1.8, the applicant explained that it performedengineering evaluations based on plant and industry experience and component and programmatic corrective actions implemented as required:
* Repairs were made to the FW nozzles and safe ends in 1977 to minimize damage to theFW nozzles due to thermal cycling. Cladding was removed from t he nozzle blend radiusand bore, and an FW sparger interference fit thermal sleeve with a piston ring seal was installed.
* New FW nozzle safe ends were installed in 1981. These safe ends have a tuning forkdesign with a welded-in thermal sleeve and provide a significant reduction in thermal cycling.
* The applicant incorporated considerations from NUREG-0619, along with NRC GL81-11, "BWR Feedwater Nozzle and Control Rod Drive Return Line Nozzle Cracking (NUREG-0619)," dated February 29, 1981, into the BWR Feedwater Nozzle Programduring the third 10-year inspection interval ending on May 1, 2003. No cracking was identified as a result of these inspections.The staff reviewed the operating experience provided in the LRA and interviewed theapplicant's technical personnel to confirm that plant-specific operating experience revealed no degradation not bounded by industry experience.On the basis of its review of the above operating experience and discussions with theapplicant's technical personnel, the staff concluded that the applicant's BWR Feedwater NozzleProgram will adequately manage the aging effects identified in the LRA for which this AMP iscredited.USAR Supplement. In LRA Section A2.1.8, the applicant provided the USAR supplement forthe BWR Feedwater Nozzle Program. The staff reviewed this section and determined that the information in the USAR supplement adequately describes the program, as required by 10 CFR 54.21(d).In its letter dated June 10, 2005, the applicant added the following three commitments to USARSection A2.1.8, documented as commitments 18-20 in Table A.5, that it will complete beforethe period of extended operation:  (1)The parameters monitored and inspected are consistent with the recommendations ofGE-NE-523-A71-0594-A, Revision 1.  (2)The regions being inspected, examination techniques, personnel qualifications, andinspection schedule are consistent with the recommendations of GE-NE-523-A71-0594-A, Revision 1.  (3)The applicant will schedule inspections per recommendations of GE-NE-523-A71-0594-A, Revision 1.
3-64The BWR Feedwater Nozzle Program is not currently augmented by the recommendations ofGE-NE-523-A71-0594". The applicant will enhance the program by including therecommendations of GE-NE-523-A71-0594-A, Revision 1. The applicant updates this program periodically as required by 10 CFR 50.55a.Conclusion. On the basis of its review and audit of the applicant's BWR Feedwater NozzleProgram, the staff determined that those program elements for which the applicant claimedconsistency with the GALL Report are consistent with the GALL Report. In addition, the staffreviewed the enhancements and confirmed that their implementation before the period ofextended operation will result in the existing AMP being consistent with the GALL Report AMPto which it was credited. The staff concluded that the applicant demonstrated that the effects ofaging will be adequately managed so that intended functions will be maintained consistent withthe CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff alsoreviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.2.8  BWR Penetrations Program Summary of Technical Information in the Application. In LRA Section B2.1.9, the applicantdescribed the BWR Penetrations Program, stating that this existing program is consistent, with exceptions, with GALL AMP XI.M8, "BWR Penetrations." The MNGP BWR Penetrations Program is part of the MNGP ASME Section XI In-Service Inspection Program. The BWR Penetrations Program is in accordance with the ASME Code, Section XI, 1995 edition through the 1996 addenda (with approved ISI relief requests) and provides for condition monitoring of the BWR penetrations. The BWR water chemistry is controlled in accordance with the EPRI guidelines of BWRVIP-130 (TR-1008192), "BWR Water Chemistry Guidelines-2004 Revision."
This document supersedes previous revisions of the guidelines, including BWRVIP-29 (TR-103515), "BWR Water Chemistry Guidelines-1993 Revision."  Program activities at MNGP incorporate the inspection and evaluation guidelines of BWRVIP-49, "BWR Vessel and Internals Project, Instrument Penetration Inspection and Flaw Evaluation Guidelines," for instrument penetrations and BWRVIP-27, "BWR Vessel and Internals Project, BWR Standby Liquid Control System/Core Plate DP Inspection and Flaw Evaluation Guidelines," for the standby liquid control (SLC) system. The applicant updates the program periodically as requiredby 10 CFR 50.55a and the BWRVIP.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's audit evaluation of this AMP. The staff reviewed the exceptions and the associated justifications todetermine whether the AMP, with the exceptions, remains adequate to manage the agingeffects for which it is credited.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses consistency of the AMP elements with GALL AMP XI.M8.In the LRA, the applicant stated the following exceptions to the program elements listed forAMP XI.M8 in the GALL Report.
3-65Exception 1:  The GALL Report recommends the following for the program descriptionassociated with of the exception taken:The program includes monitoring and control of reactor coolant water chemistryin accordance with the guidelines of BWRVIP-29 (Electric Power Research
[EPRI] TR-103515) to ensure the long-term integrity and safe operation of boilingwater reactor (BWR) vessel internal components.The GALL Report recommends the following for the Preventive Actions program elementassociated with the exception taken:Maintaining high water purity reduces susceptibility to SCC or IGSCC, andreactor coolant water chemistry is monitored and maintained in accordance with the guidelines in BWRVIP-29 (EPRI TR-103515).In the LRA, the applicant stated that it controls BWR water chemistry using BWRVIP-130instead of the guidelines in BWRVIP-29 recommended by the GALL Report.The staff evaluated this exception as part of the Plant Chemistry Program. SER Section3.0.3.2.19 documents the Plant Chemistry Program description, evaluation, and technical basisfor monitoring reactor water chemistry.The applicant stated, in the LRA, that its BWR Penetrations Program is "in accordance withASME Section XI, 1995 Edition through 1996 Addenda (with approved ISI relief requests)."During the audit and review, the staff asked the applicant whether its current approved ISI reliefrequests or code cases affect any of its AMP elements. In its response, by letter dated August 31, 2005, the applicant identified the following additional exception to the GALL Report programelements.Exception 2:  The GALL Report recommends the following for the Detection of Aging Effectsprogram element associated with the identified exception:Instrument penetrations and SLC system nozzles or housings are inspected inaccordance with the requirements of ASME Section XI, Subsection IWB.
Components are examined and tested as specified in Table IWB-2500-1, examination categories B-E for pressure-retaining partial penetration welds in vessel penetrations, B-D for full penetration nozzle-to-vessel welds, B-F for pressure-retaining-dissimilar metal nozzle-to-safe-end welds, or B-J for similar metal nozzle-to-safe end welds. In addition, these components are part of examination category B-P for pressure-retaining boundary.In its letter dated August 11, 2005, the applicant stated that its BWR Penetrations Program willdeviate from ASME Code, Section XI, Table IWB-2500-1 and Figure IWB-2500-7(b) requirements in terms of the examination volume for Category B-D components.In its evaluation of the effects of current approved ISI relief requests and code cases, theapplicant stated that during the current ISI inspection interval, which will extend approximately21 months into the period of extended operation, examination of Category B-D components 3-66(Full Penetration Welded Nozzles in Vessels) will deviate from the requirements of ASMECode, Section XI, Table IWB-2500-1, Item No. B3.90, and from the requirements of ASME Code, Section XI, Figure IWB-2500-7(b). Specifically, Figure IWB-2500-7(b) requires that a minimum volume of material equal to a distance of one-half the reactor vessel shell thickness (i.e., a distance of approximately 2-1/2 inches) be included in the examination on each side of the weld; however, the BWR Penetrations Program instead will examine a reduced volume ofone-half inch of base metal on each side of the widest portion of the weld. The applicant identified this reduction in weld examination volume as an exception to the recommendations of GALL AMP XI.M8. The applicant technically justified the reduction in examination volume as follows:The required examination volume for the reactor vessel pressure retainingnozzle-to-vessel welds extends far beyond the weld into the base metal, and is unnecessarily large. The proposed alternative re-defined the examination volume boundary to 1/2 inch of base metal on each side of the widest portion of the weld, removing from examination the base metal that was extensively examined during prior inspections, and that is not in the high residual stress region associated with the weld.The creation of flaws during plant service in the volume excluded from theproposed reduced examination is unlikely because of the low stress in the base metal away from the weld. The stresses caused by welding are concentrated at or near the weld. Cracks, should they initiate, occur in the high-stressed areas ofthe weld. These high-stress areas are contained in the volume that is defined by Code Case N-613-1 and are thus subject to examination. During previous examinations, no indications exceeding the allowable limits of the preservice or inservice criteria were found in the reactor vessel nozzle to shell examination volumes including the base metal areas proposed for exclusion from examination in this request.In its letter dated August 31, 2005, the applicant stated that it considers the alternativeexamination of Category B-D welds based on Code Case N-613-1 an exception to the Detection of Aging Effects program element as described in GALL AMP XI.M8. The staff reviewed the applicant's description and technical justification for this exception as summarized in the preceding paragraph. The staff also reviewed the applicant's letter dated February 27, 2004, which provides a similar technical justification and includes tables of previous examination results. Because the examination volume includes the heat-affected regions of base metal around the welds where new cracks are most likely to occur and previousexaminations of the base metal beyond the heat-affected regions have not detected anyunacceptable indications, the staff concluded that this exception is acceptable.During the audit and review, the staff noted that in the Detection of Aging Effects programelement the applicant referred parenthetically to "risk-informed ISI." Specifically, the first sentence of the Detection of Aging Effects program element reads as follows:The detection of aging effects is prescribed by the MNGP BWR PenetrationsProgram in accordance with the requirements of ASME Section XI, Table IWB-2500-1 for Examination Categories B-D, B-O and B-W and NRC approved alternatives for Categories B-F and B-J (risk-informed ISI (RI-ISI)).
3-67The staff asked the applicant to address the effects of its RI-ISI associated with the Detection ofAging Effects program element.In its response, by letter dated August 31, 2005, the applicant stated that its implementation ofRI-ISI affects the Detection of Aging Effects program element of its BWR Penetrations Program and is an exception to GALL AMP XI.M8.Exception 3:  The GALL Report recommends the following for the Detection of Aging Effectsprogram element associated with the exception:Instrument penetrations and SLC system nozzles or housings are inspected inaccordance with the requirements of ASME Section XI, Subsection IWB.
Components are examined and tested as specified in Table IWB-2500-1, examination categories B-E for pressure-retaining partial penetration welds in vessel penetrations, B-D for full penetration nozzle-to-vessel welds, B-F for pressure-retaining dissimilar metal nozzle-to-safe end welds, or B-J for similar metal nozzle-to-safe-end welds. In addition, these components are part of examination category B-P for pressure-retaining boundary. Further details for examination are described in Chapter XI.M1, "ASME Section XI, In-Service Inspection, Subsection IWB, IWC, and IWD," of this report.In the LRA, the applicant stated that its ASME Section XI In-Service Inspection,Subsections IWB, IWC, and IWD Program will include an RI-ISI methodology as an alternativeto the ASME Code, Section XI ISI requirements in terms of (1) the number of locations inspected, (2) the locations inspected, and (3) the method of inspection. This alternative appliesto welds in ASME Code, Section XI Categories B-F (Class 1 pressure-retaining dissimilar metal welds in vessel nozzles), B-J (Class 1 pressure-retaining welds in piping), C-F-1 (Class 2 pressure-retaining welds in austenitic stainless steel or high-alloy piping), and C-F-2 (Class 2 pressure-retaining welds in carbon or low-alloy steel piping).In its letter dated August 31, 2005, the applicant stated that its implementation of RI-ISI duringthe current inspection interval affects both GALL AMP XI.M1 and GALL AMP XI.M8." The staff's evaluation documented in SER Section 3.0.3.2.2, exception 7, applies to this exception, so thestaff concluded that the applicant's implementation of RI-ISI is an acceptable exception formanaging applicable component aging effects through the end of the applicant's current ISI inspection interval on May 31, 2012, approximately 21 months into the extended operatingperiod.On the basis of the review of the above exceptions and of operating experience for the BWRPenetrations Program, the staff found these exceptions acceptable.The staff reviewed those portions of AMP B2.1.9, "BWR Penetrations Program," that theapplicant claimed are consistent with GALL AMP XI.M8 and found them consistent. The staff found the applicant's LRA AMP acceptable because it conforms to the recommended GALL Report AMP with the exceptions as described above.Operating Experience. In LRA Section B2.1.9, the applicant explained that it periodicallyexamines materials within the scope of the BWR Penetrations Program and evaluates them for corrective action as needed. The program incorporates vendor guidance (e.g., BWRVIP-49 and 3-68-27). The applicant has implemented corrective actions to replace materials susceptible tocracking. For example, (1) the SLC nozzle safe end was replaced in 1984 using different materials to resist IGSCC, (2) in 1984 the jet pump instrumentation safe end and penetration seal were replaced with a jet pump instrumentation nozzle penetration seal using 316L stainless steel materials to resist IGSCC, and (3) a corrosion-resistant clad overlay was applied to the inside diameter (ID) of the reactor vessel head vent nozzle (N7) and the reactor vessel head cooling spray nozzles N6A & B (penetrations). The corrosion-resistant clad overlay isolated the IGSCC susceptible weld butter from the reactor coolant.The staff reviewed the operating experience provided in the LRA and interviewed theapplicant's technical personnel to confirm that plant-specific operating experience revealed no degradation not bounded by industry experience.On the basis of its evaluation of the applicant's program against the program elementsdescribed in the GALL Report AMP, the above industry and plant-specific operating experience, and its discussions with the applicant's technical personnel, the staff concluded that the applicant's BWR Penetrations Program will adequately manage the aging effects identified inthe LRA for which this AMP is credited.USAR Supplement. In LRA Section A2.1.9, the applicant provided the USAR supplement forthe BWR Penetrations Program. The staff noted that this USAR supplement includes parenthetic mention of "approved ISI relief requests." In its letter dated August 31, 2005, the applicant stated that it will delete the reference to ISI relief requests from the USAR supplementdescription of the BWR Penetrations Program. The staff reviewed this section and determined that the information in the USAR supplement after deletion of the reference to ISI reliefrequests adequately describes the program as required by 10 CFR 54.21(d).Conclusion. On the basis of its review and audit of the applicant's BWR Penetrations Program,the staff determined that those program elements for which the applicant claimed consistencywith the GALL Report are consistent with the GALL Report. In addition, the staff reviewed theexceptions and the associated justifications and determined that the AMP, with the exceptions,is adequate to manage the aging effects for which it is credited. The staff concluded that the applicant demonstrated that the effects of aging will be adequately managed so that intendedfunctions will be maintained consistent with the CLB for the period of extended operation, asrequired by 10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.2.9  BWR Stress Corrosion Cracking Program Summary of Technical Information in the Application. In LRA Section B2.1.10, the applicantdescribed the BWR Stress Corrosion Cracking Program, stating that this existing program is consistent, with exception, with GALL AMP XI.M7, "BWR Stress Corrosion Cracking."  The applicant is implementing ASME Code, Section XI, with UT volumetric, surface, and visual inspections and the RI-ISI program. The MNGP BWR Stress Corrosion Cracking Program incorporates NUREG-0313 and NRC GL 88-01, "NRC Position on IGSCC in BWR AusteniticStainless Steel Piping," dated January 25, 1988, and its Supplement 1. The applicant hasreplaced all IGSCC susceptible materials or protected them with a cladding of resistant weld material. Therefore, all piping welds are now classified as IGSCC Category A in accordance with NUREG-0313 and GL 88-01. As part of the MNGP recirculation piping replacement effort, 3-69the applicant replaced austenitic stainless steel portions of piping systems 4 inches in nominaldiameter or larger operating at temperatures above 200 F of the reactor coolant pressureboundary in accordance with the requirements of NUREG-0313. In addition, a hydrogen waterchemistry system now operates, which reduces the oxidizing environment by introducing excesshydrogen to the RCS that combines with the free oxygen produced by radiolysis.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's audit evaluation of this AMP. The staff reviewed the exception and the associated justifications todetermine whether the AMP, with the exception, remains adequate to manage the aging effectsfor which it is credited.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.M7.The applicant stated that the LRA mentioned relief requests, including RI-ISI, as parts of thecurrent ASME Code, Section XI programs credited with managing aging effects. The applicant further stated that it did not consider relief requests as exceptions to GALL Report because they are temporary and many will expire before the period of extended operation. The applicantstated that code cases and relief requests related to its ASME Section XI In-Service Inspection, Subsections IWB, IWC, IWD, and IWF Program are valid for approximately 21 months into the period of extended operation and that the current inspection interval ends on May 31, 2012. Inaddition, the applicant stated that except for one difference related to the Corrective Actionsprogram element, its implementation of RI-ISI and currently approved relief requests affect none of its BWR Stress Corrosion Cracking Program elements. Consequently, as documented in its letter dated August 31, 2005, the applicant stated that it will revise the LRA to delete allreferences to the RI-ISI program in the BWR Stress Corrosion Cracking Program description.The staff reviewed the applicant's BWR Stress Corrosion Cracking Program and additionaldescriptions of its RI-ISI program in the applicant's letter dated December 18, 2001". On the basis of its review, the staff concluded that the RI-ISI program and approved ISI relief requests affect no BWR Stress Corrosion Cracking Program elements. The staff also found that the applicant's change to delete all references to the RI-ISI program in the description of its BWR Stress Corrosion Cracking Program is acceptable.In the LRA, the applicant stated the following exceptions to the program elements listed forAMP XI.M7 in the GALL Report.Exception 1:  The GALL Report recommends the following for the Preventive Actions programelement associated with the exception taken:The program delineated in NUREG-0313 and NRC GL 88-01 does not providespecific guidelines for controlling reactor water chemistry to mitigate IGSCC; however, 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 (Electric Power Research Institute (EPRI)
TR-103515).
3-70In the LRA, the applicant stated that it controls BWR water chemistry using BWRVIP-130. Thisdocument supersedes previous revisions of the BWR water chemistry guidelines, including BWRVIP-29 referenced in the GALL Report.The staff evaluated this exception as part of the Plant Chemistry Program. SER Section3.0.3.2.19 documents the Plant Chemistry Program description, evaluation, and technical basisfor monitoring reactor water chemistry.During the audit and review, the staff asked the applicant whether its current approved ISI reliefrequests or code cases affect any of its AMP elements. In its letter dated August 31, 2005, the applicant identified the following additional exception to the GALL Report program elements.Exception 2:  The GALL Report recommends the following for the Corrective Actions programelement associated with the exception taken:The guidance for weld overlay repair and stress improvement or replacement isprovided in NRC GL 88-01; ASME Section XI, Subsections IWB-4000 andIWB-7000, IWC-4000 and IWC-7000, or IWD-4000 and IWD-7000, respectively, for Class 1, 2, or 3 components; and ASME Code Case 504-1.In its letter dated August 11, 2005, the applicant stated that an approved alternative allows theuse of the ASME Code, Section XI, 2001 edition in lieu of the 1995 edition with 1996 addenda for repair/replacement activities.The staff concluded that this alternative is not an exception and that with regard to this item, theaffected program element is consistent with the GALL Report. SER Section 3.0.3.1.7documents the staff's evaluation.The staff reviewed those portions of AMP B2.1.10, "BWR Stress Corrosion Cracking Program,"that the applicant claimed are consistent with GALL AMP XI.M7 and found them consistent. Thestaff found the applicant's AMP acceptable because it conforms to the recommended GALL Report AMP with the exceptions as described above.Operating Experience. In LRA Section B2.1.10, the applicant explained that a review of plantoperating experience for the BWR Stress Corrosion Cracking Program identified no adverse trends or issues with program performance. The applicant identified problems and corrected them before they caused any significant impact to safe operation, and it took adequatecorrective actions to prevent recurrence. The BWR Stress Corrosion Cracking Program effectively detects flaw indications in susceptible components and contains appropriate guidance for evaluation or repair of flaws. As needed, plant staff can adjust the inspection plan based on results to enhance program effectiveness. The applicant performs periodic self-assessments of the program and reviews of industry and plant experience to identify any needed improvements. Examples of corrective actions implemented as a result of program activities include the following:
* In 1984, a corrosion-resistant cladding overlay was applied to the ID of the head ventnozzle and head cooling spray and instrumentation nozzles. The weld overlay of 308L isolated the IGSCC susceptible existing weld butter located in the weld residual stress area from the reactor coolant.
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* In 1984, the recirculation inlet safe ends and thermal sleeve assembly and therecirculation outlet safe ends were replaced using nuclear-grade stainless steel materials to resist IGSCC.
* In 1986, new CSP nozzle safe ends featuring a tuning fork design with a thermal sleevewere installed. The applicant performed this modification to minimize IGSCC in the CSP system.The staff reviewed the operating experience provided in the LRA and interviewed theapplicant's technical personnel to confirm that plant-specific operating experience revealed no degradation not bounded by industry experience.On the basis of its evaluation of the applicant's program against the program elementsdescribed in the GALL Report AMP, the above industry and plant-specific operating experience, and discussions with the applicant's technical personnel, the staff concluded that the applicant'sBWR Stress Corrosion Cracking Program will adequately manage the aging effects identified inthe LRA for which this AMP is credited.USAR Supplement. In LRA Section A2.1.10, the applicant provided the USAR supplement forthe BWR Stress Corrosion Cracking Program. The staff reviewed this section and determined that the information in the USAR supplement adequately describes the program, as required by10 CFR 54.21(d). The staff noted that this USAR supplement describes "the risk-informed ISI program" in the same way as in the applicant's statement on consistency with the GALL Report.In its August 31, 2005, letter the applicant stated that it will delete the reference to the RI-ISIprogram from the USAR supplement description of the BWR Stress Corrosion Cracking Program.Conclusion. On the basis of its review and audit of the applicant's BWR Stress CorrosionCracking Program, the staff determined that those program elements for which the applicantclaimed consistency with the GALL Report are consistent with the GALL Report. In addition, thestaff reviewed the exception and the associated justifications and determined that the AMP,with the exception, is adequate to manage the aging effects for which it is credited. The staffconcluded that the applicant demonstrated that the effects of aging will be adequately managedso that intended functions will be maintained consistent with the CLB for the period of extendedoperation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.2.10  BWR Vessel ID Attachment Welds Program Summary of Technical Information in the Application. In LRA Section B2.1.11, the applicantdescribed the BWR Vessel ID Attachment Welds Program, stating that this existing program is consistent, with exception, with GALL AMP XI.M4, "BWR Vessel ID Attachment Welds." The MNGP BWR Vessel ID Attachment Welds Program is part of the MNGP ASME Section XI In-Service Inspection AMP. The BWR Vessel ID Attachment Weld Program is in accordance with the ASME Code, Section XI, 1995 edition through the 1996 addenda and approved ISI relief requests. The program provides for condition monitoring of the BWR vessel ID attachment welds. It includes inspection and flaw evaluation in accordance with BWRVIP-48 (EPRI TR-108724), "Vessel ID Attachment Weld and Inspection and Flaw Guidelines.". The 3-72BWR water chemistry is controlled in accordance with the EPRI guidelines of BWRVIP-130".The applicant updates the program periodically as required by 10 CFR 50.55a, and supplements it by implementing the guidelines of the BWRVIP documents.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's audit evaluation of this AMP. The staff reviewed the exception and the associated justifications todetermine whether the AMP, with the exception, remains adequate to manage the aging effectsfor which it is credited.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.M4.In the LRA, the applicant stated the following exception to the program elements listed for AMPXI.M4 in the GALL Report.Exception 1:  The GALL Report recommends the following for the Preventive Actions programelement associated with the exception taken:The BWRVIP-48 provides guidance on detection, but does not provide guidanceon methods to mitigate cracking. Maintaining high water purity reduces susceptibility to SCC or IGSCC. Reactor coolant water chemistry is monitored and maintained in accordance with the guidelines in BWRVIP-29 (EPRI TR-103515). The program description and evaluation and technical basis of monitoring and maintaining reactor water chemistry are presented in Section XI.M2, "Water Chemistry."In the LRA, the applicant stated that it controls the BWR water chemistry using BWRVIP-130instead of the guidelines in BWRVIP-29 recommended by the GALL Report.The staff found this exception acceptable. SER Section 3.0.3.2.19, Exception 1, documents thestaff's evaluation.During the audit and review, the staff asked the applicant to address whether its currentapproved ISI relief requests or code cases affect any of its AMP program elements. In its letter dated August 31, 2005, the applicant identified the following additional exception to the GALLReport program elements.Exception 2:  The GALL Report recommends the following for the Corrective Actions programelement associated with the exception taken:Repair and replacement procedures are equivalent to those requirements in theASME Section XI. Repair is in conformance with IWB-4000 and replacement occurs according to IWB-7000. As discussed in the appendix to this report, the staff found that licensee implementation of the guidelines in BWRVIP-48, as modified, will provide an acceptable level of quality for inspection and flawevaluation of the safety-related components addressed in accordance with 10 CFR Part 50, Appendix B, corrective actions.
3-73In its letter dated August 11, 2005, the applicant stated that an approved alternative allows theuse of the ASME Code, Section XI, 2001 edition in lieu of the 1995 edition with the 1996 addenda for repair/replacement activities.The staff concluded that this alternative is not an exception and that with regard to this item, theaffected program element is consistent with the GALL Report. SER Section 3.0.3.1.7documents the staff's evaluation.The staff reviewed those portions of AMP B2.1.11, "BWR Vessel ID Attachment WeldsProgram," that the applicant claimed are consistent with GALL AMP XI.M4 and found themconsistent. The staff found the applicant's AMP acceptable because it conforms to the recommended GALL Report AMP with the exceptions as described above.Operating Experience. In LRA Section B2.1.11, the applicant explained that it performed theengineering evaluations based on plant and industry experience and implemented component and programmatic corrective actions as required. For example, a vendor notification discussed the susceptibility of Alloy 182 welds to IGSCC/interdendritic SCC in shroud support structuressuch as those used in the MNGP vessel and shroud. BWRVIP-38, "BWR Shroud Support Inspection and Flaw Evaluation Guidelines," provides guidance on the inspection of the shroud support structure. The 2000 outage included inspection of the recommended 10-percent portions of the H8 and H9 welds using enhanced visual examination (EVT)-1 techniques around the access holes at the 0 and 180 degree locations. No indications were found. In addition, the applicant inspected 14 shroud support legs using a VT-3 technique because of flaw indications found on the initially examined support leg. The applicant continues to inspect the H8 and H9 welds in accordance with BWRVIP-38 but has found no operability impacts.The staff reviewed the applicant's operating experience evaluation for the BWR Vessel IDAttachment Welds Program and interviewed the applicant's program manager for this program to confirm that plant-specific operating experience revealed no degradation not identified byindustry experience.On the basis its evaluation of the applicant's program against the program elements describedin the GALL Report AMP, review of the above industry and plant-specific operating experience, and discussions with the applicant's technical personnel, the staff concluded that the applicant'sBWR Vessel ID Attachment Welds Program will adequately manage the aging effects identifiedin the LRA for which this AMP is credited.USAR Supplement. In LRA Section A2.1.11, the applicant provided the USAR supplement forthe BWR Vessel ID Attachment Welds Program. The staff reviewed this section and determined that the information in the USAR supplement adequately describes the program, asrequired by 10 CFR 54.21(d). The staff noted that this USAR supplement mentions "approved ISI relief requests." In its August 31, 2005, letter the applicant stated that it will delete thereference to ISI relief requests from the USAR supplement description of the BWR Vessel ID Attachment Welds Program.Conclusion. On the basis of its review and audit of the applicant's BWR Vessel ID AttachmentWelds Program, the staff determined that those program elements for which the applicantclaimed consistency with the GALL Report are consistent with the GALL Report. In addition, thestaff reviewed the exception and the associated justifications and determined that the AMP, 3-74with the exception, is adequate to manage the aging effects for which it is credited. The staffconcluded that the applicant demonstrated that the effects of aging will be adequately managedso that intended functions will be maintained consistent with the CLB for the period of extendedoperation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.2.11  BWR Vessel Internals Program Summary of Technical Information in the Application. In LRA Section B2.1.12, the applicantdescribed the BWR Vessel Internals Program, stating that this existing program is consistent, with exception and enhancement, with GALL AMP XI.M9, "BWR Vessel Internals." The BWR Vessel Internals Program is part of the ASME Section XI In-Service Inspection Program. The BWR Vessel Internals Program is in accordance with the ASME Code, Section XI, 1995 edition through the 1996 addenda and approved ISI relief requests. The program provides for condition monitoring of the BWR vessel internals for crack initiation and growth. MNGP activities include in-vessel examination procedures and plant water chemistry procedures. The in-vessel examination procedures implement the recommendations of the BWRVIP guidelines, as well as the requirements of the ASME Code, Section XI. This program relies on monitoring and control of water chemistry to keep peak levels of various contaminants below system-specific limitsbased on the EPRI guidelines in BWRVIP-130." This document supersedes previous revisions of the BWR water chemistry guidelines, including BWRVIP-29. The applicant updates this program periodically as required by 10 CFR 50.55a and the BWRVIP program.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's audit evaluation of this AMP. The staff reviewed the exception and enhancement and the associatedjustifications to determine whether the AMP, with the exception and enhancement, remainsadequate to manage the aging effects for which it is credited.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.M9.During the audit and review, the staff noted that, in the LRA, the applicant's program descriptionstated that the BWR Vessel Internals Program is "in accordance with ASME Section XI 1995 Edition through 1996 Addenda and approved ISI relief requests." The staff asked that the applicant clarify the phrase "and approved ISI relief requests." In its letter dated August 11, 2005, the applicant stated that the LRA mentions relief requests because they are parts of thecurrent ASME Code, Section XI programs credited with managing aging effects. The applicant further stated that it did not consider relief requests as exceptions to the GALL Report because they are temporary and many expire before the period of extended operation. The applicant stated that code cases and relief requests of its ASME Section XI In-Service Inspection, Subsections IWB, IWC, IWD and IWF Program are valid for approximately 21 months into the period of extended operation and that the current inspection interval ends on May 31, 2012.The applicant stated that none of its approved ISI relief requests affect any of the programelements of the BWR Vessel Internals Program. Subsequently, as documented in its letter dated August 31, 2005, the applicant revised the LRA to delete all references to ISI relief 3-75requests in the description of the BWR Vessel Internals Program. Upon review of theapplicant's evaluation of program elements against the approved relief requests, the staff found that no approved ISI relief requests affect any BWR Vessel Internals Program element. On this basis, the staff also found the applicant's revision to delete all references to ISI relief requests in the description of its BWR Vessel Internals Program acceptable.In the LRA, the applicant stated the following exception to the program elements listed for AMPXI.M9 in the GALL Report.Exception:  The GALL Report recommends the following for the Preventive Actions programelement associated with the exception taken:Maintaining high water purity reduces susceptibility to cracking due to SSC orIGSCC. Reactor coolant water chemistry is monitored and maintained in accordance with the guidelines in BWRVIP-29 (EPRI TR-103515). The program description and evaluation, and technical basis of monitoring and maintaining reactor water chemistry are presented in Chapter XI.M2, "Water Chemistry."In the LRA, the applicant stated that it controls the BWR water chemistry using BWRVIP-130instead of the guidelines in BWRVIP-29 recommended by the GALL Report.The staff found this exception acceptable. SER Section 3.0.3.2.19, Exception 1, documents thestaff's evaluation.In the LRA, the applicant stated that the following enhancement will make this AMP consistentwith the recommendation in the GALL Report.Enhancement:  The GALL Report recommends the following for the Scope of Program programelement associated with the enhancement made:The BWRVIP documents provide generic guidelines intended to present theapplicable inspection recommendations to assure safety function integrity of the subject safety-related reactor pressure vessel internal components...The various applicable BWRVIP guidelines are as follows:Core shroud: BWRVIPs -07, -63, and -76; and BWRVIP-02,Rev. 2.Core plate: BWRVIP-25; BWRVIP-50.Shroud support: BWRVIP-38; BWRVIP-52.Low-pressure coolant injection (LPCI) coupling: BWRVIP-42;BWRVIP-56.Top guide: BWRVIP-26; BWRVIP-50.Core spray: BWRVIP-18; BWRVIP-16 and BWRVIP-19.Jet pump assembly: BWRVIP-41; BWRVIP-51.
3-76Control rod drive (CRD) housing: BWRVIP-47; BWRVIP-58.Lower plenum: BWRVIP-47; BWRVIP-57.Steam Dryer: BWRVIP-139For each component or assembly, the first listed BWRVIP document provides guidelines forinspection and evaluation and the second, or last, listed provides guidelines for repair design criteria.In addition, BWRVIP-44 provides guidelines for weld repair of nickel alloys, and BWRVIP-45provides guidelines for weldability of irradiated structural components.In the LRA, the applicant stated that it will add the repair/replacement guidelines inBWRVIP-16, -19, -44, -45, -50, -51, -52, -57, and -58, as applicable, to its BWR VesselInternals Program.The applicant stated in the LRA that the enhancement is required to satisfy the GALL ReportAMP recommendations and that the enhancement is scheduled for completion before the period of extended operation. The staff found that the addition of the listed BWRVIP documentsis an appropriate enhancement to the applicant's current program that will make the applicant'sBWR Vessel Internals Program consistent with the recommendations of the GALL Report during the period of extended operation.The staff asked the applicant to verify that it will implement the applicable BWRVIP guidelinesduring the period of extended operation. In response, the applicant provided the followingdescription of its conformance with industry commitments for implementation of the BWRVIP guidelines:In a letter dated May 30, 1997, from Carl Terry (Niagara Mohawk PowerCompany, Chairman of BWR Vessel and Internals Project) to Brian Sheron (NRC), the BWRVIP member utilities commitments were expressed. The letter stated, 'We will implement the BWRVIP products at each of our plants asappropriate considering individual plant schedules, configurations and needs.'
One such document is BWRVIP-94, Program Implementation Guide.
BWRVIP-94 states that each member utility, of which Monticello/NMC is, will implement the BWRVIP guidelines to the fullest extent possible.Because the applicant's implementation documents indicate a very high degree of conformanceto BWRVIP guidelines, the staff considered this response acceptable. Additionally, in its letter, dated March 15, 2006, the applicant submitted commitment 57, which states that NMC is anactive member of the BWRVIP and will continue to follow applicable inspection guidelines andrecommendations that the executive committee of the BWRVIP has reviewed and approved throughout the period of extended operation.SER Section 4.8 discusses the staff's review of the impact of the time-limited aging analysis(TLAA) of the reactor internals core plate holddown bolts. During review of the issues, the staff requested that the applicant identify the results from the baseline inspections recommended forthe core plate holddown bolts in BWRVIP-25 (TR-107284), "BWR Core Plate Inspection and Flaw Evaluation Guidelines," issued December 1996. The applicant stated that it had not yet 3-77completed the recommended inspections because tooling had not been developed to performthe inspections. Therefore, the staff requested that the applicant complete this action beforeentering the period of extended operation. If tooling is not available, the applicant could usewedges that provide lateral restraint for the core plate, or propose alternative inspection methods that the staff will review and approve. In its letter dated March 31, 2006, the applicantprovided commitment 60 in Appendix A, stating that before the period of extended operation, itwould either inspect the core plate holddown bolts in accordance with the BWRVIP inspection guidelines, install the core plate wedges, or develop an alternative to the inspections identified in BWRVIP-25 and submit it to the staff for review and approval. The staff found this response acceptable because it is consistent with the inspection guidelines described in BWRVIP-25.The staff reviewed those portions of the AMP B2.1.12, "BWR Vessel Internals Program," thatthe applicant claimed are consistent with GALL AMP XI.M9 and found them consistent. The staff found the applicant's AMP acceptable because it conforms to the recommended GALL Report AMP with the exception and enhancement described above.During the aging management inspection, the inspectors identified that additional changes werenecessary to ensure that the applicant adequately managed plant aging effects relating to reactor vessel internals in accordance with the AMP.The inspectors noted that incore monitoring instrument dry tubes are within the scope of theAMP. However, these tubes are not subject to periodic inspections under the applicant's AMP that credits the BWRVIP-130 BWR water chemistry guidelines and the ASME Code, Section XI inspection programs. Because these tubes are subject to radiation-induced damage above the threshold for irradiation-assisted SCC (IASCC), they could crack and cause pressure boundary leakage. Operating experience for GALL AMP XI.M9 identified that cracking has been observedat other BWRs. Furthermore, GE Service Information Letter (SIL)-409, "Incore Dry Tube Cracks," recommended periodic (every other outage) visual examinations focused on the upper2 feet of the tube to detect cracking. The applicant voluntarily implemented these examinationsfor the current license; however, the applicant had not committed to continue with theseexaminations during the period of extended operation. The applicant stated that the next annualLRA revision will incorporate into its AMP the examinations of incore monitoring instrument dry tubes recommended in GE SIL-409. In its letter, dated March 15, 2006, the applicant providedcommitment 56 in Table A.5, which states that NMC has inspected the incore monitoring drytubes at every other refueling outage and will continue to perform this inspection during theperiod of extended operation, in accordance with the guidance provided in GE SIL-409. The staff found the applicant's response acceptable because it ensures that aging effects for the drytubes will be adequately managed during the period of extended operation.The inspectors determined that the steam dryer was within the scope of license renewal for itsstructural function, and the applicant conducted periodic inspection of steam dryer welds potentially subject to cracking. The applicant submitted the LRA before the issuance of theBWRVIP inspection program guidance defined in BWRVIP-139, "Steam Dryer Inspection and Flaw Evaluation Guidelines." The applicant stated that the next annual LRA revision would incorporate the BWRVIP-139 steam dryer weld examinations into the AMP. In its letter, dated March 15, 2006, the applicant provided commitment 58 in Table A.5, which states that NMC willfollow the guidance provided in BWRVIP-139 for the MNGP steam dryer inspections. The staff found the applicant's response acceptable because BWRVIP-139 provides specific guidelines 3-78to ensure that cracking of the steam dryer will be adequately managed during the period ofextended operation.In CAP 014359 (CR 20000209), the applicant documented that during the 2000 refuelingoutage, areas of the steam dryer in close proximity to the main steam (MST) nozzles appeared polished and that this wear could be caused by steam impingement. The applicant also documented in AR 000032 that Vermont Yankee, with an identical steam dryer design, hadobserved evidence of steam erosion at the underside of the steam dryer. To evaluate if steam erosion was occurring, a degradation mechanism not identified for the steam dryer in GALL AMP XI.M9, the applicant stated that it will reinspect the affected areas of the MNGP steam dryer during the next refueling outage. The evaluation of the areas will determine if erosion isan aging mechanism that needs to be managed.The inspectors also identified that in LRA Table B1.6-11, the applicant stated that the internalCSP piping welds P1, P2, and P3 were not inspected in accordance with BWRVIP-18, "Core Spray Internals Inspection and Flaw Evaluation Guidelines," because mechanical clamps were installed to ensure the structural integrity of the sparger T-box welds, and that a visual inspection was conducted each outage to confirm that T-box integrity was maintained.
Specifically, the applicant performed a general visual examination (VT-3) of the mechanical clamp repair hardware installed around the welds, instead of an enhanced visual examination (EVT-1) of the welds.BWRVIP-18 does not require examination of repaired CSP pipe welds unless the integrity ofthe repair depends upon these welds. The inspectors noted that if cracks develop in thenoninspected CSP piping welds P1, P2, and P3, a cooling water flow diversion path would exist outside the core shroud that could adversely affect the applicant's peak fuel clad temperatureanalysis. Because the applicant's primary clad temperature analysis relied, to some extent, on the leakage integrity for these repaired welds, the inspectors determined that these weldsshould be inspected using EVT-1 methods to meet BWRVIP-18 requirements. Therefore, the inspectors concluded that the applicant had deviated from the BWRVIP-18 guidance and thatthis deviation should be identified as an exception to the GALL Report. The applicant stated that it will change the LRA to remove statements about not inspecting these welds during thenext annual LRA revision, and that it will also change the applicable inspection procedures toimplement enhanced visual examinations of these welds. In its letter, dated March 15, 2006, the applicant provided commitment 59 in Table A.5, which states that NMC will add inspectionrequirements for the P1, P2, and P3 CSP piping welds in accordance with guidance provided in BWRVIP-18, or subsequent revisions. The staff found the applicant's response acceptable because it will ensure that aging effects that might impact the welds will be adequatelymanaged in accordance with the guidance in BWRVIP-18.Operating Experience. In LRA Section B2.1.12, the applicant explained that the BWR VesselInternals Program is based on inspection requirements contained in plant procedures, which incorporate the requirements of the ASME Code. Further, the ASME Code inspections are enhanced with inspections requirements consistent with the BWRVIP. The inspection and testing methodologies have been effective in detecting aging effects due to crack initiation and growth. As shown in the following examples, the applicant performed engineering evaluations based on plant and industry experience and implemented component and programmatic corrective actions as required:
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* In 2003, UT inspection of the CSP line found cracking in the CSP piping slip joint welds.The previous evaluation was determined to bound the current flaw size, and no further action was necessary.
* In 1994, mechanical clamps were installed on both of the in-vessel tee box assembliesfor the CSP sparger loops A and B. This modification provided a permanent fix that mitigates the crack in the CSP in-vessel lateral header and ensures the CSP system'ssafety function.
* In 1994, visual inspection of the jet pumps during the refueling outage revealed crackingof tack welds on the jet pump restrainer bracket adjusting screws. The cracking was attributed to high cycle fatigue from jet pump vibration. The applicant added new tackwelds to the jet pumps restrainer bracket adjusting screws.The staff reviewed the operating experience provided in the LRA and interviewed theapplicant's technical personnel to confirm that plant-specific operating experience revealed no degradation not bounded by industry experience.On the basis of its evaluation of the above industry and plant-specific operating experience anddiscussions with the applicant's technical personnel, the staff concluded that the applicant'sBWR Vessel Internals Program will adequately manage the aging effects identified in the LRAfor which this AMP is credited.USAR Supplement. In LRA Section A2.1.12, the applicant provided the USAR supplement forthe BWR Vessel Internals Program. The staff reviewed this section and determined that the information in the USAR supplement adequately describes the program, as required by 10 CFR 54.21(d).The staff noted that this USAR supplement also mentions "approved ISI relief requests."  In itsletter, dated August 31, 2005, the applicant stated that it will delete the reference to ISI reliefrequests from the USAR supplement description of the BWR Vessel Internals Program.In its letter, dated June 10, 2005, the applicant committed to add the repair/replacementguidelines in BWRVIP-16, -19, -44, -45, -50, -51, -52, -57, and -58, as applicable, to the BWRVessel Internals Program before the period of extended operation. In addition, during the periodof extended operation, the applicant committed to add top guide grid inspections  using theEVT-1 method of examination for the high fluence locations (grid beam and beam-to-beam crevice slot locations with fluence exceeding 5.0x10 20 neutrons per square centimeter (n/cm 2)).The applicant will inspect 10 percent of the total population within 12 years, with a minimum of5 percent inspected within the first 6 years.Conclusion. On the basis of its review and audit of the applicant's BWR Vessel InternalsProgram, the staff determined that those program elements for which the applicant claimedconsistency with the GALL Report are consistent with the GALL Report. In addition, the staffreviewed the exception and the associated justifications and determined that the AMP, with theexception, is adequate to manage the aging effects for which it is credited. The staff also reviewed the enhancement and confirmed that their implementation before the period ofextended operation will result in the existing AMP being consistent with the GALL Report AMPto which it was credited. The staff concluded that the applicant demonstrated that the effects ofaging will be adequately managed so that intended functions will be maintained consistent with 3-80the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff alsoreviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.2.12  Closed-Cycle Cooling Water System Program Summary of Technical Information in the Application. In LRA Section B2.1.13, the applicantdescribed the Closed-Cycle Cooling Water (CCCW) System Program, stating that this existingprogram is consistent, with exceptions and enhancement, with GALL AMP XI.M21, "Closed-Cycle Cooling Water System." The MNGP CCCW System Program includes (1)preventive measures to minimize corrosion and (2) periodic system and componentperformance testing and inspection to monitor the effects of corrosion and confirm that intended functions are met. Preventive measures include the monitoring and control of corrosion inhibitors and other chemical parameters, such as pH, in accordance with the guidelines of EPRI TR-1007820, "Closed Cooling Water Chemistry Guideline," vendor recommendations, and plant operating experience. EPRI TR-1007820 is the current revision (Revision 1) of EPRI-107396, "Closed Cooling Water Chemistry Guidelines."  As the applicant made only minor changes to the MNGP CCCW System Program to implement EPRI TR-1007820, the programis also still in accordance with the EPRI Revision 0 guidelines identified in GALL AMP XI.M21(i.e., EPRI TR-107396). The applicant also performs periodic inspection and testing to confirm function and monitor corrosion, in accordance with EPRI TR-1007820, vendor recommendations, and industry and plant operating experience. A review of plant operating experience demonstrates these measures ensure CCCW systems are performing their intended functions.The applicant has four systems within the scope of license renewal meeting the definition forconsideration as CCCW systems and portions of three additional systems (heat exchangers orcoolers) serviced directly by these cooling water systems. These systems and portions ofsystems are not subject to significant sources of contamination, in which water chemistry is controlled and heat is not rejected directly to a heat sink. The adequacy of chemistry control is confirmed by routine sampling and monitoring for established limits and by equipment performance monitoring to identify aging effects. Corrosion inhibitor concentrations are maintained within limits based on a combination of EPRI TR-1007820 guidelines, vendor recommendations, and plant experience. System and component performance test results are evaluated in accordance with EPRI TR-1007820 guidelines and used as a basis for evaluating the effectiveness of actions to mitigate cracking, corrosion, and heat exchanger fouling.
Acceptance criteria and tolerances are also based on system design parameters and functions.Many chemical parameters monitored are based on ranges identical to or more restrictive than those noted in both EPRI TR-1007820 and EPRI TR-107396. Others are based on vendor recommendations and plant experience. The frequency of performance and functional tests is consistent with EPRI TR-1007820 and based on plant operating experience, trends, and equipment performance. System and component operability tests are typically more fr equentthan once per cycle, whereas more intrusive inspections (e.g., disassembly, eddy currenttesting) are performed less frequently.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's audit evaluation of this AMP. The staff reviewed the exceptions and enhancement and the associated 3-81justifications to determine whether the AMP, with the exceptions and enhancement, remainsadequate to manage the aging effects for which it is credited.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.M21.In the LRA, the applicant stated the following exceptions to the program elements listed forAMP XI.M21 in the GALL Report.Exception 1:  The GALL Report recommends the following for the Scope of Program programelement associated with the exception taken:A CCCW system is defined as part of the service water system that is notsubject to significant sources of contamination, in which water chemistry is controlled and in which heat is not directly rejected to a heat sink. The program described in this section applies only to such a system. If one or more of theseconditions are not satisfi ed, the system is to be considered an open-cycle coolingwater system. The staff notes that if the adequacy of cooling water chemistrycontrol can not be confirmed, t he system is treated as an open-cycle system asindicated in Action III of Generic Letter (GL) 89-13.In the LRA, the applicant stated that its CCCW System Program uses EPRI TR-1007820, notEPRI TR-107396, as recommended by the GALL Report. EPRI TR-1007820 is the current revision (Revision 1) of EPRI TR-107396.The GALL Report recommends using EPRI TR-107396 to monitor for corrosion effects. Theapplicant uses EPRI TR-1007820, the revision of the same EPRI technical report. The staff reviewed the EPRI TR-107396 standards, compared them to EPRI TR-1007820, and noted that these EPRI reports contain both control and diagnostic parameters. EPRI defines control parameters (e.g., pH, conductivity, or corrosion inhibitor concentration) as those that have an immediate effect on corrosion and strict adherence to them is expected. EPRI defines diagnostic parameters as those that provide baseline information on system conditions or thatassist in problem troubleshooting and adherence to them is suggested. EPRI based the changes made to TR-1007820 on industry experience updated since the original EPRI technical report. The staff noted that the control parameters of the newer EPRI TR-1007820 are eitherthe same as or more conservative than those in the older EPRI TR-107396. On the basis of this comparison, the staff determined that no technical concerns are associated with the use ofEPRI TR-1007820 and found the exception acceptable.Exception 2:  The GALL Report recommends the following for the Preventive Actions programelement associated with the exception taken:The program relies on the use of appropriate materials, lining, or coating toprotect the underlying metal surfaces and maintenance of system corrosioninhibitor concentrations within specified limits of EPRI TR-107396 to minimize corrosion. The program includes monitoring and control of cooling water chemistry to minimize exposure to aggressive environments and application of 3-82corrosion inhibitor in the CCCW system to mitigate general, crevice, and pittingcorrosion.In the LRA, the applicant stated that the Closed-Cycle Cooling Water System Program does notinclude some of the chemical parameters recommended for routine monitoring by EPRI TR-1007820 and EPRI TR-107396. Chosen parameters are deemed adequate based on a combination of system design features (which preclude the need for monitoring somechemicals), makeup water source requirements, EPRI TR-1007820 guidelines, vendor recommendations, and plant operating experience.The applicant stated in the LRA that it monitors most of the chemical parameters recommendedby the GALL Report and EPRI TR-1007820 in the closed-cycle cooling systems. The applicantalso stated that system design precludes any need to monitor several of these parameters, andoperating and inspection activities preclude the need to monitor others. The staff noted that the LRA indicates the specific parameters monitored or excluded for the inhibitor type of each CCCW system, and the PBD itemizes them on a parameter basis.The staff concluded that the parameters that the applicant monitored in its CCCW systemsaccomplished the same goal as did those recommended by the GALL Report. The only parameters recommended for monitoring by EPRI that the applicant did not monitor are thosenot used or applicable at MNGP.On the basis of the above review and a review of MNGP operating experience for AMP B2.1.13,the staff found this exception acceptable.Exception 3:  The GALL Report recommends the following for the Parameters Monitored orInspected program element associated with the exception taken:The aging management program (AMP) monitors the effects of corrosion bysurveillance testing and inspection in accordance with standards in EPRI TR-107396 to evaluat e system and component performance. For pumps, theparameters monitored include flow and discharge and suction pressures. For heat exchangers, the parameters monitored include flow, inlet and outlet temperatures, and differential pressure.In the LRA, the applicant stated that some of the heat exchanger and pump performanceparameters recommended by the GALL Report are not monitored for specific pumps or smaller coolers serviced by the closed-cooling water systems. Some of these components are withinthe scope of license renewal only for pressure boundary considerations. Chemical control and established performance monitoring techniques based on plant experience have been
 
adequate to detect changes in system performance due to cracking or corrosion.The staff reviewed selected inspection and monitoring procedures, then compared the requiredheat exchanger and pump performance parameters against those recommended by the GALL Report. The staff noted the following exceptions to the GALL Report recommendations and the applicant's actions in lieu of those recommendations.The applicant stated that, as an exception to the GALL Report, inlet reactor building closedcooling water (RBC) heat exchanger temperature is not monitored; however, in addition to the 3-83recommendations of the GALL Report, the outlet RBC temperature and both inlet and outletraw water side temperatures are measured. After an evaluation, the staff found that theadditional information that the applicant had gathered is an adequate substitute for the information recommended by the GALL Report, because it verifies that no aging effects reduce heat transfer. The staff reviewed the applicant's additional information and found it acceptable.The applicant stated that, as an exception to the GALL Report, the RHR and REC pump sealcoolers pressure is not monitored; however, flow through these pump seal coolers is monitored, as are RBC surge tank level, various temperatures and flows, and radionuclide levels, all of which alarm when values go out of range. These parameters indicate pressure integrity failures within this closed l oop system. Reduced heat transfer performance from temperaturemonitoring results also can indicate internal corrosion. Additionally, the staff noted that the applicant performed UT measurements of pipe wall thickness to determine the extent ofcorrosion on select portions of RBC system piping, including piping connected to the RECsystem pump seal coolers inside the drywell, which confirmed the effectiveness of waterchemistry. However, the staff found no direct inspection confirming chemistry effectiveness in mitigating corrosion effects on the RBC system portion connected to the RHR system pumpseal coolers or CRD system pump coolers. The staff observed that as an enhancement aone-time inspection will monitor the effects of corrosion of the RHR system and CRD systempump coolers and nearby connected piping. The staff found that the additional information thatthe applicant had gathered adequately substituted for information recommended by the GALLReport, because the parameters monitored will ensure that the pressure boundary intendedfunction will continue through the period of extended operation. The staff reviewed theapplicant's additional information and found it acceptable.The applicant stated that, as an exception to the GALL Report, the emergency dieselgenerator (EDG) jacket water pump suction and discharge pressures and flow are not measured; however, water temperature, closed coolant level, lube oil pressure, and lube oil temperature are monitored quarterly as part of EDG operability tests. As part of the 12-yearpreventive maintenance (PM) requirements for the EDGs, the jacket water pumps are replaced, the jacket water header of the lube oil cooler is visually inspected, and the jacket water systemis inspected for any evidence of leakage from piping or joints (a leak detector dye is used in the coolant). The staff found that the additional information the applicant had gathered adequatelysubstituted for information recommended by the GALL Report, because the parameters monitored will identify aging effects that may impact the intended function of the EDG. The staffreviewed the applicant's additional information and found it acceptable.The applicant stated that, as an exception to the GALL Report, differential pressure across theEDG coolant heat exchangers is not monitored; however, heat exchanger performance is tested periodically by gathering temperature and flow results. Eddy current testing of the heat exchanger tubes is also periodic. The staff found that the additional information that the applicant had gathered adequately substituted for information recommended by the GALL Report, because it identifies aging effects reducing heat transfer. The staff reviewed the applicant's additional information and found it acceptable.The applicant stated that, as an exception to the GALL Report, it does not perform heating andventilation (HTV) system and component performance monitoring. The system contains no heatexchangers, but does contain a number of heating coils for heating to various plant locations.
The scope of license renewal includes the pipi ng system and heater coils for pressure integrity 3-84only. Some of the heating coils are visually inspected annually for leaks. After an evaluation, thestaff found that the additional information that the applicant had gathered adequatelysubstituted for information recommended by the GALL Report, because it will verify that thepressure integrity intended function will continue through the period of extended operation. Thestaff reviewed the applicant's additional information and found it acceptable.On the basis of the above review and of a review of operating experience for AMP B2.1.13, thestaff found this exception acceptable.Exception 4:  The GALL Report recommends the following for the Acceptance Criteria programelement associated with the exception taken:Corrosion inhibitor concentrations are maintained within the limits specified in theEPRI water chemistry guidelines for CCCW. System and componentperformance test results are evaluated in accordance with the guidelines of EPRI TR-107396. Acceptance criteria and tolerances are also bas ed on system designparameters and functions.In the LRA, the applicant stated that some of the acceptance criteria (ranges) for monitoredchemistry parameters based on vendor recommendations and plant operating experience are not identical to the typical ranges specified by EPRI TR-1007820 or EPRI TR-107396. The ranges based on plant operating experience have been sufficient to manage aging effects.The staff observed that both EPRI TR-107396 and EPRI TR-1007820 specify normal operatingranges for chemical control parameters. They also specify diagnostic parameters, but do not include action levels and ranges, as these parameters are used for trending. Specifically, with regard to the four CCCW systems, the chemical control parameter ranges recommended byEPRI, and hence by the GALL Report, and the corresponding ranges used at MNGP are as follows:(1)The following applies to the chromate-based RBC system, which also serves the RHR,REC, and CRD coolers:a.Chromate-Chromate is monitored to a range of 500 to 1800 parts per million(ppm), not 150 to 300 ppm as recommended by the GALL Report and EPRI. As noted in EPRI TR-107396 and EPRI TR-1007820, this may have a detrimental impact on pump seal integrity. The RBC pump seals are consumables. The applicant installed a new design seal replaced on a 2-year frequency and has monitored for but not detected any impact to system pressure boundary integrity.b.pH-pH is monitored to a more restrictive range of 9.0 to 9.7 versus the EPRITR-107396 range of 8.5 to 10.5 and the EPRI TR-1007820 range of 8.0 to 11.0.c.Chloride-Chloride is not monitored in the RBC system. Chloride is monitored inthe makeup demineralized water source, which provides makeup to the RBC system. Chloride limits for demineralized water have a limit of 10 parts per billion (ppb), which is substantially lower than the limit of 10 ppm established by both EPRI reports.
3-85(2)The following applies to the cooling loops of the EDG system (DGN):a.Nitrite-The chemical range for nitrite is identical to that in EPRI TR-107396 (500to 1000 ppm) and more restrictive than that in EPRI TR-1007820 (50 to 1500 ppm).b.pH-The range for pH is 9.0 to 10.7, which is more restrictive than the 8.5 to11.0 range in EPRI TR-1007820 and close to the 8.5 to 10.5 range specified in EPRI TR-107396.c.Tolytriazole-The specified range for tolytriazole is 10 to 40 ppm, as opposed tothe 5 to 30 ppm range recommended in EPRI TR-107396, and more restrictive than the 5 to 100 ppm range recommended in EPRI TR-1007820. EPRI TR-107396 identified no adverse impacts for slightly higher tolytriazole ranges.d.Chloride-Chloride is not monitored in the cooling loops of the DGN. Chloride ismonitored in the makeup demineralized water source, which provides makeup to the cooling loops. Chloride limits for demineralized water have a limit of 10 ppb, which is substantially lower than the limit of 10 ppm established by the EPRI reports.(3)The following applies to the piping and heating coils of the HTV system:a.EPRI TR-107396 and EPRI TR-1007820 do not specify chemical ranges for thepiping and heating coils of the HTV system, so they are monitored in accordancewith vendor recommendations and plant experience. These include conductivity, pH, phosphate, sulfites, and total gamma activity and are specified by plant procedure.(4)The following applies to the closed cooling loop used on the #14 air compressor of theinstrument and service air (AIR) system:a.Glycol percent volume-Both EPRI TR-107396 and EPRI TR-1007820recommend that glycol percent volume remain above 30 percent to avoid becoming a nutrient for microbiological growth. Further, EPRI TR-1007820 recommends that the level remain below 60 percent. The applicant maintains a concentration of about 50 percent, which is within the range specified by the EPRI reports.b.pH-MNGP procedures do not provide a specific range for pH; however,procedures require routine sampling and measurement of pH, and pH is maintained within the range specified by EPRI TR-1007820 of 7.5 to 11.0.The staff reviewed the operating ranges of each of the above 10 chemical control parametersand noted that eight were either equivalent to or more conservative than the rangerecommended by the EPRI technical reports. One, the chromate, had a higher range, but the applicant took effective action to mitigate the effects of that higher range. The last was inaccordance with vendor recommendations and plant operating experience, as the GALL Report provides no recommendation.
3-86On the basis of the above review and a review of MNGP operating experience for AMP B2.1.13,the staff found this exception acceptable.In the LRA, the applicant stated that the following enhancement will make this AMP consistentwith the recommendation in the GALL Report.Enhancement:  The GALL Report recommends the following for the Parameters Monitored orInspected program element associated with the enhancement made:The aging management program (AMP) monitors the effects of corrosion bysurveillance testing and inspection in accordance with standards in EPRI TR-107396 to evaluat e system and component performance. For pumps, theparameters monitored include flow and discharge and suction pressures. For heat exchangers, the parameters monitored include flow, inlet and outlet temperatures, and differential pressure.In the LRA, the applicant stated that a one-time inspection will monitor the effects of corrosionon select portions of CCCW systems that perform a pressure-integrity intended function.The staff reviewed the applicant's proposed enhancement and determined that augmenting theCCCW systems with a one-time inspection to monitor the effects of corrosion on select portionsof CCCW systems that perform a pressure-integrity intended function will provide additionalassurance that aging effects are identified before component failures, consistent with GALLAMP XI.M21". On the basis of its review, the staff found this enhancement acceptable, as such changes to the applicant's program provide assurance that the effects of aging will beadequately managed.The staff reviewed those portions of AMP B2.1.13, "Closed-Cycle Cooling Water SystemProgram," that the applicant claimed are consistent with GALL AMP XI.M21 and found themconsistent. The staff found the applicant's AMP acceptable because it conforms to the recommended GALL Report AMP with the exceptions and enhancement as described above.Operating Experience. In LRA Section B2.1.13, the applicant stated that, for the Closed-CycleCooling Water System Program, it initiates CRs/ARs when it finds that water chemistry is out of specification or equipment performance does not meet standards. The time duration of these conditions is typically short and no evidence of detrimental equipment impacts was found. The applicant did not identify any examples of CCCW system functional failures due to corrosion,SCC, or heat transfer degradation due to fouling resulting from inadequate chemistry control.
Steam leaks have occurred in various portions of the piping and heating coils of the HTV system (steam traps, temperature control valve packing/gaskets, heating coils, and fittings).These leaks have been isolated and corrected, were typically minor in nature, did not impact the operation of nearby safety equipment, and were not linked to inadequate chemistry or corrosion as the cause of the leak. Procedural requirements for chemistry limits are established based on EPRI and industry standards and routinely monitored. The applicant entered a CR into the site CAP because a liquid penetrant examination showed a pin-hole leak on the top side of a sampling line at the tubing end of a tubing-to-insert fillet weld (sampling line connectedon top of an RBC heat exchanger). Inadequate original welding of the connection was determined to be the cause of the leak. Adjacent and external surfaces did not show pitting or 3-87other signs of distress, suggesting this was a localized effect. The applicant removed andreplaced the affected section of stainless steel tubing.The staff reviewed the operating experience provided in the LRA and interviewed theapplicant's technical personnel to confirm that plant-specific operating experience revealed no degradation not bounded by industry experience.On the basis of its review of the above industry and plant-specific operating experience anddiscussions with the applicant's technical personnel, the staff concluded that the applicant'sCCCW System program will adequately manage the aging effects identified in the LRA forwhich this AMP is credited.USAR Supplement. In LRA Section A2.1.13, the applicant provided the USAR supplement forthe CCCW System Program. The staff reviewed this section and determined that theinformation in the USAR supplement adequately describes the program, as required by 10 CFR 54.21(d).In its letter dated June 10, 2005, the applicant added a commitment to USAR Section A2.1.13,documented as commitment 23 in Table A.5, that before the period of extended operation, it willconduct a one-time inspection to monitor the effects of corrosion on select portions of CCCWsystems performing a pressure-integrity intended function.Conclusion. On the basis of its review and audit of the applicant's CCCW System Program, thestaff determined that those program elements for which the applicant claimed consistency withthe GALL Report are consistent with the GALL Report. In addition, the staff reviewed the exceptions and the associated justifications and determined that the AMP, with the exceptions,is adequate to manage the aging effects for which it is credited. The staff also reviewed the enhancement and confirmed that their implementation before the period of extended operationwill result in the existing AMP being consistent with the GALL Report AMP to which it wascredited. The staff concluded that the applicant demonstrated that the effects of aging will beadequately managed so that intended functions will be maintained consistent with the CLB forthe period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.2.13  Compressed Air Monitoring Program Summary of Technical Information in the Application. In LRA Section B2.1.14, the applicantdescribed the Compressed Air Monitoring Program, stating that this existing program is consistent, with exceptions and enhancements, with GALL AMP XI.M24, "Compressed Air Monitoring." The MNGP Compressed Air Monitoring Program consists of inspection, monitoring, and testing of the AIR system to provide reasonable assurance that they will perform theirintended function for the duration of extended operation.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP 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.
3-88The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.M24.In the LRA, the applicant stated the following exceptions to the program elements listed forAMP XI.M24 in the GALL Report.Exception 1:  The GALL Report recommends the following for the Parameters Monitored orInspected program element associated with the exception taken:In-service inspection (ISI) and testing is performed to verify proper air quality andconfirm that maintenance practices, emergency procedures, and training are adequate to ensure that the intended function of the air system is maintained.In the LRA, the applicant stated that it does not perform ISI and inservice testing to verifyproper air quality or confirm that maintenance practices, emergency procedures, and training are adequate to ensure that the air system intended function is maintained. This is not an ISI orinservice testing function or activity. Staff engineering personnel verify air quality through semiannual testing in accordance with procedures based on GL 88-14, "Instrument Air Supply System Problems Affecting Safety Equipment, dated August 8, 1988; American National Standards Institute (ANSI)/Instrument Society of America (ISA) S7.3, "Quality Standard for Instrument Air"; ANSI Z86.1-1973, "Commodity Specification for Air and Drager Operating Instruction"; and EPRI TR-103595, "Report of Instrument Air Working Group."  Station administrative and training procedures control maintenance practices, emergency procedures, and training.On the basis of its review of NRC, EPRI, and other industry guidelines and standards, the staffdetermined that the applicant's inspection and testing verify proper air quality and confirm thatmaintenance practices, emergency procedures, and training are adequate to ensure that the intended function of the compressed air monitoring systems is maintained. Procedures andprograms at MNGP implement Compressed Air Monitoring Program activities recommended by the GALL Report. The MNGP audit and review report details the staff's review. On the basis of a review of the above exception and of operating experience for the Compressed Air Monitoring Program, the staff found this exception acceptable.Exception 2:  The GALL Report recommends the following for the Detection of Aging Effectsprogram element associated with the exception taken:Guidelines in EPRI NP-7079, EPRI TR-108147, and ASME OM-S/G-1998, Part17, ensure timely detection of degradation of the compressed air systemfunction. Degradation of the piping and any equipment would become evident by observation of excessive corrosion, by the discovery of unacceptable leakage rates, and by failure of t he system or any item of equipment to meet specifiedperformance limits.In the LRA, the applicant stated that its program is based on the guidance provided inANSI/ISA-S7.3-1975, ANSI/ISA-Z86.1-1973, EPRI TR-103595, and GL 88-14 augmented by previous NRC IN 81-38, "Potentially Significant Equipment Failures Resulting for Contamination of Air-Operated Systems," dated December 17, 1981; IN 87-28, "Air System Problems at U.S.
3-89Light-Water Reactors," dated June 22, 1987; IN 87-28 Supplement 1, and by the INPOSignificant Operating Event Report (INPO SOER) 88-01. The applicant takes exception toANSI/ISA-S7.0.01-1996 because it uses ANSI/ISA-S7.3-1975 instead. The applicant takes exception to ASME OM-S/G-1998 Part 17 as specified in GALL AMP XI.M24.The staff observed that, in lieu of the EPRI NP-7079 guidelines recommended by the GALLReport to detect degradation of compressed air system function, the applicant developedprocedures and instructions based on GL 88-14, ANSI/ISA S7.3-1975, ANSI/ISA Z86.1-1973, EPRI TR-103595, INPO SOER 88-01 augmented by IN 81-38, and IN 87-28 with Supplement
: 1. The staff reviewed and compared ANSI/ISA-S7.3-1975 with ANSI/ISAS7.0.01-1996 and found ANSI/ISA-S7.3-1975 acceptable for use as its criteria are more conservative than recommended by ANSI/ISA-S7.0.01-1996.During the audit, the staff asked that the applicant clarify its reason for taking exception toASME OM-S/G-1998, Part 17, which provides guidance for performance testing of instrument air systems in light-water reactor power plants. The applicant responded that the scope ofcomponents included in the compressed air monitoring activities includes distribution piping, valves, accumulators for air-operated SR valves, and the containment isolation valves of the instrument air system. The applicant stated that the instrument air system compressors,receivers, filters, and dryers are not within the scope of license renewal. The applicant also stated that its Compressed Air Monitoring Program will adequately manage aging for thoseinstrument air system components within the scope of license renewal. The staff reviewedseveral procedures and instructions to determine their adequacy and completeness, their frequencies, and their results, including a sampling from the applicant's CAP, and concluded that the applicant is able to ensure timely detection of degradation of the compressed airsystem function, as shown by its ability to detect corrosion or high leak rates or the failure of any component to meet its performance limits. The staff found the applicant's response acceptable.On the basis of a review of the above exception and of a review of operating experience for theCompressed Air Monitoring Program, the staff found this exception acceptable.In the LRA, the applicant stated that the following enhancements will make this AMP consistentwith the recommendation in the GALL Report.Enhancement 1:  The GALL Report recommends the following for the Scope of Programprogram element associated with the enhancement made:The program manages the effects of corrosion and the presence ofunacceptable levels of contaminants on the intended function of the compressedair system. The AMP includes frequent leak testing of valves, piping, and othersystem components, especially those made of carbon steel, and a preventivemaintenance program to check air quality at several locations in t he system.In the LRA, the applicant stated that it will revise the Compressed Air Monitoring Programprocedures to include corrective action requirements if water vapor, oil content, or particulate acceptance limits are not met. In addition, it will clarify the acceptance criteria for oil contenttesting and provide the acceptance limit bases for water vapor, oil content, and particulate tests.
3-90During the audit, the staff asked that the applicant clarify the above enhancement. Theapplicant responded that, although it regarded the guidance identified in Exception 2 asconservative compared to the guidance recommended by the GALL Report, it wanted to apply further conservatism in the event that acceptance criteria were not met in any area. The acceptance criteria of the compressed air monitoring systems procedures are evaluated underthe CAP. The staff reviewed the enhancement and found this potential augmentation of theacceptance criteria of the compressed air monitoring systems procedures consistent with therecommendations of the GALL Report as it provides additional assurance that aging effects are identified before compressed air monitoring system component failure. Therefore, the stafffound this enhancement acceptable.On the basis of a review of the above enhancement and a review of operating experience forthe Compressed Air Monitoring Program, the staff found the enhancement acceptable as such changes to the applicant's program provide assurance that the effects of aging will beadequately managed.Enhancement 2:  The GALL Report recommends the following for the Detection of AgingEffects program element associated with the enhancement made:Guidelines in EPRI NP-7079, EPRI TR-108147, and ASME OM-S/G-1998, Part17, ensure timely detection of degradation of the compressed air systemfunction. Degradation of the piping and any equipment would become evident by observation of excessive corrosion, by the discovery of unacceptable leakage rates, and by failure of t he system or any item of equipment to meet specifiedperformance limits.In the LRA, the applicant stated that it will revise its Compressed Air Monitoring Program toinclude inspection of air distribution piping based on recommendations of EPRI TR-108147, "Compressor and Instrument Air System Maintenance Guide," issued March 1998.During the audit, the staff asked that the applicant clarify the above enhancement. Theapplicant responded that EPRI TR-108147 addressed the subject piping with updated recommendations. The staff reviewed the enhancement and determined that expanding thedetection of aging effects by including air distribution piping is consistent with the recommendations of the GALL Report and will provide additional assurance that aging effectsare identified before compressed air monitoring component failure.On the basis of a review of the above enhancement and a review of the operating experiencefor the Compressed Air Monitoring Program, the staff found this enhancement acceptable as such changes to the applicant's program provide assurance that the effects of aging will beadequately managed.The staff reviewed those portions of AMP B2.1.14 "Compressed Air Monitoring Program," thatthe applicant claimed are consistent with GALL AMP XI.M24 and found them consistent. The staff found the applicant's AMP acceptable because it conforms to the recommended GALL Report AMP with the exceptions and enhancements as described above.Operating Experience. In LRA Section B2.1.14, the applicant explained that it based theCompressed Air Monitoring Program on appropriate NRC requirements and industry guidance, 3-91including the MNGP response to NRC GL 88-14. It performs established PM ta sks and otherinspections on a routine basis. For example, it performed and completed a major PM task in June 2003. Plant staff identified a number of system leaks, notifi ed the system engineer, andinitiated and completed repair WOs to fix the leaks. Such PM activities and inspections, systemrepairs, ongoing monitoring, and review of plant and industry operating experience have been effective in maintaining air system performance. Unavailability targets for this system are well within established goals.The staff reviewed the operating experience provided in the LRA and interviewed theapplicant's technical personnel to confirm that plant-specific operating experience revealed no degradation not bounded by industry experience.On the basis of its review of the above industry and plant-specific operating experience anddiscussions with the applicant's technical personnel, the staff concluded that the CompressedAir Monitoring Program will adequately manage the aging effects identified in the LRA for whichthis AMP is credited.USAR Supplement. In LRA Section A2.1.14, the applicant provided the USAR supplement forthe Compressed Air Monitoring Program. The staff reviewed this section and determined that the information in the USAR supplement adequately describes the program, as required by 10 CFR 54.21(d).In its letter, dated June 10, 2005, the applicant added commitments to USAR Section A2.1.14,documented as commitments 24 and 25 in Table A.5, that before the period of extendedoperation, it will (1) revise Compressed Air Monitoring Program procedures to include correctiveaction requirements if the acceptance limits for water vapor, oil content, or particulate are not met, clarify acceptance criteria for oil content testing, and provide the basis for the acceptancelimits for the water vapor, oil content, and particulate tests and (2) revise the Compressed Air Monitoring Program to include inspection of air distribution piping based on the recommendations of EPRI TR-108147.Conclusion. On the basis of its review and audit of the applicant's Compressed Air MonitoringProgram, the staff determined that those program elements for which the applicant claimedconsistency with the GALL Report are consistent with the GALL Report. In addition, the staffreviewed the exceptions and the associated justifications and determined that the AMP, with theexceptions, is adequate to manage the aging effects for which it is credited. The staff also reviewed the enhancements and confirmed that their implementation before the period ofextended operation will result in the existing AMP being consistent with the GALL Report AMPto which it was credited. The staff concluded that the applicant demonstrated that the effects ofaging will be adequately managed so that intended functions will be maintained consistent withthe CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff alsoreviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.2.14Electrical Cables Not Subject to 10 CFR 50.49 Environmental QualificationRequirements Used in Instrumentation Circuits ProgramSummary of Technical Information in the Application. In LRA Section B2.1.16, the applicantdescribed the Electrical Cables Not Subject to 10 CFR 50.49 Environmental Qualification 3-92Requirements Used in Instrumentation Circuits Program, stating that this new program isconsistent, with exceptions, with GALL AMP XI.E2, "Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in InstrumentationCircuits." This program applies to non-EQ electrical cables used in radiation monitoring and nuclear instrumentation circuits with sensitive, low-level signals that are within scope of license renewal and are installed in adverse localized environments caused by heat, radiation, and moisture in the presence of oxygen. Exposure of electrical cables to adverse localized environments caused by heat or radiation can result in reduced insulation resistance (IR).
Reduced IR causes an increase in leakage currents between conductors and from individual conductors to ground. A reduction in IR is a concern for circuits with sensitive, low-level signals such as radiation monitoring and nuclear instrumentation since it may contribute to inaccuracies in the instrument loop.This AMP uses routine calibration tests performed as part of the plant surveillance test programto identify the potential existence of aging degradation. When an instrumentation loop is foundto be out of calibration during routine surveillance testing, troubleshooting is performed on the loop, including the instrumentation cable. In cases in which a calibration or surveillance programdoes not include the cabli ng system in the testing circuit, or as an alternative to the review ofcalibration results described above, the applicant will perform cable system testing. Plant staffwill perform a proven cable system test for detecting deterioration of the insulation system (such as IR tests, time domain reflectometry test, or other testing judged to be effective in determining cable insulation condition).Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's audit evaluation of this AMP. The staff reviewed the exceptions and the associated justifications todetermine whether the AMP, with the exceptions, remains adequate to manage the agingeffects for which it is credited.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.E2.In the LRA, the applicant stated the following exception to the program elements listed for AMPXI.E2 in the GALL Report.Exception:  The GALL Report identifies the following criteria for the Parameters Monitored orInspected, Detection of Aging Effects, and Acceptance Criteria program elements associated with the exception taken:Parameters Monitored/Inspected:The parameters monitored are determined from the plant technicalspecifications and are specific to the instrumentation loop being calibrated, as documented in the surveillance testing procedure.
3-93Detection of Aging Effects:Calibration provides sufficient indication of the need for correctiveactions by monitoring key parameters and providing trending data based on acceptance criteria related to instrumentation loop performance. The normal calibration frequency specified in the plant technical specifications provides reasonable assurance that severe aging degradation will be detected prior to loss of the cable int endedfunction. The first tests for license renewal are to be completed before the period of extended operation.Acceptance Criteria:Calibration readings are to be within the loop-specific acceptancecriteria, as set out in the plant technical specifications surveillance test procedures.In the LRA, the applicant stated that the surveillance tests required by its TS either do notinclude all cables within the scope of license renewal or do not include the cable as part of the calibration procedure. The program will periodically test the cable insulation condition for thosecables not already tested by TS requirements.The applicant further stated that for those cables not tested as part of TS surveillanceprocedures, the program will periodically test the cable insulation. The staff reviewed theapplicant's exception and found it acceptable because Interim Staff Guidance (ISG)-15 statesthat either (1) calibration results or findings of surveillance testing or (2) direct testing of cable systems can be used to detect aging degradation of electrical cables not subject to10 CFR 50.49 EQ requirements used in instrumentation circuits.On the basis of its review of the Electrical Cables Not Subject to 10 CFR 50.49 EQRequirements Used in Instrumentation Circuits Program and in conjunction with the operating experience, the staff found this exception acceptable.The staff reviewed those portions of the AMP B2.1.16, "Electrical Cables Not Subject to10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation CircuitsProgram," that the applicant claimed are consistent with GALL AMP XI.E2 and found themconsistent. The staff found the applicant's AMP acceptable because it conforms to the recommended GALL Report AMP with the exception as described above.Operating Experience. In LRA Section B2.1.16, the applicant stated that the Electrical CablesNot Subject to 10 CFR 50.49 EQ Requirements Used in Instrumentation Circuits Program is a new program and as such has no plant-specific operating experience; however, as noted in the GALL Report, industry operating experience shows that exposure of electrical cables to adverse local environments caused by heat or radiation result in reduced IR. Reduced IR causes an increase in leakage currents between conductors and from individual conductors to ground. A reduction in IR is a concern for circuits with sensitive, low-level signals like radiation monitoring and nuclear instrumentation circuits as it may contribute to signal inaccuracies.
3-94During the audit and review, the staff asked the applicant how it captures operating experience.The applicant stated that its CAP identifies, tr acks, and trends site operating experience with allsite components. The applicant documents any site component identified as degraded, failed, or potentially unable to fulfill intended functions in the site CAP database. Plant engineeringstaff then evaluate these CAPs for the extent of the condition and take appropriate followupactions. Plant engineering staff also trend related CAPs to identify generic issues. They address trended site issues in program health reports and present them to site management on a scheduled basis. The CAP also addresses 10 CFR 54.21 issues and external operating events from the NRC, INPO, LIS, and the applicant's fleet. The staff reviewed the applicant'sresponse and found it acceptable.The staff recognizes that the CAP, which captures internal and external plant operatingexperience issues, ensures review and incorporation of operating experience as objective evidence to support the conclusion that aging effects are adequately managed.USAR Supplement. In LRA Section A2.1.16, the applicant provided the USAR supplement forthe Electrical Cables Not Subject to 10 CFR 50.49 EQ Requirements Used in Instrumentation Circuits Program. The staff reviewed this section and determined that the information in the USAR supplement adequately describes the program, as required by 10 CFR 54.21(d).In its letter, dated June 10, 2005, the applicant included a commitment to USARSection A2.1.16, documented as commitment 27 in Table A.5, which states the following:Prior to the period of extended operation, the Electrical Cables Not Subject to10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits Program will be implemented as a new program. With exceptions, it will be consistent with the recommendations of NUREG-1801Chapter XI Program XI.E2.Conclusion. On the basis of its review and audit of the applicant's Electrical Cables Not Subjectto 10 CFR 50.49 EQ Requirements Used in Instrumentation Circuits Program, the staff determined that those program elements for which the applicant claimed consistency with theGALL Report are consistent with the GALL Report. In addition, the staff reviewed the exceptions and the associated justifications and determined that the AMP, with the exceptions,is adequate to manage the aging effects for which it is credited. The staff concluded that the applicant demonstrated that the effects of aging will be adequately managed so that intendedfunctions will be maintained consistent with the CLB for the period of extended operation, asrequired by 10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.2.15  Fire Protection Program Summary of Technical Information in the Application. In LRA Section B2.1.17, the applicantdescribed the Fire Protection Program, stating that this existing program is consistent, with exception and enhancement, with GALL AMP XI.M26, "Fire Protection." For license renewal purposes, the MNGP Fire Protection Program includes a fire barrier inspection program, a diesel-driven fire pump inspection program, and a halon fire suppression system inspection.The fire barrier inspection program requires periodic visual inspection of fire barrier penetration seals, fire barrier walls, ceilings, and floors, and periodic visual inspection and functional tests 3-95of associated fire rated doors to ensure that their operability is maintained. The diesel-drivenfire pump inspection program requires that the pump be periodically tested and the diesel engine inspected to ensure that the fuel supply line can perform the intended function. Thehalon fire suppression system inspection included periodic inspection and testing of the cablespreading room halon fire suppression system.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's audit evaluation of this AMP. The staff reviewed the exception and enhancement and the associatedjustifications to determine whether the AMP, with the exception and enhancement, remainsadequate to manage the aging effects for which it is credited.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.M26.In the LRA, the applicant stated the following exception to the program elements listed for AMPXI.M26 in the GALL Report.Exception:  The GALL Report recommends the following for the Parameters Monitored andInspected program element associated with the exception taken:Periodic visual inspection and function test at least once every six monthsexamines the signs of degradation of the halon/carbon dioxide fire suppression system. The suppression agent charge pressure is monitored in the test.Material conditions that may affect the performance of the system, such ascorrosion, mechanical damage, or damage to dampers, are observed during these tests. Inspections performed at least once every month to verify that the extinguishing agent supply valves are open and the system is in automaticmode.In the LRA, the applicant stated that it conducts periodic visual inspections and function tests ofhalon systems at least once every 6 months. The cable spreading room halon system isfunctionally tested and visually inspected every 18 months instead of every 6 months as recommended in GALL AMP XI.M26.In LRA Section B2.1.17 and the associated basis document, the applicant provided itsjustification conducting these activities every 18 months instead of every 6. According to the applicant, the surveillance interval specified in the Operations Manual is part of the
 
NRC-approved Fire Protection Program, and thus forms an element of the plant's CLB. Inresponse to the staff interviews, the applicant's personnel provided further information, including the System Health Report-Fire Protection.The applicant's technical personnel stated that they reviewed industry operating experience, theprevious cable spreading room halon system surveillance test results, and plant-specificoperating experience for this subsystem. This review of operating experience revealed noage-related degradation, and thus the applicant stated that the 18-month frequency isacceptable.
3-96The staff interviewed the applicant about parameters monitored or inspected as part of fireprotection (FP) relative to the guidelines for the frequency of inspections. The applicant stated that the program has specific guidelines for the frequency of inspections requiring, for example, visual inspections of penetration seal fire area boundaries protecting safe-shutdown equipment every 18 months or following repair or maintenance of such penetrations. These inspections cover 10 percent of each type of seal, consistent with GALL Report recommendations. The staff also reviewed other inspection criteria for fire doors, the diesel driven fire pump, and the halon/carbon dioxide systems. Based on the staff's review of industry and plant-specificoperating experience, performance of surveillance tests, and the FP system health reports, theexception of the inspection frequency of 18 months instead of 6 months is acceptable, becausethe incubation period for the effect is long, and the different inspection frequencies did notresult in any differences in finding aging effects.In the LRA, the applicant stated that the following enhancement will make this AMP consistentwith the recommendation in the GALL Report.Enhancement:  The GALL Report recommends the following for the Detection of Aging Effectsprogram element associated with the enhancement made:...If any sign of degradation is detected within that 10 percent, the scope of theinspection and frequency is expanded to ensure timely detection of increased hardness and shrinkage of the penetration seal before the loss of the component intended function. Visual inspection (VT-1 or equivalent) of the fire barrier walls, ceilings, and floors performed in walkdown at least once every refueling outage ensures timely detection for concrete cracking, spalling, and loss of material.
Visual inspection (VT-3 or equivalent) detects any sign of degradation of the fire door such as wear and missing parts...In the LRA, the applicant stated that it will revise its existing Fire Protection Program cablespreading room halon visual inspection procedure to include inspection for any signs of degradation such as corrosion and mechanical damage. This visual inspection will m anageaging for external surfaces of the cable spreading room halon fire suppression system. Theapplicant will revise the Fire Protection Program plan document to include qualification criteriafor individuals visually inspecting penetration seals, fire barriers, and fire doors. The qualification criteria will be in accordance with VT-1 or equivalent and VT-3 or equivalent, asapplicable.The staff's evaluation and review of plant-specific operating experience found the enhancementto the Fire Protection Program to detect signs of aging by including qualification criteria for inspection personnel and VT-1 and VT-3 inspections of the penetration seals, fire barriers, and fire doors to be acceptable and consistent with the GALL Report for this AMP, which willmanage aging during the period of extended operation.On the basis of the staff evaluation of the above enhancement and review of the operatingexperience for the Fire Protection Program, the staff found this enhancement acceptable as such changes to the applicant's program provide assurance that the effects of aging will beadequately managed.
3-97The staff reviewed those portions of AMP B2.1.17, "Fire Protection Program," that the applicantclaimed are consistent with GALL AMP XI.M26 and found them consistent. The staff found the applicant's AMP acceptable because it conforms to the recommended GALL Report AMP with the exception and enhancement as described above.Operating Experience. In LRA Section B2.1.17, the applicant explained that, through the use ofestablished plant surveillance and procedures, its staff inspects barriers and other features on aperiodic basis. Recent assessments have noted that the overall material condition is good. Forexample, the December 2000 self-assessment using industry guidance (NEI Self- Assessment Guide 99-05) concluded that the observed seals and fireproofing appeared to be in good condition. The applicant documents and resolves problems through the site CAP. It entered prior issues with program performance noted during the NRC 2002 inspection into the site CAPdatabase for assessment and resolution. MNGP implemented a number of extensive corrective actions to improve program performance, including improved identification and resolution of deficiencies. It performed an extensive self-assessment in March 2004 to evaluate progress and program compliance. Though some areas of vulnerability were noted for correction andcontinued focus, a number of program strengths were identified and the assessment concluded that the MNGP program is consistent with corporate directive requirements and had madesignificant progress in addressing the findings from the 2002 inspection.The staff reviewed the operating experience provided in the LRA and interviewed theapplicant's technical personnel to confirm that plant-specific operating experience revealed no degradation not bounded by industry experience.On the basis of its review of the above operating experience and discussions with theapplicant's technical personnel, the staff concluded that the applicant's Fire Protection Program will adequately manage the aging effects identified in the LRA for which this AMP is credited.USAR Supplement. In LRA Section A2.1.17, the applicant provided the USAR supplement forthe Fire Protection Program. The staff reviewed this section and determined that the information in the USAR supplement adequately describes the program, as required by 10 CFR 54.21(d).In its letter, dated June 10, 2005, the applicant included the following two commitments toSection A2.1.17, documented as commitments 28 and 29 in Table A.5, that it will implementbefore the period of extended operation:(1)The applicant will revise the Fire Protection Program to include a visual inspection of thehalon fire suppressi on system to detect any signs of degradation, such as corrosion, ormechanical damage. This visual inspection will manage aging for external surfaces ofthe halon fire suppression system.(2)The applicant will revise the Fire Protection Program to include qualification criteria forindividuals visually inspecting penetration seals, fire barriers, and fire doors. The qualification criteria will be in accordance with VT-1, VT-3, or equivalent as applicable.Conclusion. On the basis of its review and audit of the applicant's Fire Protection Program, thestaff determined that those program elements for which the applicant claimed consistency withthe GALL Report are consistent with the GALL Report. In addition, the staff reviewed the 3-98exception and the associated justifications and determined that the AMP, with the exception, isadequate to manage the aging effects for which it is credited. The staff also reviewed the enhancement and confirmed that its implementation before the period of extended operationwill result in the existing AMP being consistent with the GALL Report AMP to which it wascredited. The staff concluded that the applicant demonstrated that the effects of aging will beadequately managed so that intended functions will be maintained consistent with the CLB forthe period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.2.16  Fire Water System Program Summary of Technical Information in the Application. In LRA Section B2.1.18, the applicantdescribed the Fire Water System Program, stating that this existing program is consistent, with enhancement, with GALL AMP XI.M27, "Fire Water System." The Fire Water System Program relies on testing of water-based FP system piping and components in accordance withapplicable National Fire Protection Association (NFPA) recommendations. In addition, the applicant will modify this program to include (1) portions of the FP sprinkler system that aresubjected to full flow tests before the period of extended operation and (2) portions of the FP system exposed to water that are internally visually inspected. To ensure that the aging mechanisms of corrosion and biofouling/fouling are properly being managed in the fire water system, the applicant conducts periodic full flow flush tests and system performance tests. Thesystem is also normally maintained at required operating pressure and is monitored such thatloss of system pressure is immediately detected and corrective actions initiated.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's audit evaluation of this AMP. The staff reviewed the enhancement and the associated justifications todetermine whether the AMP, with the enhancement, remains adequate to manage the agingeffects for which it is credited.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.M27.In the LRA, the applicant stated that the following enhancement will make this AMP consistentwith the recommendation in the GALL Report.Enhancement:  The GALL Report recommends the following for the Program Descriptionprogram element associated with the enhancement made:...In addition, a sample of sprinkler heads is to be inspected by using theguidance of NFPA 25, Section 2.3.3.1. This NFPA section states that 'wheresprinklers have been in place for 50 years, they shall be replaced or representative samples from one or more sample areas shall be submitted to a recognized testing laboratory for field service testing.' It also contains guidance to perform this sampling every 10 years after the initial field service testing...
3-99In the LRA, the applicant stated it will enhance the Fire Water System Program byimplementing procedures that will be revised to include the extrapolation of inspection results tobelow-grade fire water piping with conditions similar to those within the above-grade fire water piping. It will inspect and test the Fire Water System Program sprinkler heads or replace thembefore the end of the 50-year sprinkler head service life and at 10-year intervals thereafter during the extended period of operation to ensure that signs of degradation, such as corrosion,are detected promptly. Enhancements are scheduled for completion before the period ofextended operation.The staff found in its evaluation and review of plant-specific operating experience that theenhancement to the Fire Water System Program to detect signs of aging by wall thickness evaluations on above-grade piping, inspections before the period of extended operation, andextrapolations of above-ground conditions to below-ground piping for further inspections is acceptable and consistent with GALL Report recommendations relying on NFPA codes and with GALL AMP XI.M27.On the basis of its review of the above enhancement and review of operating experience for theMNGP Fire Water System Program, the staff found this enhancement acceptable as such changes to the applicant's program provides assurance that the effects of aging will beadequately managed.The staff reviewed those portions of AMP B2.1.18, "Fire Water System Program," that theapplicant claimed are consistent with GALL AMP XI.M27 and found them consistent. The staff found the applicant's AMP acceptable because it conforms to the recommended GALL Report AMP with the enhancement as described above.Operating Experience. In LRA Section B2.1.18, the applicant explained that through the use ofestablished plant surveillances and procedures, the fire water system is periodically inspected,tested, flushed, and maintained. It evaluates industry and plant experience for systemperformance impacts. The applicant documents performance issues and evaluates them through the site CAP. System availability has been good; only six cases of system impairmentfor more than 48 hours, in order to perform required maintenance, have occurred since October 1996. System unavailability is within Maintenance Rule program goals. The applicant alsoprovided an example of program activities. It conducted a FP system walkdown that reported that the system was in good condition but identified two areas of concern. First, the FP systemengineer trended greater than minimal packing leakage on the screenwash/fire pump. The applicant will perform repacking when necessary to resolve this issue. The second concern waswith a seal leak on the FP jockey pump. Plant staff replaced the mechanical seal under the work control process.The staff reviewed the operating experience provided in the LRA and interviewed theapplicant's technical personnel to confirm that plant-specific operating experience revealed no degradation not bounded by industry experience.On the basis of its review of the above operating experience and discussions with theapplicant's technical personnel, the staff concluded that the applicant's Fire Water SystemProgram will adequately manage the aging effects identified in LRA for which this AMP iscredited.
3-100USAR Supplement. In LRA Section A2.1.18, the applicant provided the USAR supplement forthe Fire Water System Program. The staff reviewed this section and determined that the information in the USAR supplement adequately describes the program, as required by 10 CFR 54.21(d).In its letter dated June 10, 2005, the applicant added the following three commitments to LRASection A2.1.18, documented as commitments 30, 31, and 32 in Table A.5, which the applicantwill perform before the period of extended operation:  (1)The applicant will revise the implementing procedures for the Fire Water SystemProgram to include extrapolation of inspection results to below-grade fire water piping with conditions similar to those within above-grade fire water piping.  (2)Sprinkler heads will be inspected and tested in accordance with NFPA requirements orreplaced before the end of their 50-year service life and at 10-year intervals thereafter during the extended period of operation to ensure that degradation, such as corrosion, isdetected promptly. Procedures to be used for aging management activities (AMAs) of the Fire Water System Program will be verified and testing will be performed inaccordance with applicable NFPA codes and standards. The applicant will reviserelevant procedures as appropriate.  (3)The applicant will verify that the procedures to be used for AMAs of the fire watersystem apply testing in accordance with the applicable NF PA codes and standards. Itwill revise the relevant procedures as appropriate.Conclusion. On the basis of its review and audit of the applicant's Fire Water System Program,the staff determined that those program elements for which the applicant claimed consistencywith the GALL Report are consistent with the GALL Report. In addition, the staff reviewed theenhancement and confirmed that its implementation before the period of extended operationwill result in the existing AMP being consistent with the GALL Report AMP to which it wascredited. The staff concluded that the applicant demonstrated that the effects of aging will beadequately managed so that intended functions will be maintained consistent with the CLB forthe period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.2.17  Fuel Oil Chemistry Program Summary of Technical Information in the Application. In LRA Section B2.1.20, the applicantdescribed the Fuel Oil Chemistry Program, stating that this existing program is consistent, with exceptions and enhancements, with GALL AMP XI.M30, "Fuel Oil Chemistry." The Fuel Oil Chemistry Program mitigates and manages aging effects on the internal surfaces of diesel fuel oil storage tanks and associated components in systems that contain diesel fuel oil. Theprogram includes (1) surveillance and monitoring procedures for maintaining diesel fuel oilquality by controlling contaminants in accordance with applicable ASTM standards, (2) periodic draining of water from diesel fuel oil tanks, if water is present, (3) periodic or conditional visual inspection of internal surfaces or wall thickness measurements (e.g., by UT) from external surfaces of diesel fuel oil tanks, and (4) one-time inspections of a representative sample of components in systems that contain diesel fuel oil.
3-101Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP 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 staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.M30.In the LRA, the applicant stated the following exceptions to the program elements listed forAMP XI.M30 in the GALL Report.Exception 1:  The GALL Report recommends the following for the Preventive Actions programelement associated with the exception taken:The quality of fuel oil is maintained by additions of biocides to minimize biologicalactivity, stabilizers to prevent biological breakdown of the diesel fuel, and corrosion inhibitors to mitigate corrosion. Periodic cleaning of a tank allows removal of sediments, and periodic draining of water collected at the bottom of a tank minimizes the amount of water and the length of contact time. Accordingly, these measures are effective in mitigating corrosion inside diesel fuel oil tanks.
Coatings, if used, prevent or mitigate corrosion by protecting the internal surfaces of the tank from contact with water and microbiological organisms.In the LRA, the applicant stated that its Fuel Oil Chemistry Program does not currently usebiocides, stabilizers, and corrosion inhibitors.The staff found this exception acceptable based on its review of various documents on site,including a comparison of ASTM standards with those recommended in the GALL Report, historical oil analyses, the PBD, and discussions with plant personnel. The review of the historical oil analyses and discussions with plant personnel showed that there had been no biological breakdown of fuel oil and that the oil purchased to ASTM D 975 requirements has remained stable and free of corrosion during storage and use. On the basis of the above review and review of plant-specific operating experience for the Fuel Oil Chemistry Program, the staff found this exception acceptable.Exception 2:  The GALL Report recommends the following for the Parameters Monitored orInspected program element associated with the exception taken:The AMP monitors fuel oil quality and the levels of water and microbiologicalorganisms in the fuel oil, which cause the loss of material of the tank internal surfaces. The ASTM Standard D 4057 is used for guidance on oil sampling. The ASTM Standards D 1796 and D 2709 are used for determination of water and sediment contamination in diesel fuel. For determination of particulates, modifiedASTM D 2276, Method A, is used. The modification consists of using a filter with a pore size of 3.0 m, instead of 0.8 m. These are the principal parametersrelevant to tank structural integrity.
3-102In the LRA, the applicant stated that it does not use ASTM D 2709 or ASTM D 2276, but ASTMD 6217, "Test Method for Particulate Contamination in Middle Distillate Fuels by LaboratoryFiltration," as a laboratory test to sample diesel fuel oil for suspended particulates. This standard applies to the grade of diesel fuel oil and also uses the more conservative
 
===0.8 micrometer===
(m) filter pore size instead of the recommended 3.0 m.The staff found this exception acceptable based on its review of various documents on site,including a comparison of ASTM standards with those recommended in the GALL Report.
Review of ASTM D 6217 showed that this laboratory analysis of the fuel oil specifically applies to the grade of oil used, and the applicant uses a more conservative filter pore size than that recommended by the GALL Report. On the basis of the above review and its review of plant-specific operating experience for the Fuel Oil Chemistry Program, the staff found this exception acceptable.Exception 3:  The GALL Report recommends the following for the Acceptance Criteria programelement associated with the exception taken:The ASTM Standard D 4057 is used for guidance on oil sampling. The ASTMStandards D 1796 and D 2709 are used for guidance on the determination of water and sediment contamination in diesel fuel. Modified ASTM D 2276, Method A is used for determination of particulates. The modification consists of using a filter with a pore size of 3.0 m, instead of 0.8 m.In the LRA, the applicant stated that it does not use ASTM D 2709 or ASTM D 2276, but usesASTM D 6217 as a laboratory test to sample diesel fuel oil for suspended particulates. This standard applies to the grade of diesel fuel oil used at MNGP and uses the more conservative
 
0.8 m filter pore size instead of the recommended 3.0 m.The staff found this exception acceptable based on its review of various documents on site,including a comparison of ASTM standards with those recommended in the GALL Report.
Review of ASTM D 1796 showed that it specifically applies to the type of diesel fuel used and contains the necessary and sufficient requirements for sampling for sediment and water.
Additionally, a review of ASTM D 6217 showed that it contains test parameters, performed by an offsite laboratory, equivalent to ASTM D 2276 recommended in the GALL Report. On the basis of the above review and its review of plant-specific operating experience for the Fuel Oil Chemistry Program, the staff found this exception acceptable.In the LRA, the applicant stated that the following enhancements will make this AMP consistentwith the recommendation in the GALL Report.Enhancement 1:  The GALL Report recommends the following for the Scope of Programprogram element associated with the enhancement made:The program is focused on managing the conditions that cause general, pitting,and microbiologically influenced corrosion (MIC) of the diesel fuel tank internal surfaces. The program serves to reduce the potential of exposure of the tank internal surface to fuel oil contaminated with water and microbiological organisms.
3-103In the LRA, the applicant stated that it will revise the procedures for the diesel fuel oil system toinclude requirements to check for general, pitting, crevice, and galvanic corrosion, MIC, and cracking.The staff review of various documents on site, including a comparison of ASTM standards withthose recommended in the GALL Report, the PBD, and discussions with plant personnel determined that the requirements to check for general, pitting, crevice, and galvanic corrosion,MIC, and cracking will continually verify the effectiveness of the program. On the basis of theabove review and its review of plant-specific operating experience for the Fuel Oil Chemistry Program, the staff found this enhancement acceptable as such changes to the applicant's program provide assurance that the effects of aging will be adequately managed.Enhancement 2:  The GALL Report recommends the following for the Preventive Actionsprogram element associated with the enhancement made:The quality of fuel oil is maintained by additions of biocides to minimize biologicalactivity, stabilizers to prevent biological breakdown of the diesel fuel, and corrosion inhibitors to mitigate corrosion. Periodic cleaning of a tank allows removal of sediments, and periodic draining of water collected at the bottom of a tank minimizes the amount of water and the length of contact time. Accordingly, these measures are effective in mitigating corrosion inside diesel fuel oil tanks.
Coatings, if used, prevent or mitigate corrosion by protecting the internal surfaces of the tank from contact with water and microbiological organisms.In the LRA, the applicant stated that it will revise its Fuel Oil Chemistry Program to require tankdraining, cleaning, and inspection if deemed necessary based on trends indicated by results of the diesel fuel oil analysis, or if recommended by the system engineer based on equipmentoperating experience.The staff review of various documents on site, including a comparison of ASTM standards withthose recommended in the GALL Report, the PBD, and discussions with plant personnel determined that these requirements (i.e., to provide tank draining, cleaning, and inspection ifdeemed necessary based on the trends indicated by the results of the diesel fuel oil analysis or as recommended by t he system engineer based on equipment operating experience) willprovide a continuing check on the effectiveness of the program. On the basis of the above review and its review of plant-specific operating experience for the Fuel Oil Chemistry Program, the staff found this enhancement acceptable as such changes to the applicant's program provide assurance that the effects of aging will be adequately managed.Enhancement 3:  The GALL Report recommends the following for the Detection of AgingEffects program element associated with the enhancement made:Degradation of the diesel fuel oil tank cannot occur without exposure of the tankinternal surfaces to contaminants in the fuel oil, such as water and microbiological organisms. Compliance with diesel fuel oil standards in item 3, above, and periodic multilevel sampling provide assurance that fuel oil contaminants are below acceptable levels. Internal surfaces of tanks that are drained for cleaning are visually inspected to detect potential degradation.
However, corrosion may occur at locations in which contaminants may 3-104accumulate, such as a tank bottom, and an ultrasonic thickness measurement ofthe tank bottom surface ensures that significant degradation is not occurring.In the LRA, the applicant stated it will write a procedure or revise existing procedures in theMNGP Fuel Oil Chemistry Program to require periodic inspections of the diesel fuel oil tanks.The staff review of various documents on site, including a comparison of ASTM standards withthose described in the GALL Report, the PBD, and discussions with plant personnel, determined that the requirement to write or revise the Fuel Oil Chemistry Program proceduresto require periodic inspections of the diesel fuel oil tanks will be a continuing check on theeffectiveness of the program. The addition of periodic tank inspections will make the programconsistent with the recommendations of the GALL Report. On the basis of the above reviewand its review of plant-specific operating experience for the Fuel Oil Chemistry Program, the staff found this enhancement acceptable as such changes to the applicant's program provide assurance that the effects of aging will be adequately managed.The staff reviewed those portions of the AMP B2.1.20, "Fuel Oil Chemistry Program," that theapplicant claimed are consistent with GALL AMP XI.M30 and found them consistent. The staff found the applicant's AMP acceptable because it conforms to the recommended GALL Report AMP with the exceptions and enhancements as described above.Operating Experience. In LRA Section B2.1.20, the applicant explained that monthly andquarterly diesel fuel oil sampling and trending activities have confirmed the adequacy of the diesel fuel oil supply. Past tank cleanings and inspections have shown that the condition of the tanks has not degraded.The staff reviewed the operating experience provided in the LRA and interviewed theapplicant's technical personnel to confirm that plant-specific operating experience revealed no degradation not bounded by industry experience.On the basis of its review of the above industry and plant-specific operating experience anddiscussions with the applicant's technical personnel, the staff concluded that the Fuel Oil Chemistry Program will adequately manage the aging effects identified in the LRA for which thisAMP is credited.USAR Supplement. In LRA Section A2.1.20, the applicant provided the USAR supplement forthe Fuel Oil Chemistry Program. The staff reviewed this section and determined that the information in the USAR supplement adequately describes the program, as required by 10 CFR 54.21(d).In its letter dated June 10, 2005, the applicant included commitments to LRA Section A2.1.20,documented as commitments 33, 34, and 35 in Table A.5, to perform the following before theperiod of extended operation:  (1)The applicant will revise its procedures related to the diesel fuel oil system to includerequirements to check for general, pitting, crevice, and galvanic corrosion, MIC, and cracking.
3-105  (2)The applicant will revise its Fuel Oil Chemistry Program procedures to require tankdraining, cleaning, and inspection if deemed necessary based on the trends indicated by the results of the diesel fuel oil analysis, or as recomm ended by the system engineerbased on equipment operating experience.  (3)The applicant will develop or revise procedures for the MNGP Fuel Oil ChemistryProgram to require periodic inspections of the diesel fuel oil tanks.Conclusion. On the basis of its review and audit of the applicant's Fuel Oil Chemistry Program,the staff determined that those program elements for which the applicant claimed consistencywith the GALL Report are consistent with the GALL Report. In addition, the staff reviewed theexceptions and the associated justifications and determined that the AMP, with the exceptions,is adequate to manage the aging effects for which it is credited. The staff also reviewed the enhancements and confirmed that their implementation before the period of extended operationwill result in the existing AMP being consistent with the GALL Report AMP to which it wascredited. The staff concluded that the applicant demonstrated that the effects of aging will beadequately managed so that intended functions will be maintained consistent with the CLB forthe period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.2.18Inspection of Overhead Heavy Load and Light Load (Related to Refueling) HandlingSystems ProgramSummary of Technical Information in the Application. In LRA Section B2.1.22, the applicantdescribed the Inspection of Overhead Heavy Load and Light Load (Related to Refueling)
Handling Systems Program, stating that this existing program is consistent, with exception and enhancement, with GALL AMP XI.M23, "Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems." The Inspection of Overhead Heavy Load & Light Load (Related to Refueling) Handling Systems Program, which the applicant implements through plant procedures and PM, manages loss of material of structural components for heavy load and fuel handling components within the scope of license renewal. The Inspection of Overhead Heavy Load & Light Load (Related to Refueling) Handling Systems Program provides for visual and NDE inspections of load-handling components within the scope of license renewal. The applicant also performs functional tests to assure their integrity. The cranes also comply with the Maintenance Rule requirements provided in 10 CFR 50.65, "Requirements forMonitoring the Effectiveness of Maintenance at Nuclear Power Plants."Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's audit evaluation of this AMP. The staff reviewed the exception and enhancement and the associatedjustifications to determine whether the AMP, with the exception and enhancement, remainsadequate to manage the aging effects for which it is credited.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.M23.
3-106In the LRA, the applicant stated the following exception to the program elements listed for AMPXI.M23 in the GALL Report.Exception:  The GALL Report recommends the following for the Parameters Monitored orInspected program element associated with the exception taken:The program evaluates the effectiveness of the maintenance monitoringprogram and the effects of past and future usage on the structural reliability ofcranes. The number and magnitude of lifts made by the crane are also reviewed.In the LRA, the applicant stated, except for special lifts made by the turbine building crane, itsprogram does not track the number and size of lifts because administrative controls ensure that only allowable loads are handled, and fatigue failure of structural elements is not expected with the limited number of lifts.The staff reviewed information on the reactor building crane that notes that it has the designcapacity for many more lifts at a higher rated tonnage than are expected to take place over its 60-year life. Additionally, the applicant informed the staff that it also performs inspections and functional che cks on the other cranes periodically and before use. The applicant also providedoperating experience showing no degradation caused by aging since plant startup. The staff found this exception acceptable based on its review of information that demonstrates the design capabilities of the reactor building crane and the required inspections before the operation ofother cranes, and review of operating experience.In the LRA, the applicant stated that the following enhancement will make this AMP consistentwith the recommendation in the GALL Report.Enhancement:  The GALL Report recommends the following for Detection of Aging Effectsprogram element associated with the enhancement made:Crane rails and structural components are visually inspected on a routine basisfor degradation. Functional tests are also performed to assure their integrity.The applicant will enhance the program to specify a 5-year inspection frequency for the fuelpreparation machines.The staff review of various documents on site, including a comparison of the GALL Reportrecommendations with the proposed enhancements, the PBD, and discussions with plant personnel, determined that this requirement, a 5-year inspection frequency for the fuel preparation machines, continually verifies the effectiveness of the program. The 5-year frequency is acceptable as operating experience shows no degradation caused by aging since installation; therefore, any aging mechanisms appear to act slowly. The addition of a specified period for fuel preparation machine inspection ensures that each component is visually inspected routinely for degradation and conforms with the recommendation in the GALL Report.On the basis of the above review and a review of operating experience for the AMP, the stafffound this enhancement acceptable as such changes to the applicant's program provide assurance that the effects of aging will be adequately managed.
3-107The staff reviewed those portions of AMP B2.1.22, "Inspection of Overhead Heavy Load andLight Load (Related to Refueling) Handling Systems Program," that the applicant claimed areconsistent with GALL AMP XI.M23 and found them consistent. The staff found the applicant'sAMP acceptable because it conforms to the recommended GALL Report AMP with the exception and enhancement as described above.Operating Experience. In LRA Section B2.1.22, the applicant explained that no incidents offailure of passive components for cranes and special lifting devices because of aging have occurred at MNGP. The inspection activities have detected and managed aging effects in crane and special lifting device components. A magnetic particle inspection of the dryer and steam separator sling found a linear indication, which was repaired before to use. An inspection of the reactor vessel head lifting device noted some minor degradation, which, in accordance with procedure, was repaired and painted.The staff reviewed the operating experience provided in the LRA and interviewed theapplicant's technical personnel to confirm that plant-specific operating experience revealed no degradation not bounded by industry experience.On the basis of its review of the above industry and plant-specific operating experience anddiscussions with the applicant's technical personnel, the staff concluded that the Inspection ofOverhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program willadequately manage the aging effects identified in the LRA for which this AMP is credited.USAR Supplement. In LRA Section A2.1.22, the applicant provided the USAR supplement forthe Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program. The staff reviewed this section and determined that the information in the USAR supplement adequately describes the program, as required by 10 CFR 54.21(d).In its letter dated June 10, 2005, the applicant included a commitment to LRA Section A2.1.22,documented as commitment 37 in Table A.5, that before the period of extended operation, theapplicant will enhance the Inspection of Overhead Heavy Load & Light Load (Related toRefueling) Handling Systems Program to specify a 5-year inspection frequency for the fuel preparation machines.Conclusion. On the basis of its review and audit of the applicant's Inspection of OverheadHeavy Load and Light Load (Related to Refueling) Handling Systems Program, the staff determined that those program elements for which the applicant claimed consistency with theGALL Report are consistent with the GALL Report. In addition, the staff reviewed the exceptionand the associated justifications and determined that the AMP, with the exception, is adequateto manage the aging effects for which it is credited. The staff also reviewed the enhancement and confirmed that its implementation before the period of extended operation will result in theexisting AMP being consistent with the GALL Report AMP to which it was credited. The staff concluded that the applicant demonstrated that the effects of aging will be adequately managedso that intended functions will be maintained consistent with the CLB for the period of extendedoperation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).
3-1083.0.3.2.19  Plant Chemistry ProgramSummary of Technical Information in the Application. In LRA Section B2.1.25, the applicantdescribed the Plant Chemistry Program, stating that this existing program is consistent, with exceptions, with GALL AMP XI.M2, "Water Chemistry." The MNGP Plant Chemistry Program mitigates the aging effects on component surfaces that are exposed to water as the process fluid; chemistry programs are used to control water chemistry for impurities (e.g., chloride and sulfate) that accelerate corrosion or crack initiation and growth and that cause heat transfer degradation due to fouling in select heat exchangers. This program relies on monitoring and control of water chemistry to keep peak levels of various contaminants below system-specificlimits based on BWRVIP-130". This document supersedes previous revisions of the BWR water chemistry guidelines, including BWRVIP-29. For low-flow or stagnant portions of a system, aone-time inspection of selected components at susceptible locations provides verification of the effectiveness of the Plant Chemistry Program.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's audit evaluation of this AMP. The staff reviewed the exceptions and the associated justifications todetermine whether the AMP, with the exceptions, remains adequate to manage the agingeffects for which it is credited.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.M2.In the LRA, the applicant stated the following exceptions to the program elements listed forAMP XI.M2 in the GALL Report.Exception 1:  The GALL Report recommends the following for the Scope of Program elementassociated with the exception taken:The program includes periodic monitoring and control of known detrimentalcontaminants such as chlorides, fluorides (PWRs only), dissolved oxygen, and sulfate concentrations below the levels known to result in loss of material or crack initiation and growth. Water chemistry control is in accordance with the guidelines in BWRVIP-29 (EPRI TR-103515) for water chemistry in BWRs; EPRI TR-105714, Rev. 3, for primary water chemistry in PWRs; EPRI TR102134, Rev. 3, for secondary water chemistry in PWRs; or later revisions or updates of these reports as approved by the staff.In the LRA, the applicant stated that the Plant Chemistry Program uses BWRVIP-130, whichsupersedes previous revisions of the BWR water chemistry guidelines, including BWRVIP-29.Based on technical analysis, the staff found the provisions of Revision 2 of BWRVIP-29, issuedin 2000, acceptable based on updated industry experience. BWRVIP-130 is the current updateof the BWR water chemistry guidelines and supersedes BWRVIP-29, Revision 2. BWRVIP-130 is based on updated industry experience with increased emphasis on fuel performance concerns, while retaining the chemistry parameters, action levels, and associated measurement frequencies essentially unchanged.
3-109LRA Section B2.1.25 states that this program has one exception in that the Plant ChemistryProgram uses the 2004 revision, not the 1993, 1996, or 2000 revisions, of the EPRI BWR waterchemistry guidelines. BWRVIP-130 replaced BWRVIP-29, Revision 2. The applicant stated that the new program incorporates updated industry experience with increased focus on fuel performance, while retaining the chemistry parameters, action levels, and associated measurement frequencies essentially unchanged. The staff interviewed the applicant regarding the relationship of the existing Plant Chemistry Program and the elements of BWRVIP-130 to the 2000 revision of the BWR water chemistry guidelines. The applicant stated that the PlantChemistry Program has the elements of BWRVIP-29 and incorporates updated guidelines based on industry experience. The staff comparison of the EPRI 2000 revision of the guidelines against the EPRI 2004 revision used by the applicant also shows that the guideline wasupdated to show industry experience.The staff determined from the documentation of these chemistry revisions that the adoption ofthe 2004 revision (BWRVIP-130) resulted in no significant changes to critical program elements, and that the revision includes updates to the technical basis and guidance to reflect additional industry experience with increased focus on fuel performance, while retaining the same chemistry parameters, action levels, and associated measurement frequencies.
Therefore, the staff found the exception acceptable.Exception 2:  The GALL Report recommends the following for the Parameters Monitored orInspected program elements associated with the exception taken:BWR Water Chemistry:  The guidelines in BWRVIP-29 (EPRI TR-103515) forBWR reactor water recommend that the concentration of chlorides, sulfates, and dissolved oxygen are monitored and kept below the recommended levels to mitigate corrosion. The two impurities, chlorides and sulfates, determine the coolant conductivity; dissolved oxygen, hydrogen peroxide, and hydrogen determine electrochemical potential (ECP). The EPRI guidelines recommend that the coolant conductivity and ECP are also monitored and kept below the recommended levels to mitigate SCC and corrosion in BWR plants. The EPRI guidelines in BWRVIP-29 (TR-103515) for BWR feedwater, condensate, and control rod drive water recommends that conductivity, dissolved oxygen level, and concentrations of iron and copper (feedwater only) are monitored and kept below the recommended levels to mitigate SCC. The EPRI guidelines in BWRVIP-29 (TR-103515) also include recommendations for controlling waterchemistry in auxiliary systems: torus/pressure suppression chamber, condensatestorage tank, and spent fuel pool.In the LRA, the applicant stated the Plant Chemistry Program does not measure hydrogenperoxide. Instead, plant staff perform site-specific radiolysis modeling. As noted in BWRVIP-130, reliable measurements of hydrogen peroxide are exceptionally difficult to obtain, and concentration can be estimated from radiolysis models.The staff interviewed the applicant for technical justification for its initial use of reactor vendormodels as the basis for hydrogen water chemistry. Since then, EPRI had developed a software program, known as the BWR Vessel and Internals Application, as part of the BWRVIP now used for radiolysis and ECP monitoring for specific regions inside the reactor vessel. Results from this model have been compared to prior reactor vendor models to confirm appropriate 3-110application of the software modeling applications. The applicant runs the model at least twiceduring each operating cycle to account for changes in reactor flux and core flow on modelresults.The staff found in its evaluation and review of plant-specific operating experience that theexception to the Plant Chemistry Program to use site-specific radiolysis modeling instead of measuring hydrogen peroxide is acceptable and consistent with the GALL Report because radiolysis models are acceptable for establishing hydrogen injection rates (to reduce oxidants in the RCS, and thus SCC) as established by EPRI guidelines for BWR vessel internals.On the basis of its review of the above exception and of operating experience for the PlantChemistry Program, the staff found this exception acceptable.The staff reviewed those portions of AMP B2.1.25, "Plant Chemistry Program," that theapplicant claimed are consistent with GALL AMP XI.M2 and found them consistent. The staff found the applicant's AMP acceptable because it conforms to the recommended GALL Report AMP with the exceptions as described above.Operating Experience. In LRA Section B2.1.25, the applicant explained that CRs/ARs areinitiated when water chemistry is found to be out of specification. Many of these conditions result from equipment or plant transient conditions (e.g., plant startup) that are resolved oncethe transient condition subsides. The time duration of these conditions is typically short and no evidence of detrimental equipment impacts could be found. Further, no examples of component functional failures due to corrosion, cracking, or heat transfer degradation resulting from inadequate chemistry control were identified. The applicant addressed industry experience related to IGSCC issues by replacing components with less susceptible materials, implementation of hydrogen water chemistry, and improvements in water chemistry standards.
It replaced the entire recirculation system piping, a number of safe ends connec ted to thereactor vessel, the jet pump holddown beam assemblies, and the shroud head bolts with materials less susceptible to IGSCC. No adverse trends in water chemistry control were identified based on a review of various chemistry performance indicators. Established procedural requirements for chemistry limits are based on EPRI and industry standards and routinely monitored by the site. Recent external and internal assessments have identified chemistry trending as a strength and personnel knowledge as good. These conclusions are based on a review of CAP issues on chemistry (and out of specification chemistry limits) from January 1, 1996, through May 1, 2004, recent external and internal Chemistry Department assessment results, system health reports, and chemistry performance indicators and trends.The staff reviewed the operating experience provided in the LRA and interviewed theapplicant's technical personnel to confirm that plant-specific operating experience revealed no degradation not bounded by industry experience.On the basis of its review of the above operating experience and discussions with theapplicant's technical personnel, the staff concluded that the applicant's Plant ChemistryProgram will adequately manage the aging effects identified in the LRA for which this AMP iscredited.USAR Supplement. In LRA Section A2.1.25, the applicant provided the USAR supplement forthe Plant Chemistry Program. The staff reviewed this section and determined that the 3-111information in the USAR supplement adequately describes the program, as required by10 CFR 54.21(d).Conclusion. On the basis of its review and audit of the applicant's Plant Chemistry Program, thestaff determined that those program elements for which the applicant claimed consistency withthe GALL Report are consistent with the GALL Report. In addition, the staff reviewed the exceptions and the associated justifications and determined that the AMP, with the exceptions,is adequate to manage the aging effects for which it is credited. The staff concluded that the applicant demonstrated that the effects of aging will be adequately managed so that intendedfunctions will be maintained consistent with the CLB for the period of extended operation, asrequired by 10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.2.20  Protective Coating Monitoring & Maintenance ProgramSummary of Technical Information in the Application. In LRA Section B2.1.27, the applicantdescribed the Protective Coating Monitoring & Maintenance Program, stating that this existingprogram is consistent, with enhancements, with GALL AMP XI.S8, "Protective Coating Monitoring and Maintenance Program." The Protective Coating Monitoring and Maintenance Program applies to Service Level 1 protective coatings inside containment to address the concerns of NRC GL 98-04, "Potential for Degradation of the Emergency Core Cooling Systemand the Containment Spray System after a Loss-of-Cooling Accident because of Construction and Protective Coating Deficiencies and Foreign Material in Containment," dated July 14, 1998.
The Protective Coating Monitoring & Maintenance Program prevents the degradation ofcoatings that could lead to the clogging of Emergency Core Cooling System (ECCS) suppression pool suction strainers. MNGP does not credit the Protective Coating Monitoring and Maintenance Program for the prevention of corrosion of carbon steel components. As outlined in the MNGP response to GL 98-04, the Protective Coating Monitoring and Maintenance Program is a comparable program for monitoring and maintaining protective coatings inside the primary containment and subject to the requirements of ANSI N101.4-1972,to the extent specified in ANSI N18.7-1976 and as modified by RG 1.54, "Service Level I, II, and III Protective Coatings Applied to Nuclear Power Plants," issued June 1973.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's audit evaluation of this AMP. The staff reviewed the enhancements and the associated justificationsto determine whether the AMP, with the enhancements, remains adequate to manage the agingeffects for which it is credited.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part,documents cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.S8.In the LRA, the applicant stated that the following enhancements will make this AMP consistentwith the recommendation in the GALL Report.Enhancement 1:  The GALL Report recommends the following for the Scope of Programprogram element associated with the enhancement made:
3-112The minimum scope of the program is Service Level 1 coatings, defined inRG 1.54, Rev 1, as follows:  "Service Level 1 coatings are used in areas inside the reactor containment where the coating failure could adversely affect the operation of post-accident fluid systems and thereby impair safe shutdown."In the LRA, the applicant stated that it will update the MNGP Protective Coating Monitoring &Maintenance Program to include inspection of all accessible painted surfaces inside containments.The staff noted that the GALL Report states that a comparable program for monitoring andmaintaining protective coatings inside containments, developed in accordance with RG 1.54, Revision 0, or the ANSI standards (since withdrawn) referenced in RG 1.54, Revision 0, and coatings maintenance programs described in licensee responses to GL 98-04, is also acceptable as an AMP for license renewal. The applicant's program is a "comparable program,"
as defined above. The staff determined that this enhancement (i.e., requiring an inspection of all accessible painted surfaces inside containment) makes the program consistent with theGALL Report recommendation of Service Level 1 coatings as defined in RG 1.54, Revision 1.
On the basis of the above review and its review of operating experience for the Protective Coating Monitoring & Maintenance Program, the staff found the enhancement acceptable assuch changes to the applicant's program provide assurance that the effects of aging will beadequately managed.Enhancement 2:  The GALL Report recommends the following for the Detection of AgingEffects program element associated with the enhancement made:ASTM D 5163-96, paragraph 5, defines the inspection frequency to be eachrefueling outage or during other major maintenance outages as needed.
ASTM D 5163-96, paragraph 8, discusses the qualifications for inspection personnel, the inspection coordinator, and the inspection results evaluator.
ASTM D 5163-96, subparagraph 9.1, discusses development of the inspection plan and the inspection methods to be used. It states, "A general visual inspection shall be conducted on all readily accessible coated surfaces during a walk-through. After a walk-through, thorough visual inspections shall be carried out on previously designated areas and on areas noted as deficient during the walk-through. A thorough visual inspection shall also be carried out on all coatings near sumps or screens associated with the Emergency Core Cooling System (ECCS)."  This subparagraph also addresses field documentation of inspection results. ASTM D 5163-96, subparagraph 9.5, identifies instruments and equipment needed for inspection.In the LRA, the applicant stated that before the period of extended operation, all coatinginspectors will meet the requirements of ANSI N45.2.6, "Qualification of Inspection,Examination, and Testing Personnel for the Construction Phase of Nuclear Power Plants."The staff review noted that the relevant ASTM standard requires that coating inspectors bequalified in accordance with ANSI N45.2.6 or the ASTM requirements. The staff queried the applicant about the qualification requirement for inspectors. The applicant agreed to add this enhancement. By letter dated August 11, 2005, the applicant stated that before the period ofextended operation all coating inspectors will meet ANSI N45.2.6 requirements. The staff 3-113determined that this enhancement (i.e., requiring all coating inspectors to be qualified inaccordance with ANSI N45.2.6) makes this program consistent with the GALL Report recommendation of qualification under the requirements in paragraph 8 of ASTM D 5163-96, "Standard Guide for Establishing Procedures To Monitor the Performance of Safety Related Coatings in an Operating Nuclear Power Plant," for inspection personnel, inspection coordinators, and inspection results evaluators. On the basis of the above review and its review of operating experience for the Protective Coating Monitoring & Maintenance Program, the stafffound this enhancement acceptable as such changes to the applicant's program provide assurance that the effects of aging will be adequately managed.Enhancement 3:  The GALL Report recommends the following for the Monitoring and Trendingprogram element associated with the enhancement made:ASTM D 5163-96 identifies monitoring and trending activities insubparagraph 6.2, which specifies a pre-inspection review of the previous two monitoring reports, and in subparagraph 10.1.2, which specifies that the inspection report should prioritize repair areas as either needing repair during the same outage or postponed to future outages, but under surveillance in theinterim period.In the LRA, the applicant stated it will include a preinspection review of the previous twoinspection reports to identify trends.The staff review has determined that this enhancement (i.e., a preinspection review of theprevious two inspection reports to identify trends) makes this program consistent with the GALL Report recommendation above. On the basis of the above review and its review of operating experience for the Protective Coating Monitoring & Maintenance Program, the staff found this enhancement acceptable as such changes to the applicant's program provide assurance that the effects of aging will be adequately managed.Enhancement 4:  The GALL Report recommends the following for the Acceptance Criteriaprogram element associated with the enhancement made:ASTM D 5163-96, subparagraphs 9.2.1 thr ough 9.2.6, 9.3, and 9.4, containguidance for characterization, documentation, and testing of defective or deficient coating surfaces. Additional ASTM and other recognized test methods are identified for use in characterizing the severity of observed defects and deficiencies. The evaluation covers blistering, cracking, flaking, peeling, delamination, and rusting. ASTM D 5163-96, paragraph 11, addresses evaluation. It specifies that the inspection report is to be evaluated by the responsible evaluation personnel, who prepare a summary of findings and recommendations for future surveillance or repair, including an analysis ofreasons or suspected reasons for failure. Repair work is prioritized as major or minor defective areas. A recommended corrective action plan is required for major defective areas so that these areas can be repaired during the same outage, if appropriate.In the LRA, the applicant stated that it will revise the AMP implementation procedures to includeanalysis of suspected reasons for coating failure.
3-114The staff review determined that this enhancement (i.e., revising implementation procedures toinclude analysis of suspected reasons for coating failure) makes this program consistent with the GALL Report recommendation. On the basis of the above review and its review of operatingexperience for the Protective Coating Monitoring & Maintenance Program, the staff found this enhancement acceptable as such changes to the applicant's program provide assurance that the effects of aging will be adequately managed.The staff reviewed those portions of AMP B2.1.27, "Protective Coating Monitoring andMaintenance Program," that the applicant claimed are consistent with GALL AMP XI.S8 andfound them consistent. The staff found the applicant's AMP acceptable because it conforms to the recommended GALL Report AMP with the enhancements as described above.Operating Experience. In LRA Section B2.1.27, the applicant explained that it does not relyupon the Protective Coating Monitoring & Maintenance Program to manage the loss of material due to corrosion of carbon steel structural elements. Therefore, only the operating experience concerned with degradation of coatings and their consequential clogging of the ECCS strainersis of importance. Since there currently are no coating inspection requirements for allcomponents inside containment, the only inspection experience to date is from those inspections of the drywell and torus shells. Inspections of the drywell and torus shell have identified the following signs of paint degradation-chipping, rusting, peeling, blistering,cracking, and other signs of degradation. All unacceptable coating degradation has beenrepaired or in the case of the torus is scheduled for repair during the next torus draining. These inspections have detected and evaluated aging effects before the loss of intended function of the ECCS suction strainers. Where applicable, the applicant made repairs to minimize further degradation of the coatings, which may lead to clogging of the ECCS suction strainers.The staff reviewed the operating experience provided in the LRA and interviewed theapplicant's technical personnel to confirm that plant-specific operating experience revealed no degradation not bounded by industry experience.On the basis of its review of the above industry and plant-specific operating experience anddiscussions with the applicant's technical personnel, the staff concluded that the ProtectiveCoating Monitoring & Maintenance Program will adequately manage the aging effects identifiedin the LRA for which this AMP is credited.USAR Supplement. In LRA Section A2.1.27, the applicant provided the USAR supplement forthe Protective Coating Monitoring & Maintenance Program. The staff reviewed this section and determined that the information in the USAR supplement adequately describes the program, asrequired by 10 CFR 54.21(d).In its letter dated June 10, 2005, the applicant included the commitments to USARSection A2.1.27, documented as commitments 39, 40, and 41 in Table A.5, which the applicantwill complete before the period of extended operation:  (1)The applicant will update procedures to include inspection of all accessible paintedsurfaces inside containment.  (2)The applicant will revise the program to include a preinspection review of the previoustwo inspection reports so that trends can be identified.
3-115  (3)The applicant will revise implementation procedures to include provisions for analysis ofsuspected reasons for coating failure.In a letter dated August 11, 2005, the applicant provided a new commitment, stating that beforethe period of extended operation, coating inspectors will meet ANSI N45.2.6 requirements.Conclusion. On the basis of its review and audit of the applicant's Protective Coating Monitoring& Maintenance Program, the staff determined that those program elements for which theapplicant claimed consistency with the GALL Report are consistent with the GALL Report. Inaddition, the staff reviewed the enhancements and confirmed that their implementation beforethe period of extended operation will result in the existing AMP being consistent with the GALLReport AMP to which it was credited. The staff concluded that the applicant demonstrated thatthe effects of aging will be adequately managed so that intended functions will be maintainedconsistent with the CLB for the period of extended operation, as required by10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.2.21  Reactor Vessel Surveillance Program Summary of Technical Information in the Application. In LRA Section B2.1.29, the applicantdescribed the Reactor Vessel Surveillance Program, stating that this existing program isconsistent, with enhancement, with GALL AMP XI.M31, "Reactor Vessel Surveillance."The applicant stated that the Reactor Vessel Surveillance Program is part of the BWRVIPIntegrated Surveillance Program (ISP) that uses data from BWR member surveillance programs to select the "best" representative material for monitoring radiation embrittlement for a particular plant. The BWRVIP ISP monitors capsule test results from various member plants.The program was implemented to comply with Appendix H, "Reactor Vessel MaterialSurveillance Program Requirements," to 10 CFR Part 50. The BWRVIP ISP guidance describes the scope of the Reactor Vessel Surveillance Program. BWRVIP-86-A, "BWR Vessel andInternals Project:  BWR Integrated Surveillance Program (ISP) Implementation," includes the ISP capsule removal schedule, and BWRVIP-78, "BWR Vessel and Internals Project: BWR Integrated Surveillance Program (ISP) Plan," describes its technical basis.The applicant stated in the Detection of Aging Effects program element of the Reactor VesselSurveillance Program that the ISP performs Charpy V-notch testing on specimens to measure the applicable aging effect, loss of fracture toughness. The applicant further stated that the Reactor Vessel Surveillance Project uses the BWRVIP ISP to monitor the effect of irradiation on the vessel.Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information inLRA Section B2.1.29 about the applicant's demonstration of the Reactor Vessel SurveillanceProgram to ensure that the effects of aging will be adequately managed so that intendedfunctions will be maintained consistent with the CLB throughout the period of extendedoperation.Appendix H to 10 CFR Part 50 provides the NRC's requirements for implementing surveillanceprograms required for a plant's reactor vessel beltline materials. The programs are used to 3-116monitor for any changes in fracture toughness properties of a plant's reactor vessel beltlinebase metal and weld materials from neutron irradiation during the plant's service lifetime.Section III.C of Appendix H to 10 CFR Part 50 provides the specific requirements forimplementation of an ISP.The BWRVIP has developed an ISP for the reactor vessel base metal and weld materials in alloperating BWRs. The BWRVIP ISP is in proprietary topical reports BWRVIP-78, "BWR Integrated Surveillance Program (ISP) Plan," and BWRVIP-86, "BWR Vessel and Internals Project:  BWR Integrated Surveillance Program (ISP) Implementation." The NRC approvedthese proprietary reports applying the design and implementation of the ISP by BWRs during their first 40-year operating period in its February 1, 2002, final safety evaluation report to the BWRVIP.The BWRVIP issued proprietary topical report BWRVIP-116, "BWR Vessel and InternalsProject Integrated Surveillance Program (ISP) Implementation for License Renewal," to address ISP changes necessary for LRAs for operating BWRs. This report was approved by the NRC ina letter dated March 1, 2006, from M.A. Mitchell (NRC) to B. Eaton (BWRVIP).The applicant identified the Reactor Vessel Surveillance Program as an existing ISP designedto comply with the requirements for ISPs in Appendix H to 10 CFR Part 50 and to conform with recommended guidelines in GALL AMP XI.M31. The applicant stated that USAR supplement Section A2.1.29 describes the Reactor Vessel Surveillance Program.The applicant stated that it based the Reactor Vessel Surveillance Program on the BWRVIPISP as described and discussed in BWRVIP-78 and BWRVIP-86. The ISP provides for a number of surveillance capsules to be removed from specified BWRs and to be available for testing during the license renewal period for the BWR fleet. The ISP establishes acceptable technical criteria for capsule withdrawal and testing.The staff approved the application of the BWRVIP ISP to the applicant's reactor vessel in theApril 22, 2003, SE, in which the staff concurred that the BWRVIP ISP, as approved inBWRVIP-78 and BWRVIP-86-A (the staff-approved version of BWRVIP-86), met requirements in Appendix H to 10 CFR Part 50 for the RPV.Proprietary topical reports BWRVIP-78 and BWRVIP-86-A, the staff's February 1, 2002,generic final safety evaluation report, and the staff's April 22, 2003, SE provide an acceptable basis for approving the Reactor Vessel Surveillance Program for the current operating period.To address the impacts of license renewal on the program, the applicant will enhance the AMPthrough the period of extended operation.The applicant stated that the BWRVIP ISP has been enhanced to address the impact of licenseextension on the ISP for BWR facilities and that proprietary topical report BWRVIP-116discusses the enhanced program.The BWRVIP submitted BWRVIP-116 to the staff in 2003 to address the impacts of licenseextension on the proposed surveillance capsule withdrawal schedule and to determine whetheradditional ISP capsules will need to be designated for the proposed surveillance capsulewithdrawal schedule.
3-117The staff's review of LRA Section B2.1.29 identified an area for which it needed additionalinformation to complete its evaluation of the applicant's program. The applicant responded to the staff's RAI as discussed below.In RAI B2.1.29-1, dated September 28, 2005, the staff requested that the applicant commit toenhancing the Reactor Vessel Surveillance Program to ensure that any additional requirementsthat result from the staff review of BWRVIP-116 will be addressed before the period ofextended operation.In its response, by letter dated October 28, 2005, the applicant stated that it will enhance theReactor Vessel Surveillance Program to address additional requirements from the staff review before the period of extended operation.In its letter dated March 15, 2006, the applicant provided commitment 42 in Table A.5, whichwill ensure that it will incorporate into the Reactor Vessel Surveillance Program any changes tothe withdrawal schedule requirements for the ISP, as approved in the staff's acceptance ofBWRVIP-116 and found applicable to the reactor vessel, will be incorporated into its R VSP.With this RVSP enhancement included as a commitment for the LRA, the staff found the applicant's response acceptable.Operating Experience. In the Operating Experience program attribute for the Reactor VesselSurveillance Program, the applicant stated that it participates in the BWRVIP ISP to ensure theprogram meets accepted industry practices. The staff has accepted the ISP methodology for monitoring radiation embrittlement at BWRVIP plants as reasonable assurance that the applicant will continue to evaluate aging effects of reactor vessel material loss of fracturetoughness by sampling, analysis, and testing. The staff has confirmed that these topical reports and NRC evaluations apply to the staff's approval of the Reactor Vessel Surveillance Programfor the applicant's CLB. The staff therefore concluded that the applicant's Operating Experienceattribute for the Reactor Vessel Surveillance Program is acceptable.USAR Supplement. In LRA Section A2.1.29, the applicant provided the USAR supplement forthe Reactor Vessel Surveillance Program. The staff reviewed this section and determined that the information in the USAR supplement adequately describes the program, as required by 10 CFR 54.21(d).In its letter dated June 10, 2005, the applicant included the following commitments to USARSection A2.1.29, documented as commitments 42 and 43 in Table A.5:(1)NMC intends to use the ISP for MNGP during the period of extended operation byimplementing the requirements of BWRVIP-116, which the NRC is currently reviewing.(2)NMC will retain the capsules removed from the MNGP reactor vessel as part of theReactor Vessel Surveillance Program.Conclusion. On the basis of its review and audit of the applicant's Reactor Vessel SurveillanceProgram, the staff determined that those program elements for which the applicant claimedconsistency with the GALL Report are consistent with the GALL Report. In addition, the staffreviewed the enhancement and confirmed that its implementation before the period of extendedoperation will result in the existing AMP being consistent with the GALL Report AMP to which it 3-118was credited. The staff concluded that the applicant demonstrated that the effects of aging willbe adequately managed so that intended functions will be maintained consistent with the CLBfor the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.2.22  Selective Leaching of Materials Program Summary of Technical Information in the Application. In LRA Section B2.1.30, the applicantdescribed the Selective Leaching of Materials Program, stating that this new program is consistent, with exception, with GALL AMP XI.M33, "Selective Leaching of Materials." The program includes a one-time visual inspection and hardness measurement of selected components that are susceptible to selective leaching. In situations where hardness testing isnot practical, the applicant will use a qualitative method by other NDE or metallurgical methodsto determine the presence and extent of selective leaching. The program will determine ifselective leaching is occurring for selected components. The applicant will write any requiredinstructions or procedures during development of the program, and may use existing MNGP procedures or work instructions.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's audit evaluation of this AMP. The staff reviewed the exception and the associated justifications todetermine whether the AMP, with the exception, remains adequate to manage the aging effectsfor which it is credited.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part,documents cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.M33.In the LRA, the applicant stated the following exceptions to the program elements listed forAMP XI.M33 in the GALL Report.Exceptions 1 and 2:  The GALL Report recommends the following for the Detection of AgingEffects program element associated with the exceptions taken:The one-time visual inspection and hardness measurement includes closeexamination of a select set of components to determine whether selective leaching has occurred and whether the resulting loss of strength and/or material will affect the intended functions of these components during the period ofextended operation. Selective leaching generally does not cause changes in dimensions and is difficult to detect. However, in certain brasses it causes plug-type dezincification, which can be detected by visual inspection. One acceptable procedure is to visually inspect the susceptible components closely and conduct Brinell Hardness testing on the inside surfaces of the selected set of components to determine if selective leaching has occurred. If it is occurring, an engineering evaluation is initiated to determine acceptability of the affectedcomponents for further service.
3-119In the LRA, the applicant stated that the first exception is that the program may use hardnesstesting, other than Brinell hardness testing, to detect selective leaching of material. In the second exception, the applicant stated that it will use qualitative methods in lieu of hardnesstesting to detect selective leaching where hardness testing is not practical.The staff discussed these exceptions with the applicant's technical personnel. With regard toException 1, the staff concurred that Brinell hardness testing is one of several methodologiesthat are currently being used and is only a GALL Report recommendation. The staff found the applicant's position acceptable. With regard to Exception 2, the staff asked that the applicantclarify the use of qualitative methods versus hardness testing.In its letter dated August 11, 2005, the applicant stated that the methods used to detectselective leaching include visual inspection in conjunction with mechanistic techniques like scratch testing, hardness testing, or NDEs. The staff found the applicant's position acceptable because the applicant is using qualitative mechanistic techniques in addition to visual inspection, as recommended by the GALL Report.The staff reviewed those portions of AMP B2.1.30, "Selective Leaching of Materials Program,"that the applicant claimed are consistent with GALL AMP XI.M33 and found them consistent.The staff found the applicant's AMP acceptable because it conforms to the recommended GALL Report AMP with the exceptions as described above.Operating Experience. In LRA Section B2.1.30, that applicant stated that the SelectiveLeaching of Materials Program is a new program with no operating experience.During the audit and review, the staff asked the applicant how it captures operating experience.The applicant indicated that the CAP identifies, tracks, and trends site operating experiencerelated to all site components. The site CAP database documents any site components identified as degraded, as failed, or as potentially unable to fulfill intended functions. Plantengineering staff then evaluate these CAPs for the extent of the condition and take appropriatefollowup actions. Plant engineering staff also trend related CAP data to identify generic issues.
They address trended site issues in program health reports presented to site management on a scheduled basis. The CAP also addresses 10 CFR 54.21 issues and external operating events from the NRC, INPO, LIS, and the applicant's fleet. The staff reviewed the applicant's responseand found it acceptable.A review of CRs for leaching identified a possible selective leaching issue, a higher than normallead content in the number 12 EDG lube oil. A document review indicated that INPOSOER 80-04 recommends that if lead soldered joint coolers are installed, there should be inspections for exfoliation-type solder corrosion. A work history review determined that the number 11 EDG lube oil cooler had been replaced with the rolled tube design in 1991, but that the number 12 EDG lube oil cooler st ill had its original cooler. The applicant replaced thenumber 12 EDG lube oil cooler during the 2003 refueling outage with a rolled tube design.The staff recognized that the CAP captures, evaluates, and incorporates internal and externalplant operating experience for objective evidence of adequate management of aging effects.USAR Supplement. In LRA Section A2.1.30, the applicant provided the USAR supplement forthe Selective Leaching of Materials Program. The staff reviewed this section and determined 3-120that the information in the USAR supplement adequately describes the program, as required by10 CFR 54.21(d).In its letter dated June 10, 2005, the applicant included the commitment to USARSection A2.1.30, documented as commitment 44 in Table A.5, that before the period ofextended operation, it will implement the Selective Leaching of Materials Program as a newprogram consistent, with exceptions, to the recommendations of GALL AMP XI.M33.Conclusion. On the basis of its review and audit of the applicant's Selective Leaching ofMaterials Program, the staff determined that those program elements for which the applicantclaimed consistency with the GALL Report are consistent with the GALL Report. In addition, thestaff reviewed the exception and the associated justifications and determined that the AMP,with the exception, is adequate to manage the aging effects for which it is credited. The staffconcluded that the applicant demonstrated that the effects of aging will be adequately managedso that intended functions will be maintained consistent with the CLB for the period of extendedoperation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.2.23  Structures Monitoring Program Summary of Technical Information in the Application. In LRA Section B2.1.31, the applicantdescribed the Structures Monitoring Program, stating that this existing program is consistent,with enhancements, with GALL AMP XI.S6, "Structures Monitoring Program." The Structures Monitoring Program is based on the guidance provided in RG 1.160, Revision 2, "Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," issued March 1997, and NUMARC 93-01, Revision 2, "Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," issued April 1996. The applicant implements the Structures Monitoring Program as part of the structures monitoring done under the MNGP Maintenance Rule program and with additional inspections of the intake structure and diesel fuel oil transfer house. The Structures Monitoring Program also implements GALL AMP XI.S5, "Masonry Wall Program."  Masonry block wall inspections are performed as part of the Maintenance Rule inspections and are based on Inspection and Enforcement Bulletin 80-11 with administrative controls in accordance with IN 87-67, "Lessons Learned from Regional Inspections of Licensee Actions in Response to IE Bulletin 80-11," dated December 21, 1987.
As permitted by GALL AMP XI.S7, "RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants," the Structures Monitoring Program includes the inspection of water control structures. The only water control structure in scope for license renewal is the intake structure. Maintenance Rule inspections are performed on the portions of the intake structure above the water line. The Structures Monitoring Program includes separate inspections of the underwater portions of the intake structure. In addition, special settlement checks of the diesel fuel oil transfer house are performed outside the Maintenance Ruleinspections. The Structures Monitoring Program does not rely upon protective coatings to manage the effects of aging.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's audit evaluation of this AMP. The staff reviewed the enhancements and the associated justifications 3-121to determine whether the AMP, with the enhancements, remains adequate to manage the agingeffects for which it is credited.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.S6.In the LRA, the applicant stated that it will implement the following enhancements to make thisAMP consistent with the recommendations in the GALL Report.Enhancement 1:  The GALL Report recommends the following for the Scope of Programprogram element for GALL AMPs XI.S5 and XI.S7 associated with the enhancement made:The scope includes all masonry walls identified as performing functions inaccordance with 10 CFR 54.4.RG 1.127 applies to water-control structures associated with emergency coolingwater systems or flood protection of nuclear power plants.The applicant indicated that it is not committed to RG 1.127, Revision 1, "Inspection of Water-Control Structures Associated with Nuclear Power Plants," March 1978. The StructuresMonitoring Program includes inspections of water control structures as recommended by the GALL Report.In the LRA, the applicant stated that it will expand the Structures Monitoring Program, asnecessary, to include inspections of structures and structural elements within the scope of license renewal not inspected as part of another AMP.According to AMP B2.1.31, "Structures Monitoring Program," the program includes masonryblock walls and water control structures within the scope of license renewal. The Scope of Program program element lists water control structures, which include the access tunnel and diesel fire pump house.On the basis of its review of Structures Monitoring Program operating experience and based onsatisfying the GALL Report recommendations as discussed above, the staff found this enhancement acceptable as such changes to the applicant's program provide assurance that the effects of aging will be adequately managed.Enhancement 2:  The GALL Report recommends the following for the Scope of Programprogram element for GALL AMP XI.S7 associated with the enhancement made:The water-control structures included in the RG 1.127 program are concretestructures; embankment structures; spillway structures and outlet works;reservoirs; cooling water channels and canals, and intake and discharge structures; and safety and performance instrumentation.In the LRA, the applicant stated that it will enhance implementing procedures for the StructuresMonitoring Program to ensure that structural inspections are performed on submerged portions of the intake structure from the service water bays to the wing walls.
3-122The applicant stated, in the LRA, that the Structures Monitoring Program includes separateinspections of the underwater portions of the intake structure and that under the Scope of Program element, the program also provides inspection requirements to manage aging effects described in the Parameters Monitored or Inspected element. As documented in the audit and review report, the applicant's structural inspections of the service water bays will include moredetailed inspection criteria. In addition, the frequency of the applicant's structural inspections of the submerged portions of the intake structure will meet or exceed that required by AmericanConcrete Institute (ACI) 349.3R-96, "Evaluation of Existing Nuclear Safety Related Concrete Structures."On the basis of its review of Structures Management Program operating experience and basedon satisfying the GALL Report recommendations as discussed above, the staff found this enhancement acceptable as such changes to the applicant's program provide assurance that the effects of aging will be adequately managed.Enhancement 3:  The GALL Report recommends the following for the Parameters Monitored orInspected program element associated with the enhancement made:...ACI 349.3R-96 and ANSI/ASCE 11-90 provide an acceptable basis forselection of parameters to be monitored or inspected for concrete or steel structural elements...In the LRA, the applicant stated that it will enhance existing implementing procedures for theStructures Monitoring Program to include monitoring/inspection parameters for structural components within the scope of license renewal.The staff reviewed the Structures Monitoring Program PBD, which incorporates intakestructures and masonry walls, and found it to be in general agreement with the above recommendations.On the basis of its review of Structures Management Program operating experience and basedon satisfying the GALL Report recommendations as discussed above, the staff found this enhancement acceptable as such changes to the applicant's program provide assurance that the effects of aging will be adequately managed.Enhancements 4 and 5:  The GALL Report recommends the following for the ParametersMonitored or Inspected program element associated with the enhancement made:Parameters monitored or inspected are to be commensurate with industry codes,standards and guidelines, and are to also consider industry and plant-specific operating experience.In the LRA, the applicant stated that it will enhance the Structures Monitoring Program tosample ground water for pH, chloride concentration, and sulfate concentration.The applicant stated, in the LRA, that to ensure that the soil environment remainsnonaggressive, it will enhance the Structures Monitoring Program to include periodicground-water sampling for pH, chloride concentration, and sulfate concentration. The PBD 3-123reiterates this statement, providing the limiting values of pH greater than 5.5, chlorides greaterthan 500 ppm, and sulfates greater than 1500 ppm for a nonaggressive environment.On the basis of its review of Structures Management Program operating experience and basedon satisfying the GALL Report recommendations as discussed above, the staff found this enhancement acceptable as such changes to the applicant's program provide assurance that the effects of aging will be adequately managed.In the LRA, the applicant stated that it will enhance the Structures Monitoring Program toinclude concrete evaluations of inaccessible areas if degradation of accessible areas is detected to ensure the soundness of the buried concrete. The PBD reiterates this statement.On the basis of its review of the Structures Management Program operating experience andbased on satisfying the GALL Report recommendations as discussed above, the staff found this enhancement acceptable as such changes to the applicant's program provide assurance that the effects of aging will be adequately managed.Enhancement 6:  The GALL Report recommends the following for the Acceptance Criteriaprogram element of GALL AMP XI.S7 associated with the enhancement made:"Evaluation Criteria" provided in Chapter 5 of ACI 349.3R-96 providesacceptance criteria (including quantitative criteria) for determining the adequacy of observed aging effects and specifies criteria for further evaluation. Although not required, plant-specific acceptance criteria based on Chapter 5 of ACI 349.3R-96 are acceptable.In the LRA, the applicant stated that it will enhance the implementing procedures for theStructures Monitoring Program to include acceptance criteria for structural inspections of submerged portions of the intake structure.The applicant's technical personnel stated that for structural components of the intake structurein a raw water/river water environment, acceptance criteria will be based on relevant industrycodes and standards. ACI 349.3R-96 will guide evaluation of concrete degradation.On the basis of its review of Structures Monitoring Program operating experience and based onsatisfying the GALL Report recommendations as discussed above, the staff found this enhancement acceptable as such changes to the applicant's program provide assurance that the effects of aging will be adequately managed.The staff reviewed those portions of AMP B2.1.31, "Structures Monitoring Program," that theapplicant claimed are consistent with GALL AMP XI.S6 and found them consistent. The staff found the applicant's AMP acceptable because it conforms to the recommended GALL Report AMP with the enhancements as described above.Operating Experience. In LRA Section B2.1.31, the applicant stated that the StructuresMonitoring Program, including the Masonry Block Wall Program and RG 1.127 and implemented through the Maintenance Rule and other procedures, has detected aging effectsof structural components and has ensured that repairs were made in a timely manner before the loss of intended function. The program also evaluates external operating experience for 3-124impact on structures and structural inspections through administrative procedures and thecorrective action process.The two most recent inspections, performed in 1998 and 2001/2002, noted several deficiencies.The 1998 inspection noted 21 deficiencies and the 2001/2002 inspection noted 30 deficiencies.
However, not all of these deficiencies were directly attributed to an aging effect. The aging effects detected during the structural inspections were concrete spalling, cracking, surface deterioration and flaking, grout deterioration, corroded rebar or other steel components, andcracked welds. Applicant personnel created WOs and/or corrective actions to repair the deficiencies. Several deficiencies were evaluated and determined to be acceptable as-is and subjected to further inspections.The staff reviewed the operating experience provided in the LRA and interviewed theapplicant's technical personnel to confirm that plant-specific operating experience revealed no degradation not bounded by industry experience.On the basis of its review of the above industry and plant-specific operating experience anddiscussions with the applicant's technical personnel, the staff concluded that the applicant'sStructures Monitoring Program will adequately manage the aging effects identified in the LRAfor which this AMP is credited.USAR Supplement. In LRA Section A2.1.31, the applicant provided the USAR supplement forthe Structures Monitoring Program. The staff reviewed this section and determined that the information in the USAR supplement adequately describes the program, as required by 10 CFR 54.21(d).By letter dated June 10, 2005, the applicant included the following commitments to USARSection A2.1.31 that it will perform before the period of extended operation:  (1)The program will be expanded, as necessary, to include inspections ofstructures and structural elements in scope for License Renewal that are not inspected as part of another aging management program.  (2)Implementing procedures will be enhanced to ensure that structuralinspections are performed on submerged portions of the Intake Structure from the service water bays to the wing walls.  (3)Implementing procedures will be revised to incl ude themonitoring/inspection parameters for structural components within the scope of License Renewal.  (4)The program will be enhanced to include a requirement to sample groundwater for pH, chloride concentration and sulfate concentration.  (5)The program will be enhanced to include concrete evaluations ofinaccessible areas if degradation of accessible areas is detected.  (6)Implementing procedures will be enhanced to include acceptance criteriafor structural inspections of submerged portions of the Intake Structure.
3-125Conclusion. On the basis of its review and audit of the applicant's Structures MonitoringProgram, the staff determined that those program elements for which the applicant claimedconsistency with the GALL Report are consistent with the GALL Report. In addition, the staffreviewed the enhancements and confirmed that their implementation before the period ofextended operation will result in the existing AMP being consistent with the GALL Report AMPto which it was credited. The staff concluded that the applicant demonstrated that the effects ofaging will be adequately managed so that intended functions will be maintained consistent withthe CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff alsoreviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.2.24  Metal Fatigue of the Reactor Coolant Pressure Boundary Program Summary of Technical Information in the Application. In LRA Section B3.2, the applicantdescribed the Metal Fatigue of the Reactor Coolant Pressure Boundary Program, stating that this existing program is consistent, with enhancement, with GALL AMP X.M1, "Metal Fatigue of Reactor Coolant Pressure Boundary." The Metal Fatigue of the Reactor Coolant Pressure Boundary Program is part of the Thermal Fatigue Monitoring Program (FMP). The MNGP Thermal FMP provides for the periodic review of plant transients for impact on selected components. In addition, environmental effects have been evaluated in accordance with NUREG/CR-6260, "Application of NUREG/CR-5999 Interim Fatigue Curves for SelectedNuclear Power Plant Components." Selected components were evaluated using material specific guidance presented in NUREG/CR-6583, "Effects of LWR Coolant Environments onFatigue Design Curves of Carbon and Low-Alloy Steels," issued February 1998, for carbon and low alloy steels and in NUREG/CR-5704, "Effects of LWR Coolant Environments on FatigueDesign Curves of Austenitic Stainless Steels," issued April 1999. The MNGP program ensures that limiting components remain within the acceptance criteria for cumulative fatigue usage throughout the licensed term and, if trends indicate otherwise, appropriate corrective action can be implemented.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's audit evaluation of this AMP. The staff reviewed the enhancement and the associated justifications todetermine whether the AMP, with the enhancement, remains adequate to manage the agingeffects for which it is credited.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP X.M1.In the LRA, the applicant stated that it will implement the following enhancement to make thisAMP consistent with the recommendation in the GALL Report.Enhancement:  The GALL Report recommends the following for the Scope of Program programelement associated with the enhancement made:The program includes preventive measures to mitigate fatigue cracking of metalcomponents of the reactor coolant pressure boundary caused by anticipated cyclic strains in the material.
3-126In the LRA, the applicant stated that it will incorporate requirements for inclusion ofNUREG/CR-6260 locations in implementing procedures for the Thermal FMP.During the audit and review, the staff noted that this enhancement also affects the Monitoringand Trending program element as described in GALL AMP X.M1.The GALL Report recommends the following for the Monitoring and Trending program element:The program monitors a sample of high fatigue usage locations. As a minimum,this sample is to include the locations identified in NUREG/CR-6260.The staff found the applicant's enhancement to the Metal Fatigue of the Reactor CoolantPressure Boundary Program (to include all NUREG/CR-6260 locations in implementingprocedures for the Thermal FMP necessary for consistency with the GALL Report AMP description and acceptable.During the audit and review, the staff asked whether the applicant has plant-specific locationswhere fatigue cumulative usage factors (CUFs) are projected to be higher than the values projected for NUREG/CR-6260 locations. In response, the applicant stated that the LRAidentified other areas as acceptable in accordance with 10 CFR 54.21(c)(1)(iii) projected tohave cumulative fatigue usage values higher than those for NUREG/CR-6260 locations. Theapplicant stated that it will revise its FMP to include these locations as well as theNUREG/CR-6260 locations. The applicant stated that it updates fatigue evaluations conductedin accordance with this program once per cycle and projects them to a 60-year end of life (EOL)and that it will take appropriate corrective actions for any locations projected to exceed the codeacceptance criteria for fatigue before its occurrence.The staff reviewed the applicant's response together with the pertinent section of the LRA.Because the applicant's Thermal Fatigue Management Program includes most limiting locations and all of the applicable NUREG/CR-6260 locations, the staff found the applicant's responseacceptable.For the "Acceptance Criteria" program element, the applicant indicated that an alternativeapproach will be taken if the fatigue usage limit for the monitored components can not bedemonstrated to remain less than 1.0. In accordance with GALL program X.M1, acceptable corrective actions include a more rigorous analysis of the component to demonstrate that the design code limit will not be exceeded, repair, or replacement of the component. The applicantindicated that an alternative approach would be to show that potential cracking is maintainedbelow the criteria of ASME Section XI, Appendix L, or an approved NRC limit. The staff has notendorsed an alternative approach which relies on inspection in lieu of meeting the ASME Code fatigue limit of 1.0. The staff notes that, if this alternative option is selected, the inspectiondetails, including scope, qualification, method, and frequency must be provided to the NRC forreview and approval prior to the period of extended operation. An aging management program under this option would be a departure from the design basis CUF evaluation, described in the USAR supplement, and therefore, would require a license amendment pursuant to 10 CFR
 
50.59.
3-127The staff reviewed those portions of AMP B3.2, "Metal Fatigue of the Reactor Coolant PressureBoundary Program," that the applicant claimed are consistent with GALL AMP X.M1 and foundthem consistent. The staff found the applicant's AMP acceptable because it conforms to the recommended GALL Report AMP with the enhancement as described above.Operating Experience. In LRA Section B3.2, the applicant explained that the MNGP technicalstaff monitors industry operating experience through peer groups, industry information (e.g.,
INs, licensee event reports, SILs), and by communications with other plant's subject matter experts. The staff evaluates information from these sources for impact on the Metal Fatigue of the Reactor Coolant Pressure Boundary Program. In addition, the MNGP technical staff updates internal operating experience to account for operating cycles and their effect on fatigueof limiting components on a frequency of at least once per refueling cycle. This ensures theadequacy of the program in terms of providing a periodic means of evaluating fatigue margins and establishing corrective action plans as necessary. For example, in May 1999, MNGP experienced several transients as indicated by FW and RWCU flow data. Subsequent review concluded that these transients could have an impact on FW nozzle fatigue usage and that theydid not conform to the transient descriptions that will normally be considered in the Thermal FMP. An evaluation of these transients found that the effect on fatigue was not significant(0.003 addition). However, the applicant incorporated the results into the Thermal FMP which is updated at least once every refueling cycle. The MNGP CAP database documents thisoperating experience.The staff reviewed the operating experience provided in the LRA and interviewed theapplicant's technical personnel to confirm that plant-specific operating experience revealed no degradation not bounded by industry experience.On the basis of its evaluation of the applicant's program against the program elementsdescribed in the GALL Report AMP, its review of the above industry and plant-specific operating experience, and its discussions with the applicant's technical personnel, the staff concluded that the applicant's Metal Fatigue of the Reactor Coolant Pressure Boundary Program willadequately manage the aging effects identified in LRA for which this AMP is credited.USAR Supplement. In LRA Section A4.2, the applicant provided the USAR supplement for theMetal Fatigue of the Reactor Coolant Pressure Boundary Program. The staff reviewed this section and determined that the information in the USAR supplement adequately describes theprogram, as required by 10 CFR 54.21(d).By letter dated June 10, 2005, the applicant included commitment 52, that before the period ofextended operation, it will incorporate requirements for inclusion of NUREG/CR-6260 locationsin implementing procedures for the Thermal Fatigue Monitoring Program; however, USAR supplement Section A4.2 did not capture this commitment. The applicant stated that it willupdate the USAR supplement to include the commitment in the annual LRA update letter. In itsletter dated February 28, 2005, the applicant provided a revision to USAR supplement Section A4.2, which included the commitment.Conclusion. On the basis of its review and audit of the applicant's Metal Fatigue of the ReactorCoolant Pressure Boundary Program, the staff determined that those program elements forwhich the applicant claimed consistency with the GALL Report are consistent with the GALLReport. In addition, the staff reviewed the enhancement and confirmed that its implementation 3-128before the period of extended operation will result in the existing AMP being consistent with theGALL Report AMP to which it was credited. The staff concluded that the applicant demonstrated that the effects of aging will be adequately managed so that intended functionswill be maintained consistent with the CLB for the period of extended operation, as required by10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.3  AMPs That Are Not Consistent with or Not Addressed in the GALL Report In LRA Appendix B, the applicant identified the following plant-specific AMPs:
* Bus Duct Inspection Program (B2.1.6)
* System Condition Monitoring Program (B2.1.32)For AMPs that are not consistent with or not addressed by the GALL Report, the staffperformed a complete review of the AMPs to determine if they are adequate to manage aging.
The following sections of this SER document the staff's review of these plant-specific AMPs.3.0.3.3.1  Bus Duct Inspection Program Summary of Technical Information in the Application. In LRA Section B2.1.6, the applicantdescribed the Bus Duct Inspection Program, stating that this new program will be consistentwith the applicable 10 elements described in SRP-LR Appendix A. In the LRA, the applicantstated that the primary purpose of this new, plant-specific program is to demonstrate that agingeffects will be adequately managed so that nonsegregated bus ducts within the scope oflicense renewal will perform their intended function in accordance with the CLB during theperiod of extended operation. The intended function of nonsegregated bus ducts is to provide electrical connections to specified sections of an electrical circuit to deliver voltage, current, or signals.Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the informationincluded in LRA Section B2.1.6 regarding the applicant's demonstration of the Bus Duct Inspection Program to ensure that the effects of aging, as discussed above, will be adequatelymanaged so that intended functions will be maintained consistent with the CLB for the period ofextended operation.The applicant credited the Bus Duct Inspection Program with aging management of thenonsegregated phase bus. The applicant stated that the Bus Duct Inspection Program is a new plant-specific program. Its purpose is to demonstrate that the aging effects caused by ingress of moisture or contaminants (dust and debris), insulation degradation from heat or radiation in the presence of oxygen, and bolt relaxation from thermal cycling will be adequately managed sothat the nonsegregated bus ducts subject to an AMR will perform their intended function inaccordance with the CLB during the period of extended operation.To determine whether the applicant's AMP is adequate to manage the effects of aging so thatintended functions will be maintained consistent with the CLB for the period of extendedoperation, the staff evaluated the (1) scope of program, (2) preventive actions, (3) parametersmonitored or inspected, (4) detection of aging effects, (5) monitoring and trending, (6) acceptance criteria, and (7) operating experience. SER Section 3.0.4 provides the staff's 3-129evaluation of the applicant's corrective actions, confirmation process, and administrativecontrols.(1) Scope of Program-This program applies to all bus ducts within the scope of licenserenewal. The program manages the aging effects for components in the offsite power/station blackout (SBO) recovery path commodity group. The staff reviewed the specific components that the program identified.The staff confirmed that the Scope of Program element satisfies the SRP-LR A.1.2.3 criterion.The program includes all bus ducts within the scope of license renewal. On this basis, the staff found the applicant's program scope acceptable.(2) Preventive Actions-The Bus Duct Inspection Program monitors conditions. The programdoes not include any actions to prevent or mitigate aging degradation, and the staff identified noneed for such actions.The staff confirmed that the Preventive Actions element satisfies the SRP-LR A.1.2.3 criterion.The staff identified no need for preventive actions for this AMP as a condition monitoring program. On this basis, the staff found the applicant's Preventive Actions program element acceptable.(3) Parameters Monitored or Inspected-The applicant stated that this program will check asample of accessible bolted connections (bus joints and ending devices) for proper torque, or the resistance of bolted joints for resistance with a micro-ohmmeter of sufficient current capacity for checking bus bar connections. This program will also inspect internal portions ofaccessible bus ducts for cracks, corrosion, foreign debris, dust buildup, and moisture intrusion.The applicant will inspect the bus insulating system for signs of embrittlement, cracking, melting, swelling, or discoloration that may indicate overheating or aging degradation. It willinspect the bus supports for structural integrity and cracking.The staff confirmed that the Parameters Monitored or Inspected element satisfies theSRP-LR A.1.2.3 criteria and is capable of detecting the presence and extent of aging effects.On this basis, the staff found the applicant's Parameters Monitored or Inspected program element acceptable.(4) Detection of Aging Effects-The applicant stated that this program visually inspects internalportions of bus ducts, the bus insulating system, and the bus supports. In addition, a torque testor resistance test of a sample of accessible bolted connections will be performed. The applicantwill complete the program before the end of the initial 40-year license term and every 10 yearsthereafter, a period adequate for preventing failures of the bus ducts as experience shows that aging degradation is a slow process. A 10-year inspection frequency provides two data points during a 20-year period to characterize the degradation rate.In RAI B2.1.6-1, dated November 7, 2005, the staff noted that vendors do not recommend there-torque of bolted connections unless the joint requires service or the bolted connections are clearly loose. The torque required to turn the fastener in the tightening direction (restart torque) is not a good indication of the preload after the fastener is in service. Because of relaxation of parts of the joint, the final loads are likely to be lower than the installed loads; therefore, the 3-130staff requested that the applicant justify that re-torquing of bolted connections is a goodindicator of the preload after the fastener is in service.In its response dated December 7, 2005, the applicant stated that it will follow the guidance ofEPRI TR-104213, Section 8.2, "Inspection of Electrical Bolted Joints," which does not recommend re-torquing of bolted connections. It will check a sample of accessible boltedconnections loose connections by thermography or by connection resistance measurement with a low-range ohmmeter. Metal enclosed bus (MEB) internal surfaces will be visually inspectedfor aging degradation of insulating material, foreign debris and excessive dust buildup, and evidence of moisture intrusion. Bus insulation will be visually inspected for signs ofembrittlement, cracking, melting, swelling, or discoloration that may indicate overheating or aging degradation. Internal bus supports will be visually inspected for structural integrity andcracks. The applicant will complete this program before the period of extended operation andevery 10 years thereafter if visual inspection is not used to check bolted connections. A 10-year inspection interval will provide two data points during a 20-year period to characterize the degradation rate. This inspection frequency is adequate to prevent failures of the MEBs, as experience shows that aging degradation is a slow process.The applicant will use visual inspection as an alternative to thermography or connectionresistance measurement for accessible bolted connections covered with heat-shrink tape, sleeving, insulating boots, and other materials. Visual inspection of the insulation material willdetect surface anomalies, such as discoloration, cracking, chipping, or surface contamination.
When this alternative visual inspection is used to check bolted connections, the first inspection will be completed before the period of extended operation and every 5 years thereafter.Based on its review, the staff found that the visual inspection of bus ducts and internal bussupports will indicate aging effects and that thermography or resi stance checks of a sample ofbolted joints will ensure that bolted connections do not loosen from ohmic heating. The staffalso found that the 10-year inspection frequency is adequate to prevent failures of bus ducts as industry experience shows that the aging degradation is a slow process. Therefore, the staff'sconcern described in RAI B2.1.6-1 is resolved.The staff confirmed that the Detection of Aging Effects element satisfies SRP-LRSection A.1.2.3 criteria and is capable of detecting the presence and extent of aging effects. Onthis basis, the staff found the applicant's proposed Detection of Aging Effects program element acceptable.(5) Monitoring and Trending-The applicant stated that this program does not include trendingactions because the ability to trend inspection results is limited. The staff found this acceptablebecause trending will be performed under a controlled administrative process.The staff confirmed that the Monitoring and Trending element satisfies SRP-LR Section A.1.2.3criteria, as it takes into consideration plant-specific and industry operating experience. On this basis, the staff found the applicant's proposed Monitoring and Trending program element acceptable.(6) Acceptance Criteria-The applicant stated that in this program, bolted connections mustmeet the manufacturer's minimum torque specifications or the resistance of bolted joints must meet required specifications. Bus ducts must be free from any surface anomalies that suggest 3-131conductor insulation degradation exists. An additional acceptance criterion requires noindication of unacceptable corrosion, cracking, foreign debris, dust buildup, or moisture intrusion. Any condition or situation that, if not corrected, could lead to a loss of intendedfunction is considered unacceptable.As discussed above, the staff expressed concern about re-torquing of the bolted connections.The applicant stated that it will revise its acceptance criteria to remove reference to checking the torque of bolted connections, and to use thermography or resist ance checks of a sample ofbolted joints for reasonable assurance that bolted connections do not loosen from ohmic heating. In its letter dated February 28, 2006, the applicant revised the acceptance criteria toremove reference to checking bolt torque, which resolved the staff's concern.The staff confirmed that the Acceptance Criteria element satisfies SRP-LR A.1.2.3 criteria. TheAcceptance Criteria element provides a basis for evaluation of the need for corrective actions to ensure that the bus duct intended function will be maintained during the period of extendedoperation. On this basis, the staff found the applicant's Acceptance Criteria program elementacceptable.After reviewing the Corrective Actions program element, the staff identified an area for which itneeded additional information to complete its evaluation of the applicant's Bus Duct Inspection Program. In RAI B2.1.6-2, dated November 7, 2005, the staff noted that, with regard to this element, the applicant had stated that requirements of Appendix B, "Quality Assurance Criteriafor Nuclear Power Plants and Fuel Processing Plants," to 10 CFR Part 50 apply; however, it is the staff's position that the Corrective Actions element should provide for further investigation and evaluation when acceptance criteria are not met. Corrective actions may include but are not limited to cleaning, drying, increased inspection frequency, repair, or replacement of the affected metal enclosed bus components. If an unacceptable condition or situation is identified, a determination is made as to whether the same condition or situation applies to otheraccessible or inaccessible metal enclosed bus. Therefore, the staff requested that the applicantrevise the corrective actions in LRA Section B2.1.6 to add specific requirements or justify why corrective actions are not necessary.In its response, by letter dated December 7, 2005, the applicant stated that it will add thefollowing statement to the Corrective Actions element:Further investigation and evaluation are performed when the acceptance criteriaare not met. Corrective actions may include, but are not limited to, cleaning, drying, increased inspection frequency, replacement, or repair of the affected metal enclosed bus components. If an unacceptable condition or situation is identified, a determination is made as to whether the same condition or situationis applicable to other accessible or inaccessible metal enclosed bus.Based on its review, the staff found the applicant's response to RAI B2.1.6-2 acceptable;therefore, the staff's concern described in RAI B2.1.6-2 is resolved.The staff confirmed that the Corrective Actions element satisfies the SRP-LR A.1.2.3 criteria.The Corrective Actions element describes actions to be taken when the acceptance criteria are not met to ensure that the bus duct intended function will be maintained during the period of 3-132extended operation. On this basis, the staff found the applicant's Corrective Actions programelement acceptable.Operating Experience. In LRA Section B2.1.6, the applicant explained that the Bus DuctInspection Program is a new program and no site operating experience exists. Industry operating experience has demonstrated that the failures of bus ducts are caused by cracked insulation of the bus combined with moisture or debris buildup internal to the bus ducts. It has also been shown that bus duct internals exposed to appreciable ohmic heating during operation may experience loosening of bolted connections related to repeated cycling of connected loads.The staff found that the proposed program will ensure that bus ducts are not exposed toexcessive ohmic or ambient heating.USAR Supplement. In LRA Section A2.1.6, the applicant provided the USAR supplement forthe Bus Duct Inspection Program. The staff reviewed this section and determined that the information in the USAR supplement adequately describes the program, as required by 10 CFR 54.21(d).In its letter dated June 10, 2005, the applicant added a commitment to USAR Section A2.1.6,documented as commitment 17 in Table A.5, which states that before the period of extendedoperation, the applicant will implement the Bus Duct Inspection Program consistent with theappropriate 10 elements described in Appendix A to the SRP-LR.Conclusion. On the basis of its review and audit of the applicant's Bus Duct InspectionProgram, the staff concluded that the applicant demonstrated that the effects of aging will beadequately managed so that intended functions will be maintained consistent with the CLB forthe period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.3.2  System Condition Monitoring Program Summary of Technical Information in the Application. In LRA Section B.2.1.32, the applicantdescribed its System Condition Monitoring Program". The applicant stated that this existing plant-specific MNGP program with enhancements, will be consistent with the applicable 10elements described in SRP-LR Appendix A.The applicant stated that the System Condition Monitoring Program is an existing plant-specificprogram that is based on system engineer monitoring. Although MNGP performs manymonitoring activities, this AMP brings aging management into the scope of the monitoring activities. Other groups augment this program by identifying and reporting adverse material conditions via the corrective action process or work control process. This monitoring consists of system-level performance monitoring, inspections and walkdowns, health and status reporting,and PM.The applicant will enhance this program to include specific activities and criteria for managingage-related degradation for SSCs within the scope of license renewal. This program manages aging effects for normally accessible external surfaces of piping, tanks, hangers and supports, racks, panels, and other components and equipment within the scope of license renewal. These 3-133aging effects are managed through visual inspection and monitoring of external surfaces forleakage and evidence of material degradation.Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the informationincluded in LRA Section B2.1.32 to demonstrate that the System Condition Monitoring Program will ensure that the effects of aging will be adequately managed so that the intended functionwill be maintained consistent with the CLB throughout the period of extended operation.The staff reviewed the System Condition Monitoring Program against the AMP elements foundin the GALL Report, SRP-LR Section A.1.2.3, and SRP-LR Table A.1-1, and focused on theprogram's management of aging effects through the effective incorporation of the 10 program elements. The applicant indicated that the site-controlled Quality Assurance Program includesthe corrective actions, confirmation process, and administrative controls. SER Section 3.0.4 discusses the staff's evaluation of the Quality Assurance Program.(1) Scope of Program-The applicant stated that the System Condition Monitoring Programvisually inspects and monitors the accessible external surfaces of systems and componentswithin the scope of license renewal for signs of excessive and/or abnormal aging effects and material degradation. The System Condition Monitoring Program consists of activities that manage the aging effects for components of various mechanical and civil/structure systems,including alternate nitrogen supply, automatic pressure relief, chemistry sampling, circulating water (CWT), combustible gas control (CGC), condensate and FW, condensate storage, CRD,CSP, demineralized water, EDGs, emergency filtration train, ESW, FIR, fuel pool cooling and cleanup (FPC), hangers and supports, HTV, HPCI, AIR, main condenser (MC), MST, primary containment mechanical, radwaste solid and liquid, reactor building, RBC, reactor core isolation cooling (RCIC), reactor head vent, REC, reactor vessel instrumentation, RWCU, RHR,secondary containment, service and seal water, SLC, turbine generator, and wells and domestic water.The staff's review of LRA Section B2.1.32 identified areas for which it needed additionalinformation to complete its evaluation of the applicant's program elements. The applicant responded to the staff's RAIs as discussed below.In RAI B2.1.32-1, dated July 20, 2005, the staff requested that the applicant list anyinaccessible surfaces of components (including lagged/insulated piping <212 F) to bemanaged by this program and discuss the bases for determining that the inaccessible surfaces will be adequately managed.In its response, by letter dated August 16, 2005, the applicant stated the following:The System Condition Monitoring Program manages aging effects through visualinspection and monitoring of SSCs that are accessible during normal operation, during refueling outages, or as part of planned maintenance.Accessible areas are those areas that are available for inspection and monitoringduring routine operations or that become accessible for inspection and monitoring during refueling or maintenance activities. Insulated piping can be made accessible, as needed, for inspection and monitoring for the presence of age related degradation of SSCs within the scope of license renewal. For 3-134example, insulated piping at operating temperatures >212 degrees F cannormally be evaluated for aging effects based on the inspection of uninsulated piping of the same materials in the same environment. Because of this temperature, a wetted environment is not expected. For insulated pipingoperating <212 degrees F (e.g., HVAC cooling loops), inspections will includeremoval of insulation where it is determined that inspections of uninsulated portions cannot be extrapolated for managing relevant aging effects.Visual inspections will be performed of observable indicators that detectage-related degradation. Examples of observable indicators are crack-like indications, corrosion, erosion, leakage, presence of moisture (condensation), or physical displacement.Inaccessible areas are those areas that have no access due to facilityconstruction (i.e., require a plant modification to access) or that present a significant health, safety, and/or radiological hazard. SSCs that require aging management that are inaccessible will be evaluated for the impact of agingbased on comparable accessible locations. This evaluation will be performed on accessible SSCs on the basis of same material(s) and the same or more severe environment(s) as those portions that are considered inaccessible.If an unacceptable condition or situation is identified in an accessible portion of asystem, an extent of condition evaluation will be performed to determine whetherthe same condition or situation is applicable to other accessible or inaccessible portions of t he system. Appropriate follow-up inspection and corrective actionswill be implemented as needed.Based on its review, the staff found the applicant's response to RAI B2.1.32-1 acceptable. Theapplicant stated that it will evaluate inaccessible surfaces for the impact of aging based on comparable accessible locations. For insulated piping, inspections will include removal ofinsulation where inspections of uninsulated portions cannot be extrapolated. This will allow formanaging relevant aging effects consistent with the staff's position for management of inaccessible surfaces for the External Surfaces Monitoring Program in Revision 1 of the GALL Report. Therefore, the staff's concern described in RAI B2.1.32-1 is resolved.The staff confirmed that the Scope of Program element satisfies the SRP-LR A.1.2.3 criteria.The scope of the program identifies mechanical, civil, and structural components from various systems included in the program. On this basis, the staff found the applicant's program scopeacceptable.(2) Preventive Actions-The applicant stated that no preventive actions are associated with thisAMP, the objective of which is to identify and manage aging effects of concern before the loss of intended function (i.e., condition monitoring).The staff confirmed that the Preventive Actions element satisfies the SRP-LR A.1.2.3 criteria.The staff identified no need for preventive actions for this AMP as a condition monitoring program. On this basis, the staff found the applicant's Preventive Actions program element acceptable.
3-135(3) Parameters Monitored or Inspected-The applicant stated that the System ConditionMonitoring Program uses periodic plant system inspections and walkdowns to monitor formaterial degradation of mechanical systems/components and civil structures. It will also inspecthanger and support, rack, panel, and anchorage material condition for excessive and/or abnormal material degradation conditions such as cracking, paint deterioration (an indicator of possible underlying degradation), loose, worn or missing parts/components, fluid leaks, bolting or fastener degradation, evidence of corrosion, sealant deterioration, and other problems. It willrevise implementing instructions and procedures to include specific parameters to be monitored and inspected. These parameters will be generated based on industry practices from INPO,EPRI, and other organizations.The staff confirmed that the Parameters Monitored or Inspected element satisfies theSRP-LR A.1.2.3 criteria and is capable of detecting the presence and extent of aging effects.On this basis, the staff found the applicant's Parameters Monitored or Inspected program element acceptable.(4) Detection of Aging Effects-The applicant stated that the readily accessible externalsurfaces of various components (e.g., pump casings, valve bodies, piping, expansion joints) are visually inspected for leakage and evidence of excessive and abnormal material degradation.
The minimum walkdown frequency is once per year for systems and components accessibleduring normal operation. The inspection frequency may be increased according to the safety significance, production significance, and/or operating experience of each system. Theapplicant inspects systems and components accessible only during plant outages at least onceper refueling interval.In RAI B2.1.32-2, dated July 20, 2005, the staff requested that the applicant discuss theinspection methods and acceptance criteria for the aging effects listed below:a)change in material properties and cracking for neoprene ventilation seals inESF systems,b)SCC for stainless steel piping and fittings in auxiliary systems,c)crevice corrosion for steel and copper alloy components in the auxiliarysystems,d)crevice corrosion for copper alloy components in the steam and powerconversion systems,e)SCC and crevice corrosion for stainless steel spent fuel pool liner.In its response, by letter dated August 16, 2005, the applicant stated the following:The methods and techniques for the detection of the above aging effects will beaccomplished in accordance with the recommendations of industry guidelines.
Direct visual inspection may be augmented by the use of tools such as mirrors, binoculars, and flashlights. EPRI documents will be the general source forguidance on aging detection techniques. These guidance documents include field guides and aging identification and assessment checklists. These documents provide descriptions of observable indicators relative to specific aging degradation.
3-136Examples of EPRI guidance documents are:
* EPRI TR-107668, "Guidelines for System Monitoring by System Engineers"
* EPRI TR-104514, "How to Conduct Material Condition Inspections"
* EPRI 1007933, "Aging Assessment Field Guide."EPRI 1007933 is a field guide for assessing aging degradation. This field guideprovides a description of the aging degradation and photographic images of the actual degradation. This field guide has specific indicators to identify aging degradation. For example, the polymers (including neoprene) section lists indicators for chemical, thermal, radiation, ultraviolet, etc. induced degradation.
Crevice corrosion is also included under the topic of metal degradation.Instruction to understand age-related degradation of plant SSCs and to identifythe leading indicators of various degradation mechanisms and effects will beprovided. EPRI guidance, supplemented by other related materials, will be usedto establish this instruction. Examples of training topics are:
* Fundamentals
* Metals Aging Degradation
* Concrete Aging Degradation
* Polymers Aging Degradation
* Protective Coatings and Linings Aging Degradation
* Electrical Components Aging DegradationShould there be indication of an unacceptable degradation, the visual inspectionwill be supplemented with other examine techniques or analytical evaluation asneeded. For example, visual observation of crack-like-indications identified during monitoring will be reported via the corrective action process. As part ofthe corrective action process, further evaluation will be performed using applicable techniques such as non-destructive examination methods (e.g., dye penetrant testing), to determine the extent of degradation and needed correctiveactions. This process would be used to confirm the presence of stress corrosion cracking.In response to the specific items in this question, the following information isprovided:Item aRegarding changes in material condition or cracking inelastomers, including neoprene, visual inspection will detectdegradation indicators such as discoloration, surface films, wrinkling, distortion, and crack-like indications. The presence of any of these indicators will trigger an evaluation to determine theextent of degradation.
3-137Item bVisual inspection will identify crack-like indications that will requirefurther evaluation via the corrective action process. Further evaluation, via NDE methods, will identify the specific type ofcracking, such as stress corrosion cracking. See response to RAI 3.3.2.3-1.Items c and dVisual inspection will identify loss of material due to corrosion asevidenced by the presence of localized corrosion products, such as scale and metal oxides. The majority of the remaining exposed base metal will appear unaffected. Identification of the corrosionas crevice corrosion is based on locations and materials that would be susceptible to this type of corrosion because of crevice geometry (e.g., presence of crevices or crevice forming materials, bolted versus welded connections) and stagnant liquid environment. Additional guidance (from industry sources such as NACE International) will be used to identify crevice corrosion aswell as other types of corrosion as appropriate. Significant surface degradation will be evaluated via the corrective action process.Item eCracking due to stress corrosion cracking and loss of material dueto crevice corrosion for the stainless steel spent fuel pool liner in a treated water environment is managed by the Plant Chemistry Program as stated in LRA Table 3.5.2-15 (Page 3-748). This is consistent with GALL line item IlI.A5.2-b......Additionally, Note 539 states, "The System Condition MonitoringProgram is credited for monitoring the spent fuel pool water level and spent fuel pool leakage". This note was specifically added to define the consistency with GALL and to differentiate between the two AMPs with regard to what aging effect/mechanism was managed by each.Based on its review, the staff found the applicant's response to RAI B2.1.32-2 acceptable. Theapplicant addressed inspection methods and acceptance criteria for various aging effects, including change in material properties for elastomers, SCC, pitting, and crevice corrosion. The methods described by the applicant are acceptable detection techniques for the aging effectsaddressed; therefore, the staff's concern described in RAI B2.1.32-2 is resolved
.The staff confirmed that the Detection of Aging Effects element satisfies SRP-LRSection A.1.2.3 criteria. The Detection of Aging Effects element links the Parameters Monitored or Inspected element to the aging effects managed, the System Condition Monitoring Program adequately describes data collection, and examination methods and frequency are adequately 3-138linked to plant-specific and industry operating experience. On this basis, the staff found theapplicant's proposed Detection of Aging Effects program element acceptable.(5) Monitoring and Trending-The applicant stated that the System Condition MonitoringProgram is capable of detecting the effects of aging before a structure's (hangers and supports) or component's loss of function can occur. Visual inspections performed at least once per year for systems and components accessible during normal plant operation may increase infrequency based on the safety significance, production significance, or operating experience of
 
each system. The applicant inspects systems and components accessible only during plantoutages at least once per refueling interval. These inspections and walkdowns provide timely detection of aging effects (i.e., before the loss of intended function). It documents inspection and walkdown results for condition trending information.The staff confirmed that the Monitoring and Trending element satisfies SRP-LR Section A.1.2.3criteria. The System Condition Monitoring Program monitors and trends certain attributes like leakage and addresses the predictability of the extent of degradation and, thus, timelycorrective action. On this basis, the staff found the applicant's proposed Monitoring and Trending program element acceptable.(6) Acceptance Criteria-The applicant stated that it will use normal design standards,procedural requirements, CLB information, and industry codes or standards (e.g., EPRI, INPO) to determine acceptance criteria. Implementing instructions and procedures will includeacceptance criteria for age-related degradation such as corrosion, leakage, deformation, cracking, and other adverse conditions that negatively impact performance of a license renewal intended function. The applicant will use references such as EPRI field guides for acceptancecriteria guidance. It will enter excessive or abnormal conditions not meeting acceptance criteriainto the corrective action process based on evaluation results.The staff confirmed that the Acceptance Criteria element satisfies SRP-LR A.1.2.3 criteria. TheAcceptance Criteria element provides a basis for evaluation of the need for corrective actions to ensure that the SC intended function will be maintained during the period of extendedoperation. On this basis, the staff found the applicant's Acceptance Criteria program elementacceptable.Operating Experience. The applicant stated that the System Condition Monitoring Program hasbeen effective in monitoring system performance and, as enhanced, provides reasonableassurance of effective management of aging effects from external visible aging mechanisms.
The System Condition Monitoring Program is based on routine walkdowns by qualified systemengineers. The Engineering Department monitors walkdown progress monthly as a performance indicator, with a goal of 90 percent completed as scheduled. Since data gathering began in May 2003, the applicant completed 100 percent of the monthly walkdowns through August 2004 as scheduled. Numerous examples were noted where system engineersdocumented needed corrective actions through minor maintenance tasks, WOs, or AR (enteredinto the site CAP). System engineers maintain system health reports as one way to track theprogress of system performance, outstanding work, and the results of their operatingexperience reviews. Of the 82 systems tracked by system health reports, all but three met orexceeded performance expectations as of September 2004.
3-139The staff confirmed that the Operating Experience element satisfies SRP-LR A.1.2.3 criteria.Operating experience with the existing program shows that the System Condition MonitoringProgram detects system degradation in a timely manner. On this basis, the staff found theapplicant's Operating Experience program element acceptable.The applicant credited the System Condition Monitoring Program with managing aging effectsfor structural components like concrete anchors and elastomers. The GALL Report recommends the Structures Monitoring Program for management of these types of components. As documented in the audit and review report, the staff asked the applicant to discuss how the System Condition Monitoring Program addresses the GALL Report recommendations for the Structures Monitoring Program for managing aging effects of these components. The applicant stated that it reassigned a number of components to be managedby the Structures Monitoring Program as recommended by the GALL Report to the System Condition Monitoring Program. For these components, the 10 attributes of both AMPs are compatible in that they address similar scope, preventive actions, parameters monitored orinspected, detection of aging effects, monitoring and trending, acceptance criteria, corrective actions, confirmation process, and administrative controls elements. On the basis of its review and the information provided by the applicant, the staff found that the System ConditionMonitoring Program provides acceptable aging management for these structural components.USAR Supplement. In LRA Section A2.1.32, the applicant provided the USAR supplement forthe System Condition Monitoring Program. The staff reviewed this section and determined that the information in the USAR supplement adequately describes the program, as required by 10 CFR 54.21(d).Conclusion. On the basis of its review and audit of the applicant's System Condition MonitoringProgram, the staff concluded that the applicant demonstrated that the effects of aging will beadequately managed so that intended functions will be maintained consistent with the CLB forthe period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.4  Quality Assurance Program Attributes Integral to Aging Management Programs Pursuant to 10 CFR 54.21(a)(3), a license renewal applicant must demonstrate that the effectsof aging on SCs subject to an AMR will be adequately managed so that their intended functionswill be maintained consistent with the CLB for the period of extended operation.Branch Technical Position IQMB-1, "Quality Assurance For Aging Management Programs,"(SRP-LR Section A.2) provides the following guidance with regard to the QA attributes of AMPs:
* SR SCs are subject to the requirements of Appendix B to 10 CFR Part 50, which areadequate to address all quality-related aspects of an AMP consistent with the CLB of the facility for the period of extended operation.
* For NSR SCs that are subject to an AMR, an applicant has an option to expand thescope of its program for Appendix B to 10 CFR Part 50 to include these SCs to address corrective actions, the confirmation process, and administrative controls for aging 3-140management during the period of extended operation. In this case, the applicant shoulddocument such a commitment in the USAR supplement in accordance with 10 CFR 54.21(d).3.0.4.1  Summary of Technical Information in the Application LRA Section A2, "Programs That Manage the Effects of Aging," states that the elements ofCorrective Actions, Confirmation Process, and Administrative Controls in the Quality Assurance Program apply to both SR and NSR SSCs subject to an AMR. In LRA Section B1.3, "Quality Assurance Program and Administrative Controls," the applicant described the quality attributes of the plant-specific AMPs and summarized them as follows:
* A single corrective actions process is applied regardless of the safety classification ofthe SC. Corrective actions are implemented through the initiation of an AR in accordance with plant procedures established in response to Appendix B to 10 CFR Part 50.
* The programs correct equipment deficiencies through the initiation of a WO inaccordance with plant procedures. Although a WO may initially document equipment deficiencies, the corrective action process specifies that an AR also be initiated for actual or potential problems, including failures, malfunctions, discrepancies, deviations, defective material and equipment, nonconformances, and administrative control discrepancies. Site-specific administrative work instructions will apply to both SR andNSR SCs that are subject to an AMR consistent with the CLB during the period of extended operation.
* The confirmation process is part of the CAP. The confirmation process focuses on thefollowup actions that must be taken to verify effective implementation of corrective actions. Effectiveness is measured in terms of correcting the adverse condition and precluding repetition of significant conditions adverse to quality. Plant procedures include provisions for timely evaluation of adverse conditions and implementation of any corrective actions required, including root cause determinations and prevention of recurrence where appropriate (e.g., significant conditions adverse to quality). These procedures provide for tracking, coordinating, monitoring, reviewing, verifying, validating, and approving corrective actions to ensure that effective corrective actions are taken. The AR process is also monitored for potentially adverse trends. The existence of an adverse trend because of recurring or repetitive adverse conditions willresult in the initiation of an AR. The AMAs required for license renewal will also uncoverany unsatisfactory condition resulting from ineffective corrective action. The applicant
 
will enhance site documents that implement AMAs for license renewal to ensure that anAR is prepared in accordance with plant procedures whenever nonconforming conditions are found (i.e., the acceptance criteria are not met).
* The document control process applies to all MNGP documents, procedures, andinstructions regardless of safety classification of the associated SC. The applicant implements the document control processes in accordance with the requirements ofAppendix B to 10 CFR Part 50. The document control requirements will apply to AMPs.
3-141In its letter dated June 10, 2005, the applicant revised Appendix A to its LRA to addSection A.5, which contains a commitment list related to license renewal aging management that will be added to the USAR following receipt of the extended license.3.0.4.2  Staff Evaluation The staff reviewed portions of the applicant's AMPs described in LRA Sections A2, A5, andB1.3 to ensure that the AMAs are consistent with the staff's guidance in Branch Technical Position IQMB-1 regarding AMP QA attributes. The staff confirmed that the descriptions, commitments, and applicability of the plant-specific AMPs and their associated quality attributesprovided in LRA Sections A2, A5, and B1.3 are consistent with the staff position in Branch Technical Position IQMB-1 regarding aging management QA.3.0.4.3  Conclusion The applicant described the quality attributes of the programs and activities for managing theeffects of aging for both SR and NSR SSCs within the scope of license renewal. The staff found that the QA attributes of the applicant's AMPs as described in LRA Sections A2, A5, and B1.3 are consistent with the staff position in Branch Technical Position IQMB-1. Therefore, the QA attributes of the applicant's AMPs appropriately ensure adequate management of aging effects to maintain intended functions consistent with the CLB in accordance with 10 CFR 54.21(a)(3).
The staff also found the commitment in the applicant's letter dated June 10, 2005, to revise theUSAR to specify commitments related to license renewal aging management consistent with Branch Technical Position IQMB-1. Therefore, it meets the requirement in 10 CFR 54.21(d).3.1  Aging Management of Reactor Coolant SystemThis section of the SER documents the staff's review of the applicant's AMR results for theRCS components and component groups associated with the following systems:
* reactor head vent system
* reactor pressure vessel
* reactor pressure vessel internals
* reactor recirculation system
* reactor vessel instrumentation3.1.1  Summary of Technical Information in the Application In LRA Section 3.1, the applicant provided AMR results for the RCS components andcomponent groups. In LRA Table 3.1.1, the applicant provided a summary comparison of its AMRs with the AMRs evaluated in the GALL Report for the reactor vessel, internals, and RCS components and component groups.The applicant's AMRs incorporated applicable operating experience in the determination ofAERMs. These reviews included evaluation of plant-specific and industry operating experience.
The plant-specific evaluation included reviews of CRs and discussions with appropriate site personnel to identify AERMs. The applicant's review of industry operating experience included a 3-142review of the GALL Report and operating experience issues identified since the issuance of theGALL Report.3.1.2  Staff Evaluation The staff reviewed LRA Section 3.1 to determine if the applicant provided sufficient informationto demonstrate that the effects of aging for the RCS components that are within the scope oflicense renewal and subject to an AMR will be adequately managed so that intended functionswill be maintained consistent with the CLB for the period of extended operation, as required by10 CFR 54.21(a)(3).In addition, the staff performed an onsite audit of AMRs to confirm the applicant's claim thatcertain identified AMRs are consistent with the GALL Report. The staff did not repeat its reviewof the matters described in the GALL Report; however, the staff did verify that the material presented in the LRA is applicable and that the applicant had identified the appropriate GALLReport AMRs. SER Section 3.0.3 documents the staff's evaluations of the AMPs. The MNGP audit and review report details the staff's audit evaluation, which is summarized in SER Section 3.1.2.1.The staff also performed an onsite audit of those selected AMRs that are consistent with theGALL Report and for which further evaluation is recommended. The staff confirmed that the applicant's further evaluations are consistent with the acceptance criteria in Section 3.1.2.2 ofthe SRP-LR. The MNGP audit and review report documents the staff's audit evaluations, which are summarized in SER Section 3.1.2.2.The staff performed an onsite audit and conducted a technical review of the remaining AMRsthat are not consistent with, or not addressed in, the GALL Report. The audit and technicalreview included evaluating whether the applicant identified all plausible aging effects and whether the aging effects listed are appropriate for the combination of materials and environments specified. The MNGP audit and review report documents the staff's audit evaluations. SER Section 3.1.2.3 documents the staff's audit evaluations and technical review. Finally, the staff reviewed the AMP summary descriptions in the USAR supplement to ensurethat they adequately describe the programs credited with managing or monitoring aging for theRCS components.Table 3.1-1 below summarizes the staff's evaluation of components, aging effects/mechanisms,and AMPs listed in LRA Section 3.1, that are addressed in the GALL Report.
3-143Table 3.1-1  Staff Evaluation for Reactor Coolant System Components in the GALLReportComponent GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff EvaluationReactor coolantpressure boundarycomponents(Item Number3.1.1-01)Cumulative fatiguedamageTLAA, evaluated inaccordance with10 CFR 54.21(c)TLAAThis TLAA isevaluated inSection 4.3, MetalFatigue of the RPVand Internals, andReactor CoolantPressure BoundaryPiping andComponentsSteam generatorshell assembly(Item Number3.1.1-02)Loss of materialdue to pitting andcrevice corrosionInserviceinspection; waterchemistryNot applicable,PWR onlyIsolation condenser(Item Number3.1.1-03)Loss of materialdue to general,pitting, and crevicecorrosionInserviceinspection; waterchemistryNot applicable (seeSection 3.1.2.2.2)Pressure vesselferritic materialsthat have a neutronfluence greater than 10 17 n/cm 2(E > 1 MeV)
(Item Number3.1.1-04)Loss of fracturetoughness due toneutron irradiationembrittlementTLAA, evaluated inaccordance withAppendix G to10 CFR 50 andRG 1.99TLAAThis TLAA isevaluated inSection 4.2,NeutronEmbrittlement of theReactor PressureVessel andInternalsReactor vesselbeltline shell andwelds(Item Number3.1.1-05)Loss of fracturetoughness due toneutron irradiationembrittlementReactor vesselsurveillanceReactor VesselSurveillanceProgram (B2.1.29) Consistent withGALL, whichrecommends furtherevaluation (seeSection 3.1.2.2.3)Westinghouse andB&W baffle/formerbolts(Item Number3.1.1-06)Loss of fracturetoughness due toneutron irradiationembrittlement andvoid swellingPlant specificNot applicable,PWR onlySmall-bore reactorcoolant system andconnected systemspiping(Item Number3.1.1-07)Crack initiation andgrowth due to SCC,intergranular SCC,and thermal andmechanical loadingInserviceinspection; waterchemistry, one-timeinspectionASME Section XIIn-ServiceInspection,Subsections IWB,IWC, and IWDProgram (B2.1.2);One-TimeInspection Program(B2.1.23); PlantChemistry Program(B2.1.25) Consistent withGALL, whichrecommends furtherevaluation (seeSection 3.1.2.2.4)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation3-144Jet pump sensingline, and reactorvessel flange leakdetection line(Item Number3.1.1-08)Crack initiation andgrowth due to SCC,intergranular stresscorrosion cracking(IGSCC), or cyclicloadingPlant specificASME Section XIIn-ServiceInspection,Subsections IWB,IWC, and IWDProgram (B2.1.2);One-TimeInspection Program(B2.1.23); PlantChemistry Program(B2.1.25) The jet pumpsensing linesinternal to thereactor vessel areoutside the scope oflicense renewal.The vessel flangeleak detection lineis covered by ItemNumber 3.1.1-07.Further evaluationin Section 3.1.2.2.4Isolation condenser(Item Number3.1.1-09)Crack initiation andgrowth due to stresscorrosion cracking(SCC) or cyclicloadingInserviceinspection; waterchemistryNot applicable (seeSection 3.1.2.2.4)Vessel shell(Item Number3.1.1-10)Crack growth due tocyclic loadingTLAANot applicable,PWR onlyReactor internals(Item Number3.1.1-11)Changes indimension due tovoid swellingPlant specificNot applicable,PWR onlyPWR core supportpads, instrumenttubes (bottom headpenetrations),pressurizer sprayheads, and nozzlesfor the steamgeneratorinstruments anddrains(Item Number3.1.1-12)Crack initiation andgrowth due to SCCand/or primarywater stresscorrosion cracking(PWSCC)Plant specificNot applicable,PWR onlyCast austeniticstainless steel(CASS) reactorcoolant systempiping(Item Number3.1.1-13)Crack initiation andgrowth due to SCCPlant specificNot applicable,PWR onlyPressurizerinstrumentationpenetrations andheater sheaths andsleeves made ofNi-alloys(Item Number3.1.1-14)Crack initiation andgrowth due toPWSCCInserviceinspection; waterchemistryNot applicable,PWR only Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation3-145Westinghouse andB&W baffle formerbolts(Item Number3.1.1-15)Crack initiation andgrowth due to SCCand IASCCPlant specificNot applicable,PWR onlyWestinghouse andB&W baffle formerbolts(Item Number3.1.1-16)Loss of preload dueto stress relaxationPlant specificNot applicable,PWR onlySteam generatorfeedwaterimpingement plateand support(Item Number3.1.1-17)Loss of sectionthickness due toerosionPlant specificNot applicable,PWR only(Alloy 600) steamgenerator tubes,repair sleeves, andplugs(Item Number3.1.1-18)Crack initiation andgrowth due toPWSCC, outsidediameter stresscorrosion cracking(ODSCC), and/orintergranular attack(IGA) or loss ofmaterial due towastage and pittingcorrosion, andfretting and wear; ordeformation due tocorrosion at tubesupport plateintersectionsSteam generatortubing integrity;water chemistryNot applicable,PWR onlyTube support latticebars made ofcarbon steel(Item Number3.1.1-19)Loss of sectionthickness due to FACPlant specificNot applicable,PWR onlyCarbon steel tubesupport plate(Item Number3.1.1-20)Ligament crackingdue to corrosionPlant specificNot applicable,PWR onlySteam generatorfeedwater inlet ringand supports(Item Number3.1.1-21)Loss of materialdue toflow-corrosionCombustionengineering (CE)steam generatorfeedwater ringinspectionNot applicable,PWR onlyReactor vesselclosure studs andstud assembly(Item Number3.1.1-22)Crack initiation andgrowth due to SCCand/or IGSCCReactor headclosure studsReactor HeadClosure StudsProgram (B2.1.28) Consistent withGALL Report, whichrecommends nofurther evaluation Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation3-146CASS pump casingand valve body(Item Number3.1.1-23)Loss of fracturetoughness due tothermal agingembrittlementInservice inspectionASME Section XIIn-ServiceInspection,Subsections IWB,IWC, and IWDProgram (B2.1.2)Consistent withGALL Report (seeSection 3.1.2.1.1)CASS piping(Item Number3.1.1-24)Loss of fracturetoughness due tothermal agingembrittlementThermal agingembrittlement of CASSNot applicable,MNGP does nothave CASS pipingBWR piping andfittings; steamgeneratorcomponents(Item Number3.1.1-25)Wall thinning due toflow-acceleratedcorrosionFlow-acceleratedcorrosionFlow-AcceleratedCorrosion Program(B2.1.19) Consistent withGALL Report forBWR piping andfittings in the RCS.MNGP is a BWRand does not havea steam generatorReactor coolantpressure boundary(RCPB) valveclosure bolting,manway andholding bolting, andclosure bolting inhigh pressure andhigh-temperaturesystems(Item Number3.1.1-26)Loss of materialdue to wear, loss ofpreload due tostress relaxation,crack initiation andgrowth due to cyclicloading and/or SCCBolting integrityBolting IntegrityProgram (B2.1.4) Consistent withGALL Report, whichrecommends nofurther evaluationFeedwater andcontrol rod drive(CRD) return linenozzles(Item Number3.1.1-27)Crack initiation andgrowth due to cyclicloadingFeedwater nozzle,CRD return linenozzleBWR Control RodDrive Return LineNozzle Program(B2.1.7), BWRFeedwater NozzleProgram (B2.1.8) Consistent withGALL Report, whichrecommends nofurther evaluationVessel shellattachment welds(Item Number3.1.1-28)Crack initiation andgrowth due to SCC,IGSCCBWR vessel IDattachment welds,water chemistryBWR Vessel IDAttachment WeldsProgram (B2.1.11),Plant ChemistryProgram (B2.1.25) Consistent withGALL Report, whichrecommends nofurther evaluation Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation3-147Nozzle safe ends,recirculation pumpcasing, connectedsystems piping andfittings, body andbonnet of valves(Item Number3.1.1-29)Crack initiation andgrowth due to SCC,IGSCCBWR stresscorrosion cracking;water chemistryASME Section XIIn-ServiceInspection,Subsections IWB,IWC, and IWDProgram (B2.1.2);BWR StressCorrosion CrackingProgram (B2.1.10);One-TimeInspection Program(B2.1.23); PlantChemistry Program(B2.1.25) Consistent withGALL Report, whichrecommends nofurther evaluationPenetrations(Item Number3.1.1-30)Crack initiation andgrowth due to SCC,IGSCC, cyclicloadingBWR penetrations,water chemistryBWR PenetrationsProgram (B2.1.9),Plant ChemistryProgram (B2.1.25) Consistent withGALL Report, whichrecommends nofurther evaluationCore shroud andcore plate, supportstructure, top guide,core spray lines andspargers, jet pumpassemblies, controlrod drive housing,nuclearinstrumentationguide tubes(Item Number3.1.1-31)Crack initiation andgrowth due to SCC,IGSCC, IASCCBWR vesselinternals, waterchemistryBWR VesselInternals Program(B2.1.12), PlantChemistry Program(B2.1.25) Consistent withGALL Report, whichrecommends nofurther evaluationCore shroud andcore plate accesshole cover (weldedand mechanicalcovers)(Item Number3.1.1-32)Crack initiation andgrowth due to SCC,IGSCC, IASCCASME Section XIinserviceinspection; waterchemistryASME Section XIIn-ServiceInspection,Subsections IWB,IWC, and IWDProgram (B2.1.2);Plant ChemistryProgram (B2.1.25) Consistent withGALL Report, whichrecommends nofurther evaluationJet pump assemblycastings, orificedfuel support(Item Number3.1.1-33)Loss of fracturetoughness due tothermal aging andneutronembrittlementThermal aging andneutron irradiationembrittlementThermal Aging &Neutron IrradiationEmbrittlement ofCast AusteniticStainless Steel(CASS) Program(B2.1.33) Consistent withGALL Report, whichrecommends nofurther evaluationUnclad top headand nozzles(Item Number3.1.1-34)Loss of materialdue to general,pitting, and crevicecorrosionInserviceinspection; waterchemistryNot applicable. Thetop head enclosureis clad at MNGPCRD nozzle(Item Number3.1.1-35)Crack initiation andgrowth due toPWSCCNi-alloy nozzles andpenetrations, waterchemistryNot applicable,PWR only Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation3-148Reactor vesselnozzles safe endsand CRD housing,reactor coolantsystem components(except CASS andbolting)(Item Number3.1.1-36)Crack initiation andgrowth due to cyclicloading, and/or SCCand PWSCCInserviceinspection; waterchemistryNot applicable,PWR onlyReactor vesselinternals CASScomponents(Item Number3.1.1-37)Loss of fracturetoughness due tothermal aging,neutron irradiationembrittlement, andvoid swellingThermal aging andneutron irradiationembrittlementNot applicable,PWR onlyExternal surfaces ofcarbon steelcomponents inreactor coolantsystem pressureboundary(Item Number3.1.1-38)Loss of materialdue to boric acidcorrosionBoric acid corrosionNot applicable,PWR onlySteam generatorsecondarymanways andhandholds (CS)(Item Number3.1.1-39)Loss of materialdue to erosionInservice inspectionNot applicable,PWR onlyReactor internals,reactor vesselclosure studs, andcore support pads(Item Number3.1.1-40)Loss of materialdue to wearInservice inspectionNot applicable,PWR onlyPressurizer integralsupport(Item Number3.1.1-41)Crack initiation andgrowth due to cyclicloadingInservice inspectionNot applicable,PWR onlyUpper and lowerinternals assembly(Westinghouse)(Item Number3.1.1-42)Loss of preload dueto stress relaxationInserviceinspection; loosepart and/or neutronnoise monitoringNot applicable,PWR onlyReactor vesselinternals in fuelzone region (exceptWestinghouse andB&W baffle bolts)(Item Number3.1.1-43)Loss of fracturetoughness due toneutron irradiationembrittlement, andvoid swellingPWR vesselinternals, waterchemistryNot applicable,PWR only Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation3-149Steam generatorupper and lowerheads, tubesheets,primary nozzles andsafe ends(Item Number3.1.1-44)Crack initiation andgrowth due to SCC,PWSCC, IASCCInserviceinspection; waterchemistryNot applicable,PWR onlyVessel internals(exceptWestinghouse andB&W baffle formerbolts)(Item Number3.1.1-45)Crack initiation andgrowth due to SCCand IASCCPWR vesselinternals, waterchemistryNot applicable,PWR onlyReactor internals(B&W screws andbolts)(Item Number3.1.1-46)Loss of preload dueto stress relaxationInserviceinspection; loosepart monitoringNot applicable,PWR onlyReactor vesselclosure studs andstud assembly(Item Number3.1.1-47)Loss of materialdue to wearReactor headclosure studsNot applicable,PWR onlyReactor internals(Westinghouseupper and lowerinternal assemblies;CE bolts and tierods)(Item Number3.1.1-48)Loss of preload dueto stress relaxationInserviceinspection; loosepart monitoringNot applicable,PWR onlyThe staff's review of the MNGP component groups followed one of several approaches. Oneapproach, documented in SER Section 3.1.2.1, involves the staff's review of the AMR resultsfor components in the RCS that the applicant indicated are consistent with the GALL Reportand do not require further evaluation. Another approach, documented in SER Section 3.1.2.2,involves the staff's review of the AMR results for components in the RCS that the applicantindicated are consistent with the GALL Report and for which further evaluation is recommended. A third approach, documented in SER Section 3.1.2.3, involves the staff'sreview of the AMR results for components in the RCS that the applicant indicated are notconsistent with, or not addressed in, the GALL Report. SER Section 3.0.3 documents the staff'sreview of AMPs that are credited to manage or monitor aging effects of the RCS components.3.1.2.1  AMR Results That Are Consistent with the GALL Report Summary of Technical Information in the Application. In LRA Section 3.1.2.1, the applicantidentified the materials, environments, and AERMs. The applicant identified the following programs that manage the aging effects related to the RCS components:
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* ASME Section XI In-Service Inspection, Subsections IWB, IWC, and IWDProgram (B2.1.2)
* Bolting Integrity Program (B2.1.4)
* BWR Control Rod Drive Return Line Nozzle Program (B2.1.7)
* BWR Feedwater Nozzle Program (B2.1.8)
* BWR Penetrations Program (B2.1.9)
* BWR Stress Corrosion Cracking Program (B2.1.10)
* BWR Vessel ID Attachment Welds Program (B2.1.11)
* BWR Vessel Internals Program (B2.1.12)
* Closed-Cycle Cooling Water System Program (B2.1.13)
* Flow-Accelerated Corrosion Program (B2.1.19)
* One-Time Inspection Program (B2.1.23)
* Plant Chemistry Program (B2.1.25)
* Reactor Head Closure Studs Program (B2.1.28)
* Reactor Vessel Surveillance Program (B2.1.29)
* System Condition Monitoring Program (B2.1.32)
* Thermal Aging & Neutron Irradiation Embrittlement of Cast Austenitic StainlessSteel (CASS) Program (B2.1.33)Staff Evaluation. In LRA Tables 3.1.2-1 through 3.1.2-5, the applicant provided a summary ofAMRs for the RCS components, and identified which AMRs it considered to be consistent with the GALL Report.For component groups evaluated in the GALL Report for which the applicant has claimedconsistency with the GALL Report, and for which the GALL Report does not recommend further evaluation, the staff performed an audit and review to determine whether the GALL Reportevaluation bounds the plant-specific components contained in these GALL Report componentgroups.The applicant provided a note for each AMR line item. The notes describe how the informationin the tables aligns with the information in the GALL Report. The staff audited those AMRs with Notes A through E, which indicate that 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 AMP identified in the GALL Report. The staff audited these line items to verify consistency with the GALL Report and the validity of the AMR for the site-specific conditions.Note B 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 AMP identified in the GALL Report. The staff audited these line items to verify consistency with 3-151the GALL Report. The staff verified that it had reviewed and accepted the identified exceptionsto the GALL Report AMPs. The staff also determined whether the AMP identified by the applicant is consistent with the AMP identified in the GALL Report and whether the AMR is validfor the site-specific conditions.Note C indicates that the component for the AMR line item, although different, is consistent withthe GALL Report for material, environment, and aging effect. In addition, the AMP is consistent with the AMP identified by the GALL Report. This note indicates that the applicant was unableto find a listing of some system components in the GALL Report. However, the applicantidentified a different component in the GALL Report that has 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 determined whether the AMR line item of the different component is applicable to the component under review and whether the AMR isvalid for the site-specific conditions.Note D indicates that the component for the AMR line item, although different, is consistent withthe GALL Report for material, environment, and aging effect. In addition, the AMP takes some exceptions to the AMP identified in the GALL Report. The staff audited these line items to verify consistency with the GALL Report. The staff verified whether the AMR line item of the different component is applicable to the component under review. The staff verified that it had reviewed and accepted the identified exceptions to the GALL Report AMPs. The staff also determinedwhether the AMP identified by the applicant is consistent with the AMP identified in the GALLReport and whether the AMR is 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 the applicant credited a different AMP. The staff audited these line items to verify consistency with the GALL Report. The staff also determined whether the identified AMP will manage the aging effect consistent with the AMP identified by the GALLReport and whether the AMR is valid for the site-specific conditions.The staff conducted an audit and review of the information provided in the LRA, as documentedin the MNGP audit and review report. The staff did not repeat its review of the matters described in the GALL Report; however, the staff did verify that the material presented in the LRA is applicable and that the applicant identified the appropriate GALL Report AMRs. The following sections discuss the staff's evaluation.3.1.2.1.1  Loss of Fracture Toughness Due to Thermal Aging Embrittlement NRC Audit Item 3.1-18In the discussion section of LRA Table 3.1.1, Item Number 3.1.1-23, the applicant stated thefollowing:This line item is not used at MNGP. The reactor coolant systems components ofCASS material are portions of the Jet Pump, Fuel Support, and CRD assemblies. See items 3.1.1-31 and 3.1.1-33 for these components. In addition,CASS valve bodies in the ESF system are discussed in item 3.2.1-11 ofTable 3.2.1.
3-152During the audit and review, the staff noted that the LRA states that, "This line item is not usedat MNGP." Based on the LRA discussion in Table 3.1.1, Item 3.1.1-23, the staff reviewed ESFItem Number 3.2.1-11 in LRA Table 3.2.1 for CASS piping and fittings in the ECCS. The staff confirmed that the LRA includes AMR results for CASS valve bodies in the CSP system (LRATable 3.2.2-3) and in the RHR system (LRA Table 3.2.2-7), which the applicant had referencedappropriately to GALL Report line IV.C1.3-b. The staff also confirmed that the material, environment, aging effect, and AMP combination specified in the LRA for these valves is consistent with GALL Report line IV.C1.3-b, which applies to CASS valves in a reactor coolant water environment with an aging effect of loss of fracture toughness due to thermal aging embrittlement and which specifies the ASME Section XI In-Service Inspection, Subsections IWB, IWC, and IWD Program as the AMP for Class 1 components. However, the staff noted that the applicant had linked these AMR results with Item 3.1.1-23 in LRATable 3.1.1, where the discussion states that, "This line item is not used at MNGP."Therefore, the staff asked that the applicant resolve the LRA discrepancy linking AMR resultsfor components in one table with an item number in another table, while stating that MNGPdoes not use the item number. In its response, dated August 11, 2005, the applicant stated thefollowing:LRA Table 3.1.1, Item Number 3.1.1-23, should be revised to read, 'CASScomponents in the ESF systems subject to an environment that supports loss offracture toughness due to thermal aging embrittlement were assigned to the ASME Section XI In-Service Inspection, Subsections IWB, IWC and IWD Program. Those CASS components that are subject to this aging effect/
mechanism are valves.'Based on its review, the staff found the applicant's response to NRC Audit Item 3.1-18acceptable because the components, material, aging effect, and AMP identified in the LRA are consistent with the GALL Report. The staff found that the applicant had appropriatelyaddressed the aging management for these components. SER Section 3.0.3.2.2 documents thestaff's evaluation of the applicant's ASME Section XI In-Service Inspection, Subsections IWB, IWC, and IWD Program.On the basis of its review, the staff found that the applicant addressed the aging effects andmechanisms as identified in the GALL Report.Conclusion. The staff evaluated the applicant's claim of consistency with the GALL Report. Thestaff also reviewed information pertaining to the applicant's consideration of recent operating experience and proposals for managing associated aging effects. On the basis of its review, the staff concluded that the AMR results, which the applicant claimed to be consistent with theGALL Report, are consistent with the AMRs in the GALL Report; therefore, the staff concludedthat the applicant has demonstrated that the effects of aging for these components will beadequately managed so that their intended function(s) will be maintained consistent with theCLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3-1533.1.2.2AMR Results That Are Consistent with the GALL Report, for Which Further EvaluationIs RecommendedSummary of Technical Information in the Application. In LRA Section 3.1.2.2, the applicantprovided further evaluation of aging management as recommended by the GALL Report for the RCS components. The applicant provided information concerning how it will m anage thefollowing aging effects:
* cumulative fatigue damage
* loss of material due to pitting and crevice corrosion
* loss of fracture toughness due to neutron irradiation embrittlement
* crack initiation and growth due to thermal and mechanical loading or stress corrosioncracking
* crack growth due to cyclic loading
* changes in dimension due to void swelling
* crack initiation and growth due to stress corrosion cracking or primary water stresscorrosion cracking
* crack initiation and growth due to stress corrosion cracking or irradiation-assisted stresscorrosion cracking
* loss of preload due to stress relaxation
* loss of section thickness due to erosion
* crack initiation and growth due to PWSCC, ODSCC, or intergranular attack or loss ofmaterial due to wastage and pitting corrosion or loss of section thickness due to fretting and wear or denting due to corrosion of carbon steel tube support plate
* loss of section thickness due to flow-accelerated corrosion
* ligament cracking due to corrosion
* loss of material due to flow-accelerated corrosionStaff Evaluation. For component groups evaluated in the GALL Report for which the applicanthas claimed consistency with the GALL Report, and for which the GALL Report recommends further evaluation, the staff audited and reviewed the applicant's evaluation to determinewhether it adequately addressed the issues that were further evaluated. In addition, the staffreviewed the applicant's further evaluations against the criteria contained in Section 3.1.2.2 ofthe SRP-LR. The staff's audit and review report details the staff's audit. The following sections discuss the staff's evaluation of the aging effects.3.1.2.2.1  Cumulative Fatigue Damage In LRA Section 3.1.2.2.1, the applicant stated that fatigue is a TLAA, as defined in10 CFR 54.3, "Definitions."  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 evaluationof this TLAA.
3-1543.1.2.2.2  Loss of Material Due to Pitting and Crevice CorrosionThe staff reviewed LRA Sections 3.1.2.2.2.1 and 3.1.2.2.2.2 against SRP-LR Section 3.1.2.2.2criteria.In LRA Section 3.1.2.2.2.1, the applicant addressed loss of material due to pitting and crevicecorrosion in the steel pressurized-water reactor (PWR) steam generator shell assembly.Loss of material for a steam generator shell assembly applies to PWRs only. The staff foundthis aging effect not applicable.In LRA Section 3.1.2.2.2.2, the applicant addressed loss of material due to pitting and crevicecorrosion in BWR isolation condenser components.MNGP has no isolation condenser. The staff found this aging effect not applicable.
3.1.2.2.3  Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement The staff reviewed LRA Sections 3.1.2.2.3.1 through 3.1.2.2.3.3 against SRP-LRSection 3.1.2.2.3 criteria.In LRA Section 3.1.2.2.3.1, the applicant addressed loss of fracture toughness due to neutronirradiation embrittlement for pressure vessel ferritic materials with a neutron fluence greater
 
than 10 17 n/cm 2. The applicant stated that neutron irradiation embrittlement is a TLAA asdefined in 10 CFR 54.3. Applicants must evaluate TLAAs in accordance with 10 CFR 54.21(c)(1). LRA Section 4.2 describes the applicant's evaluation of this TLAA.In LRA Section 3.1.2.2.3.2, the applicant addressed loss of fracture toughness due to neutronirradiation embrittlement for the reactor vessel, stating that the Reactor Vessel SurveillanceProgram, described in LRA Section B2.1.29, manages loss of fracture toughness due to neutron irradiation embrittlement for the reactor vessel. SER Section 3.0.3.2.21 documents thestaff's review of the Reactor Vessel Surveillance Program.SRP-LR Section 3.1.2.2.3 states that certain aspects of neutron irradiation embrittlement areTLAAs as defined in 10 CFR 54.3 and that TLAAs must be evaluated in accordance with 10 CFR 54.21(c)(1). SER Section 4.2 documents the staff's review of the applicant's evaluationof this TLAA. SRP-LR Section 3.1.2.2.3 also states that for loss of fracture toughness due toneutron embrittlement of the reactor vessel beltline shell, nozzle, and welds exposed to reactor coolant and neutron flux, a reactor vessel materials surveillance program monitors neutronirradiation embrittlement of the reactor vessel.Appendix H to 10 CFR Part 50 requires the applicant's Reactor Vessel Surveillance Program.BWRVIP ISP guidance describes the scope of the Reactor Vessel Surveillance Program.BWRVIP-86-A includes the ISP capsule removal schedule, and BWRVIP-78 describes its technical basis. The NRC approved the ISP in an SE to the BWRVIP, dated February 1, 2002,concluding that, if implemented in accordance with the conditions in the SE, the ISP is an acceptable alternative to all existing BWR plant-specific RPV surveillance programs for maintaining compliance with the requirements of Appendix H to 10 CFR Part 50 through the end of the current facility 40-year operating license period.
3-155BWRVIP-116 incorporates the technical criteria specified in BWRVIP-78 and BWRVIP-86 andextends the ISP to cover the BWR fleet through an extended period of operation. The applicantcommitted to implement the requirements of BWRVIP-116, when approved.In LRA Section 3.1.2.2.3.3, the applicant addressed loss of fracture toughness due to neutronirradiation embrittlement in Westinghouse and Babcock and Wilcox (B&W) baffle/former bolts.
This section applies to PWRs only. The staff found this aging effect not applicable.On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LRSection 3.1.2.2.3. For those line items that apply to LRA Sections 3.1.2.2.3.1 through3.1.2.2.3.3, the staff determined that the applicant's AMRs are consistent with the GALL Reportand the applicant has demonstrated that the effects of aging will be adequately managed sothat the intended function(s) will be maintained consistent with the CLB during the period ofextended operation, as required by 10 CFR 54.21(a)(3).3.1.2.2.4Crack Initiation and Growth Due to Thermal and Mechanical Loading or Stress-Corrosion CrackingThe staff reviewed LRA Sections 3.1.2.2.4.1 through 3.1.2.2.4.3 against SRP-LRSection 3.1.2.2.4 criteria.In LRA Section 3.1.2.2.4.1, the applicant addressed crack initiation and growth due to thermaland mechanical loading or SCC in small-bore RCS and connect ed system piping less than 4-inch nominal pipe size (NPS). The applicant stated that the ASME Section XI In-Service Inspection, Subsections IWB, IWC, and IWD Program, together with the Plant Chemistry Program and One-Time Inspection Program manage the aging effect. The applicant further stated that the ASME Code, Section XI, does not require volumetric examination of pipes lessthan 4-inch NPS and that the scope of the One-Time Inspection Program validates AMPeffectiveness by verifying unacceptable degradation. The applicant stated that the aging effectsmonitored/inspected by its One-Time Inspection Program include crack initiation and growth and that this program includes one-time inspections to monitor a component's degradation using a variety of NDE methods.SRP-LR Section 3.1.2.2.4, item 1, states the following:Crack initiation and growth due to thermal and mechanical loading or SCC(including intergranular stress corrosion cracking [IGSCC]) could occur in small-bore reactor cool ant system and connected system piping less than NPS4. The existing program relies on ASME Section XI ISI and on control of water chemistry to mitigate SCC. The GALL report recommends that a plant-specific destructive examination or a nondestructive examination (NDE) that permits inspection of the inside surfaces of the piping be conducted to ensure that cracking has not occurred and the component intended function will bemaintained during the extended period. The AMPs should be augmented by verifying that service-induced weld cracking is not occurring in the small-bore piping less than NPS 4, including pipe, fittings, and branch connections. A one-time inspection of a sample of locations is an acceptable method to ensure that the aging effect is not occurring and the component's intended function willbe maintained during the period of extended operation.
3-156The staff reviewed LRA Section 3.1.2.2.4.1, Tables 3.1.2-1 through 3.1.2-5, and LRAAppendix B2.1.23, and confirmed that the applicant's One-Time Inspection Programappropriately includes the small bore, Class 1 piping in the head vent system and the reactorvessel instrumentation system.The staff also reviewed the applicant's drawings of the RCS and connected systems andidentified a number of small-bore, Class 1 pipe segments. The staff asked the applicant whether the One-Time Inspection Program includes each of the segments. In its response, by letter dated August 11, 2005, the applicant provided additional information including references to LRA table entries. The staff reviewed the applicant's response and concluded that theapplicant's One-Time Inspection Program appropriately includes all Class 1 small-bore pipe segments.As part of its response, the applicant stated that in Class 1, small-bore stainless steel piping,the aging effect managed by the Plant Chemistry and One-Time Inspection Programs is cracking due to SCC; however, in Class 1, small-bore carbon steel piping, the aging effect managed by the Plant Chemistry and One-Time Inspection Programs is loss of material due to corrosion. Because different examination techniques are typically required to detect the aging effect of cracking versus that of loss of material, the staff asked the applicant to justify why it does not manage the Class 1, small-bore carbon steel piping for an aging effect of crack initiation and growth due to thermal and mechanical loading.In its response dated August 11, 2005, the applicant stated that it had performed an analyticalevaluation to classify all Class 1 and 2 piping welds by failure potential based on methodology in EPRI TR-112657, Revision B-A. Based on this evaluation, the applicant determined that ithas no Class 1, small-bore carbon steel piping in an environment where cracking due to mechanical or thermal loading will occur. Consequently, one-time inspection of Class 1,small-bore carbon steel piping will focus on the loss of material, but not on the crack initiationand growth aging effect.The staff reviewed the applicant's response together with the applicant's calculation providingthe analytical basis for excluding cracking as an aging effect in Class 1, small-bore carbon steel piping. The staff noted that SRP-LR Section 3.1.2.2.4 makes no distinction between stainlesssteel and carbon steel piping, and that the purpose of the one-time inspection is to validate the absence of cracks that the ASME Code, Section XI, examinations required for small-bore pipingmight not detect. Because the applicant used an appropriate methodology to exclude the agingeffect of cracking in carbon steel small-bore piping and will perform a one-time inspection forcracking in stainless steel small-bore piping, the staff found the applicant's programs for managing aging effects in Class 1, small-bore piping acceptable. SER Sections 3.0.3.2.2, 3.0.3.2.19, and 3.0.3.1.4 document the staff's evaluations of the applicant's ASME Section XI,In-Service Inspection, Subsections IWB, IWC, and IWD Program, Plant Chemistry Program, and One-Time Inspection Program, respectively.On the basis of its review, the staff concluded that the applicant has met the SRP-LRSection 3.1.2.2.4.1 criteria for further evaluation. For those line items that apply to LRASection 3.1.2.2.4.1, the staff found that the applicant's AMRs are consistent with the GALLReport and the applicant has demonstrated that the effects of aging will be adequatelymanaged so that the intended functions will be maintained during the period of extendedoperation as required by 10 CFR 54.21(a)(3).
3-157In LRA Section 3.1.2.2.4.2, the applicant addressed crack initiation and growth due to thermaland mechanical loading or SCC in reactor vessel flange leak detection lines and jet pump sensing lines.SRP-LR Section 3.1.2.2.4, item 2, states the following:Crack initiation and growth due to thermal and mechanical loading or SCC(including IGSCC) could occur in BWR reactor vessel flange leak detection line and BWR jet pump sensing line. The GALL report recommends that a plant specific aging management program be evaluated to mitigate or detect crack initiation and growth due to SCC of vessel flange leak detection line.In LRA Section 3.1.2.2.4.2, the applicant stated that the jet pump sensing lines internal to thereactor vessel are not within the scope of license renewal, referring to the LRA's "Further Evaluation" description of crack initiation and growth due to thermal and mechanical loading or SCC regarding management of the reactor vessel flange leak detection line and other small-bore RCS and c onnected system piping.The staff noted that the jet pump sensing lines external to the vessel are small-bore piping andincluded in LRA Table 3.1.2-5 as piping and fittings made of stainless steel in a treated water environment with an aging effect of cracking due to SCC/IGA. For this component, material, environment, and aging effect, the LRA stated that the applicable AMPs are the ASME Section XI In-Service Inspection, Subsections IWB, IWC, and IWD Program, the One-Time Inspection Program, and the Plant Chemistry Program. This is consistent with the GALL Report recommendation for small-bore, stainless steel pipe in a reactor coolant water environment.
Based on consistency with the GALL Report recommendations, the staff found the applicant'sAMPs for these components acceptable as consistent with the GALL Report recommendations.For aging management of the reactor vessel flange leak detection line, the applicant, in LRASection 3.1.2.2.4.2, stated that the aging effects/mechanisms for this component are the sameas for other small-bore RCS and connect ed system piping. For these components, theapplicable AMPs are the ASME Section XI In-Service Inspection, Subsections IWB, IWC, and IWD Program together with the Plant Chemistry Program and the One-Time Inspection Program. As the reactor vessel flange leak detection line has the same material and environment and, consequently, the same aging effects as Class 1 small-bore piping, the staffconcluded that the AMPs that the applicant identified for this component are acceptable. SERSections 3.0.3.2.2, 3.
0.3.2.19, and 3.0.3.1.4 document the staff reviews and evaluations of theapplicant's ASME Section XI In-Service Inspection, Subsections IWB, IWC, and IWD Program, Plant Chemistry Program, and One-Time Inspection Program, respectively.On the basis of its review, the staff concluded that the applicant has met SRP-LRSection 3.1.2.2.4.2 criteria for further evaluation. For those line items that apply to LRASection 3.1.2.2.4.2, the staff found that the applicant's AMRs are consistent with the GALLReport and the applicant has demonstrated that the effects of aging will be adequatelymanaged so that the intended functions will be maintained during the period of extendedoperation as required by 10 CFR 54.21(a)(3).
3-158In LRA Section 3.1.2.2.4.3, the applicant addressed crack initiation and growth due to thermaland mechanical loading or SCC in the BWR isolation condenser. Because there is no isolation condenser, the staff found this aging effect not applicable.3.1.2.2.5  Crack Growth Due to Cyclic Loading The staff reviewed LRA Section 3.1.2.2.5 against SRP-LR Section 3.1.2.2.5 criteria.In LRA Section 3.1.2.2.5, the applicant stated that this aging effect applies to PWRs only.SRP-LR Section 3.1.2.2.5 states that crack growth due to cyclic loading could occur in thereactor vessel shell and the RCS piping and fittings. SRP-LR Table 3.1-1 states that further evaluation for this aging effect is for PWR plants only.The staff found this aging effect not applicable.
3.1.2.2.6  Changes in Dimension Due to Void SwellingThe staff reviewed LRA Section 3.1.2.2.6 against SRP-LR Section 3.1.2.2.6 criteria.In LRA Section 3.1.2.2.6, the applicant stated that this aging effect applies to PWRs only.SRP-LR Section 3.1.2.2.6 states that changes in dimension due to void swelling could occur inreactor internal components. SRP-LR Table 3.1-1 states that further evaluation for this aging effect is for PWR plants only.The staff found this aging effect not applicable.
3.1.2.2.7  Crack Initiation and Growth Due to Stress-Corrosion Cracking or Primary WaterStress-Corrosion CrackingThe staff reviewed LRA Sections 3.1.2.2.7.1 through 3.1.2.2.7.3 against SRP-LRSection 3.1.2.2.7 criteria.In LRA Sections 3.1.2.2.7.1 through 3.1.2.2.7.3, the applicant stated that this aging effectapplies to PWRs only.SRP-LR Section 3.1.2.2.7 states that crack initiation and growth due to SCC and PWSCC couldoccur (1) in PWR core support pads (or core guide lugs), instrument tubes (bottom head penetrations), pressurizer spray heads, and nozzles for the steam generator instruments and drains, (2) in PWR CASS RCS piping and fittings and pressurizer surge line nozzles, and (3) in PWR pressurizer instrumentation penetrations and heater sheaths and sleeves made of nickel alloys. SRP-LR Table 3.1-1 states that further evaluation for this aging effect is for PWR plants only.The staff found this aging effect not applicable.
3-1593.1.2.2.8Crack Initiation and Growth Due to Stress-Corrosion Cracking or Irradiation-AssistedStress-Corrosion CrackingThe staff reviewed LRA Section 3.1.2.2.8 against SRP-LR Section 3.1.2.2.8 criteria.In LRA Section 3.1.2.2.8, the applicant stated that this aging effect applies to PWRs only.SRP-LR Section 3.1.2.2.8 states that crack initiation and growth due to SCC or IASCC couldoccur in baffle/former bolts in Westinghouse and B&W reactors. SRP-LR Table 3.1-1 states that further evaluation for this aging effect is for PWR plants only.The staff found this aging effect not applicable.
3.1.2.2.9  Loss of Preload Due to Stress Relaxation The staff reviewed LRA Section 3.1.2.2.9 against SRP-LR Section 3.1.2.2.9 criteria.In LRA Section 3.1.2.2.9, the applicant stated that this aging effect applies to PWRs only.SRP-LR Section 3.1.2.2.9 states that loss of preload due to stress relaxation could occur inbaffle/former bolts in Westinghouse and B&W reactors. SRP-LR Table 3.1-1 states that further evaluation for this aging effect is for PWR plants only.The staff found this aging effect not applicable.
3.1.2.2.10  Loss of Section Thickness Due to Erosion The staff reviewed LRA Section 3.1.2.2.10 against SRP-LR Section 3.1.2.2.10 criteria.In LRA Section 3.1.2.2.10, the applicant stated that this aging effect applies to PWRs only.SRP-LR Section 3.1.2.2.10 states that loss of section thickness due to erosion could occur insteam generator FW impingement plates and supports. SRP-LR Table 3.1-1 states that furtherevaluation for this aging effect is for PWR plants only.The staff found this aging effect not applicable.
3.1.2.2.11Crack Initiation and Growth Due to Primary Water Stress-Corrosion Cracking,Outside-Diameter Stress-Corrosion Cracking, or Intergranular Attack or Loss of Material Due to Wastage and Pitting Corrosion or Loss of Section Thickness Due to Fretting and Wear or Denting Due to Corrosion of Carbon Steel Tube Support PlateThe staff reviewed LRA Section 3.1.2.2.11 against SRP-LR Section 3.1.2.2.11 criteria.In LRA Section 3.1.2.2.11, the applicant stated that this aging effect applies to PWRs only.SRP-LR Section 3.1.2.2.11 states that crack initiation and growth due to PWSCC, ODSCC, orIGA or loss of material due to wastage and pitting corrosion or deformation due to corrosion 3-160could occur in Alloy 600 components of the steam generator tubes, repair sleeves, and plugs.SRP-LR Table 3.1-1 states that further evaluation for this aging effect is for PWR plants only.The staff found this aging effect not applicable.
3.1.2.2.12  Loss of Section Thickness Due to Flow-Accelerated Corrosion The staff reviewed LRA Section 3.1.2.2.12 against SRP-LR Section 3.1.2.2.12 criteria.In LRA Section 3.1.2.2.12, the applicant stated that this aging effect applies to PWRs only.SRP-LR Section 3.1.2.2.12 states that loss of section thickness due to FAC could occur in tubesupport lattice bars made of carbon steel. SRP-LR Table 3.1-1 states that further evaluation for this aging effect is for PWR plants only.The staff found this aging effect not applicable.
3.1.2.2.13  Ligament Cracking Due to Corrosion The staff reviewed LRA Section 3.1.2.2.13 against SRP-LR Section 3.1.2.2.13 criteria.In LRA Section 3.1.2.2.13, the applicant stated that this aging effect applies to PWRs only.SRP-LR Section 3.1.2.2.13 states that ligament cracking due to corrosion could occur in carbonsteel components in the steam generator tube support plate. SRP-LR Table 3.1-1 states thatfurther evaluation for this aging effect is for PWR plants only.The staff found this aging effect not applicable.
3.1.2.2.14  Loss of Material Due to Flow-Accelerated Corrosion The staff reviewed LRA Section 3.1.2.2.14 against SRP-LR Section 3.1.2.2.14 criteria.In LRA Section 3.1.2.2.14, the applicant stated that this aging effect applies to PWRs only.SRP-LR Section 3.1.2.2.14 states that loss of material due to FAC could occur in FW inlet ringand supports. SRP-LR Table 3.1-1 states that further evaluation for this aging effect is for PWR plants only.The staff found this aging effect not applicable.
Conclusion. On the basis of its review, for component groups evaluated in the GALL Report forwhich the applicant has claimed consistency with the GALL Report, and for which the GALL Report recommends further evaluation, the staff determined that the applicant adequatelyaddressed the applicable issues that were further evaluated. The staff found that the effects ofaging will be adequately managed so that intended functions will be maintained consistent withthe CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).
3-1613.1.2.3  AMR Results That Are Not Consistent with or Not Addressed in the GALL ReportSummary of Technical Information in the Application. In LRA Tables 3.1.2-1 through 3.1.2-5,the staff reviewed additional details of the results of the AMRs for material, environment, AERM, and AMP combinations that are not consistent with the GALL Report, or that are notaddressed in the GALL Report.In LRA Tables 3.1.2-1 through 3.1.2-5, the applicant indicated, via Notes F through J, that thecombination of component type, material, environment, and AERM does not correspond to a line item in the GALL Report, and provided information concerning the management of the aging effect. Specifically, Note F indicates that the GALL Report does not evaluate the material for the AMR line item component. Note G indicates that the GALL Report does not evaluate the environment for the AMR line item component and material. Note H indicates that the GALL Report does not evaluate the aging effect for the AMR line item component, material, and environment combination. Note I indicates that the aging effect identified in the GALL Report forthe line item component, material, and environment combination does not apply. Note J indicates that the GALL Report does not evaluate either the component or the material andenvironment combination for the line item.Staff Evaluation. For component type, material, and environment combinations that the GALLReport does not evaluate, the staff reviewed the applicant's evaluation to determine whetherthe applicant had demonstrated that the effects of aging will be adequately managed so that theintended function(s) will be maintained consistent with the CLB during the period of extendedoperation. The following sections discuss line items that are not consistent with the GALLReport or not addressed in the GALL Report.In LRA Tables 3.1.2-1 through 3.1.2-5, the applicant identified AMR line items for which it hadnot identified any aging effects as a result of the aging review process. Specifically, the applicant stated that no aging effects occurred when components fabricated from stainlesssteel material were exposed to a primary containment air or plant indoor air environment, or when components fabricated from stainless steel or carbon steel were exposed to a lubricating oil internal environment. The applicant stated that a material science evaluation for these materials in these environments discovered no aging effects.Because stainless steels are highly resistant to corrosion in dry atmospheres in the absence ofcorrosive species, as stated in the Metals Handbook, Ninth Edition, American Society for MetalsInternational, the staff accepted the position that stainless steel in an indoor, uncontrolled airenvironment (e.g., plant indoor air) or in a gas environment (e.g., primary containment air inerted with nitrogen) exhibits no aging effect and that the SC will therefore remain capable ofperforming intended functions consistent with the CLB for the period of extended operation.Because both oxygen and moisture must be present to corrode steel, also stated in the MetalsHandbook, Ninth Edition, the staff likewise accepted the position that steel (carbon or stainless)in a lubricating oil internal environment with no water pooling exhibits no aging effect and that the SC will therefore remain capable of performing intended functions consistent with the CLBfor the period of extended operation.On the basis of its review of current industry research and operating experience, the staff foundthat plant indoor air or primary containment air on stainless steel, or lubricating oil on stainlesssteel or carbon steel, will not cause aging of concern during the period of extended operation; 3-162therefore, the staff concluded that no AERMs apply to the component, material, andenvironment described in the preceding discussion.3.1.2.3.1Reactor Coolant System - Reactor Head Vent System - Summary of AgingManagement Evaluation - Table 3.1.2-1The staff reviewed LRA Table 3.1.2-1, which summarizes the results of AMR evaluations for thereactor head vent system component groups.On the basis of its review of the applicant's programs, aging effects, and plant-specific andindustry operating experience, the staff determined that the applicant had demonstrated thatthe effects of aging will be adequately managed so intended functions will be maintainedconsistent with the CLB during the period of extended operation, as required by10 CFR 54.21(a)(3).3.1.2.3.2Reactor Coolant System-Reactor Pressure Vessel-Summary of AgingManagement Evaluation-Table 3.1.2-2The staff reviewed LRA Table 3.1.2-2, which summarizes the results of AMR evaluations for theRPV component groups.In LRA Table 3.1.2-2, the applicant stated that the aging effect of cumulative fatigue damage ofType 316NG stainless steel materials for the component type of nozzle safe end/CRDRL capexposed to a reactor coolant water environment does not apply and no AMP is specified. The LRA assigns Note I to this item, indicating that the aging effect in the GALL Report for this component, material, and environment combination does not apply. An additional note in the LRA states that the CRD hydraulic return nozzle was capped with a 4-inch diameter pipe cap in 1977, that the CRD return nozzle weld butter was removed and the weld preparation reclad withchromium carbide to improve resistance to IGSCC, and that a new nozzle cap was installed in 1986. LRA Table 3.1.2-2 also states that the aging effect of crack initiation and growth due toSCC or IGSCC also applies to this component, and that the BWR SCC Program (AMP B2.1.10) and the Plant Chemistry Program (AMP B2.1.25) manage the aging effect.The staff noted that the applicant's evaluation of this component refers to GALL Report,Volume 2, Item IV.A1.4-b, which is the CRDRL nozzle safe end. The GALL Report line item isbased on an inservice CRDRL safe end that will routinely experience cyclic flow, not oneeffectively out of service by removal of the previously attached pipe and installation of a cap on the safe end. Capping the CRDRL safe end eliminated the cyclic flow environment to which thesafe end had been exposed and thereby eliminated the potential for the aging effect ofcumulative fatigue damage. In addition, review of operating experience since the CRDRLnozzle cap replacement in 1986 indicates that no new cracking has occurred at this location.
Because there is no potential for cumulative fatigue damage from flow cycling at the cappedCRDRL safe end and no new cracking has been detected at this location since the nozzle wascapped, the staff found the applicant's statement that cumulative fatigue damage does notapply to the CRDRL safe end cap in the RPV acceptable.The applicant proposed to manage crack initiation and growth/SCC for the top head torus,flange, and dollar plate using the ASME Section XI In-Service Inspection, Subsections IWB, 3-163IWC, and IWD Program and Plant Chemistry Program. The material is identified as alloy steel(A533 Grade B Class and A508 Class 2) and clad (308/309).The staff's review of LRA Section 3.1.2 identified an area for which it needed additionalinformation to complete its evaluation of the applicant's results. The applicant responded to the staff's RAI as discussed below.In RAI 3.1.2-1, dated September 28, 2005, the staff requested that the applicant identify whichmaterials provide the pressure boundary function and provide the basis, including any operating experience, for concluding that these materials are susceptible to crack initiation and growth due to SCC.In its response, by letter dated October 28, 2005, the applicant responded that the basematerial provided the pressure boundary function and that operating experience identified in BWRVIP-74-A, "BWR Reactor Pressure Vessel Inspection and Flaw Evaluation Guidelines for License Renewal," indicates that the base material was susceptible to SCC. The staff reviewed this BWRVIP report and could find no operating experience indicating that the alloy steel base material will be susceptible to SCC. In its letter dated December 16, 2005, the applicant agreedwith the staff that this aging mechanism does not affect the low-alloy base material and stated that it will revise the LRA accordingly as part of the annual update. By letter dated March 15,2006, the applicant removed crack initiation and growth due to SCC as an AERM from the top head enclosure components in LRA Table 3.1.2-2. The staff agreed that crack initiation andgrowth is not an AERM for the alloy steel base material in a steam environment; therefore, the staff's concerns described in RAI 3.1.2-1 are resolved.The applicant identified no aging effect for the external surface of the reactor vessel exposed toprimary containment air. The staff agreed with this conclusion because the primary containment air has not caused degradation of the reactor vessel.On the basis of its review of the applicant's programs, aging effects, and plant-specific andindustry operating experience, the staff determined that the applicant had demonstrated thatthe effects of aging will be adequately managed so that the intended functions will bemaintained during the period of extended operation, as required by 10 CFR 54.21(a)(3).3.1.2.3.3Reactor Coolant System-Reactor Pressure Vessel Internals-Summary of AgingManagement Evaluation-Table 3.1.2-3The staff reviewed LRA Table 3.1.2-3, which summarizes the results of AMR evaluations for theRPV internals component groups.In LRA Table 3.1.2-3, the applicant proposed to manage crack initiation and growth due tocyclic loading of stainless steel materials for the steam dryer exposed to reactor coolant water or steam environment using AMP B2.1.12.SER Section 3.0.3.2.11 documents the staff's evaluation of the BWR Vessel Internals Program.The applicant's BWR Vessel Internals Program monitors the condition of the BWR vessel internals for crack initiation and growth. The program includes in-vessel examination and plant water chemistry procedures. The in-vessel examination procedures implement the recommendations of the BWRVIP guidelines as well as the requirements of the ASME Code, 3-164Section XI. As a result of steam dryer failure at Quad Cities following an extended poweruprate, steam dryers have been within the scope of license renewal pursuant to 10 CFR 54.4(a)(2), because it was shown that failure of the NSR component could prevent satisfactory accomplishment of intended functions of SR components. They may exhibit cracking due to flow-induced vibration or cyclic loading and therefore require an AMP.LRA Table 3.1.2-3 identifies AMP B2.1.12 as the applicable program to manage the agingeffect/mechanism of crack initiation and growth due to cyclic loading. The applicant, in note 136of the LRA, stated that it will inspect the steam dryer using the guidelines in the approvedBWRVIP topical report for steam dryer inspection and will reevaluate the inspectionrequirements if it installs a new steam dryer. Because the applicant's steam dryer inspections will be consistent with approved, industry-consensus inspection guidelines, the staff found thatthe applicant's proposed AMP is acceptable to manage the aging effect of crack initiation and growth due to cyclic loading of stainless steel material in the steam dryer exposed to a reactorcoolant water or steam environment.On the basis of its review of the applicant's programs, aging effects, and plant-specific andindustry operating experience, the staff determined that the applicant has demonstrated that theeffects of aging will be adequately managed so that intended functions will be maintainedduring the period of extended operation, as required by 10 CFR 54.21(a)(3).3.1.2.3.4Reactor Coolant System-Reactor Recirculation System-Summary of AgingManagement Evaluation-Table 3.1.2-4The staff reviewed LRA Table 3.1.2-4, which summarizes the results of AMR evaluations for theREC system component groups.In LRA Table 3.1.2-4, the applicant identified no aging effect for stainless steel fasteners, heatexchangers, manifolds, piping and fittings, pump casings, thermowells, and valve bodies exposed to a primary containment air environment.In addition, it identified no aging effects for carbon steel and stainless steel componentsexposed to a lubricating oil environment. SER Section 3.1.2.3 documents the staff's evaluation.On the basis of its review of the applicant's programs, aging effects, and plant-specific andindustry operating experience, the staff determined that the applicant has demonstrated that theeffects of aging will be adequately managed so that intended functions will be maintainedduring the period of extended operation, as required by 10 CFR 54.21(a)(3).3.1.2.3.5Reactor Coolant System-Reactor Vessel Instrumentation-Summary of AgingManagement Evaluation-Table 3.1.2-5The staff reviewed LRA Table 3.1.2-5, which summarizes the results of AMR evaluations for thereactor vessel instrumentation component groups.In LRA Table 3.1.2-5, the applicant identified no aging effect for stainless steel fasteners,manifolds, piping and fittings, restricting orifices, thermowells, and valve bodies exposed to a primary containment air environment. SER Section 3.1.2.3 documents the staff's evaluation.
3-165On the basis of its review of the applicant's programs, aging effects, and plant-specific andindustry operating experience, the staff determined that the applicant has demonstrated that theeffects of aging will be adequately managed so that intended functions will be maintainedduring the period of extended operation, as required by 10 CFR 54.21(a)(3).Conclusion. On the basis of its review, the staff found that the applicant appropriately evaluatedAMR results involving material, environment, AERM, and AMP combinations that the GALL Report does not evaluate. The staff found that the applicant has demonstrated that the effectsof aging will be adequately managed so that intended functions will be maintained consistentwith the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.1.3  Conclusion The staff concluded that the applicant provided sufficient information to demonstrate that theeffects of aging for the RCS components that are within the scope of license renewal and subject to an AMR will be adequately managed so that intended function(s) will be maintainedconsistent with the CLB for the period of extended operation, as required by10 CFR 54.21(a)(3).The staff also reviewed the applicable USAR supplement program summaries and concludedthat they adequately describe the AMPs credited for managing aging of the RCS, as requiredby 10 CFR 54.21(d).3.2  Aging Management of Engineered Safety FeaturesThis section of the SER documents the staff's review of the applicant's AMR results for the ESFcomponents and component groups associated with the following systems:
* automatic pressure relief system
* combustible gas control system
* core spray system
* high pressure coolant injection system
* primary containment mechanical system
* reactor core isolation cooling system
* residual heat removal system
* secondary containm ent system3.2.1  Summary of Technical Information in the Application In LRA Section 3.2, the applicant provided AMR results for the ESF components andcomponent groups. In LRA Table 3.2.1, the applicant provided a summary comparison of its AMRs with the AMRs evaluated in the GALL Report for the ESF components and component groups.The applicant's AMRs incorporated applicable operating experience in the determination ofAERMs. These reviews involved evaluation of plant-specific and industry operating experience.
The plant-specific evaluation included reviews of CRs and discussions with appropriate site personnel to identify AERMs. The applicant's review of industry operating experience included a 3-166review of the GALL Report and operating experience issues identified since the issuance of theGALL Report.3.2.2  Staff Evaluation The staff reviewed LRA Section 3.2 to determine if the applicant provided sufficient informationto demonstrate that the effects of aging for the ESF components that are within the scope oflicense renewal and subject to an AMR will be adequately managed so that intended functionswill be maintained consistent with the CLB for the period of extended operation, as required by10 CFR 54.21(a)(3).In addition, the staff performed an onsite audit of AMRs to confirm the applicant's claim thatcertain identified AMRs are consistent with the GALL Report. The staff did not repeat its reviewof the matters described in the GALL Report; however, the staff did verify that the material presented in the LRA is applicable and that the applicant had identified the appropriate GALLReport AMRs. SER Section 3.0.3 documents the staff's evaluations of the AMPs. The MNGP audit and review report details the staff's audit evaluation, as summarized in SER Section 3.2.2.1.The staff also performed an onsite audit of those selected AMRs that are consistent with theGALL Report and for which further evaluation is recommended. The staff confirmed that the applicant's further evaluations were consistent with the acceptance criteria in Section 3.2.2.2 ofthe SRP-LR. The MNGP audit and review report documents the staff's audit evaluations, which are summarized in SER Section 3.2.2.2.The staff performed an onsite audit and conducted a technical review of the remaining AMRsthat are not consistent with, or not addressed in, the GALL Report. The audit and technicalreview included evaluating whether the applicant identified and evaluated all plausible agingeffects and evaluating whether the aging effects listed are appropriate for the combination ofmaterials and environments specified. The MNGP audit and review report documents the staff's audit evaluations. SER Section 3.2.2.3 documents these audit evaluations as well as the staff'sevaluation of its technical review.Finally, the staff reviewed the AMP summary descriptions in the USAR supplement to ensurethat they adequately describe the programs credited with managing or monitoring aging for theESF components.Table 3.2-1 below summarizes the staff's evaluation of components, aging effects/mechanisms,and AMPs listed in LRA Section 3.2, that are addressed in the GALL Report.
3-167Table 3.2-1  Staff Evaluation for Engineered Safety Features Components in the GALLReportComponent GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff EvaluationPiping, fittings, andvalves inemergency corecooling system(Item Number3.2.1-01)Cumulative fatiguedamageTLAA, evaluated inaccordance with10 CFR 54.21(c)TLAAThis TLAA isevaluated in Section4.3, Metal Fatigueof the RPV andInternals, andReactor CoolantPressure BoundaryPiping andComponentsPiping, fittings,pumps, and valvesin emergency corecooling system(Item Number3.2.1-02)Loss of materialdue to generalcorrosionWater chemistry,one-time inspectionOne-TimeInspection Program(B2.1.23), PlantChemistry Program(B2.1.25) Components incontainment spray(PWR only),standby gastreatment (BWRonly), andcontainmentisolation, andemergency corecooling systems(Item Number3.2.1-03)Loss of materialdue to generalcorrosionPlant specificOne-TimeInspection Program(B2.1.23), SystemConditionMonitoring Program(B2.1.32) Piping, fittings, pumps, and valvesin emergency corecooling system(Item Number3.2.1-04)Loss of materialdue to pitting andcrevice corrosionWater chemistry,one-time inspectionOne-TimeInspection Program(B2.1.23), PlantChemistry Program(B2.1.25) Consistent withGALL, whichrecommends furtherevaluation (seeSection 3.2.2.2.3)Components incontainment spray(PWR only),standby gastreatment (BWRonly), containmentisolation, andemergency corecooling systems(Item Number3.2.1-05)Loss of materialdue to pitting andcrevice corrosionPlant specificOne-TimeInspection Program(B2.1.23), PlantChemistry Program(B2.1.25) Containment isolation valves andassociated piping(Item Number3.2.1-06)Loss of materialdue tomicrobiologicallyinfluenced corrosionPlant specificOne-TimeInspection Program(B2.1.23), PlantChemistry Program(B2.1.25) Consistent withGALL, whichrecommends furtherevaluation (seeSection 3.2.2.2.4)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation3-168Seals in standbygas treatmentsystem(Item Number3.2.1-07)Changes inproperties due toelastomerdegradationPlant specificOne-TimeInspection Program(B2.1.23), SystemConditionMonitoring Program(B2.1.32) Consistent withGALL, whichrecommends furtherevaluation (seeSection 3.2.2.2.5)High-pressuresafety injection(charging) pumpminiflow orifice(Item Number3.2.1-08)Loss of materialdue to erosionPlant specificNot applicable,PWR only (seeSection 3.2.2.2.6)Drywell andsuppressionchamber spraysystem nozzles andflow orifices(Item Number3.2.1-09)Plugging of nozzlesand flow orificesdue to generalcorrosionPlant specificNot applicable (seeSection 3.2.2.2.7)External surface ofcarbon steelcomponents (ItemNumber 3.2.1-10)Loss of materialdue to generalcorrosionPlant specificOne-TimeInspection Program(B2.1.23), SystemConditionMonitoring Program(B2.1.32)Consistent withGALL, whichrecommends furtherevaluation (seeSection 3.2.2.2.2)Piping and fittingsof CASS inemergency corecooling system(Item Number3.2.1-11)Loss of fracturetoughness due tothermal agingembrittlementThermal agingembrittlement of CASSNot applicable.No CASScomponentssusceptible tothermal agingembrittlement inengineered safetyfeaturesComponentsserviced byopen-cycle coolingsystem(Item Number3.2.1-12)Local loss ofmaterial due tocorrosion and/orbuildup of depositdue to biofoulingOpen-cycle coolingwater systemOne-TimeInspection Program(B2.1.23),Open-Cycle CoolingWater SystemProgram (B2.1.24),
Plant ChemistryProgram (B2.1.25) Consistent withGALL Report, whichrecommends nofurther evaluationComponentsserviced byclosed-cycle coolingsystem(Item Number3.2.1-13)Loss of materialdue to general,pitting, and crevicecorrosionClosed-cyclecooling watersystemClosed-CycleCooling WaterSystem Program(B2.1.13)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation3-169Emergency corecooling systemvalves and lines toand from HPCI andRCIC pumpturbines(Item Number3.2.1-14)Wall thinning due toflow-acceleratedcorrosionFlow-acceleratedcorrosionThis line item is notused at MNGP (seeSection 3.2.2.1.1)Pumps, valves,piping, and fittingsin containmentspray andemergency corecooling systems(Item Number3.2.1-15)Crack initiation andgrowth due to SCCWater chemistryNot applicable,PWR onlyPumps, valves,piping, and fittingsin emergency corecooling systems(Item Number3.2.1-16)Crack initiation andgrowth due to SCCand IGSCCWater chemistry,BWR stresscorrosion crackingBWR StressCorrosion CrackingProgram (B2.1.10),One-TimeInspection Program(B2.1.23), PlantChemistry Program(B2.1.25) Consistent withGALL Report, whichrecommends nofurther evaluationCarbon steelcomponents(Item Number3.2.1-17)Loss of materialdue to boric acidcorrosionBoric acid corrosionNot applicable,PWR onlyClosure bolting inhigh-pressure orhigh-temperaturesystems(Item Number3.2.1-18)Loss of materialdue to generalcorrosion, loss ofpreload due tostress relaxation,and crack initiationand growth due tocyclic loading or SCCBolting integrityBolting IntegrityProgram (B2.1.4) Consistent withGALL Report, whichrecommends nofurther evaluationThe staff's review of the MNGP component groups followed one of several approaches. Oneapproach, documented in Section 3.2.2.1, involves the staff's review of the AMR results forcomponents in the ESF systems that the applicant indicated are consistent with the GALLReport and do not require further evaluation. Another approach, documented in Section 3.2.2.2,involves the staff's review of the AMR results for components in the ESF systems that theapplicant indicated are consistent with the GALL Report and for which further evaluation isrecommended. A third approach, documented in Section 3.2.2.3, involves the staff's review ofthe AMR results for components in the ESF systems that the applicant indicated are notconsistent with, or not addressed in, the GALL Report. SER Section 3.0.3 documents the staff'sreview of AMPs that are credited to manage or monitor aging effects of the ESF systemscomponents.
3-1703.2.2.1  AMR Results That Are Consistent with the GALL ReportSummary of Technical Information in the Application. In LRA Section 3.2.2.1, the applicantidentified the materials, environments, and AERMs. The applicant identified the following programs that manage the aging effects related to the ESF components:
* ASME Section XI In-Service Inspection, Subsections IWB, IWC, and IWDProgram (B2.1.2)
* Bolting Integrity Program (B2.1.4)
* Buried Piping & Tanks Inspection Program (B2.1.5)
* BWR Stress Corrosion Cracking Program (B2.1.10)
* Closed-Cycle Cooling Water System Program (B2.1.13)
* Flow-Accelerated Corrosion Program (B2.1.19)
* One-Time Inspection Program (B2.1.23)
* Open-Cycle Cooling Water System Program (B2.1.24)
* Plant Chemistry Program (B2.1.25)
* Selective Leaching of Materials Program (B2.1.30)
* System Condition Monitoring Program (B2.1.32)Staff Evaluation. In LRA Tables 3.2.2-1 through 3.2.2-8, the applicant summarized the AMRsfor the ESF components and identified which AMRs it considered to be consistent with the GALL Report.For component groups evaluated in the GALL Report for which the applicant has claimedconsistency with the GALL Report, and for which the GALL Report does not recommend further evaluation, the staff performed an audit and review to determine whether the GALL Reportevaluation bounds the plant-specific components contained in these GALL Report componentgroups.The applicant provided a note for each AMR line item. The notes describe the relationship ofthe information in the tables to the information in the GALL Report. The staff audited thoseAMRs with Notes A through E, which indicate that 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 AMP identified in the GALL Report. The staff audited these line items to verify consistency with the GALL Report and the validity of the AMR for the site-specific conditions.Note B 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 AMP identified in the GALL Report. The staff audited these line items to verify consistency with the GALL Report. The staff verified that the staff had reviewed and accepted the identifiedexceptions to the GALL Report AMPs. The staff also determined whether the AMP identified by 3-171the applicant is consistent with the AMP identified in the GALL Report and whether the AMR isvalid for the site-specific conditions.Note C indicates that the component for the AMR line item, although different, is consistent withthe GALL Report for material, environment, and aging effect. In addition, the AMP is consistent with the AMP identified by the GALL Report. This note indicates that the applicant could not finda listing of some system components in the GALL Report. However, the applicant identified adifferent component in the GALL Report that has 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 determined whether the AMR line item of the different component is applicable to the component under review and whether the AMR is valid for the site-specific conditions.Note D indicates that the component for the AMR line item, although different, is consistent withthe GALL Report for material, environment, and aging effect. In addition, the AMP takes some exceptions to the AMP identified in the GALL Report. The staff audited these line items to verify consistency with the GALL Report. The staff verified whether the AMR line item of the different component applies to the component under review. The staff verified whether it had reviewed and accepted the identified exceptions to the GALL Report AMPs. The staff also determinedwhether the AMP identified by the applicant is consistent with the AMP identified in the GALLReport and whether the AMR is 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 the applicant credited a different AMP. The staff audited these line items to verify consistency with the GALL Report. The staff also determined whether the identified AMP will manage the aging effect consistent with the AMP identified by the GALLReport and whether the AMR is valid for the site-specific conditions.The staff conducted an audit and review of the information provided in the LRA, as documentedin the MNGP audit and review report. The staff did not repeat its review of the matters described in the GALL Report; however, the staff did verify that the material presented in the LRA is applicable and that the applicant identified the appropriate GALL Report AMRs. The following sections discuss the staff's evaluation.3.2.2.1.1  Wall Thinning Due to Flow-Accelerated Corrosion In the discussion section of LRA Table 3.2.1, Item Number 3.2.1-14, the applicant stated thefollowing:Aging effect is managed by the Flow-Accelerated Corrosion program.
Consistent with NUREG-1801, some sections of the High Pressure CoolantInjection (HPC) and Reactor Core Isolation Cooling (RCI) systems aresusceptible to flow-accelerated corrosion (FAC) and the Flow-Accelerated Corrosion Program is credited to manage the aging effect. The predominate sections of the HPC and RCI systems were evaluated as not susceptible to FACbased on material type or the components have no flow or operate less than 2%
of the plant operating time. The components that fall in the latter category do notrequire aging management for FAC in accordance with EPRI, NSAC-202L, R2 3-172 and NUREG-1557, 'Summary of Technical Information and Agreements from theNuclear Regulatory Management and Resources Council Industry Reports Addressing License Renewal.'During the audit and review, the staff noted that the applicant did not use Table 3.2.1, Item3.2.1-14, for Table 2 data. The staff reviewed the GALL Report (Sections V.D2.1-f, V.D2.3-a),which contains no line item covering ECCS piping in treated water susceptible to FAC. The applicant did not use Table 3.2.1, Item 3.2.1-14; instead, the applicant included ECCS pipingand fittings exposed to treated water and susceptible to FAC in LRA Table 3.1.1, Item 3.1.1-25.This line item was a better match for the GALL Report (Section IV.C1.1-c) for materials, environment, aging effects, and components. The staff asked the applicant the reason for crediting another line item for this aging effect. The applicant responded that the GALL Report, Chapter V, contains no line item for ECCS piping in treated water susceptible to FAC; for this reason, the applicant did not use this line item. Instead the applicant used Table 1 Item 3.1.1-25as a better match with the GALL Report (Section IV.C.1.1-c). By its letter dated August 11, 2005, the applicant revised the LRA Table 1, Item 3.2.1-14, from "Aging effect is managed bythe FAC Program," to, "This line item is not used at MNGP."On this basis, the staff found this program acceptable for managing aging of wall thinning dueto FAC for some sections of the HPC and RCI systems. SER Section 3.0.3.1.2 documents thestaff evaluation of the FAC Program.On the basis of its review, the staff found that the applicant addressed the agingeffect/mechanism as identified in the GALL Report.Conclusion. The staff evaluated the applicant's claim of consistency with the GALL Report. Thestaff also reviewed information pertaining to the applicant's consideration of recent operating experience and proposals for managing associated aging effects. The staff's review concluded that the AMR results, which the applicant claimed to be consistent with the GALL Report, areconsistent with the AMRs in the GALL Report; therefore, the staff concluded that the applicanthas demonstrated that the effects of aging for these components will be adequately managedso that their intended function(s) will be maintained consistent with the CLB for the period ofextended operation, as required by 10 CFR 54.21(a)(3).3.2.2.2AMR Results That Are Consistent with the GALL Report, for Which Further EvaluationIs RecommendedSummary of Technical Information in the Application. In LRA Section 3.2.2.2, the applicantprovided further evaluation of aging management as recommended by the GALL Report for the ESF components. The applicant provided information concerning its management of the following aging effects:
* cumulative fatigue damage
* loss of material due to general corrosion
* local loss of material due to pitting and crevice corrosion
* local loss of material due to microbiologically influenced corrosion
* changes in properties due to elastomer degradation
* local loss of material due to erosion
* buildup of deposits due to corrosion 3-173Staff Evaluation. For component groups evaluated in the GALL Report for which the applicanthas claimed consistency with the GALL Report, and for which the GALL Report recommends further evaluation, the staff audited and reviewed the applicant's evaluation to determinewhether it adequately addressed the issues that were further evaluated. In addition, the staffreviewed the applicant's further evaluations against the criteria contained in Section 3.2.2.2 ofthe SRP-LR. The staff's audit and review report details the staff's audit. The following sections discuss the staff's evaluation of the aging effects.3.2.2.2.1  Cumulative Fatigue Damage In LRA Section 3.2.2.2.1, the applicant stated that fatigue is a TLAA, as defined in10 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 General Corrosion The staff reviewed LRA Sections 3.2.2.2.2.1 and 3.2.2.2.2.2 against the criteria in SRP-LRSection 3.2.2.2.2.In LRA Section 3.2.2.2.2.1, the applicant addressed the loss of material due to generalcorrosion of piping, fittings, pumps, and valves in the ECCS. The applicant stated that the One-Time Inspection Program or a combination of the One-Time Inspection Program and Plant Chemistry Program manages the aging effect.SRP-LR Section 3.2.2.2.2 states the following:The management of loss of material due to general corrosion of pumps, valves,piping, and fittings associated with some of the BWR emergency core cooling systems (high-pressure coolant injection, reactor core isolation cooling, high-pressure core spray, low-pressure core spray, low-pressure coolant injection (residual heat removal)) and with lines to the suppression chamber and to the drywell and suppression chamber spray system should be furtherevaluated. The existing aging management program relies on monitoring and control of primary water chemistry based on BWRVIP 29 (EPRI TR-103515) for BWRs to mitigate degradation. However, control of primary water chemistry does not preclude loss of material due to general corrosion at locations of stagnant flow conditions. Therefore, verification of the effectiveness of the chemistry control program should be performed to ensure that corrosion is not occurring.
The GALL Report recommends further evaluation of programs to manage loss of material due to general corrosion to verify the effectiveness of the chemistry control program. A one-time inspection of select components at susceptible locations is an acceptable method to determine whether an aging effect is not occurring or an aging effect is progressing very slowly such that the component's intended function will be maintained during the period of extended operation.In LRA Section 3.2.2.2.2.1, the applicant stated that loss of material due to general corrosion ofpiping, fittings, pumps, and valves could occur in the ECCS and will be managed by theOne-Time Inspection Program, or a combination of the One-Time Inspection Program and the Plant Chemistry Program. The applicant stated that, when applied in combination with the Plant 3-174Chemistry Program, the scope of the One-Time Inspection Program incorporates activities toverify the effectiveness of the Plant Chemistry Program, including a sample of components where the flow of water is low or stagnant conditions exist.SER Sections 3.0.3.1.4 and 3.0.3.2.19 document the staff's evaluations of the One-TimeInspection Program and the Plant Chemistry Program, respectively.The applicant, in the LRA, included some component types subject to general corrosion(fans/blower housings and turbines) not consistent with the GALL Report; however, the materials, environments, and aging effects are similar. The staff found that these items will beproperly managed during the period of extended operation. In addition, there are some agingmechanisms, galvanic corrosion and MIC, covered in LRA Section 3.2.2.2.2, managed by the One-Time Inspection Program and Plant Chemistry Program not consistent with the GALL Report. The staff requested that the applicant explain why it added these aging mechanisms.The applicant responded that these mechanisms could cause the aging effect, loss of material, and that this approach was conservative. The staff concluded that the applicant had taken a conservative approach to aging management and was consistent with the GALL Report.Based on the technical information provided in LRA Section 3.2 and review of the One-TimeInspection and Plant Chemistry Programs, the staff found that the applicant appropriately addressed the aging effect/mechanism of loss of material due to general corrosion of pumps, valves, piping, and fittings associated with some of the ECCSs (HPC, RCI, low-pressure CSP, LPCI (RHR)) and lines to the suppression chamber and to the drywell and suppression chamber spray system for components in the ESF systems.In LRA Section 3.2.2.2.2.2, the applicant addressed the loss of material due to generalcorrosion of components in the standby gas treatment and containment isolation systems, andECCS. The applicant stated that the One-Time Inspection Program or the System ConditionMonitoring Program manages the aging effect.SRP-LR Section 3.2.2.2.2.2 states the following:Loss of material due to general corrosion could occur in the drywell andsuppression chamber spray (BWR) systems header and spray nozzlecomponents, standby gas treatment system components (BWR), containmentisolation valves and associated piping, the automatic depressurization systempiping and fittings (BWR), emergency core cooli ng system header piping andfittings and spray nozzles (BWR), and the external surfaces of BWR carbon steel components. The GALL Report recommends further evaluation on a plant-specific basis to ensure that the aging effect is adequately managed.The applicant stated in LRA Section 3.2.2.2.2.2, that the One-Time Inspection Program and/orthe System Condition Monitoring Program manages the aging effect for an air/gas environment.The LRA describes the One-Time Inspection Program as a new AMP. The scope of this newAMP includes activities to verify potential long incubation periods for certain aging effects on SCs. The environments applicable to this item are characteristic of long incubation periods (air/gas environments with the potential for moisture). The staff evaluated the One-TimeInspection Program and found it acceptable for managing the aging effects of loss of material 3-175due to general corrosion. SER Section 3.0.3.1.4 documents the evaluation of the One-TimeInspection Program.The LRA describes the System Condition Monitoring Program as an existing plant-specificprogram that manages aging effects for normally accessible, external surfaces of piping, tanks, and other components and equipment within the scope of license renewal. The applicant manages these aging effects through visual inspection and monitoring of external surfaces for leakage and evidence of material degradation.The staff considers visual inspection an examination technique capable of detecting loss ofmaterial due to various aging mechanisms (e.g., general or galvanic corrosion) on the exterior surface of components, and the staff considers an examination frequency of once per year or per refueling outage adequate for the detection of this effect before the loss of component function occurs. The staff's review found the System Condition Monitoring Program acceptable for managing aging of general corrosion during the period of extended operation. SER Section 3.0.3.3.2 documents the evaluation of the System Conditioning Monitoring Program.The System Conditioning Monitoring Program and One-Time Inspection Program cover agingmanagement in the drywell and suppression chamber spray, systems header and spray nozzlecomponents, standby gas treatment system (SGTS) components, containment isolation valvesand associated piping, the automatic depressurizati on system piping and fittings, ECCS headerpiping and fittings and spray nozzles, and the external surfaces of carbon steel components.On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LRSection 3.2.2.2.2. For those line items that apply to LRA Sections 3.2.2.2.2.1 and 3.2.2.2.2.2,the staff determined that the applicant's AMRs are consistent with the GALL Report and theapplicant has demonstrated that the effects of aging will be adequately managed so that theintended function(s) will be maintained consistent with the CLB during the period of extendedoperation, as required by 10 CFR 54.21(a)(3).3.2.2.2.3  Local Loss of Material Due to Pitting and Crevice Corrosion The staff reviewed LRA Sections 3.2.2.2.3.1 and 3.2.2.2.3.2 against the criteria in SRP-LRSection 3.2.2.2.3.In LRA Section 3.2.2.2.3.1, the applicant addressed the loss of material due to pitting andcrevice corrosion of piping, fittings, pumps, and valves in the ECCS. The applicant stated that the One-Time Inspection Program, or the combination of the One-Time Inspection Program and Plant Chemistry Program, manages the aging effect.SRP-LR Section 3.2.2.2.3 states the following:The management of local loss of material due to pitting and crevice corrosion ofpumps, valves, piping, and fittings associated with some of the BWR emergency core cooling system piping and fittings (high-pressure coolant injection, reactorcore isolation cooling, high-pressure core spray, low-pressure core spray, low-pressure coolant injection (residual heat removal)) and with lines to the suppression chamber and to the drywell and suppression chamber spray systemshould be evaluated further. The existing aging management program relies on 3-176monitoring and control of primary water chemistry based on EPRI guidelines ofTR-105714 for PWRs and BWRVIP 29 (EPRI TR-103515) for BWRs to mitigate degradation. However, control of coolant water chemistry does not preclude loss of material due to crevice and pitting corrosion at locations of stagnant flow conditions. Therefore, verification of the effectiveness of the chemistry control program should be performed to ensure that corrosion is not occurring. The GALL Report recommends further evaluation of programs to manage the loss of material due to pitting and crevice corrosion to verify the effectiveness of the chemistry control program. A one-time inspection of select components at susceptible locations is an acceptable method to determine whether an aging effect is not occurring or an aging effect is progressing very slowly so that the component's intended function will be maintained during the period of extendedoperation.In LRA Section 3.2.2.2.3.1, the applicant addressed loss of material due to pitting and crevicecorrosion of piping, fittings, pumps, and valves in the ECCS. The applicant stated that the One-Time Inspection Program, or the combination of the One-Time Inspection Program and Plant Chemistry Program, manages the aging effect. When applied in combination with the Plant Chemistry Program, the scope of the One-Time Inspection Program incorporates activities to verify the effectiveness of the Plant Chemistry Program, including a sample of components where the flow of water is low or stagnant conditions exist. Implementation of the One-Time Inspection Program and the Plant Chemistry Program to manage the aging effect provides added assurance that the aging effect is not occurring or that the aging effect isprogressing very slowly, such that the component's intended function will be maintained duringthe period of extended operation.As documented in the audit and review report, the applicant stated that in some instances, thecomponent within the scope of license renewal has an environment that does not lend itself to benefits from the Plant Chemistry Program (low-flow stagnant conditions, or an air/gas environment). The staff determined that the use of the One-Time Inspection Program alone incertain cases, such as no-flow conditions, in which the use of the Plant Chemistry Program is not a viable option, is acceptable. The staff concluded, based on MNGP technical procedures,that this is an appropriate aging management method based on the details of the program'ssampling locations, frequencies, and corrective actions.The applicant uses the One-Time Inspection Program, or the combination of the One-TimeInspection Program and the Plant Chemistry Program, to manage the aging effect/mechanism of loss of material due to pitting and crevice corrosion for areas of stagnant flow. The staff evaluated the One-Time Inspection Program and Plant Chemistry Program, as documented in SER Sections 3.0.3.1.4 and 3.0.3.2.19, respectively.The staff reviewed the applicant's programs credited for aging management for the materials,environment, and aging effects/mechanisms. The pumps, valves, piping, and fittings associated with some of the BWR ECCS piping and fittings (HPC, RCI, low-pressure CSP, LPCI (RHR))and with lines to the suppression chamber and to the drywell and suppression chamber spray system are subject to local loss of material due to pitting and crevice corrosion. The One-TimeInspection Program or the combination of the Plant Chemistry Program and the One-Time Inspection Program manages the aging effects.
3-177In LRA Section 3.2.2.2.3.2, the applicant addressed loss of material due to pitting and crevicecorrosion of components in the standby gas treatment and containment isolation systems, andECCS. The applicant stated that the One-Time Inspection Program, or the combination of theOne-Time Inspection Program and Plant Chemistry Program, manages the aging effect.SRP-LR Section 3.2.2.2.3.2 states the following:Local loss of material from pitting and crevice corrosion could occur in thecontainment isolation valves and associated piping, and automaticdepressurizati on system piping and fittings (BWR). The GALL Reportrecommends further evaluation to ensure that the aging effect is adequately managed.In LRA Section 3.2.2.2.3.2, the applicant stated that the One-Time Inspection Program is a newAMP. The scope of this new AMP will include activities to verify potential long incubationperiods for certain aging effects on SCs. The environments applicable to this item are characteristic of long incubation periods (air/gas environments with the potential for moisture).This program is sometimes used by itself in locations where the Plant Chemistry Program will not be effective (such as air/gas or low-flow/stagnant environments). The staff determined that the use of the One-Time Inspection Program alone in certain cases, such as no-flow conditions, in which the use of the Plant Chemistry Program is not a viable option, is acceptable.The staff evaluated the Plant Chemistry and One-Time Inspection Programs and found themacceptable for managing the aging effect of local loss of material from pitting and crevice corrosion that could occur in the containment isolation valves and associated piping, and ADSpiping and fittings. SER Sections 3.0.3.2.19 and 3.0.3.1.4 document the staff's evaluation of thePlant Chemistry Program and One-Time Inspection Program, respectively.The staff evaluated both of these AMPs with respect to applications to the materials,environment, and aging effects. The applicant included an additional aging mechanism (galvanic corrosion) not consistent with the GALL Report (Sections V.C.1-a/b, V.D2.1-e). Thestaff determined that the applicant used a conservative approach for aging management byincluding this additional aging mechanism, and that this is consistent with the GALL Report for the aging effect.3.2.2.2.4  Local Loss of Material Due to Microbiologically Influenced CorrosionThe staff reviewed LRA Section 3.2.2.2.4 against the criteria in SRP-LR Section 3.2.2.2.4.In LRA Section 3.2.2.2.4, the applicant addressed loss of material due to MIC of valves andassociated piping in containment isolation.
3-178SRP-LR Section 3.2.2.2.4 states the following:Local loss of material due to microbiologically influenced corrosion (MIC) couldoccur in BWR and PWR containment isolation valves and associated piping in systems that are not addressed in other chapters of the GALL Report. The GALLReport recommends further evaluation to ensure that the aging effect is adequately managed.Although the applicant does not use this line item at MNGP, the loss of material due to MIC ispredicted for ESF system valve bodies and associated piping. The applicant credited acombination of the Plant Chemistry Program and the One-Time Inspection Program for the aging effect. The staff evaluated the Plant Chemistry Program and One-Time Inspection Program and found them acceptable for managing aging of local loss of material from MIC that could occur in the containment isolation valves and associated piping, and ADS piping andfittings. SER Sections 3.0.3.2.19 and 3.0.3.1.4 document the evaluation of the Plant ChemistryProgram and One-Time Inspection Program, respectively.The applicant's LRA is consistent with the GALL Report (Section V.C.1-a/b) for components,materials, environment, and programs for managing aging for the containment isolation valves.
Based on the information provided by the applicant, as noted in the LRA, the staff's review and audit found that the applicant's AMPs are acceptable for management of loss of material due to MIC for the containment isolation valves and associated piping.3.2.2.2.5  Changes in Properties Due to Elastomer DegradationThe staff reviewed LRA Section 3.2.2.2.5 against the criteria in SRP-LR Section 3.2.2.2.5.In LRA Section 3.2.2.2.5, the applicant addressed the change in material properties of seals inthe SGTS. The applicant stated that the One-Time Inspection Program manages the agingeffect for the internal environment and the System Condition Monitoring Program manages it for the external environment. The System Condition Monitoring Program is an existing plant-specific program.SRP-LR Section 3.2.2.2.5 states the following:Changes in properties due to elastomer degradation could occur in sealsassociated with the standby gas treatm ent system ductwork and filters. TheGALL Report recommends further evaluation to ensure that the aging effect is adequately managed.The One-Time Inspection Program is a new AMP, the scope of which includes activities toverify potential long incubation periods for certain aging effects on SCs. The environments 3-179applicable to this item are characteristic of long incubation periods (high-temperature air orozone). The staff evaluated the One-Time Inspection Program and found it acceptable and consistent with the GALL Report for managing this aging effect. SER Section 3.0.3.1.4documents the evaluation of the One-Time Inspection Program.The System Condition Monitoring Program is an existing plant-specific program that is based on system engineer monitoring, and it is used to manage the aging effect/mechanisms onsystem components in the ESF, including elastomer degradation of seals in the SGTS ductworkand filters. The staff reviewed the System Condition Monitoring Program and found it acceptable and consistent with the GALL Report for managing this aging effect/mechanism.
SER Section 3.0.3.3.2 documents the evaluation of the System Condition Monitoring Program.The staff reviewed the applicant's use of the One-time Inspection Program and SystemMonitoring Program (which is periodic) and determined that it is acceptable and consistent with the GALL Report (Sections V.B.1-b, V.B.2-b) as the programs will verify the condition of theelastomer seals and provide reasonable assurance that hardening and cracking do not occur.
The staff found that the materials, environment, aging effects, and the aging programs are consistent with the GALL Report. The applicant manages these aging effects through visual inspection of internal surfaces and monitoring of external surfaces for leakage and evidence of material degradation.On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LRSection 3.2.2.2.5. For those line items that apply to LRA Secti on 3.2.2.2.5, the staff determinedthat the applicant's AMRs are consistent with the GALL Report and the applicant hasdemonstrated that the effects of aging will be adequately managed so that the intendedfunction(s) will be maintained consistent with the CLB during the period of extended operation,as required by 10 CFR 54.21(a)(3).3.2.2.2.6  Local Loss of Material Due to Erosion The staff reviewed LRA Section 3.2.2.2.6 against the criteria in SRP-LR Section 3.2.2.2.6.In LRA Section 3.2.2.2.6, the applicant stated that this aging effect applies to PWRs only.SRP-LR Section 3.2.2.2.6 states that local loss of material due to erosion could occur in thehigh-pressure safety injection pump miniflow orifice. SRP-LR Table 3.2-1 states that further evaluation for this aging effect is for PWR plants only.The staff found this aging effect not applicable.
3.2.2.2.7  Buildup of Deposits Due to Corrosion The staff reviewed LRA Section 3.2.2.2.7 against the criteria in SRP-LR Section 3.2.2.2.7.In LRA Section 3.2.2.2.7, the applicant addressed plugging of nozzles and flow orifices in thedrywell and suppression chamber spray system due to general corrosion. The drywell andsuppression chamber spray system nozzles are fabricated from copper alloy materials, whichare not susceptible to loss of material (plugging of nozzles and flow orifices) due to general 3-180corrosion; therefore, no aging management is required. The associated GALL Report line item(Section V.D2.5-b) does not evaluate copper alloy material.SRP-LR Section 3.2.2.2.7 states the following:The plugging of components due to general corrosion could occur in the spraynozzles and flow orifices of the drywell and suppression chamber spray system.This aging mechanism and effect will apply since the spray nozzles and floworifices are occasionally wetted, even though the majority of the time this systemis on standby. The wetting and drying of these components can aid in the acceleration of this particular corrosion. The GALL Report recommends further evaluation to ensure that the aging effect is adequately managed.The staff reviewed the GALL Report (Section V.D2.5-b), which addresses only carbon steel inan air environment for drywell suppression chamber spray systems. The materials at MNGP aremade of copper in an air/potential water environment, which the GALL Report does not address. After reviewing documentation from the GALL Report for aging effects, materials, and environments, the staff concurred that these nozzles are not subject to aging effects in the environments listed according to material science evaluations (as noted below) and, therefore,are not susceptible to corrosion product buildup that could cause plugging.As shown in the Metals Handbook, Ninth Edition, Volume 13, "Corrosion," comprehensive testsover a 20-year period under the supervision of ASTM confirmed the suitability of copper alloysfor atmospheric exposure. Additionally, the gaseous internal environments to which components within the scope of license renewal may be subject include air, nitrogen, carbon dioxide, freon, and halon. Industry experience suggests that copper piping exposed to an internal gaseous operating condition will be resistant to any age-related degradation; therefore,the SC will remain capable of performing intended functions consistent with the CLB for theperiod of extended operation.On the basis of its review of current industry research and operating experience, the staff foundthat effects of the listed environments on the listed materials will not cause aging of concern during the period of extended operation; therefore, the staff concluded that there are noapplicable AERMs for the component material and environment described in the preceding discussion.On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LRSection 3.2.2.2.7. For those line items that apply to LRA Secti on 3.2.2.2.7, the staff determinedthat the applicant's AMRs are consistent with the GALL Report and the applicant hasdemonstrated that the effects of aging will be adequately managed so that the intendedfunction(s) will be maintained consistent with the CLB during the period of extended operation,as required by 10 CFR 54.21(a)(3).Conclusion. On the basis of its review, for component groups evaluated in the GALL Report forwhich the applicant has claimed consistency with the GALL Report, and for which the GALL Report recommends further evaluation, the staff determined that the applicant adequatelyaddressed the issues that were further evaluated. The staff found that the applicant hasdemonstrated that the effects of aging will be adequately managed so that intended functions 3-181will be maintained consistent with the CLB for the period of extended operation, as required by10 CFR 54.21(a)(3).3.2.2.3  AMR Results That Are Not Consistent with or Not Addressed in the GALL ReportSummary of Technical Information in the Application. In LRA Tables 3.2.2-1 through 3.2.2-8,the staff reviewed additional details of the results of the AMRs for material, environment, AERM, and AMP combinations that are not consistent with the GALL Report, or that are notaddressed in the GALL Report.In LRA Tables 3.2.2-1 through 3.2.2-8, the applicant indicated, via Notes F through J, that thecombination of component type, material, environment, and AERM does not correspond to a line item in the GALL Report, and provided information concerning the management of the aging effect. Specifically, Note F indicates that the GALL Report does not evaluate the material for the AMR line item component. Note G indicates that the GALL Report does not evaluate the environment for the AMR line item component and material. Note H indicates that the GALL Report does not evaluate the aging effect for the AMR line item component, material, and environment combination. Note I indicates that the aging effect identified in the GALL Report forthe line item component, material, and environment combination is not applicable. Note J indicates that the GALL Report evaluates neither the component nor the material andenvironment combination for the line item.Staff Evaluation. For component type, material, and environment combinations that the GALLReport does not evaluate, the staff reviewed the applicant's evaluation to determine whether theapplicant had demonstrated that the effects of aging will be adequately managed so that theintended function(s) will be maintained consistent with the CLB during the period of extendedoperation. The following sections discuss the staff's evaluation.In LRA Tables 3.2.2-1 through 3.2.2-8, the staff identified AMR line items for which theapplicant stated that there were no aging effects as a result of the AMR process. In mostinstances, the applicant identified materials that have no aging effects in the environments theyare exposed to during plant operations. The applicant stated that no aging effects occur forESF system components fabricated from the following materials:  *copper    *carbon steel
  *nickel alloy
  *stainless steel
  *CASS
  *insulationThese materials are exposed to the following environments:
  *plant indoor air (external/internal)  *primary containment air (external/internal)
  *air/gas (internal)
  *gas-instrument air (internal)
  *gas-nitrogen (internal) 3-182  *lubricating oil (external/internal)  *outdoor air protectedThe applicant stated that components fabricated from these materials in these environmentshave no aging effects based on material science evaluations of these materials exposed to atmospheric conditions. Specifically, the applicant stated that no aging effects occur whencomponents fabricated from stainless steel material are exposed to a primary containment air, plant indoor air (and outdoor air protected), lubricating oil, or gas (instrument air) environment,or when components fabricated from copper alloys are exposed to a primary containment air, plant indoor air, lubricating oil, or gas (instrument air) environment. The applicant also stated that no aging effects occur in components fabricated from carbon steel in a gas (nitrogen or instrument air) or lubricating oil environment. In addition, the applicant stated that no agingeffects occur in components fabricated from CASS or nickel alloys in a primary containment air or plant indoor air environment. The applicant stated that a material science evaluation for these materials in these environments found no aging effects.The GALL Report states that steel, copper, nickel alloy, and stainless steel in an environment ofplant indoor air (external), gas, and lubricating oil are not subject to any aging mechanisms.
The staff reviewed this technical information against LRA Tables 3.2.2-1 through 3.2.2-8 and concluded that the applicant's analysis of the material and environment combinations will allowcomponents within the scope of license renewal fabricated from these materials in these environments to perform their intended functions through the period of extended operation. Thisconclusion is based on industry and plant operating experience of these components in these environments.As cited in Metals Handbook, Ninth Edition, Volume 13, stainless steels are highly resistant tocorrosion in dry atmospheres in the absence of corrosive species; therefore, stainless steel in an indoor, uncontrolled air environment (e.g., plant indoor air) or in a gas environment (e.g.,
primary containment air inerted with nitrogen) exhibits no aging effect, and such an SC willremain capable of performing intended functions consistent with the CLB for the period of extended operation. Because both oxygen and moisture must be present to corrode steel, as cited in Metals Handbook, Ninth Edition, steel (carbon or stainless) and copper alloys in alubricating oil internal environment with no water pooling exhibit no aging effect, and such an SC will therefore remain capable of performing intended functions consistent with the CLB forthe period of extended operation. Because components fabricated from CASS, copper, andnickel alloys are highly resistant to corrosion in dry atmospheres in the absence of corrosive species, as cited in the Metals Handbook, Ninth Edition, the staff accepted the position thatCASS, copper, and nickel alloys in an indoor (primary containment), uncontrolled air environment (e.g., plant indoor air), or gas environment (e.g., plant instrument air) exhibit no aging effect, and such SCs will therefore remain capable of performing intended functionsconsistent with the CLB for the period of extended operation.LRA Tables 3.2.2.4 and 3.2.2.7 list insulation for piping and heat exchangers in the HPC andRHR systems exposed to plant indoor air. LRA Section 3.2.1 states that the GALL Report doesnot show this material for this component as subject to aging management.The staff reviewed technical information based on industry experience and concluded that theapplicant's analysis of the material and environment is acceptable, and insulation exposed to 3-183plant indoor air will remain capable of performing its intended function during the period ofextended operation.The staff reviewed the materials and environments for this section and compared thisinformation with the technical references noted above. Except for carbon steel in outdoor air, the ESF components fabricated from carbon steel, nickel alloy, stainless steel, CASS, and insulation subject to plant indoor air (external/internal), primary containment air (external/internal), air/gas (internal), gas (instrument air/nitrogen), lubricating oil (external/internal), or outdoor air are not subject to aging effects/mechanisms.On the basis of its review of current industry research and operating experience, the staff foundthat the listed materials in the listed environments will not experience aging effects of concern during the period of extended operation; therefore, the staff concluded that there are noapplicable AERMs for the component material and environment described in the preceding discussion.3.2.2.3.1Engineered Safety Features-Automatic Pressure Relief System-Summary ofAging Management Evaluation-Table 3.2.2-1The staff reviewed LRA Table 3.2.2-1, which summarizes the results of AMR evaluations for theautomatic pressure relief system component groups.All line items in this table are consistent with the GALL Report or are included in the discussionin Section 3.2.2.3 above.3.2.2.3.2Engineered Safety Features-Combustible Gas Control System-Summary of AgingManagement Evaluation-Table 3.2.2-2In its letter dated March 15, 2006, the applicant stated that it deactivated the CGC system bycutting and capping process lines connecting to interfacing systems during the 2005 refuelingoutage because of NRC approval of License Amendment 138, which eliminated therequirements for hydrogen recombiners and relaxed the requirements for hydrogen and oxygen monitoring. Therefore, the system has been removed from the scope of license renewal.3.2.2.3.3Engineered Safety Features-Core Spray System-Summary of Aging ManagementEvaluation-Table 3.2.2-3The staff reviewed LRA Table 3.2.2-3, which summarizes the results of AMR evaluations for theCSP system component groups.In LRA Table 3.2.2-3, the applicant proposed to manage loss of material due to crevicecorrosion, MIC, and pitting corrosion of copper alloys for ESF heat exchangers exposed to a raw water environment using the Open-Cycle Cooling Water Program.The OCCW System Program relies on the implementation of the recommendations of GL 89-13to ensure that the effects of aging on the raw water service water systems will be managed forthe period of extended operation. This program manages the aging effects of meta lliccomponents in water systems (e.g., piping and heat exchangers) exposed to raw, untreated(e.g., service) water. The staff reviewed the OCCW System Program and found it to be 3-184acceptable and consistent with the GALL Report. SER Section 3.0.3.1.5 documents theevaluation of the OCCW System Program. The staff determined that this AMP is adequate formanaging this material, environment, and aging effect.In LRA Table 3.2.2-3, the applicant proposed to manage loss of material due to selectiveleaching of copper alloys for ESF heat exchangers in a raw water environment using the Selective Leaching of Materials Program.The staff reviewed the applicant's Selective Leaching of Materials Program, and SERSection 3.0.3.2.22 documents its evaluation. This new program includes a one-time visualinspection and hardness measurement of certain components susceptible to selective leaching.
The program will determine if selective leaching occurs for certain components. The staffdetermined that this AMP is adequate for managing this material, environment, and aging effect.the aging effect of loss of material dueto crevice corrosion, MIC, and pitting corrosion and loss of material due to selective leaching of copper alloys for ESF heat exchangers exposed to raw water environment in LRA Table 3.2.2-3 are effectively managed using the OCCW System Program and the Selective Leaching of Materials Program, respectively.3.2.2.3.4Engineered Safety Features-High-Pressure Coolant Injection System-Summaryof Aging Management Evaluation-Table 3.2.2-4The staff reviewed LRA Table 3.2.2-4, which summarizes the results of AMR evaluations for theHPC system component groups.In LRA Table 3.2.2-4, the applicant proposed to manage heat transfer degradation and foulingof heat exchangers fabricated from copper alloy in lubricating oil (external)/treated water (internal) environments with the One-Time Inspection Program, and in steam (external)/treated water (internal) environments using the Plant Chemistry Program combined with the One-TimeInspection Program. The applicant also proposed to manage the loss of material due to crevice corrosion and pitting corrosion of heat exchangers fabricated from copper alloy in steam (external)/treated water (internal) environments, and MIC in a treated water (internal) environment using the Plant Chemistry Program, combined with the One-Time Inspection Program.The staff reviewed the applicant's Plant Chemistry Program and the One-Time InspectionProgram, and SER Sections 3.0.3.2.19 and 3.0.3.1.4, respectively, document its evaluation ofeach. The Plant Chemistry Program mitigates the aging effects on component surfaces exposed to water as the process fluid; chemistry programs are used to control water chemistry for impurities (e.g., chloride and sulfate) that accelerate corrosion or crack initiation and growth or that cause heat transfer degradation due to fouling in select heat exchangers. This program relies on monitoring and control of water chemistry to keep peak levels of various contaminants below system-specific limits. The new One-Time Inspection Program is consistent with therecommendations of GALL AMP XI.M32. This program will include measures to verify theeffectiveness of the Plant Chemistry Program. This program will also confirm the absence of age degradation in selected components (e.g., flow restrictors, venturis, and small bore piping) 3-185within the scope of license renewal. The One-Time Inspection Program addresses concernsand provides confirmation for the potential long incubation period for certain aging effects on SCs. If system contaminants are maintained within the limits specified by the Plant ChemistryProgram, the corrosion exhibited by the copper alloy in a closed system is adequatelymanaged. The applicant has chosen a different combination of AMPs to manage the AERM.
The staff found this combination adequate and acceptable for managing this material, environment, and aging effect, because contaminants are maintained within limits to inhibit corrosion of the copper alloy.The staff's review of LRA Section 3.2 identified areas for which it needed additional informationto complete its evaluation of the applicant's results. The applicant responded to the staff's RAIs as discussed below.In RAI 3.2-1, dated July 20, 2005, the staff noted that in LRA Table 3.2.2-4, the applicant statedthat it would manage heat transfer degradation due to fouling of heat exchangers fabricatedfrom copper alloy in a lubricating oil environment using the One Time Inspection Program. On the basis of the staff's review of the information provided in the LRA, it was not clear what preventive measures the applicant was taking to ensure that the lubricating oil remains free ofcontaminants that might degrade the tubing. Therefore, the staff requested that the applicantprovide the following:iiii)Specific material composition of the copper alloys.jjjj)A description of the oil analysis program and/or other methods to ensure thatthe lubricating oil remains free of contaminants which might degrade the tubing.kkkk)PM procedures to ensure that heat transfer degradation does not reachunacceptable levels.In its response, by letter dated August 16, 2005, the applicant stated the following:llll)The High Pressure Coolant Injection System (HPC) lubricating oilcooler (E-206) is an American Standard (Whitlock) cooler of carbon steel construction with 5/8" O.D. Admiralty tubes in accordance with the vendor's technical manual. Admiralty brass is composed of 71Cu-28Zn-1Sn.
mmmm)Lube oil samples from the HPC lube oil cooler are obtained everysix months in accordance with MNGP site procedures, and the sample results are evaluated and trended. These parameters include iron, copper, etc. for indications of wear, dielectric, viscosity, etc. for chemical analysis and water, silicon, etc. forindication of contamination. Sampling is performed IAW EPRI 1007459 (November 2002) for the HPC lube oil cooler.
Electric Power Research Institute (EPRI) Report 1007459 recommends that 'oil moisture content be verified on a monthly basis and that acidity, viscosity, and particle count be verified each quarter until a data trending program can justify extending the inspection frequency.' This frequency, based upon data trending results, was extended to a six-month frequency. Any 3-186indication of an anomalous condition or adverse trend will result inan investigation under the site corrective action program. All results have been acceptable to date to ensure that the lubricatingoil remains free of contaminants that could potentially degrade the heat exchanger (cooler) tubes, with the last sample taken and evaluated in March 2005.nnnn)Preventive maintenance procedures are in effect to both clean andinspect the HPC lube oil cooler and perform eddy current testing every three cycles. Eddy current testing was last performed in January 2000 onthe originally installed cooler. All tubes were inspected. No tubes required plugging and no unacceptable defects were detected.Based on its review, the staff found the applicant's response to RAI 3.2-1 acceptable becausethe lube oil coolers are monitored and tested in accordance with industry standards and NRC guidelines. In addition, the applicant's operational experience supports the adequacy of its maintenance practices; therefore, the staff's concern described in RAI 3.2-1 is resolved.In RAI 3.2-2, dated July 20, 2005, the staff noted that in LRA Table 3.2.2-4, the applicant statedthat it will manage heat transfer degradation due to fouling of the copper alloy heat exchangertubes in a steam environment with the Plant Chemistry and One-Time Inspection Programs.
The applicant further stated that the GALL Report does not evaluate either the components orthe material and environment combination; therefore, the staff requested that the applicantverify that the steam in the heat exchangers identified above originated from treated water. Inaddition, the staff requested the applicant to justify not considering erosion and FAC as agingmechanisms for this material and environment combination.In its response, by letter dated August 16, 2005, the applicant stated the following:Per LRA 2.3.2.4, High Pressure Coolant Injection (HPC) System, 'The HPCturbine is driven with steam from the RPV. Two sources of water are available for the HPC System. Normally, water is supplied to the suction of the HPC pump from the two condensate storage tanks (CST). When the level in either CST falls to the predetermined setpoint, the pump suction is automatically transferred to the suppression pool.' The HPC heat exchanger in question is the HPC Gland Seal Condenser, E-204, which condenses the gland seal steam from the HPC turbine by using cooling water from the discharge of the HPC pump. Therefore, the steam in this heat exchanger is produced by the treated water in the RPV.EPRI NSAC 202L, R2, 'Recommendations for an Effective Flow-AcceleratedCorrosion (FAC) Program,' page 4-3, allows an exclusion from FAC for systemswhich operate less than 2% of the time, which would be applicable to this HPC condenser. In addition, this component is not subject to high velocity, constricted flow, or fluid direction changes. Therefore, in accordance with EPRI 1003056,
'Non-Class 1 Mechanical Implementation Guideline and Mechanical Tools,'
Revision 3, loss of material due to erosion or FAC are not potential aging mechanisms.
3-187Based on its review, the staff found the applicant's response to RAI 3.2-2 acceptable becausethe applicant provided satisfactory explanations of the purity of the steam environment and the absence of erosion and FAC as aging mechanisms for the heat exchanger in question; therefore, the staff's concern described in RAI 3.2-2 is resolved.In LRA Table 3.2.2-4, the applicant proposed to manage the loss of material due to selectiveleaching of heat exchangers fabricated from copper alloy in a steam (external)/treated water (internal) environment with the Selective Leaching of Materials Program.The staff reviewed the applicant's Selective Leaching of Materials Program, and SERSection 3.0.3.2.22 documents its evaluation. This new program includes a one-time visualinspection and hardness measurement of selected components susceptible to selective leaching. The program will determine if selective leaching occurs for selected components. Thestaff found this program adequate for managing this material, environment, and aging effect.3.2.2.3.5Engineered Safety Features-Primary Containment Mechanical System-Summaryof Aging Management Evaluation-Table 3.2.2-5The staff reviewed LRA Table 3.2.2-5, which summarizes the results of AMR evaluations for theprimary containment mechanical system component groups.All line items in this table are consistent with the GALL Report or are included in the discussionin Section 3.2.2.3 above.3.2.2.3.6Engineered Safety Features-Reactor Core Isolation Cooling System-Summary ofAging Management Evaluation-Table 3.2.2-6The staff reviewed LRA Table 3.2.2-6, which summarizes the results of AMR evaluations for theRCI system component groups.In LRA Table 3.2.2-6, the applicant proposed to manage heat transfer degradation and foulingof heat exchangers fabricated from copper alloy in a lubricating oil (external) environment with the One-Time Inspection Program, and in a treated water (internal) environment with the Plant Chemistry Program, combined with the One-Time Inspection Program. The applicant also proposed to manage the loss of material due to crevice corrosion, pitting corrosion, and MIC of heat exchangers fabricated from copper alloy in a treated water (internal) environment with the Plant Chemistry Program, combined with the One-Time Inspection Program.The staff reviewed and evaluated the applicant's Plant Chemistry Program and the One-TimeInspection Program, as documented in SER Sections 3.0.3.2.19 and 3.0.3.1.4, respectively.The Plant Chemistry Program mitigates the aging effects on component surfaces exposed to water as the process fluid; chemistry programs are used to control water chemistry for impurities (e.g., chloride and sulfate) that accelerate corrosion or crack initiation and growth or that cause heat transfer degradation due to fouling in select heat exchangers. This program relies on monitoring and control of water chemistry to keep peak levels of various contaminants below system-specific limits. The new One-Time Inspection Program is consistent with therecommendations of GALL AMP XI.M32. This program will include measures to verify theeffectiveness of the Plant Chemistry Program. This program will also confirm the absence of age degradation in selected components (e.g., flow restrictors, venturis, and small bore piping) 3-188within scope of license renewal. The One-Time Inspection Program addresses concerns andprovides confirmation for the potential long incubation period for certain aging effects on SCs. If system contaminants are maintained within the limits specified by the Plant Chemistry Program,the corrosion exhibited by the copper alloy in a closed system is adequately managed. Theapplicant has chosen a different combination of AMPs to manage the AERM. The staff found this combination adequate and acceptable for managing this material, environment, and aging effect, because contaminants are maintained within limits to inhibit corrosion of the copper alloy.The response to RAI 3.2-1, discussed in SER Section 3.2.2.3.4, is generally applicable to thecopper alloy components of the heat exchangers in the RCI system.The staff found the applicant's response reasonable and acceptable because the lube oilcoolers are monitored and tested in accordance with industry standards and NRC guidelines. Inaddition, the applicant's operational experience supports the adequacy of its maintenancepractices.In LRA Table 3.2.2-6, the applicant proposed to manage the loss of material due to selectiveleaching of heat exchangers fabricated from copper alloy in a treated water (internal) environment using the Selective Leaching of Materials Program.The staff reviewed and evaluated the applicant's Selective Leaching of Materials Program, asdocumented in SER Section 3.0.3.2.22. This new program includes a one-time visual inspection and hardness measurement of certain components susceptible to selective leaching. The program will determine if selective leaching occurs for certain components. The staff found thisprogram adequate and acceptable for managing this material, environment, and aging effect.3.2.2.3.7Engineered Safety Features-Residual Heat Removal System-Summary of AgingManagement Evaluation-Table 3.2.2-7The staff reviewed LRA Table 3.2.2-7, which summarizes the results of AMR evaluations for theRHR system component groups.In LRA Table 3.2.2-7, the applicant proposed to manage heat transfer degradation and foulingof heat exchangers fabricated from copper alloy in a lubricating oil (external) environment with the One-Time Inspection Program, and in a raw water (internal) environment using the Open-Cycle Cooling Water System Program. The applicant also proposed to manage the loss of material due to crevice corrosion, MIC, and pitting corrosion of heat exchangers fabricated from copper alloy in a raw water (internal) environment using the Open-Cycle Cooling Water System Program.The staff reviewed and evaluated the applicant's One-Time Inspection Program, asdocumented in SER Section 3.0.3.1.4. The new One-Time Inspection Program, consistent withthe recommendations of GALL AMP XI.M32, will confirm the absence of age degradation inselected components (e.g., flow restrictors, venturis, and small bore piping) within the scope of license renewal. The One-Time Inspection Program addresses concerns and provides confirmation for the potential long incubation period for certain aging effects on SCs.
3-189The OCCW System Program relies on the implementation of the recommendations of GL 89-13to ensure that the effects of aging on the raw water service water systems will be managed forthe period of extended operation. This program manages the aging effects of meta lliccomponents in water systems (e.g., piping and heat exchangers) exposed to raw, untreated(e.g., service) water. The staff reviewed the OCCW System Program and found it acceptable and consistent with the GALL Report. SER Section 3.0.3.1.5 documents the evaluation of theOCCW System Program. The staff has found this AMP adequate and acceptable for managing this material, environment, and aging effect.In LRA Table 3.2.2-7, the applicant proposed to manage the loss of material due to MIC,crevice corrosion, and pitting corrosion of RHR nozzles fabricated from copper alloy in a treatedwater (internal) environment with the Plant Chemistry Program, combined with the One-Time Inspection Program.The staff reviewed and evaluated the applicant's Plant Chemistry Program and the One-TimeInspection Program, as documented in SER Sections 3.0.3.2.19 and 3.0.3.1.4, respectively.The Plant Chemistry Program mitigates the aging effects on component surfaces exposed to water as the process fluid; chemistry programs are used to control water chemistry for impurities (e.g., chloride and sulfate) that accelerate corrosion or crack initiation and growth, or that cause heat transfer degradation due to fouling in select heat exchangers. This program relies on monitoring and control of water chemistry to keep peak levels of various contaminants below system-specific limits.The new One-Time Inspection Program, consistent with the recommendations of GALL AMPXI.M32, will include measures to verify the effectiveness of the Plant Chemistry Program andwill also confirm the absence of age degradation in selected components (e.g., flow restrictors,venturis, and small bore piping) within the scope of license renewal. The One-Time Inspection Program addresses concerns and provides confirmation for the potential long incubation period for certain aging effects on SCs. If system contaminants are maintained within the limitsspecified by the Plant Chemistry Program, the corrosion exhibited by the copper alloy in a closed system is adequately managed. The applicant has chosen a different combination ofAMPs to manage the AERM. The staff found this combination adequate and acceptable for managing this material, environment, and aging effect, because contaminants are maintained within limits to inhibit corrosion of the copper alloy.In LRA Table 3.2.2-7, the applicant proposed to manage the loss of material due to selectiveleaching of heat exchangers fabricated from copper alloy in a raw water (internal) environment, and RHR nozzles fabricated from copper alloy in a treated water (internal) environment with theSelective Leaching of Materials Program.The staff reviewed and evaluated the applicant's Selective Leaching of Materials Program, asdocumented in SER Section 3.0.3.2.22. This new program includes a one-time visual inspection and hardness measurement of certain components susceptible to selective leaching. Because the program will determine if selective leaching occurs for certain components, the staff foundthis AMP adequate and acceptable for managing this material, environment, and aging effect.In LRA Table 3.2.2-7, the applicant contends that no aging effects are associated with thermalinsulation installed on heat exchangers and exposed to an indoor plant air environment. The 3-190staff concurred with the applicant's assessment and found the applicant's routine maintenancepractices adequate to maintain the thermal insulation of the RHR heat exchangers effectively.3.2.2.3.8Engineered Safety Features-Secondary Containment System-Summary of AgingManagement Evaluation-Table 3.2.2-8The staff reviewed LRA Table 3.2.2-8, which summarizes the results of AMR evaluations for thesecondary containment system component groups.All line items in this table are consistent with the GALL Report or are included in the discussionin Section 3.2.2.3 above.Conclusion. On the basis of its review, the staff found that the applicant appropriately evaluatedAMR results involving material, environment, AERMs, and AMP combinations that are not evaluated in the GALL Report. The staff found that the applicant has demonstrated that theeffects of aging will be adequately managed so that intended functions will be maintainedconsistent with the CLB for the period of extended operation, as required by10 CFR 54.21(a)(3).3.2.3  Conclusion The staff concluded that the applicant provided sufficient information to demonstrate that theeffects of aging for the ESF 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 bemaintained consistent with the CLB for the period of extended operation, as required by10 CFR 54.21(a)(3).The staff also reviewed the applicable USAR supplement program summaries and concludedthat they adequately describe the AMPs credited for managing aging of the ESF, as required by10 CFR 54.21(d).3.3  Aging Management of Auxiliary SystemsThis section of the SER documents the staff's review of the applicant's AMR results for theauxiliary systems components and component groups associated with the following systems:
* alternate nitr ogen system
* chemistry sampling system
* circulating water system
* control rod drive system
* demineralized water system
* emergency diesel generators system
* emergency filtration train system
* emergency service water system
* fire system 3-191
* fuel pool cooling and cleanup system
* heating and ventilati on syst em
* instrument and service air system
* radwaste solid and liquid system
* reactor building closed cooling water system
* reactor water cl eanup system
* service and seal water system
* standby liquid control system
* wells and domestic water system3.3.1  Summary of Technical Information in the Application In LRA Section 3.3, the applicant provided AMR results for the auxiliary systems com ponentsand component groups. In LRA Table 3.3.1,the applicant provided a summary comparison of its AMRs with the AMRs evaluated in the GALL Report for the auxiliary systems components andcomponent groups.The applicant's AMRs incorporated applicable operating experience in the determination ofAERMs. These reviews included evaluation of plant-specific and industry operating experience.
The plant-specific evaluation included reviews of CRs and discussions with appropriate site personnel to identify AERMs. The applicant's review of industry operating experience included a review of the GALL Report and operating experience issues identified since the issuance of the GALL Report.3.3.2  Staff Evaluation The staff reviewed LRA Section 3.3 to determine if the applicant provided sufficient informationto demonstrate that the effects of aging for the auxiliary systems components that are within thescope of license renewal and subject to an AMR will be adequately managed so that intendedfunctions will be maintained consistent with the CLB for the period of extended operation, asrequired by 10 CFR 54.21(a)(3).In addition, the staff performed an onsite audit of AMRs to confirm the applicant's claim thatcertain identified AMRs are consistent with the GALL Report. The staff did not repeat its reviewof the matters described in the GALL Report; however, the staff did verify that the material presented in the LRA is applicable and that the applicant identified the appropriate GALLReport AMRs. SER Section 3.0.3 documents the staff's evaluations of the AMPs. The MNGP audit and review report details the staff's audit evaluation, which is summarized in SER Section 3.3.2.1.The staff also performed an onsite audit of those selected AMRs that were consistent with theGALL Report and for which further evaluation is recommended. The staff confirmed that the applicant's further evaluations were consistent with the acceptance criteria in Section 3.3.2.2 ofthe SRP-LR. The staff's audit evaluations are documented in the MNGP audit and review report and are summarized in SER Section 3.3.2.2.The staff performed an onsite audit and conducted a technical review of the remaining AMRsthat are not consistent with, or not addressed in, the GALL Report. The audit and technical 3-192review included evaluating whether the applicant identified all plausible aging effects andwhether the aging effects listed are appropriate for the combination of materials and environments specified. The MNGP audit and review report documents the staff's audit evaluations. SER Section 3.3.2.3 summarizes the staff's audit evaluations and documents itstechnical review.Finally, the staff reviewed the AMP summary descriptions in the USAR supplement to ensurethat they adequately describe the programs credited with managing or monitoring aging for theauxiliary systems components.Table 3.3-1 below summarizes the staff's evaluation of components, aging effects/mechanisms,and AMPs listed in LRA Section 3.3 that are addressed in the GALL Report.Table 3.3-1  Staff Evaluation for Auxiliary Systems Components in the GALL ReportComponent GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff EvaluationComponents inspent fuel poolcooling and cleanup(Item Number3.3.1-01)Loss of materialdue to general,pitting, and crevicecorrosionWater chemistry,one-time inspectionOne-TimeInspection Program(B2.1.23), PlantChemistry Program(B2.1.25) Consistent withGALL, whichrecommends furtherevaluation (seeSection 3.3.2.2.1)Linings in spent fuelpool cooling andcleanup system,seals and collars inventilation systems(Item Number3.3.1-02)Hardening, crackingand loss of strengthdue to elastomerdegradation; loss ofmaterial due towearPlant specificNot applicable (seeSection 3.3.2.2.2)Components in loadhandling, chemicaland volume controlsystem (PWR), andreactor watercleanup andshutdown coolingsystems (olderBWR)(Item Number3.3.1-03)Cumulative fatiguedamageTLAA, evaluated inaccordance with10 CFR 54.21(c)TLAAThis TLAA isevaluated in Section4.3, Metal Fatigueof the RPV andInternals, andReactor CoolantPressure BoundaryPiping andComponents andSection  4.9,Reactor BuildingCrane Load CyclesHeat exchangers inreactor watercleanup system(BWR); highpressure pumps inchemical andvolume controlsystem (PWR)(Item Number3.3.1-04)Crack initiation andgrowth due to SCCor crackingPlant specific Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation3-193Components inventilation systems,diesel fuel oilsystem, andemergency dieselgenerator systems;external surfaces ofcarbon steelcomponents(Item Number3.3.1-05)Loss of materialdue to general,pitting, and crevicecorrosion, and MICPlant specificFire ProtectionProgram (B2.1.17),Fire Water SystemProgram (B2.1.18),One-TimeInspection Program(B2.1.23), SystemCondition MonitoringProgram (B2.1.32) Components in reactor coolantpump oil collectsystem of fireprotection(Item Number3.3.1-06)Loss of materialdue to galvanic,general, pitting, andcrevice corrosionOne-timeinspectionNot applicable (seeSection 3.3.2.2.6)Diesel fuel oil tanksin diesel fuel oilsystem andemergency dieselgenerator system(Item Number3.3.1-07)Loss of materialdue to general,pitting, and crevicecorrosion, MIC, andbiofoulingFuel oil chemistry,one-time inspectionPiping, pumpcasing, and valvebody and bonnets inshutdown coolingsystem (older BWR)(Item Number3.3.1-08)Loss of materialdue to pitting andcrevice corrosionWater chemistry,one-time inspectionCompressed AirMonitoring Program(B2.1.14), One-TimeInspection Program(B2.1.23), PlantChemistry Program(B2.1.25)Heat exchangers in chemical andvolume controlsystem(Item Number3.3.1-09)Crack initiation andgrowth due to SCCand cyclic loadingWater chemistryand a plant-specificverification programNot applicable,PWR onlyNeutron-absorbingsheets in spent fuelstorage racks(Item Number3.3.1-10)Reduction ofneutron-absorbingcapacity and loss ofmaterial due togeneral corrosion(boral, boron steel)Plant specificOne-TimeInspection Program(B2.1.23), PlantChemistry Program(B2.1.25)Consistent withGALL, whichrecommends furtherevaluation (seeSection 3.3.2.2.10)New fuel rackassembly(Item Number3.3.1-11)Loss of materialdue to general,pitting, and crevicecorrosionStructuresmonitoringNoneNot applicable Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation3-194Neutron-absorbingsheets in spent fuelstorage racks(Item Number3.3.1-12)Reduction ofneutron-absorbingcapacity due toBoraflexdegradationBoraflex monitoringSpent fuel storageracks and valves inspent fuel poolcooling and cleanup(Item Number3.3.1-13)Crack initiation andgrowth due to stresscorrosion crackingWater chemistryPlant ChemistryProgram (B2.1.25) Closure bolting and external surfaces ofcarbon steel andlow-alloy steelcomponents(Item Number3.3.1-14)Loss of materialdue to boric acidcorrosionBoric acid corrosionComponents in orserviced byclosed-cycle coolingwater system(Item Number3.3.1-15)Loss of materialdue to general,pitting, and crevicecorrosion, and MICClosed-cyclecooling watersystemCranes includingbridge and trolleysand rail system inload handlingsystem(Item Number3.3.1-16)Loss of materialdue to generalcorrosion and wearOverhead heavyload and light loadhandling systemsInspection ofOverhead HeavyLoad and Light Load(Related toRefueling) HandlingSystems Program(B2.1.22)Components in or serviced byopen-cycle coolingwater systems(Item Number3.3.1-17)Loss of materialdue to general,pitting, crevice, andgalvanic corrosion,MIC, and biofouling;buildup of depositdue to biofoulingOpen-cycle coolingwater systemOne-TimeInspection Program(B2.1.23),Open-Cycle CoolingWater SystemProgram (B2.1.24)Consistent withGALL Report, whichrecommends nofurther evaluationBuried piping andfittings(Item Number3.3.1-18)Loss of materialdue to general,pitting, and crevicecorrosion, and MICBuried piping andtanks surveillance or Buried piping andtanks inspectionBolting IntegrityProgram (B2.1.4),Buried Piping &Tanks InspectionProgram (B2.1.5)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation3-195Components incompressed airsystem(Item Number3.3.1-19)Loss of materialdue to general andpitting corrosionCompressed airmonitoringComponents (doorsand barrierpenetration seals)and concretestructures in fireprotection(Item Number3.3.1-20)Loss of materialdue to wear;hardening andshrinkage due toweatheringFire protectionFire ProtectionProgram (B2.1.17)Components in water-based fireprotection(Item Number3.3.1-21)Loss of materialdue to general,pitting, crevice, andgalvanic corrosion,MIC, and biofoulingFire water systemFire ProtectionProgram (B2.1.17),Fire Water SystemProgram (B2.1.18) (seeSection 3.3.2.1.1)Components indiesel fire system(Item Number3.3.1-22)Loss of materialdue to galvanic,general, pitting, andcrevice corrosionFire protection, fueloil chemistryFire ProtectionProgram (B2.1.17),Fuel Oil ChemistryProgram (B2.1.20),One-TimeInspection Program(B2.1.23),and the aging effectis managed by theFuel Oil Chemistryand One-TimeInspectionProgramsTanks in diesel fueloil system(Item Number3.3.1-23)Loss of materialdue to general,pitting, and crevicecorrosionAbovegroundcarbon steel tanks Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation3-196Closure bolting(Item Number3.3.1-24)Loss of materialdue to generalcorrosion, crackinitiation and growthdue to cyclicloading and SCCBolting integrityBolting IntegrityProgram (B2.1.4) Components in contact with sodiumpentaboratesolution in standbyliquid controlsystem (BWR)(Item Number3.3.1-25)Crack initiation andgrowth due to SCCWater chemistryNot applicable. AtMNGP, thecomponentsexposed to sodiumpentaboratesolution are in anenvironment suchthat thecomponents are notsusceptible to SCCComponents inreactor watercleanup system(Item Number3.3.1-26)Crack initiation andgrowth due to SCCand IGSCCReactor watercleanup systeminspectionConsistent withGALL Report, whichrecommends nofurther evaluationComponents inshutdown coolingsystem (older BWR)(Item Number3.3.1-27)Crack initiation andgrowth due to SCCBWR stresscorrosion crackingand waterchemistryBWR StressCorrosion CrackingProgram (B2.1.10),Closed-CycleCooling WaterSystem Program(B2.1.13), One-TimeInspection Program(B2.1.23), PlantChemistry Program(B2.1.25) Consistent withGALL Report, whichrecommends nofurther evaluationComponents inshutdown coolingsystem (older BWR)(Item Number3.3.1-28)Loss of materialdue to pitting andcrevice corrosion,and MICClosed-cyclecooling watersystemComponents (aluminum bronze,brass, cast iron,cast steel) inopen-cycle andclosed-cycle coolingwater systems, andultimate heat sink(Item Number3.3.1-29)Loss of materialdue to selectiveleachingSelective leachingof materialsSelective Leachingof MaterialsProgram (B2.1.30)Consistent withGALL Report, whichrecommends nofurther evaluation Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation3-197Fire barriers, walls,ceilings, and floorsin fire protection(Item Number3.3.1-30)Concrete crackingand spalling due tofreeze-thaw,aggressivechemical attack,and reaction withaggregates; loss ofmaterial due tocorrosion ofembedded steelFire protection,structuresmonitoringFire ProtectionProgram (B2.1.17),StructuresMonitoring Program(B2.1.31)Consistent withGALL Report, whichrecommends nofurther evaluationThe staff's review of the MNGP component groups followed one of several approaches. Oneapproach, documented in SER Section 3.3.2.1, involves the staff's review of the AMR resultsfor components in the auxiliary systems that the applicant indicated are consistent with theGALL Report and do not require further evaluation. Another approach, documented in SERSection 3.3.2.2, involves the staff's review of the AMR results for components in the auxiliarysystems that the applicant indicated are consistent with the GALL Report and for which furtherevaluation is recommended. A third approach, documented in SER Section 3.3.2.3, involves thestaff's review of the AMR results for components in the auxiliary systems that the applicantindicated are not consistent with, or not addressed in, the GALL Report. SER Section 3.0.3documents the staff's review of AMPs that are credited to manage or monitor aging effects of the auxiliary systems components.3.3.2.1  AMR Results That Are Consistent with the GALL Report Summary of Technical Information in the Application. In LRA Section 3.3.2.1, the applicantidentified the materials, environments, and AERMs. The applicant identified the following programs that manage the aging effects related to the auxiliary systems components:
* Bolting Integrity Program (B2.1.4)
* Buried Piping & Tanks Inspection Program (B2.1.5)
* BWR Stress Corrosion Cracking Program (B2.1.10)
* Closed-Cycle Cooling Water System Program (B2.1.13)
* Compressed Air Monitoring Program (B2.1.14)
* Fire Protection Program (B2.1.17)
* Fire Water System Program (B2.1.18)
* Flow-Accelerated Corrosion Program (B2.1.19)
* Fuel Oil Chemistry Program (B2.1.20)
* One-Time Inspection Program (B2.1.23)
* Open-Cycle Cooling Water System Program (B2.1.24)
* Plant Chemistry Program (B2.1.25)
* Selective Leaching of Materials Program (B2.1.30)
* System Condition Monitoring Program (B2.1.32)Staff Evaluation. In LRA Tables 3.3.2-1 through 3.3.2-18, the applicant summarized the AMRsfor the auxiliary systems components and identified which AMRs it considered to be consistentwith the GALL Report.
3-198For component groups evaluated in the GALL Report for which the applicant has claimedconsistency with the GALL Report, and for which the GALL Report does not recommend further evaluation, the staff performed an audit and review to determine whether the GALL Reportevaluation bounds the plant-specific components contained in these GALL Report componentgroups.The applicant provided a note for each AMR line item. The notes describe how the informationin the tables aligns with the information in the GALL Report. The staff audited those AMRs with Notes A through E, which indicate that 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 AMP identified in the GALL Report. The staff audited these line items to verify consistency with the GALL Report and the validity of the AMR for the site-specific conditions.Note B 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 AMP identified in the GALL Report. The staff audited these line items to verify consistency with the GALL Report. The staff verified that it had reviewed and accepted the identified exceptionsto the GALL Report AMPs. The staff also determined whether the AMP identified by the applicant is consistent with the AMP identified in the GALL Report and whether the AMR is validfor the site-specific conditions.Note C indicates that the component for the AMR line item, although different, is consistent withthe GALL Report for material, environment, and aging effect. In addition, the AMP is consistent with the AMP identified by the GALL Report. This note indicates that the applicant could not finda listing of some system components in the GALL Report; however, the applicant identified adifferent component in the GALL Report that has 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 determined whether the AMR line item of the different component is applicable to the component under review and whether the AMR is valid for the site-specific conditions.Note D indicates that the component for the AMR line item, although different, is consistent withthe GALL Report for material, environment, and aging effect. In addition, the AMP takes some exceptions to the AMP identified in the GALL Report. The staff audited these line items to verify consistency with the GALL Report. The staff verified whether the AMR line item of the different component applies to the component under review. The staff verified whether it had reviewed and accepted the identified exceptions to the GALL Report AMPs. The staff also determinedwhether the AMP identified by the applicant is consistent with the AMP identified in the GALLReport and whether the AMR is 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 the applicant credited a different AMP. The staff audited these line items to verify consistency with the GALL Report. The staff also determined whether the identified AMP will manage the aging effect consistent with the AMP identified by the GALLReport and whether the AMR is valid for the site-specific conditions.
3-1993.3.2.1.1  Loss of Material for Components in Water-Based Fire ProtectionIn the discussion section of LRA Table 3.3.1, Item 3.3.1-21, the applicant stated the following:Loss of material due to general, pitting, crevice, galvanic corrosion, and MIC aswell as heat transfer degradation due to fouling for components in the fire system are managed by the Fire Protection and Fire Water System Programs.The Fire Water System Program is applied for the majority of the components in the fire system. The Fire Protection Program is applied to those components inthe fire system associated with the diesel fire pump with the exception of thediesel fire pump diesel engine fuel oil supply. In addition, the Fire Protection Program is applied to non-water-based fire protection subsystems such asHalon. Exceptions apply to NUREG-1801 recommendations for Fire ProtectionProgram implementation. Implementation of the Fire Water System and FireProtection Programs to manage the aging effect provides added assurance that the aging effect is not occurring; or that the aging effect is progressing very slowly such that the component's intended function will be maintained during theperiod of extended operation.In RAI 3.3.2.1.9-3, the staff noted that in LRA Table 3.3.2-9 for FIRs, the applicant credited theFire Protection Program with managing loss of material due to general, pitting, crevice, and galvanic corrosion, and MIC for copper alloy, and loss of material due to general and galvanic corrosion for gray cast iron material in a raw water environment, referring to GALL Report item VII.G6-b, which evaluates filter, fire hydrant, mulsifier, pump casing, sprinkler, strainer, and valve bodies from various materials including cast iron, bronze, and copper. The GALL Report also recommends the Fire Water System Program for managing this aging effect. The applicant referenced Note E, which indicates that a different AMP, Fire Protection Program, is used. As stated above, the applicant, in Table 3.3-1, Item 3.3.1-21, indicated that it applies the FireProtection Program to nonwater-based fire protection systems. This indication conflicts with theTable 3.3.2-9 line items. Furthermore, the LRA does not identify in the program description how the Fire Protection Program will manage this aging effect in water-based systems.Therefore, the staff requested that the applicant clarify how the Fire Protection Program willmanage loss of material due to general, pitting, crevice, and galvanic corrosion in water-based FP systems.In its response, dated November 22, 2005, the applicant stated the following:Although the LRA does not expressly identify how the Fire Protection Program will manage loss of material in water-based subsystems (i.e., diesel fire pump) inthe Program Description of Appendix B, this is specifically addressed in the Fire Protection AMP Program Basis Document (PBD). Under the heading
'Diesel-Driven Fire Pump,' the PBD states that the water initiated aging effects 3-200will be managed by the Fire Water System AMP. Therefore, the Fire ProtectionProgram invokes the Fire Water System Program to manage loss of material due to crevice, galvanic, general and pitting corrosion in the water-based subsystem for the diesel fire pump. This is confirmed in the Fire Water System PBD.As a result, the Fire Protection AMP will adequately manage the effect of loss ofmaterial due to crevice, galvanic, general and pitting corrosion for these components in the Fire System by invoking the Fire Water System AMP for the water initiated aging effects related to the diesel fire pump water-based subsystem.The applicant's response also stated, "Although the Fire Water System AMP is credited in thelicense renewal database for managing the aging effect of loss of material for copper alloy filters and strainers in a raw water environment, it was inadvertently omitted from LRA Table 3.3.2-9. The Fire Water System AMP is credited for managing these components in thewater-based portion of the Fire System."The applicant agreed to revise the Fire Protection Program in the LRA to specifically addresshow it intends to credit the Fire Water System Program with managing loss of material in water-based subsystems. The applicant will also provide revised AMR line items to correct theinadvertent omission of the Fire Water System Program for managing the aging effect of loss of material for copper alloy filters and strainers in a raw water environment.In its letter dated February 28, 2006, the applicant provided an update to LRA Table 3.3.2-9,adding the Fire Water System Program to the Fire Protection Program for managing the aging effect of loss of material for copper alloy filters and strainers in a raw water environment. In addition, the applicant amended the program description of the Fire Protection Program to invoke the Fire Water System Program for water-initiated aging effects related to the diesel fire pump water-based subsystem. Because the Fire Protection Program credits the Fire WaterSystem Program for managing the aging effects of loss of material in water-based subsystems,the staff found the applicant's response acceptable. Therefore, the staff's concern described inRAI 3.3.2.1.9-3 is resolved.Conclusion. The staff evaluated the applicant's claim of consistency with the GALL Report. Thestaff also reviewed information pertaining to the applicant's consideration of recent operating experience and proposals for managing associated aging effects. The staff's review concluded that the AMR results, which the applicant claimed to be consistent with the GALL Report, areconsistent with the AMRs in the GALL Report; therefore, the staff concluded that the applicanthas demonstrated that the effects of aging for these components will be adequately managedso that their intended function(s) will be maintained consistent with the CLB for the period ofextended operation, as required by 10 CFR 54.21(a)(3).3.3.2.2AMR Results That Are Consistent with the GALL Report, for Which Further EvaluationIs RecommendedSummary of Technical Information in the Application. In LRA Section 3.3.2.2, the applicantprovided further evaluation of aging management as recommended by the GALL Report for the 3-201auxiliary systems components. The applicant provided information concerning how it willmanage the following aging effects:
* loss of material due to general, pitting, and crevice corrosion
* hardening and cracking or loss of strength due to elastomer degradation or loss ofmaterial due to wear
* cumulative fatigue damage
* crack initiation and growth due to cracking or stress corrosion cracking
* loss of material due to general, microbiologically influenced, pitting, and crevicecorrosion
* loss of material due to general, galvanic, pitting, and crevice corrosion
* loss of material due to general, pitting, crevice, and microbiologically influencedcorrosion and biofouling
* crack initiation and growth due to stress corrosion cracking and cyclic loading
* reduction of neutron-absorbing capacity and loss of material due to general corrosion
* loss of material due to general, pitting, crevice, and microbiologically influencedcorrosionStaff Evaluation. For component groups evaluated in the GALL Report for which the applicanthas claimed consistency with the GALL Report, and for which the GALL Report recommends further evaluation, the staff audited and reviewed the applicant's evaluation to determinewhether it adequately addressed the issues that were further evaluated. In addition, the staffreviewed the applicant's further evaluations against the criteria contained in Section 3.3.2.2 ofthe SRP-LR. The staff's audit and review report details the staff's audit. The following sections discuss the staff's evaluation of the aging effects.3.3.2.2.1  Loss of Material Due to General, Pitting, and Crevice Corrosion The staff reviewed LRA Sections 3.3.2.2.1.1 and 3.3.2.2.1.2 against the criteria in SRP-LRSection 3.3.2.2.1.In LRA Section 3.3.2.2.1.1, the applicant addressed loss of material due to general, pitting, andcrevice corrosion of heat exchanger components in the auxiliary systems.SRP-LR Section 3.3.2.2.1.1 states the following:Loss of material due to general, pitting, and crevice corrosion could occur in thechannel head and access cover, tubes, and tubesheets of the heat exchanger in the spent fuel pool cooling and cleanup (system). The Water Chemistry programrelies on monitoring and control of reactor water chemistry based on EPRI guidelines of BWRVIP-29 (TR-103515) for water chemistry in BWRs to manage the effects of loss of material from general, pitting or crevice corrosion. However, high concentrations of impurities at crevices and locations of stagnant flow conditions could cause general, pitting, or crevice corrosion. Therefore, 3-202verification of the effectiveness of the chemistry control program should beperformed to ensure that corrosion is not occurring. The GALL Report recommends further evaluation of programs to manage loss of material from general, pitting, and crevice corrosion to verify the effectiveness of the Water Chemistry program. A one-time inspection of select components at susceptible locations is an acceptable method to ensure that corrosion is not occurring and that the component's intended function will be maintained during the period ofextended operation.In LRA Section 3.3.2.2.1.1, the applicant stated thatThe staff determined that the use of the One-Time Inspection Program alone isacceptable in certain cases, such as no-flow conditions, in which the Plant Chemistry Program is not a viable option. These AMPs are appropriate for the aging effects/mechanisms identified and assure effective management through the period of extended operation. The staff reviewed the Plant Chemistry Program and the One-Time Inspection Program and found them acceptable for managing aging degradation. SER Sections 3.0.3.
2.19 and 3.0.3.1.4,respectively, document the evaluations.In LRA Section 3.3.2.2.1.2, the applicant addressed loss of material due to pitting and crevicecorrosion of components in the auxiliary systems.SRP-LR Section 3.3.2.2.1.2 states the following:Loss of material due to pitting and crevice corrosion could occur in the piping,filter housing, valve bodies, and shell and nozzles of the ion exchanger in the spent fuel pool cooling and cleanup system. The Water Chemistry program relieson monitoring and control of reactor water chemistry based on EPRI guidelines of BWRVIP-29 (TR-103515) for water chemistry in BWRs to manage the effects of loss of material from pitting or crevice corrosion. However, high concentrations of impurities at crevices and locations of stagnant flow conditions could cause pitting or crevice corrosion. Therefore, verification of the effectiveness of the chemistry control program should be performed to ensure that corrosion is not occurring. The GALL Report recommends further evaluation of programs to manage loss of material from pitting and crevice corrosion to verify the effectiveness of the Water Chemistry program. A one-time inspection of select 3-203components at susceptible locations is an acceptable method to ensure thatcorrosion is not occurring and that the component's intended function will bemaintained during the period of extended operation.In the One-Time Inspection Program and the Plant Chemistry Program, or theCompressed Air Monitoring Program manages the loss of material due to pitting and crevice corrosion of these components. The scope of the One-Time Inspection Program incorporates activities to verify the effectiveness of the Plant Chemistry Program, including a sample of components where the water flow is low or stagnant conditions exist. Implementation of the One-Time Inspection Program and the Plant Chemistry Program to manage the aging effect adds assurance that the aging effect does not occur or progresses very slowly such that the component's intended function will be maintained during the period of extended operation. Insome cases in which the Plant Chemistry Program is not a viable option and aging effects/mechanisms are not expected to be significant, the One-Time Inspection Program alone is credited with managing aging effects. The Compressed Air Monitoring Program is used to manage loss of material of stainless steel valve bodies of the AIR system in an air/gasenvironment (the applicant conservatively treats components with a "wet air/gas" environment in the same manner as treated water). The scope of the Compressed Air Monitoring Program includes procedurally required testing for water vapor, oil content, and particulate to ensure that instrument air quality does not have unacceptable levels of contaminants. In addition, external visual inspections of the AIR systems check once per cycle for corrosion and system pressureboundary degradation.The staff's review determined that the applicant's Plant Chemistry Program exceptions arenontechnical and that the program is based on a more recent EPRI document for BWR water chemistry instead of the EPRI document recommended by the GALL Report, BWRVIP-29. The staff determined that the use of the One-Time Inspection Program alone is acceptable incertain cases, such as no flow conditions, in which the use of the Plant Chemistry Program is not a viable option. The Compressed Air Monitoring Program includes procedurally required testing for water vapor, oil content, and particulate to ensure that instrument air quality does not have unacceptable levels of contaminants. In addition, external visual inspections of the AIR systems check once per cycle for corrosi on and system pressure boundary degradation.Engineering personnel must conduct a system walkdown and look for vibrating piping, leaks, orother indications of pending failures. These AMPs are appropriate for the aging effects/mechanisms identified and assure effective management through the period of extended operation. The staff reviewed the Plant Chemistry Program, the One-Time InspectionProgram, and the Compressed Air Monitoring Program and found them acceptable for managing aging degradation. SER Sections 3.0.3.2.19, 3.0.3.1.4, and 3.0.3.2.13, respectively,document the evaluations.On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LRSection 3.3.2.2.1. For those line items that apply to LRA Sections 3.3.2.2.1.1 and 3.3.2.2.1.2,the staff determined that the applicant's AMRs are consistent with the GALL Report and theapplicant has demonstrated that the effects of aging will be adequately managed so that theintended function(s) will be maintained consistent with the CLB during the period of extendedoperation, as required by 10 CFR 54.21(a)(3).
3-2043.3.2.2.2Hardening and Cracking or Loss of Strength Due to Elastomer Degradation or Lossof Material Due to WearThe staff reviewed LRA Section 3.3.2.2.2 against the criteria in SRP-LR Section 3.3.2.2.2.In LRA Section 3.3.2.2.2, the applicant addressed hardening and cracking or loss of strengthdue to elastomer degradation or loss of material due to wear in the auxiliary systems.SRP-LR Section 3.3.2.2.2 states the following:Hardening and cracking due to elastomer degradation could occur in elastomerlinings of the filter, valve, and ion exchangers in spent fuel pool cooling and cleanup systems (BWR and PWR). Hardening and loss of strength due toelastomer degradation could occur in the collars and seals of the duct and in the elastomer seals of the filters in the control room area, auxiliary and radwastearea, and primary containment heating ventilation systems and in the collars andseals of the duct in the diesel generator building ventilation system. Loss ofmaterial due to wear could occur in the collars and seals of the duct in the ventilation systems. The GALL report recommends further evaluation to ensurethat these aging effects are adequately managed.In LRA Section 3.3.2.2.2, the applicant stated that elastomer (e.g., neoprene, rubber)components are indoors and not subject to ultraviolet (UV) radiation, ozone, or significant radiation exposure. In addition, they are not subject to temperatures where change in material properties or cracking could occur. Therefore, the applicant claims that aging management is not required.The applicant provided a detailed discussion of the technical basis for determining that agingmanagement is not required in response to RAI 3.2.2.3-3, dated August 16, 2005. SER Section3.3.2.3 documents the discussion and the staff's evaluation.On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LRSection 3.3.2.2.2. For those line items that apply to LRA Secti on 3.3.2.2.2, the staff determinedthat the applicant's AMRs are consistent with the GALL Report and the applicant hasdemonstrated that the effects of aging will be adequately managed so that the intendedfunction(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  Cumulative Fatigue Damage In LRA Section 3.3.2.2.3, the applicant stated that fatigue is a TLAA, as defined in10 CFR 54.3. Applicants must evaluate TLAAs in accordance with 10 CFR 54.21(c)(1). SER Sections 4.3 and 4.9 document the staff's review of the applicant's evaluation of this TLAA formechanical auxiliary systems and the reactor building crane, respectively.3.3.2.2.4  Crack Initiation and Growth Due to Cracking or Stress-Corrosion Cracking 3-205Crack initiation and growth due to SCC could occur in the regenerative andnon-regenerative heat exchanger components in the reactor water cleanup system of BWR plants. The GALL Report recommends further evaluation toensure that these aging effects are managed adequately.does not occur and no aging management isrequired.The staff's review determined that the applicant's assessment that SCC does not apply to thecarbon steel shell is acceptable; therefore, the staff concluded that the applicant's furtherevaluation is acceptable because SRP-LR Section 3.3.2.2.4 does not apply.On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LRSection 3.3.2.2.4. For those line items that apply to LRA Secti on 3.3.2.2.4, the staff determinedthat the applicant's AMRs are consistent with the GALL Report and the applicant hasdemonstrated that the effects of aging will be adequately managed so that the intendedfunction(s) will be maintained consistent with the CLB during the period of extended operation,as required by 10 CFR 54.21(a)(3).3.3.2.2.5Loss of Material Due to General, Microbiologically Influenced, Pitting, and CreviceCorrosion 3-206F in the ventilation systems. The GALL Report recommends furtherevaluation to ensure that these aging effects are adequately managed.In LRA Section 3.3.2.2.5, the applicant stated that loss of material due to corrosion ofmechanical components could occur on surfaces exposed to air/gas under a range of atmospheric conditions. For the internal surfaces of mechanical components in the EDGs, emergency filtration train, and HTV systems, the One-Time Inspection Program is credited withmanaging the aging effect. For the external surfaces of mechanical components in all auxiliarysystems, the applicant credits the Fire Water System Program, Fire Protection Program,System Condition Monitoring Program, and/or One-Time Inspection Program with managing the aging effect.The staff's review determined that the applicant's Fire Water System Program and the FireProtection Program together manage aging effects in the water-based FP system piping andcomponents in accordance with applicable NFPA recommendations and aging effects for components in the FIR, including components for the diesel fire pump. The staff also reviewed the System Condition Monitoring Program and determined that this existing plant-specific AMP manages aging effects for normally accessible external surfaces of piping, tanks, and other components and equipment within the scope of license renewal. The applicant manages these aging effects through visual inspection and monitoring of external surfaces for leakage and evidence of material degradation. The staff's review also determined that the One-TimeInspection Program includes a sample of components in which flow is low or stagnant conditions exist. Implementation of the One-Time Inspection Program adds assurance that the aging effect does not occur or progresses very slowly, such that the component's intended function will be maintained during the period of extended operation. The staff reviewed theapplicant's Fire Water System Program, the Fire Protection Program, the One-Time Inspection Program, and the System Condition Monitoring Program and found them acceptable for managing aging degradation. SER Sections 3.0.3.2.
16, 3.0.3.2.15, 3.0.
3.1.4, and 3.0.3.3.2,respectively, document the evaluations. These AMPs are appropriate for the aging effects/mechanisms identified and assure effective management of aging effects through the period of extended operation.On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LRSection 3.3.2.2.5. For those line items that apply to LRA Secti on 3.3.2.2.5, the staff determinedthat the applicant's AMRs are consistent with the GALL Report and the applicant hasdemonstrated that the effects of aging will be adequately managed so that the intendedfunction(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  Loss of Material Due to General, Galvanic, Pitting, and Crevice Corrosion The staff reviewed LRA Section 3.3.2.2.6 against the criteria in SRP-LR Section 3.3.2.2.6.In LRA Section 3.2.2.2.6, the applicant addressed loss of material due to general, galvanic,pitting, and crevice corrosion for components in the reactor coolant pump (RCP) oil collection system for FP.SRP-LR Section 3.2.2.2.6 states the following:
3-207Loss of material due to general, galvanic, pitting, and crevice corrosion couldoccur in tanks, piping, valve bodies, and tubing in the reactor coolant pump oil collection system in fire protection. The Fire Protection program relies on a combination of visual and volumetric examinations in accordance with the guidelines of 10 CFR Part 50 Appendix R and Branch Technical Position 9.5-1 to manage loss of material from corrosion. However, corrosion may occur at locations where water from wash downs may accumulate. Therefore, verification of the effectiveness of the program should be performed to ensure that corrosion is not occurring. The GALL Report recommends further evaluation of programs to manage loss of material due to general, galvanic, pitting, and crevice corrosion to verify the effectiveness of the program. A one-time inspection of the bottom half of the interior surface of the tank of the reactor coolant pump oil collection system is an acceptable method to ensure that corrosion is notoccurring and that the component's intended function will be maintained duringthe period of extended operation.In LRA Section 3.3.2.2.6, the applicant stated that MNGP is not designed with an RCP(recirculation pump) oil collection system because these pumps are within the primarycontainment, which is inerted with nitrogen during normal operation.On the basis of its review, the staff determined that the applicant has no components coveredby SRP-LR Section 3.3.2.2.6. The staff found this aging effect not applicable.3.3.2.2.7Loss of Material Due to General, Pitting, Crevice, and Microbiologically InfluencedCorrosion and BiofoulingThe staff reviewed LRA Section 3.3.2.2.7 against the criteria in SRP-LR Section 3.3.2.2.7.In LRA Section 3.3.2.2.7, the applicant addressed loss of material due to general, pitting, andcrevice corrosion, MIC, and biofouling for components in the EDGs.SRP-LR Section 3.3.2.2.7 states the following:Loss of material due to general, pitting, and crevice corrosion, MIC, andbiofouling could occur on the internal surface of tanks in the diesel fuel oil system and due to general, pitting, and crevice corrosion and MIC in the tanks ofthe diesel fuel oil system in the EDG system. The existing AMP relies on the fueloil chemistry program for monitoring and control of fuel oil contamination in accordance with the guidelines of ASTM Standards D4057, D1796, D2709 and D2276 to manage loss of material due to corrosion or biofouling. Corrosion or biofouling may occur at locations where contaminants accumulate. Verification of the effectiveness of the chemistry control program should be performed to ensure that corrosion is not occurring. The GALL Report recommends further evaluation of programs to manage corrosion/biofouling to verify the effectiveness of the program. A one-time inspection of selected components at susceptible locations is an acceptable method to ensure that corrosion is not occurring and that the component's intended function will be maintained during the period ofextended operation.
3-208In LRA Section 3.3.2.2.7, the applicant stated that its Fuel Oil Chemistry Program managesloss of material for all components wetted by fuel oil. The One-Time Inspection Program confirms the effectiveness of the Fuel Oil Chemistry Program. The Fuel Oil Chemistry Program uses existing diesel oil system procedures that encompass the GALL Report programrequirements. The Fuel Oil Chemistry Program mitigates and manages aging effects on the surfaces wetted by fuel oil in fuel oil storage tanks and associated components, including the tank and other components supplying fuel to the diesel fire pump. The program includes (1) surveillance and monitoring procedures for maintaining fuel oil quality by controllingcontaminants in accordance with applicable ASTM standards, (2) periodic draining of water from fuel oil tanks, (3) periodic or conditional visual inspection of internal surfaces or wall thickness measurements (e.g., by UT) from external surfaces of fuel oil tanks, and (4) one-time inspections of a representative sample of components in systems that contain fuel oil. TheOne-Time Inspection Program includes (1) determination of sample size based on an assessment of materials of fabrication, environment, plausible aging effects, and operating experience, (2) identification of the inspection locations in the system or component based onthe aging effect, (3) determination of the examination technique, including acceptance criteriathat will be effective in managing the aging effect for which the component is examined; and (4)evaluation of the need for followup examinations to monitor the progression of any aging degradation.The staff reviewed the applicant's Fuel Oil Chemistry Program and the One-Time InspectionProgram and found them acceptable for managing aging degradation. SER Sections 3.0.3.2.17and 3.0.3.1.4, respectively, document the evaluation.On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LRSection 3.3.2.2.7. For those line items that apply to LRA Secti on 3.3.2.2.7, the staff determinedthat the applicant's AMRs are consistent with the GALL Report and the applicant hasdemonstrated that the effects of aging will be adequately managed so that the intendedfunction(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  Quality Assurance for Aging Management of Nonsafety-Related ComponentsSER Section 3.0.4 provides the staff's evaluation of the applicant's Quality Assurance Program.3.3.2.2.9  Crack Initiation and Growth Due to Stress-Corrosion Cracking and Cyclic Loading The staff reviewed LRA Section 3.3.2.2.9 against the criteria in SRP-LR Section 3.3.2.2.9.In LRA Section 3.3.2.2.9, the applicant stated that this aging effect applies to PWRs only.SRP-LR Section 3.3.2.2.9 states that crack initiation and growth due to SCC and cyclic loadingcould occur in the channel head and access cover, tubesheet, tubes, shell and access cover, and closure bolting of the regenerative heat exchanger and in the channel head and access cover, tubesheet, and tubes of the letdown heat exchanger in the chemical and volume controlsystem (CVCS). SRP-LR Table 3.3-1 states that further evaluation for this aging effect is for PWR plants only.The staff found this aging effect not applicable.
3-2093.3.2.2.10Reduction of Neutron-Absorbing Capacity and Loss of Material Due to GeneralCorrosionThe staff reviewed LRA Section 3.3.2.2.10 against the criteria in SRP-LR Section 3.3.2.2.10.In LRA Section 3.3.2.2.10, the applicant addressed reduction of neutron-absorbing capacity andloss of material due to general corrosion for boral.SRP-LR Section 3.3.2.2.10 states the following:Reduction of neutron-absorbing capacity and loss of material due to generalcorrosion could occur in the neutron-absorbing sheets of the spent fuel storage rack in the spent fuel storage. The GALL Report recommends further evaluation to ensure that these aging effects are adequately managed.In LRA Section 3.3.2.2.10. By letter dated November 17, 2005, the applicantstated that it will visually examine the unclad boral coupon sample before the period ofextended operation. The applicant will remove the coupon from the spent fuel pool for a briefperiod of time, visually examine it, and then immediately return it to the spent fuel pool.The staff's review determined that the Plant Chemistry Program, supplemented by the One-Time Inspection Program, will manage reduction of neutron-absorbing capacity and loss ofmaterial due to general corrosion. The one-time inspection of boral coupon test specimens willconfirm that no significant aging degradation will occur and that the neutron-absorbingcapability of the boral has not been reduced.These AMPs are appropriate for the aging effects/mechanisms identified and assure effectivemanagement through the period of extended operation. The staff reviewed the Plant ChemistryProgram and the One-Time Inspection Program and found them acceptable for managing aging degradation. SER Sections 3.0.3.2.19 and 3.0.3.1.4, respectively, document theevaluations.On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LRSection 3.3.2.2.10. For those line items that apply to LRA Section 3.3.2.2.10, the staffdetermined that the applicant's AMRs are consistent with the GALL Report and the applicanthas demonstrated that the effects of aging will be adequately managed so that the intendedfunction(s) will be maintained consistent with the CLB during the period of extended operation,as required by 10 CFR 54.21(a)(3).
3-2103.3.2.2.11Loss of Material Due to General, Pitting, Crevice, and Microbiologically InfluencedCorrosionThe staff reviewed LRA Section 3.3.2.2.11 against the criteria in SRP-LR Section 3.3.2.2.11.In LRA Section 3.3.2.2.11, the applicant addressed loss of material due to general, pitting, andcrevice corrosion and MIC of underground (buried) piping and fittings in the DGN, FIR, and ESW systems.SRP-LR Section 3.3.2.2.11 states the following:Loss of material due to general, pitting, and crevice corrosion and MIC couldoccur in the underground piping and fittings in the open-cycle cooling watersystem (SW system) and in the diesel fuel oil system. The buried piping andtanks inspection program relies on industry practice, frequency of pipe excavation, and operating experience to manage the effects of loss of material from general, pitting, and crevice corrosion and MIC. The effectiveness of the buried piping and tanks inspection program should be verified to evaluate an applicant's inspection frequency and operating experience with buried components, ensuring that loss of material is not occurring.In LRA Section 3.3.2.2.11, the applicant stated that the Buried Piping & Tanks InspectionProgram manages the loss of material due to general, pitting, and crevice corrosion, MIC, galvanic corrosion, and selective leaching for buried valve bodies, piping, and fittings. The Bolting Integrity Program manages loss of material due to general, pitting, and crevice corrosion, MIC, and galvanic corrosion for buried fasteners. The Buried Piping & Tanks Inspection Program consists of preventive and condition monitoring measures to manage the aging effect. Preventive measures consist of protective coatings and/or wraps on buried components. Condition monitoring consists of periodic inspections of buried components. The applicant's operating experience shows no buried pipe/tank failures for components within the scope of license renewal. The Bolting Integrity Program consists of guidelines on materials selection, strength and hardness properties, installation procedures, lubricants and sealants, corrosion considerations in the selection and installation of pressure-retaining bolting for nuclear applications, and inspection techniques.The staff's review determined that the Buried Piping & Tanks Inspection Program providesadequate management of aging effects for buried pipes, components, and tanks during the period of extended operation. The Bolting Integrity Program references and invokes the provisions of the Buried Piping & Tanks Inspection Program to implement inspection of these components. The staff reviewed the Buried Piping & Tanks Inspection Program and the Bolting Integrity Program and found them acceptable for managing aging degradation. SER Sections 3.0.3.2.5 and 3.0.3.2.4, respectively, document the evaluations.
3-211Conclusion. On the basis of its review, for component groups evaluated in the GALL Report forwhich the applicant has claimed consistency with the GALL Report, and for which the GALL Report recommends further evaluation, the staff determined that the applicant adequatelyaddressed the issues that were further evaluated. The staff found that the applicant hasdemonstrated that the effects of aging will be adequately managed so that intended functionswill be maintained consistent with the CLB for the period of extended operation, as required by10 CFR 54.21(a)(3).3.3.2.3  AMR Results That Are Not Consistent with or Not Addressed in the GALL ReportSummary of Technical Information in the Application. In LRA Tables 3.3.2-1 through 3.3.2-18,the staff reviewed additional details of the results of the AMRs for material, environment, AERM, and AMP combinations that are not consistent with the GALL Report, or that are notaddressed in the GALL Report.In LRA Tables 3.3.2-1 through 3.3.2-18, the applicant indicated, via Notes F through J, that thecombination of component type, material, environment, and AERM does not correspond to a line item in the GALL Report and provided information concerning the management of the aging effect. Specifically, Note F indicates that the GALL Report does not evaluate the material for the AMR line item component. Note G indicates that the GALL Report does not evaluate the environment for the AMR line item component and material. Note H indicates that the GALL Report does not evaluate the aging effect for the AMR line item component, material, and environment combination. Note I indicates that the aging effect identified in the GALL Report forthe line item component, material, and environment combination does not apply. Note J indicates that the GALL Report evaluates neither the component nor the material andenvironment combination for the line item.Staff Evaluation. For component type, material, and environment combinations that the GALLReport does not evaluate, the staff reviewed the applicant's evaluation to determine whetherthe applicant had demonstrated that the effects of aging will be adequately managed so thatintended functions will be maintained consistent with the CLB during the period of extendedoperation. This section addresses the AMR results for which LRA Tables 3.3.2-1 through 3.3.2-18 do not identify any aging effects. Each table discussion separately addresses otherline items not consistent with or not addressed in the GALL Report. The following sections discuss the staff's evaluation.The staff's review of LRA Tables 3.3.2-1 through 3.3.2-18 identified areas for which it neededadditional information to complete its evaluation of the applicant's results. The applicant responded to the staff's general RAIs as discussed below.In RAI 3.3.2.3-2, dated July 20, 2005, the staff noted that LRA Tables 3.3.2-6 and 3.3.2-8identify heat transfer degradation due to fouling as an AERM for copper heat exchangers (heat transfer and pressure boundary functions) in a lubricating oil environment. The applicant credited the One-Time Inspection Program with managing this aging effect. The One-Time Inspection Program verifies the effectiveness of an AMP and confirms the absence of an aging effect. For fouling of heat exchangers in a lubricating oil environment, mitigation of the aging effect depends on a lubricating oil monitoring program to maintain the integrity of the oil; therefore, the staff requested that the applicant identify an AMP to mitigate the effects of fouling 3-212in the heat exchangers during the period of extended operation and verify the effectiveness ofthat program with a one-time inspection.In its response, by letter dated August 16, 2005, the applicant stated the following:Table 3.3.2-6, Emergency Diesel Generators System (EDG) and Table 3.3.2-8,Emergency Service Water System (ESW) identify copper alloy heat exchanger tubes for both the EDG lube oil coolers and RHR Service Water (RSW) pumpmotor thrust bearing oil coolers, with lubricating oil as an external environment for these Auxiliary Systems.The NMC position concerning the potential aging effect of heat transferdegradation due to fouling in a lubricating oil environment is that degradationeffects are insignificant for lubricating oil systems if the oil remains free of waterand other contaminants. Under these conditions, lubricating oil systems andassociated components have few, if any, significant aging effects. The purity of the EDG and ESW lubricating oil systems is maintained and chemically analyzedperiodically. For equipment not normally in operation during power operation such as the EDG lube oil coolers and the RSW motor thrust bearing oil coolers, periodic testing of the equipment, in conjunction with oil sampling, is performed to detect any contaminants or water in the oil.Lubricating oil is usually non-corrosive and flow rates for lube oil systems aretypically low. Strict controls for the quality and purity of the lubricating oil procured and scheduled sampling techniques and parameters monitored are requirements of the MNGP lubricating oil sampling procedures. Very little corrosion occurs in lubricating oil systems due to low oxygen content, the factthat lubricating oils are not good electrolytes and purification systems aregenerally installed and/or corrosion inhibitors added to maintain the lubricating oil free of corrosion products.Lube oil samples for the EDG lube oil coolers are obtained quarterly andsamples for the RSW pump motor thrust bearing oil coolers are obtained annually in accordance with MNGP site procedures. The sample results are evaluated and trended for these components. Any indication of an anomalous condition or adverse trend will result in an investigation under the site correctiveaction program. All sample results have been acceptable to date to ensure that the lubricating oil remains free of moisture and contaminants that could potentially degrade the heat exchanger tubes, with the last samples taken and evaluated for both the EDG and ESW systems in 2005. Although MNGPoperating experience did result in the replacement of the EDG lube oil coolers due to the lead solder joints and resultant exfoliation corrosion, this was a design issue and not age-related (Institute of Nuclear Power Operations SOER 80-04).Based on the above procurement and sampling requirements to maintain theintegrity of the lubricating oil and MNGP plant-specific operating experience thatconfirms the absence of this aging effect, MNGP conservatively credits the One-Time Inspection Program to verify the absence of the aging effect of heat transfer degradation due to fouling for these components in the EDG and ESW 3-213Systems. The MNGP One-Time Inspection Program will use the CorrectiveAction Program to evaluate indications or relevant conditions of degradation. The need to increase the number of selected components for inspection will also beevaluated when indications or relevant conditions of degradation or unacceptable conditions are found.Based on its review, the staff found the applicant's response to RAI 3.3.2.3-2 acceptable,because the applicant satisfactorily identified procurement and sampling requirements to maintain the integrity of the lubricating oil and use of the One-Time Inspection Program to verify the absence of the aging effect of heat transfer degradation due to fouling in the DGN and ESW system heat exchangers; therefore, the staff's concern described in RAI 3.3.2.3-2 isresolved.In RAI 3.3.2.3-3, dated July 20, 2005, the staff noted that LRA Tables 3.3.2-3 and 3.3.2-16identify no aging effects for rubber expansion joints in a raw water environment; therefore, the staff requested that the applicant identify an AMP to manage hardening and loss of strength forrubber expansion joints in a raw water environment.In its response, by letter dated August 16, 2005, the applicant stated the following:Several EPRI Technical Reports and Industry handbooks were reviewed foraging of elastomers. A summary of the review is provided below.EPRI Report 1008035, 'Expansion Joint Maintenance Guide', Revision 1, May2003, Table 5-4, rates elastomers against oxidation, tensile strength, andradiation. Elastomers, such as neoprene, natural rubber, Chlorobutyl, Buna-N, viton, and EPDM, are rated as good or better in the categories of oxidation, tensile strength, and radiation.EPRI Report NP-6608, 'Shelf Life of Elastomeric Components,' May 1994,Appendix A, provides curves that describe the change in physical properties for different elastomers as they undergo natural aging. The figures demonstrate that there is very little change in the hardness and tensile strength of elastomers over a 33 year period.EPRI Report NP-6408, 'Guidelines for Establishing, Maintaining, and Extendingthe Shelf Life Capability of Limited Life Items (NCIG-13)', May 1992,section 4.3.2, states that test results demonstrated Viton and Neoprene ashaving excellent weather resistance and are therefore UV resistant.
Section 4.4.2 states that these elastomers are also highly resistant to ozone.The Parker O-Ring Handbook, Page 2-24, in a discussion about aging of rubberseals states, 'It is environment and not age that is significant to seal life, both instorage and actual service.' The following is a discussion of the role of environment on the aging of elastomers.EPRI 1003056, November 2001, 'Non-Class 1 Mechanical ImplementationGuideline and Mechanical Tools, Revision 3, states 'For a complete discussion of the aging effects of typical elastomers used in nuclear plants, the applicant is 3-214referred to EPRI TR-114881, 'Aging Effects for Structures and StructuralComponents (Structural Tools)'. EPRI TR-114881 has been superceded by EPRI 1002950, 'Aging Effects for Structures and Structural Components (Structural Tools), Revision 1', May 2003. This report discusses the three stressors: (1) Ultraviolet, (2) Thermal, and (3) Radiation listed below.  (135)Ultraviolet: The Structural Tools state 'Rubber is decomposed byexposure to ultraviolet radiation. Ultraviolet radiation sources at nuclear plants include solar radiation and ultraviolet or fluorescent lamps. The deterioration of rubber is greatly accelerated in the presence of oxygen. Cracking and checking (splitting), which may occur when rubber is exposed to air and sunlight, are due mainly to reaction with ozone.' None of the elastomers in the scope of license renewal at MNGP are exposed to solar radiation. EPRI Report NP-6408, Section 4.3.2, states that UV on elastomers caused by artificial light is of little concern since the amount of UV is very small. For conservatism, MNGP took the position that any elastomers in close proximity to fluorescent lamps would be managed for aging, however none were found. Therefore, given the absence of solar radiation and the negligible effects from artificial light, these elastomers are not susceptible to hardening and loss of strength, which could be caused by the ultraviolet radiation exposure.  (136)Thermal: The Structural Tools state, 'In general, if the ambienttemperature is less than about 95 &deg;F, then thermal aging may be considered not significant for the period of extended operation'.
Since these elastomers are not exposed to temperatures
>95 degrees F, they are therefore not susceptible to hardening and loss of strength caused by thermal exposure.  (137)Radiation: The Structural Tools state, 'Material property changesand cracking owing to radiation is an applicable aging effect for rubber, neoprene, and s ilicone elastomers in environments wherethe radiation exceeds the limits defined above.' The limit listed for rubber is 10 7 Rads, Butyl Rubber 10 6 Rads, and Neoprene 10 6Rads. Since these elastomers are not exposed to this degree of ionizing radiation exposure, which is orders of magnitude above that corresponding to 60 years of normal plant operation, they are therefore not susceptible to hardening and loss of strength caused by radiation.EPRI 1002950, 'Structural Tools,' reviewed industry failure data and NRCgeneric communications to determine if there was any additional aging effects that should be considered for elastomers. The review did not uncover any new aging effects.EPRI Report 1007933, 'Aging Assessment Field Guide,' December 2003, pages60 through 65, lists degradation mechanisms brought on by the stressors:
Thermal, Radiation, and Ultraviolet. Since these elastomers are not exposed to 3-215ultraviolet, radiation, or temperatures >95&deg;F, they are therefore not susceptible tohardening and loss of strength and therefore no aging management is required.Consistent with the above discussion, Monticello only included elastomers in anaging management program that are subject to elevated temperature, ultraviolet, or ionizing radiation. Elastomers are included in the One-Time Inspection Program to confirm that unacceptable degradation has not occurred such that they will perform their intended function during the period of extended operation.If inspections of these more severe applications identify unacceptable degradation, the inspection scope would be expanded as required by the One-Time Inspection Program. The expanded scope would include less environmentally severe applications and could eventually include the elastomers that were excluded from aging management as described above. Therefore, elastomers not explicitly identified as requiring aging management, based on industry experience and technical research, are subject to the One-Time Inspection Program requirements concerning scope expansion and could be inspected if needed based on the examination results of more severe applications.By letter, dated November 17, 2005, the applicant described the following additional agingmanagement for elastomers in an air environment exposed to ozone:After further evaluation of this issue, NMC has taken the conservative approachof managing change in material properties due to ozone for elastomers in an air environment, specifically for natural rubber. This is a result of the fact that neither representative ozone concentrations nor technically substantiated thresholds could be adequately or consistently determined, even thoughplant-specific operating experience has indicated that there has been no changein material properties due to ozone for these elastomer components. Further evaluation also revealed the inability to confirm that none of these componentsare fabricated from natural rubber.As a result, elastomers in an external air environment in the following LRA tableswill utilize the System Condition Monitoring Program to manage the potentialaging effect of change in material properties due to ozone which shall be assigned to these components.
* Table 3.3.2-3 expansion joints in the Circulating Water System
* Table 3.3.2-5 piping and fittings in the Demineralized Water System
* Table 3.3.2-6 piping and fittings in the Emergency Diesel GeneratorsSystem
* Table 3.3.2-7 ventilation seals in the Emergency Filtration Train System
* Table 3.3.2-16 expansion joints in the Service and Seal Water System
* Table 3.4.2-2 expansion joints in the Condensate and Feedwater System(those which were not previously managed externally) 3-216Elastomers in Table 3.2.2-8 (ventilation seals in the Secondary ContainmentSystem) are presently being managed utilizing the One-Time InspectionProgram for the internal surfaces and the System Condition Monitoring Program for the external surfaces. These Aging Management Programs (AMPs) were initially credited to manage change in material properties and cracking due to thermal exposure, since a temperature threshold of greater than 95 F wasassigned to these components. Consequently, these same AMPs will alsomanage change in material properties due to ozone which shall be assigned to these components.Elastomers (expansion joints) in Table 3.4.2-3 (Main Condenser System) do notrequire aging management since these components do not serve a pressure boundary intended function but provide for plate-out and holdup of radioactive material during design basis events. Condenser integrity is continuously demonstrated during normal plant operation thus validating that this intendedfunction is maintained as stated in the plant-specific notes for these components in Section 3.4 of the LRA.Elastomers in an internal air environment in Table 3.3.2-6 (piping and fittings inthe Emergency Diesel Generators System) and Table 3.3.2-7 (ventilation sealsin the Emergency Filtration Train System) will utilize the One-Time Inspection Program to manage the potential aging effect of change in material properties due to ozone which shall be assigned to these components.Elastomers in both an internal and external air environment in Table 3.3.2-11(ventilation seals in the Heating and Ventilation System) were inadvertentlyomitted from this table. These components shall be managed for the potentialaging effect of change in material properties due to ozone utilizing the One-TimeInspection Program for the internal surfaces and the System Condition Monitoring Program for the external surfaces which shall be assigned to these components.All the elastomers addressed are long-lived components. Any component that isnot long-lived and replaced at specified intervals is eliminated from AMR consideration during the screening process. Although the expansion joints are presently under review for replacement on a fixed periodicity, this change has not been effected and they remain as and have been analyzed as long-lived components.Any degradation of elastomer components in an air environment resulting fromchange in material properties due to ozone for the external surfaces of these components shall be evaluated as discussed in the response to RAI B2.1.32-2 which addresses the System Condition Monitoring AMP.This response also applies to the previous RAI responses concerning elastomersincluding RAI 3.3.2.3-3, RAI 3.3.2.3-4, RAI 3.3.2.3-5, RAI 3.3.2.3-6, andRAI 3.4-01.
3-217Based on its review, the staff found the applicant's response to RAI 3.3.2.3-3 acceptable,because it satisfactorily identified stressors and thresholds for which hardening and loss of strength are aging effects for elastomer components and applied aging management for these cases. Where the stressors and thresholds for which hardening and loss of strength are not exceeded, aging management is not required. Therefore, the staff's concern described inRAI 3.3.2.3-3 is resolved.In RAI 3.3.2.3-4, dated July 20, 2005, the staff noted that LRA Tables 3.3.2-3, 3.3.2-5, 3.3.2-6,3.3.2-7, and 3.3.2-16 identify no aging effects for rubber expansion joints, piping and fittings,and elastomer ventilation seals in a plant indoor air environment; therefore, the staff requested that the applicant identify an AMP to manage hardening and loss of strength for these rubberand elastomer components in a plant indoor air environment.In its response, by letter dated August 16, 2005, the applicant stated that its response toRAI 3.3.2.3-3 applies to this RAI as well.The staff found the applicant's response acceptable. Therefore, the staff's concern described inRAI 3.3.2.3-4 is resolved.In RAI 3.3.2.3-5, dated July 20, 2005, the staff noted that LRA Tables 3.3.2-5 and 3.3.2-17identify no aging effects for rubber accumulators, piping, and fittings in a treated water environment. Previously, the staff had identified hardening and loss of strength as aging effects for rubber and elastomer components in this environment and recommended a plant-specific program to manage these aging effects by periodic inspections of the components; therefore, the staff requested that the applicant identify an AMP to manage hardening and loss of strengthfor these rubber components in a treated water environment.In its response, by letter dated August 16, 2005, the applicant referred to its response toRAI 3.3.2.3-3.The staff found the applicant's response acceptable; therefore, the staff's concern described inRAI 3.3.2.3-5 is resolved.In RAI 3.3.2.3-6, dated July 20, 2005, the staff noted that LRA Tables 3.3.2-6 and 3.3.2-7identify no aging effects for rubber ventilation seals, piping, and fittings in a gas and air internal environment; therefore, the staff requested that the applicant identify an AMP to managehardening and loss of strength for these rubber components in a gas and air internal environment where the internal temperature exceeds 95 F.In its response, by letter dated August 16, 2005, the applicant referred to its response toRAI 3.3.2.3-3.The staff found the applicant's response acceptable; therefore, the staff's concern described inRAI 3.3.2.3-6 is resolved.In RAI 3.3.2.3-7, dated July 20, 2005, the staff noted that LRA Tables 3.3.2-6 and 3.3.2-9identify no aging effects for stainless steel fasteners/bolting and copper alloy flame arresters in an environment exposed to weather; therefore, the staff requested that the applicant identify an 3-218AMP to manage loss of material due to pitting and crevice corrosion for these stainless steeland copper alloy components exposed to weather.In its response, by letter dated August 16, 2005, the applicant stated the following:Table 3.3.2-6, Emergency Diesel Generators System (EDG) and Table 3.3.2-9,Fire System (FIR) identify stainless steel fasteners/bolting (EDG and FIR),
copper alloy flame arrestors (EDG and FIR) and hose house supply valves (FIR) exposed to weather for these Auxiliary Systems. The NMC materials science position, which is in accordance with EPRI 1003056 (Non-Class I Mechanical Implementation Guideline and Mechanical Tools, Revision 3), is that these components do not have a surface exposed to an aggressive chemical species, do not have the potential for concentrating contaminants and are not subject towetting other than their normal environment. Therefore, loss of material due to crevice or pitting corrosion is not a potential aging mechanism.Crevice corrosion is a potential aging mechanism for wetted stainless steel andhigh zinc copper alloys under certain conditions. Crevice corrosion is strongly dependent on the presence of dissolved oxygen. Although oxygen depletion in crevices may occur as a result of the corrosion process, oxygen is st ill requiredfor the onset of corrosion, and a bulk fluid oxygen content or the presence ofcontaminants such as chlorides is necessary for the continued dissolution of material in the crevice. For systems with extremely low oxygen content (<0.1ppm), crevice corrosion is considered insignificant. This form of corrosion requires a crevice where contaminants and corrosion products can concentrate.
In addition to oxygen, moisture is required for the mechanism to operate.
Alternate wetting and drying is particularly harmful as this leads to a concentration of atmospheric pollutants and contaminants if they are present.These conditions do not exist at the MNGP.Pitting corrosion is a potential aging mechanism for wetted stainless steel andhigh zinc copper alloys under certain conditions. Unless cupric, ferric or mercuric halides are present in the environment, oxygen is required for pitting initiation.
Areas where aggressive species can concentrate are particularly susceptible to pitting. Most pitting is the result of halide contamination, with chlorides, bromides, and hypochlorites being prevalent. Pitting is a significant aging effect for stainless steels and high zinc copper alloys when exposed to a corrosive environment. Any continuously wetted or alternately wetted and dried surfaces tend to concentrate aggressive species if they are present and are prone to pitting corrosion. These conditions also do not exist at the MNGP.For conservatism, the stainless steel fastener/bolting component was added as a'global' asset to assure no components, materials or environments were inadvertently omitted during the AMR process. Recent walk downs of both the EDG and FIR Systems revealed there were no stainless steel fasteners/bolting exposed to weather in either of these systems. Additionally, the FIR hose housesupply valves reside within the individual hose house metal enclosures. Although these copper alloy valves are subjected to an 'Outside Air Protected from Weather' environment, they were conservatively assigned to the 'Exposed to 3-219Weather' environment. Sheltered environments tend to preclude the presence ofsufficient moisture to promote significant corrosion. Lastly, the copper alloy flame arrestors, though painted (no credit is taken for coatings at MNGP with respect to the mechanical systems), were confirmed to be aluminum during these walkdowns. Since aluminum and copper alloys are analyzed essentially in the same manner for loss of material due to crevice and pitting corrosion in an 'exposed to weather' external environment, the difference in actual material is considered inconsequential. However, both the EDG and FIR Systems' stainless steel fasteners/bolting exposed to weather asset shall be removed from Table 3.3.2-6 and Table 3.3.2-9 and the material for the flame arrestors shall be changed from copper alloy to aluminum in Table 3.3.2-6.Since none of these components have a surface exposed to an aggressivechemical species (sulfur dioxide, chlorine gases, sulfur gases, ozone, etc.), do not have the potential for concentrating contaminants and are not subject towetting other than their normal environment, loss of material due to crevice or pitting corrosion is not a potential aging mechanism. This has been confirmed by system walk downs and substantiated by plant-specific operating experience.Based on its review, the staff found the applicant's response to RAI 3.3.2.3-7 acceptablebecause (1) no stainless steel fasteners/bolting in the DGN and FIR system are exposed toweather and (2) the aluminum flame arrestors in Table 3.3.2-6 and the copper alloy hose house supply valves in Table 3.3.2-9 are not subject to environments that promote pitting and crevicecorrosion. Therefore, aging management is not required for these components and the staff'sconcern described in RAI 3.3.2.3-7 is resolved.In LRA Tables 3.3.2-1 through 3.3.2-18, the applicant identified line items for which it did notidentify any aging effects as a result of the aging review process.Specifically, the applicant stated that no aging effects occur when components fabricated frombronze, CASS, copper alloy, and stainless steel materials are exposed to air/gas (internal and external), concrete (external), dry air (internal), gas-halon (internal), gas-instrument air (internal), gas-nitrogen (internal), gas-refrigerant (internal), lubricating oil (internal and external),plant indoor air (internal and external), and primary containment air (external) environments. In addition, components fabricated from carbon steel, galvanized steel, and cast iron exposed to these same environments, with the exception of indoor air and primary containment airenvironments, have no aging effects. The applicant stated that materials science evaluation ofthese materials in such environments found no aging effects for the components and materials.
No aging effects are considered applicable to components fabricated from the above list of materials exposed to the given environments.As shown in the Metals Handbook, Ninth Edition, Volume 13, comprehensive tests over a20-year period under ASTM supervision confirmed the suitability of copper alloys foratmospheric exposure. Additionally, because the gaseous internal environments to which components within the scope of license renewal may be subject include air, nitrogen, carbon dioxide, freon, and halon, industry experience shows that copper piping exposed to an internal gaseous environment will be resistant to any age-related degradation; therefore, the SC willremain capable of performing intended functions consistent with the CLB for the period of extended operation.
3-220As shown in the Metals Handbook, Ninth Edition, Volumes 1 and 13, both oxygen and moisturemust be present to corrode steel. Experience has shown that general corrosion of steel (including carbon steel, alloy steel, gray cast iron, and galvanized steel) will apply only if it wereexposed to outdoor or indoor environments that promote condensation of water on the externalsurfaces of components; therefore, the SC will remain capable of performing intended functionsconsistent with the CLB for the period of extended operation.As shown in Metals Handbook, Ninth Edition, Volumes 3 and 13, stainless steels are highlyresistant to corrosion in dry atmospheres in the absence of corrosive species (which will bereflective of indoor uncontrolled air or primary containment air inerted with nitrogen); therefore, the SC will remain capable of performing intended functions consistent with the CLB for theperiod of extended operation.As shown in the Metals Handbook, Ninth Edition, Volumes 1 and 13, both oxygen and moisturemust be present to corrode steel. Components are not subject to wetting if their surfaces remain oil-coated; therefore, steel (carbon or stainless) in a lubricating oil environment with nowater pooling exhibits no aging effect, and the SC will remain capable of performing intendedfunctions consistent with the CLB for the period of extended operation.For carbon steel embedded in concrete, loss of material due to general corrosion could occur inan aggressive environment. An aggressive environment has pH less than 5.5, chlorides greater than 500 ppm, or sulfates greater than 1500 ppm. Plant documents confirm that thebelow-grade environment is not aggressive. The applicant's data indicate that the pH exceeds 7, chlorides are less than 100 ppm, and sulfates are less than 100 ppm. To ensure that the below-grade environment remains nonaggressive, the Structures Monitoring Programincludes periodic monitoring of ground water chemistry for the above parameters; therefore, the SC will remain capable of performing intended functions consistent with the CLB for the periodof extended operation.The staff's review of current industry research and operating experience found that effects ofthe listed environments on the given materials will not result in aging effects of concern during the period of extended operation; therefore, the staff concluded that no AERMs apply for thecomponent, material, and environment combinations described in the preceding discussion.3.3.2.3.1Auxiliary Systems-Alternate Nitrogen System-Summary of Aging ManagementEvaluation-Table 3.3.2-1The staff reviewed LRA Table 3.3.2-1, which summarizes the results of AMR evaluations for thealternate nitrogen system component groups.All line items in this table are consistent with the GALL Report or are included in the discussionin Section 3.3.2.3 above.3.3.2.3.2Auxiliary Systems-Chemistry Sampling System-Summary of Aging ManagementEvaluation-Table 3.3.2-2The staff reviewed LRA Table 3.3.2-2, which summarizes the results of AMR evaluations for thechemistry sampling system component groups.
3-221All line items in this table are consistent with the GALL Report or are included in the discussionin Section 3.3.2.3 above.3.3.2.3.3Auxiliary Systems-Circulating Water System-Summary of Aging ManagementEvaluation-Table 3.3.2-3The staff reviewed LRA Table 3.3.2-3, which summarizes the results of AMR evaluations for theCWT system component groups.The applicant stated that it expects no aging effects for stainless steel and polyvinyl chloride(PVC) filters/housings exposed to a plant indoor air environment. The staff's review of plant-specific and industry operating experience found no aging effects expected for stainless steel and PVC filters/housings exposed to a plant indoor air environment in the CWT system.Likewise, the applicant stated that it expects no aging effects for rubber expansion jointsexposed to plant indoor air and treated water environments. RAIs 3.3.2.3-3 and 3.3.2.3-4 inSER Section 3.3.2.3 discuss the staff's evaluation.Based on the above evaluations, the staff found that the applicant has identified the appropriateAMP for the materials and environment associated with the above components in the CWTsystem.3.3.2.3.4Auxiliary Systems-Control Rod Drive System-Summary of Aging ManagementEvaluation-Table 3.3.2-4The staff reviewed LRA Table 3.3.2-4, which summarizes the results of AMR evaluations for theCRD system component groups.The applicant proposed to manage the CRD system aging effects with the System ConditionMonitoring Program. SER Section 3.0.3.3.2 documents the staff's review of the applicant'sSystem Condition Monitoring Program.The staff's review of LRA Table 3.3.2-4 identified an area for which it needed additionalinformation to complete its evaluation of the applicant's results. The applicant responded to the staff's RAI as discussed below.In RAI 3.3.2.3-1, dated July 20, 2005, the staff noted that LRA Table 3.3.2-4 identifies SCC asan AERM for stainless steel piping and fittings in a primary containment air environment. To manage this aging effect, the applicant credited the System Conditioning Monitoring Program, which uses visual inspections of component external surfaces for detection of aging effects; therefore, the staff requested that the applicant provide operating experience or other bases fordetermining that SCC is an aging effect in this environment. In addition, since methods like VT-1, liquid penetrant, or volumetric inspections are used to detect SCC, the staff asked the applicant to identify the methods and acceptance criteria of the System Conditioning MonitoringProgram to detect SCC for these components.In its response, by letter dated August 16, 2005, the applicant stated the following:
3-222Data suggests that temperature is an important factor in stress corrosioncracking (SCC) and that SCC is seldom found at temperatures below 140 degrees F. However, a review of plant operating experience revealed two locations where cracking was observed on the exterior of the Control Rod Drive System (CRD) withdrawal lines, prompting NMC to manage cracking on theexterior of the stainless steel CRD lines located inside containment.In 1998, during performance of the visual walkdown portion of the reactorcoolant pressure boundary leakage test, a crack was identified on a CRD withdrawal line within the drywell. The specific CRD is CRD 34-27. Failure analysis performed by a metallurgical laboratory revealed the cause to be transgranular stress corrosion cracking (TGSCC) due to chloride attack of the external surface. This evaluation showed the cracking to originate from the outside diameter inwards. Also, the metallurgical laboratory found chloride in the through wall flaw. The source of the chloride contamination was not positively identified. The leaking pipe was in an area located directly under catwalks.
These open areas are more vulnerable to contamination due to personnel traffic and potential for sp ills.As a result of the leak, the following inspections were made during the 1998refueling outage:
* All lines were VT-2 inspected during the ASME Code, Section XI, reactorcoolant pressure boundary leakage test. No leaks were found after the cracked piping was replaced.
* All elbows (where the vertical run turns horizontal for penetration of thebiological shield) were visually inspected. There were no indications.
* Dye penetrant testing on the elbows of 14 withdraw lines in the samebundle as CRD 34-27 (outside of the biological shield, with the exceptionof an elbow on CRD 38-27 which was inside the biological shield.) was conducted. No indications were found.During the 2000 outage, the accessible CRD piping had been wiped down andforeign material, including tape, was removed. After the piping was cleaned, an inspection of 504 one-foot long sections of all accessible CRD insert andwithdrawal lines from the hydraulic accumulator units (HCUs) to the reactor pedestal was implemented. A crack indication was found on CRD withdrawalline 14-27 inside the drywell. The drywell pipe section contained a defect greater than 10% through wall. The apparent cause of the indication appears to have been chloride induced SCC. The indication was identified as being under a piece of tape on a vertical section of the withdraw line. The laborer removing the tape from the area with the relevant indication noted that that particular piece of tapewas different from the others removed in that it was both discolored and difficult to remove. It is possible, although unlikely, that the chlorides necessary for TGSCC leached from this tape. However, a more plausible explanation is that chloride contaminated water from another source dripped down the pipe and the tape acted as a crevice, providing a spot for the aqueous chlorides to begin their 3-223attack. A source of aqueous chlorides leaking from above would be consistentwith the relevant conditions found during the 1998 refueling outage.In view of this plant specific operating experience, NMC conservatively assumedcracking on the external surface of the CRD pipes inside the drywell despite the extensive testing already conducted. The cracking will be managed using theSystem Condition Monitoring Program. The System Condition Monitoring Program is an existing plant-specific program. This program manages aging effects for normally accessible, external surfaces of piping, tanks, and other components and equipment within the scope of license renewal. The aging effects are to be managed through visual inspection to look for degradation conditions such as crack-like indications and corrosion. Crack-like indications willbe entered into the corrective action process for evaluation. The evaluation will include appropriate acceptance criteria based on applicable code specifications and industry practices such as EPRI. The evaluation will consider the need forfurther surface examinations such as liquid penetrant or volumetric inspection to determine the extent of condition.The staff reviewed the applicant's response and found it acceptable. The applicant satisfactorilyexplained its management of SCC as an aging effect in this environment and identified the methods and acceptance criteria used by System Conditioning Monitoring Program to detect SCC for these components. The staff's concern described in RAI 3.3.2.3-1 is resolved.The staff's review of plant-specific and industry operating experience found that the SystemCondition Monitoring Program effectively manages cracking due to SCC of stainless steel material for component types in the CRD system; therefore, the staff found that the applicanthas identified the appropriate AMP for the materials and environment associated with the aboveCRD system components.3.3.2.3.5Auxiliary Systems-Demineralized Water System-Summary of Aging ManagementEvaluation-Table 3.3.2-5The staff reviewed LRA Table 3.3.2-5, which summarizes the results of AMR evaluations for theDWS component groups.The applicant stated that it expects no aging effects for PVC and fiberglass piping, fittings,pump casings, tanks, thermowells, and valve bodies exposed to plant indoor air and treated water environments in the DWS. On the basis of its review of plant-specific and industry operating experience, the staff agreed with this statement.RAIs 3.3.2.3-4 and 3.3.2.3-5 in SER Section 3.3.2.3 discusses the staff's evaluation withrespect to the lack of aging effects for rubber piping and fittings exposed to a plant indoor air and treated water environments.Based on the above evaluations, the staff found that the applicant has identified the appropriateAMP for the materials and environment associated with the above components in the DWS.In LRA Table 3.3.2-5, the applicant proposed to manage loss of material due to pitting andcrevice corrosion and MIC of copper alloy materials for the component types of flow elements, 3-224piping and fittings, and valve bodies exposed to a treated water environment with the PlantChemistry Program combined with the One-Time Inspection Program.The staff reviewed and evaluated the applicant's Plant Chemistry Program and the One-TimeInspection Program, as documented in SER Sections 3.0.3.2.19 and 3.0.3.1.4, respectively.The Plant Chemistry Program mitigates the aging effects on component surfaces exposed to water as the process fluid; chemistry programs control water chemistry for impurities (e.g.,
chloride and sulfate) that accelerate corrosion or crack initiation and growth, or that cause heat transfer degradation due to fouling in select heat exchangers. This program relies on monitoring and control of water chemistry to keep peak levels of various contaminants below system-specific limits. The new One-Time Inspection Program is consistent with therecommendations of GALL AMP XI.M32, and includes measures to verify the effectiveness of the Plant Chemistry Program. The One-Time Inspection Program addresses concerns and provides confirmation of the potential long incubation period for certain aging effects on SCs. If system contaminants are maintained within the limits specified by the Plant Chemistry Program,the corrosion exhibited by the copper alloy in a closed system is adequately managed. Theapplicant has chosen a different combination of AMPs to manage the AERM. The staff found this combination adequate and acceptable for managing this material, environment, and aging effect because contaminants are maintained within limits to inhibit corrosion of the copper alloy.In LRA Table 3.3.2-5, the applicant proposed to manage loss of material due to selectiveleaching of copper alloy materials for the component types of flow elements, piping and fittings, and valve bodies exposed to a treated water (internal) environment with the Selective Leaching of Materials Program.The staff reviewed and evaluated the applicant's Selective Leaching of Materials Program, asdocumented in SER Section 3.0.3.2.22. This new program includes a one-time visual inspection and hardness measurement of certain susceptible components to determine if selective leaching occurs. The staff determined that this AMP is adequate for managing this material, environment, and aging effect.the aging effect of loss of material due to MIC and selective leaching ofcopper alloy material exposed internally to treated water environment given in LRA Table 3.3.2-5.3.3.2.3.6Auxiliary Systems-Emergency Diesel Generators System-Summary of AgingManagement Evaluation-Table 3.3.2-6The staff reviewed LRA Table 3.3.2-6, which summarizes the results of AMR evaluations for theDGN component groups.The staff reviewed AMR line items for the DGN, which experiences cracking due to SCC ofcopper alloy, carbon steel, and cast iron; fouling of copper alloy; and loss of material for copper alloy for the following component types:
* piping and fittings 3-225
* fasteners and bolting
* flame arrestors
* gauges (flow, sight and level)
* heat exchangers
* pump casings
* tanks
* valve bodies
* heaters/coolersFor those components requiring staff review, the following environments apply:
* exposed to weather (external)
* treated water (internal)
* lubricating oil (external)
* fuel oil (internal)
* treated water (external)RAI 3.3.2.3-7 in SER Section 3.3.2.3 discusses the staff's evaluation with respect to agingeffects for stainless steel fasteners and bolting exposed to weather environment as well as for copper alloy flame arrestors exposed to weather environment is discussed in RAI 3.3.2.3-7 in SER Section 3.3.2.3. RAIs 3.3.2.3-4 and 3.3.2.3-6 in SER Section 3.3.2.3 discuss the staff'sevaluation with respect to aging effects for rubber piping and fittings exposed to a plant indoor air and gas instrument air environments. RAI 3.3.2.3-2 in SER Section 3.3.2.3 discusses thestaff's review of the management of fouling of heat exchangers in a lubricating oil environments using the One-Time Inspection Program.The applicant proposed to manage DGN aging effects with the CCCW System Program,One-Time Inspection Program, and Fuel Oil Chemistry Program. SER Sections 3.0.3.2.12, 3.0.3.1.4, and 3.0.3.2.17, respectively, document the staff's evaluation of these programs.The staff's review of plant-specific and industry operating experience found that the Closed-Cycle Cooling Water System Program, One-Time Inspection Program, Fuel Oil Chemistry Program effectively manage cracking due to SCC of copper alloy, carbon steel, and cast iron, fouling of copper alloy, and loss of material for copper alloy for DGN component types.Based on the above evaluations, the staff found that applicant has identified the appropriateAMPs for the materials and environment associated with the above components of the DGNcomponents.In LRA Table 3.3.2-6, the applicant proposed to manage heat transfer degradation due tofouling of copper alloy materials for component types of heat exchangers exposed to a treated water environment with the Closed-Cycle Cooling Water System Program.In LRA Table 3.3.2-6, the applicant proposed to manage loss of material due to pitting andcrevice corrosion, and MIC of copper alloy materials for component types including gauges (flow, level, and sight), heat exchangers, and valve bodies exposed to a treated water environment with the Closed-Cycle Cooling Water System Program.
3-226SER Section 3.0.3.2.12 documents the staff's review and evaluation of the applicant's CCCWProgram. The CCCW Program includes (1) preventive measures to minimize corrosion and (2)periodic system and component performance testing and inspection to monitor the effects ofcorrosion and confirm performance of intended functions. Preventive measures include the monitoring and control of corrosion inhibitors and other chemical parameters like pH, in accordance with the guidelines of EPRI TR-1007820, vendor recommendations, and plant operating experience.As the applicant made only minor changes to its CCCW System Program to implement EPRITR-1007820, the program is also still in accordance with the guidelines identified in GALL AMPXI.M21 (i.e., EPRI TR-107396). The applicant also performs periodic inspection and testing to confirm function and monitor corrosion in accordance with EPRI TR-1007820, vendor recommendations, and industry and plant operating experience. If system corrosion inhibitorconcentrations are maintained within the limits specified by the Plant Chemistry Program, corrosion of the copper alloy in a closed system is adequately managed. The staff found thisAMP adequate for managing this material, environment, and aging effect.In LRA Table 3.3.2-6, the applicant proposed to manage loss of material due to selectiveleaching of copper alloy materials for the component types of gauges (flow, level, and sight),
heat exchangers, and valve bodies exposed to treated water environment with the Selective Leaching of Materials Program.The staff reviewed and evaluated the applicant's Selective Leaching of Materials Program, asdocumented in SER Section 3.0.3.2.22. This new program includes a one-time visual inspection and hardness measurement of certain components susceptible to selective leaching. The program will determine if selective leaching occurs for certain components. The staff found thisAMP adequate for managing this material, environment, and aging effect.In LRA Table 3.3.2-6, the applicant proposed to manage loss of material due to pitting andcrevice corrosion and MIC of copper alloy materials for the component types of valve bodies exposed to a fuel oil environment with the Fuel Oil Chemistry Program, combined with the One-Time Inspection Program.In LRA Table 3.3.2-6, the applicant proposed to manage loss of material due to pitting andcrevice corrosion and MIC of stainless steel materials for component types of manifolds, piping and fittings, and valve bodies exposed to a fuel oil environment with the Fuel Oil Chemistry Program, combined with the One-Time Inspection Program.The staff reviewed and evaluated the applicant's Fuel Oil Chemistry Program, as documentedin Section 3.0.3.2.17, and the One-Time Inspection Program, as documented in SERSection 3.0.3.1.4. The Fuel Oil Chemistry Program is an existing program using existing diesel fuel oil system procedures that encompass the GALL Report program recommendations inmitigating and managing aging effects on the internal surfaces of diesel fuel oil storage tanks and associated components in systems that contain diesel fuel oil. The program includes (1)surveillance and monitoring procedures for maintaining diesel fuel oil quality by controllingcontaminants in accordance with applicable ASTM standards, (2) periodic draining of water, if present, from diesel fuel oil tanks, (3) periodic or conditional visual inspection of internal surfaces or wall thickness measurements (e.g., by UT) from external surfaces of diesel fuel oil 3-227tanks, and (4) one-time inspections of a representative sample of components in systems thatcontain diesel fuel oil.The applicant's new One-Time Inspection Program is consistent with the recommendations ofGALL AMP XI.M32. This program will include measures to verify the effectiveness of the PlantChemistry Program and the Fuel Oil Chemistry Program and also confirm the absence of age degradation in selected components (e.g., flow restrictors, venturis, and small bore piping) within the scope of license renewal. The One-Time Inspection Program addresses concerns and provides confirmation of the potential long incubation period for certain aging effects on SCs. The staff review found the Fuel Oil Chemistry Program supplemented by the One-Time Inspection Program adequate for managing these material, environment, and aging effects combinations.On the basis of its review of the applicant's programs, aging effects, and plant-specific andindustry operating experience, the staff determined that the Closed-Cycle Cooling WaterSystem Program, Selective Leaching of Materials Program, or Fuel Oil Chemistry Program combined with the One-Time Inspection Program effectively manage the aging effects of heat transfer degradation due to fouling, loss of material due to pitting and crevice corrosion, and MIC, and loss of material due to selective leaching of copper alloy or stainless steel materials exposed to a treated water (internal or external) or fuel oil environments in LRA Table 3.3.2-6.3.3.2.3.7Auxiliary Systems-Emergency Filtration Train System-Summary of AgingManagement Evaluation-Table 3.3.2-7The staff reviewed LRA Table 3.3.2-7, which summarizes the results of AMR evaluations for theemergency filtration train system component groups.RAIs 3.3.2.3-4 and 3.3.2.3-6 discuss the staff evaluation with respect to aging effects forelastomer ventilation seals exposed to air, gas, and plant indoor air environments.Based on the above evaluation, the staff found that the applicant has identified the appropriateAMPs for the materials and environments associated with the above components in the emergency filtration train system.The staff reviewed and evaluated the Selective Leaching of Materials Program, as documented in SER Section 3.0.3.2.22. This new program includes a one-time visual inspection and hardness measurement of certain components susceptible to selective leaching to determine if selective leaching occurs.the aging effect of loss of material due to selective leaching ofcopper alloy material exposed externally to a wet air/gas environment. On this basis, the staff found the applicant's program to manage loss of material due to selective leaching in LRA Table 3.3.2-7 acceptable.
3-2283.3.2.3.8Auxiliary Systems-Emergency Service Water System-Summary of AgingManagement Evaluation-Table 3.3.2-8The staff reviewed LRA Table 3.3.2-8, which summarizes the results of AMR evaluations for theESW system component groups.The staff reviewed AMR line items for the ESW system. This system experiences fouling of thecopper alloy component of heat exchangers.For those components requiring staff review, the lubricating oil (external) environment applies.
The applicant proposed to manage the ESW system aging effects with the One-TimeInspection Program. SER Section 3.0.3.1.4 documents the staff's evaluation of this program.RAI 3.3.2.3-2 discusses the staff evaluation with respect to managing fouling of heatexchangers in a lubricating oil environment using the One-Time Inspection Program.The staff's review of the plant-specific and industry operating experience found that the One-Time Inspection Program effectively manages fouling of copper alloy components in the ESW system.Based on the above evaluation, the staff found that the applicant has identified the appropriateAMP for the material and environment associated with the above components in the ESW system.3.3.2.3.9Auxiliary Systems-Fire System-Summary of Aging ManagementEvaluation-Table 3.3.2-9The staff reviewed LRA Table 3.3.2-9, which summarizes the results of AMR evaluations for theFIR component groups.In LRA Section 3.3.2.1.9 and Table 3.3.2-9, the applicant identified the materials, environments,and AERMs. The materials identified include bronze, carbon steel, cast iron, copper alloy, ductile iron, galvanized steel, gray cast iron, and stainless steel.The applicant identified the inside, outside, and buried environments to which these materialscould be exposed as air and gas (wetted, ambient and dry), atmosphere/weather, halon, rawwater, and treated water. The applicant identified loss of material (from corrosion or leaching) and heat transfer degradation due to fouling as the aging effects associated with the FIR.The applicant proposed to manage the FIR aging effects with the Bolting Integrity Program,Buried Piping & Tanks Inspection Program, Fire Protection Program, Fire Water System Program, and System Condition Monitoring Program. SER Sections 3.
0.3.2.4, 3.0.3.2.5, 3.0.3.2.15, 3.0.3.2.16, and 3.0.3.3.2, respectively, document the staff's evaluations of theseprograms.
3-229The staff reviewed LRA Section 3.3.2.1.9 and LRA Table 3.3.2-9 to determine whether theapplicant demonstrated that it will adequately manage the aging effects for the FIR during theperiod of extended operation, as required by 10 CFR 54.21(a)(3). The staff conducted its review, described below, in accordance with SRP-LR Section 3.3 and the GALL Report.The staff's review of LRA Table 3.3.2-9 identified areas for which it needed additionalinformation to complete its evaluation of the applicant's results. The applicant responded to the staff's RAIs as discussed below.In RAI 3.3.2.1.9-1, dated August 18, 2005, the staff noted that LRA Table 3.3.2-9 refers toNotes J and 319, which describe the AMRs for copper alloy in heat exchangers; therefore, the staff requested that the applicant justify the conclusion in Note 319 that "the AMP referenced isappropriate for the aging effects/mechanisms identified and provides assurance that the aging effects/mechanisms are effectively managed through the period of extended operation."In its response, by letter dated September 16, 2005, the applicant stated that the Fire WaterSystem Program manages aging of water-based FIR piping and components in accordance with applicable NFPA recommendations. The FP AMP manages aging of fire barriers, the diesel-driven fire pump, and the halon fire suppression system consistent with the GALLReport, since GALL AMP XI.M26 states for FP that, "For operating plants, the fire protection AMP includes a fire barrier inspection program and a diesel-driven fire pump inspection program." As a result, both the Fire Water System and Fire Protection Programs are credited for line items such as filter/strainers, manifolds, pump casings, and valve bodies because these line items apply to both the diesel-driven fire pump (Fire Protection Program) as well as the remainder of the water-based components (Fire Water System Program). In this specific case, the Fire Protection Program, not the Fire Water System Program, manages the copper alloy heat exchanger (radiator) for the diesel-driven fire pump addressed in the Fire Protection Program. Consequently, Note J, which states, "Neither the component nor the material and environment combination is evaluated in NUREG-1801," applies to this line item because theGALL Report, Section VII.G, addresses the diesel-driven fire pump copper heat exchanger in neither a treated water nor raw water environment. Additionally, Note 319, which states the following, further defines this issue: NUREG-1801, Volume 2, Chapter VII (Auxiliary Systems), Section G.6 (FireProtection) does not address this environment for the mechanical portion of the Fire Protection AMP (XI.M26). The AMP referenced is appropriate for the aging effects/mechanisms identified and provides assurance that the aging effects/mechanisms are effectively managed through the period of extended operation to further define this issue. Consequently, the Fire Protection Program, as defined in LRA Section B2.1.17, is appropriateto manage the aging effects of heat transfer degradation and loss of material for the copper alloy diesel-driven fire pump heat exchanger addressed in LRA Table 3.3.2-9 and assures effective management of the aging effects/mechanisms through the period of extended operation.Based on its review, the staff found the applicant's response to RAI 3.3.2.1.9-1 acceptablebecause it adequately explains that the GALL Report does not evaluate the copper alloydiesel-driven fire pump heat exchanger, in both treated water and raw water environments. The 3-230applicant stated that the Fire Protection Program manages the aging effects of heat transferdegradation and loss of material for the copper alloy diesel-driven fire pump heat exchanger.
The staff reviewed the applicant's Fire Protection Program and found acceptable the management of heat transfer degradation due to fouling and loss of material due to general, galvanic, crevice, and pitting corrosion and MIC, as given in LRA Table 3.3.2-9; therefore, the staff's concern described in RAI 3.3.2.1.9-1 is resolved.In RAI 3.3.2.1.9-2, dated August 18, 2005, the staff noted that LRA Table 3.3.2-9 shows noAMP for stainless steel fasteners/bolting; therefore, the staff requested that the applicantexplain why these fasteners/bolting do not require an AMP as recommended by GALL AMP XI.M18.In its response, by letter dated September 16, 2005, the applicant stated that Table 3.3.2-9identifies stainless steel fasteners/bolting in exposed to weather and plant indoor air external environments. The applicant's materials science position, which is consistent with EPRI 1003056, is that these components have no surface exposed to an aggressive chemical species, have no potential for concentrating contaminants, and are not subject to wetting otherthan their normal environment; therefore, loss of material is not a potential aging effect asidentified by LRA Note 327. Additionally, the FIR has no bolts with a specified minimum yield strength >150 ksi.Crevice corrosion is a potential aging mechanism for wetted stainless steel under certainconditions. Crevice corrosion depends strongly on the presence of dissolved oxygen. Although oxygen depletion in crevices may occur as a result of corrosion, oxygen is st ill required for theonset of corrosion and bulk fluid oxygen content or the presence of contaminants like chloridesis necessary for the continued dissolution of material in the crevice. In systems with extremelylow oxygen content (< 0.1 ppm), crevice corrosion is considered insignificant. This form of corrosion requires a crevice where contaminants and corrosion products can concentrate. In addition to oxygen, moisture is required for the mechanism to operate. Alternate wetting and drying is particularly harmful as this leads to a concentration of atmospheric pollutants and contaminants, if present. These conditions do not exist for stainless steel fasteners/bolting at MNGP.Pitting corrosion is a potential aging mechanism for wetted stainless steel under certainconditions. Unless cupric, ferric, or mercuric halides are present in the environment, oxygen is required for pitting initiation. Areas where aggressive species can concentrate are particularly susceptible to pitting. Most pitting is the result of halide contamination with prevalent chlorides, bromides, and hypochlorites. Pitting is a significant aging effect for stainless steels when exposed to a corrosive environment. Any continuously wetted or alternately wetted and dried surfaces tend to concentrate any aggressive species, if they are present, and are prone to pitting corrosion. These conditions also do not exist for stainless steel fasteners/bolting at MNGP.For conservatism during the integrated plant assessment process, both the exposed to weatherand plant indoor air environments include the stainless steel fastener/bolting component to ensure that the evaluations have not inadvertently omitted any components, materials, orenvironments from the evaluations; however, recent walkdowns of the FIR revealed no stainless steel fasteners/bolting exposed to weather.
3-231Consequently, the applicant will remove the FIR stainless steel fasteners/bolting exposed toweather asset from LRA Table 3.3.2-9. Stainless steel fasteners/bolting in a plant indoor air environment have no aging effects for the same reasons as stated above.Based on its review, the staff found the applicant's response to RAI 3.3.2.1.9-2 acceptable,because the applicant stated that stainless steel fasteners/bolting in the FIR have no potentialfor concentrating contaminants and are not subject to wetting other than their normalenvironment. The applicant also stated that recent walkdowns of the FIR revealed no stainless steel fasteners/bolting exposed to weather, so it will remove this asset from LRA Table 3.3.2-9;therefore, the staff's concern described in RAI 3.3.2.1.9-2 is resolved.On the basis of its review of the applicant's programs, aging effects, and plant-specific andindustry operating experience, the staff determined that the aging effects from exposure of thefire water system components to the environments described in LRA Table 3.3.2.6 areconsistent with the GALL Report and with industry experience for these material-environment combinations; therefore, the staff found that the applicant identified the applicable aging effectsand associated AMPs and that they are appropriate for the combination of materials and environments listed.In LRA Table 3.3.2-9, the applicant proposed to manage heat transfer degradation due tofouling, loss of material due to crevice and pitting corrosion, MIC, and loss of material due to selective leaching of copper alloy materials for the component types of heat exchangers exposed to a raw water environment with the Fire Protection Program.The staff reviewed and evaluated the Fire Protection Program, as documented in SER Section 3.0.3.2.15. The Fire Protection Program includes a fire barrier inspection program, a diesel-driven fire pump inspection program, and a halon fire suppression system inspection.The program requires periodic visual inspection of fire barriers, seals, walls, ceilings, floors, andassociated fire-rated doors. The diesel-driven fire pump inspection program periodically tests the pump and inspects the diesel engine to ensure that the fuel supply line can perform the intended function. The halon fire-suppression system inspection includes periodic inspectionand testing of the cable spreading room halon fire-suppression system. The applicant willenhance the existing Fire Protection Program under the Parameters Monitored or Inspected element to be consistent, with certain exceptions, with GALL AMP XI.M26, as modified by ISG-04. The exception to the GALL Report concerns the periodic visual inspection and function test of halon systems at least once every 6 months. The applicant functionally tests and visuallyinspects the cable spreading room halon system every 18 months instead of every 6 months asrecommended in the GALL Report. The staff found this exception acceptable, as documented in SER Section 3.0.3.2.15.
3-232With respect to copper alloy in raw water, the staff has accepted that these AERMs exist inother systems, such as CWT and diesel generator support systems. The fire water and FPsystems also have instances of copper alloy in raw water. The applicant credits the FireProtection Program with managing loss of material due to crevice and pitting corrosion, MIC, and selective leaching. The staff review found this AMP adequate for managing this material, environment, and aging effect. With respect to copper alloy in glycol corrosion-inhibited treated water (external), the staff has accepted that these AERMs exist in other systems, such as the CWT and diesel generator support systems. With respect to gray cast iron in glycolcorrosion-inhibited treated water (external), the applicant credited the Fire Protection Programwith managing loss of material due to general, galvanic, crevice, and pitting corrosion, MIC, and selective leaching. The staff's review found this AMP adequate for managing the AERMs of heat transfer degradation due to fouling, loss of material due to crevice and pitting corrosion, and MIC for the materials identified.In RAI 3.3.2.2.5-1, dated October 31, 2005, the staff requested that the applicant demonstratehow the Fire Water System and the Fire Protection Programs will manage loss of material dueto selective leaching for these materials.In its response, dated November 22, 2005, the applicant stated that it inadvertently omitted theFIR from the applicable systems table in LRA Section B2.1.30 (under "Scope of Program") forthe Selective Leaching of Materials Program. The applicant agreed to revise LRA Section B2.1.30 to include the FIR within the scope of the program. In its letter dated February 28, 2006, the applicant revised LRA Section B2.1.30 to include the FIR within the scope of the program.Additionally, in its response, the applicant stated that under "Scope of Program," the FireProtection, Fire Water System, and Buried Piping & Tanks Programs credit the Selective Leaching of Materials Program for managing loss of material due to selective leaching. The applicant inadvertently omitted such credits not specifically stated from these programdescriptions in the LRA for the respective AMPs.It was not clear to the staff how the applicant intended to credit the Selective Leaching ofMaterial Program, as the Parameters Monitored or Inspected element and the Detection of Aging Effects element for the AMPs do not specify any components that could have an agingeffect of loss of material due to selective leaching. The applicant agreed to revise these AMPs to describe how they will credit the Selective Leaching of Materials Program. In its letter, datedFebruary 28, 2006, the applicant revised the Scope of Program element for the Fire Protection,Fire Water System, and Buried Piping & Tanks Programs to include loss of material due to selective leaching by crediting the Selective Leaching of Materials Program.The staff found this response acceptable; therefore, the staff's concern described inRAI 3.3.2.2.5-1 is resolved.In LRA Table 3.3.2-9, the applicant proposed to manage loss of material due to galvanic andgeneral corrosion of carbon steel materials for the component types of valve bodies exposed to air/gas (internal) environment with the Fire Water System Program.The staff reviewed and evaluated the Fire Water System Program, as documented in SERSection 3.0.3.2.16. The Fire Water System Program relies on testing of water-based FP system 3-233piping and components in accordance with applicable NFPA recommendations. In addition, theapplicant will modify this program to include (1) portions of the FP sprinkler system subject tofull-flow tests before the period of extended operation and (2) portions of the FP systemexposed to water that are visually inspected internally. Periodic full-flow fl ush test s and systemperformance tests ensure that the aging mechanisms of corrosion and biofouling/fouling are properly managed in the fire water system. With respect to carbon steel in an air/gas (internal)environment, the applicant has chosen, for conservatism, to manage the AERM as though the environment were water. The staff review found this AMP adequate for managing this material, environment, and aging effect.On the basis of its review of the applicant's programs, aging effects and plant-specific andindustry operating experience, the staff determined that the Fire Protection and Fire WaterSystem Programs effectively manage the aging effect of heat transfer degradation due to fouling, loss of material due to general, galvanic, crevice, and pitting corrosion and MIC, and loss of material due to selective leaching of copper alloy, gray cast iron, and carbon steel materials exposed to raw water, glycol corrosion-inhibited treated water (internal and external),
and air/gas (internal) environments. On this basis, the staff found acceptable the management of heat transfer degradation due to fouling, loss of material due to general, galvanic, crevice, and pitting corrosion and MIC, and loss of material due to selective leaching in LRA Table 3.3.2-9.3.3.2.3.10Auxiliary Systems-Fuel Pool Cooling and Cleanup-Summary of AgingManagement Evaluation-Table 3.3.2-10The staff reviewed LRA Table 3.3.2-10, which summarizes the results of AMR evaluations forthe FPC component groups.In LRA Table 3.3.2-10, the applicant proposed to manage loss of material due to crevice andpitting corrosion and MIC of copper alloy materials for the component types of piping and fittings, and valve bodies exposed internally to a treated water environment with the Plant Chemistry Program combined with the One-Time Inspection Program.The staff reviewed and evaluated the applicant's Plant Chemistry Program and the One-TimeInspection Program, as documented in SER Sections 3.0.3.2.19 and 3.0.3.1.4, respectively.The Plant Chemistry Program mitigates the aging effects on component surfaces that are exposed to water as the process fluid; chemistry programs are used to control water chemistry for impurities (e.g., chloride and sulfate) that accelerate corrosion or crack initiation and growth and that cause heat transfer degradation due to fouling in select heat exchangers. This program relies on monitoring and control of water chemistry to keep peak levels of various contaminants below system-specific limits. The new One-Time Inspection Program is consistentwith the recommendations of GALL AMP XI.M32 and will verify the effectiveness of the PlantChemistry Program. The One-Time Inspection Program addresses concerns and provides confirmation for the potential long incubation period for certain aging effects on SCs. The staff review determined that the Plant Chemistry Program supplemented by the One-Time InspectionProgram is adequate for managing this material, environment, and aging effect combination.In LRA Table 3.3.2-10, the applicant proposed to manage loss of material due to selectiveleaching of copper alloy materials for the component types of piping and fittings, and valve 3-234bodies exposed internally to a treated water environment with the Selective Leaching ofMaterials Program.The staff reviewed and evaluated the Selective Leaching of Materials Program, as documentedin SER Section 3.0.3.2.22. This new program includes a one-time visual inspection and hardness measurement to determine if selective leaching occurs for certain susceptible components. The staff's program review found management of loss of material due to selective leaching in LRA Table 3.3.2-7 acceptable.the aging effects of loss of material due to crevice and pitting corrosion,MIC, and selective leaching of copper alloy material exposed to a treated water (internal) environment. On this basis, the staff found management of loss of material due to crevice and pitting corrosion, MIC, and selective leaching, as given in LRA Table 3.3.2-10, acceptable.3.3.2.3.11Auxiliary Systems-Heating and Ventilation-Summary of Aging ManagementEvaluation-Table 3.3.2-11The staff reviewed LRA Table 3.3.2-11, which summarizes the results of AMR evaluations forthe HTV component groups.In LRA Table 3.3.2-11, the applicant proposed to manage loss of material due to pitting andcrevice corrosion of copper alloy materials for the component types of heaters/coolers, heating, ventilation, and air conditioning (HVAC) units, piping and fittings, and valve bodies exposed to a treated water or steam environment with the Closed-Cycle Cooling Water System Program.Section 3.0.3.2.12. The CCCW System Program includes (1) preventive measures to minimizecorrosion and (2) periodic system and component performance testing and inspection tomonitor the effects of corrosion and confirm performance of intended functions. Preventive measures monitor and control corrosion inhibitors and other chemical parameters like pH, in accordance with the guidelines of EPRI TR-1007820, vendor recommendations, and plant operating experience. As only minor changes were made to the CCCW System Program toimplement EPRI TR-1007820, the program is also still consistent with the guidelines identifiedin GALL AMP XI.M21 (i.e., EPRI TR-107396). Periodic inspection and testing to confirm function and monitor corrosion are also performed in accordance with EPRI TR-1007820, vendor recommendations, and industry and plant-operating experience. The staff's review found this AMP adequate for managing this material, environment, and aging effect.In LRA Table 3.3.2-11, the applicant proposed to manage loss of material due to pitting andcrevice corrosion and MIC of copper alloy materials for the component types of gauges (flow, level, and sight), chillers, piping and fittings, and valve bodies exposed to a treated waterenvironment with the One-Time Inspection Program.
3-235In LRA Table 3.3.2-11, the applicant proposed to manage loss of material due to selectiveleaching of copper alloy materials for the component types of chillers, gauges (flow, level, andsight), heaters/coolers, HVAC units, piping and fittings, and valve bodies exposed to treated water, treated water or steam (internal), and wet air/gas (external) environments with the Selective Leaching of Materials Program. Section 3.0.3.2.22. This new program includes a one-time visual inspection andhardness measurement to determine if selective leaching occurs for certain susceptible components. The staff's review found this AMP adequate for managing this material, environment, and aging effect.On the basis of its review of the applicant's programs, aging effects, and plant-specific andindustry operating experience, the staff determined that the Closed-Cycle Cooling WaterSystem Program, One-Time Inspection Program, and Selective Leaching of Materials Program effectively manage the aging effect of loss of material due to pitting and crevice corrosion, MIC, and selective leaching of copper alloy material exposed to treated water (internal), treated water or steam (internal), and wet air/gas (external) environments. On this basis, the staff found that management of inTable 3.3.2-11 is acceptable.3.3.2.3.12Auxiliary Systems-Instrument and Service Air System-Summary of AgingManagement Evaluation-Table 3.3.2-12The staff reviewed LRA Table 3.3.2-12, which summarizes the results of AMR evaluations forthe AIR system component groups.In LRA Table 3.3.2-12, the applicant proposed to manage loss of material due to crevice andpitting corrosion and MIC of copper alloy materials for the component types of gauges (flow, level, and sight) and valve bodies exposed to a treated water environment with the CCCWSystem Program.The staff reviewed and evaluated the CCCW System Program, as documented in SERSection 3.0.3.2.12. The CCCW System Program includes (1) preventive measures to minimizecorrosion and (2) periodic system and component performance testing and inspection tomonitor the effects of corrosion and confirm performance of intended functions. Preventive measures monitor and control corrosion inhibitors and other chemical parameters like pH in 3-236accordance with the guidelines of EPRI TR-1007820, vendor recommendations, and plantoperating experience. As only minor changes were made to the CCCW System Program toimplement EPRI TR-1007820, the program is also still consistent with the guidelines identifiedin GALL AMP XI.M21 (i.e., EPRI TR-107396). Periodic inspection and testing to confirm function and monitor corrosion are also performed in accordance with EPRI TR-1007820, vendor recommendations, and industry and plant operating experience. The staff's review found this AMP adequate for managing this material, environment, and aging effect. a gas-compressed air environment with the Compressed Air Monitoring Program. Section 3.0.3.2.13. The Compressed Air Monitoring Program consists of inspection,monitoring, and testing of the AIR system for reasonable assurance that the components willperform their intended functions for the period of extended operation. With respect to copper alloy in a gas-compressed air environment, MNGP has chosen, for conservatism, to manage the AERM as though it were an environment with condensation. The staff's review found this AMP adequate for managing this material, environment, and aging effect.environments with theSelective Leaching of Materials Program.The staff reviewed and evaluated the Selective Leaching of Materials Program, as documentedin SER Section 3.0.3.2.22. This new program includes a one-time visual inspection and hardness measurement to determine if selective leaching occurs for certain susceptible components. The staff's review found this AMP adequate for managing this material, environment, and aging effect.On the basis of its review of the applicant's programs, aging effects, and plant-specific andindustry operating experience, the staff determined that the Closed-Cycle Cooling WaterSystem Program, Compressed Air Monitoring Program, and Selective Leaching of Materials Program effectively manage the aging effect of loss of material due to crevice and pitting corrosion, MIC, and selective leaching of copper alloy material exposed to treated water (internal) and gas-compressed air (internal) environments. On this basis, the staff found management of loss of material due to crevice and pitting corrosion, MIC, and selective leaching in LRA Table 3.3.2-12 acceptable.3.3.2.3.13Auxiliary Systems-Radwaste Solid and Liquid System-Summary of AgingManagement Evaluation-Table 3.3.2-13The staff reviewed LRA Table 3.3.2-13, which summarizes the results of AMR evaluations forthe radwaste solid and liquid system component groups.All line items in this table are consistent with the GALL Report or are included in the discussionin Section 3.3.2.3 above.
3-2373.3.2.3.14Auxiliary Systems-Reactor Building Closed Cooling Water System-Summary ofAging Management Evaluation-Table 3.3.2-14The staff reviewed LRA Table 3.3.2-14, which summarizes the results of AMR evaluations forthe RBC system component groups. a treated water environment with the CCCW System Program.The staff reviewed and evaluated the CCCW System Program, as documented in SERSection 3.0.3.2.12. The CCCW System Program includes (1) preventive measures to minimizecorrosion and (2) periodic system and component performance testing and inspection tomonitor the effects of corrosion and confirm performance of intended functions. Preventive measures monitor and control corrosion inhibitors and other chemical parameters like pH, in accordance with the guidelines of EPRI TR-1007820, vendor recommendations, and plant operating experience. As only minor changes were made to the CCCW System Program toimplement EPRI TR-1007820, the program is also still consistent with the guidelines identifiedin GALL AMP XI.M21 (i.e., EPRI TR-107396). Periodic inspection and testing to confirm function and monitor corrosion are also performed in accordance with EPRI TR-1007820, vendor recommendations, and industry and plant operating experience. The staff's review found this AMP adequate for managing this material, environment, and aging effect.environment with the Selective Leaching of MaterialsProgram.. The staff's review found this AMP adequate for managing this material,environment, and aging effect.Table 3.3.2-14, is acceptable.3.3.2.3.15Auxiliary Systems-Reactor Water Cleanup System-Summary of AgingManagement Evaluation-Table 3.3.2-15The staff reviewed LRA Table 3.3.2-15, which summarizes the results of AMR evaluations forthe RWCU system component groups.
3-238All line items in this table are consistent with the GALL Report or are included in the discussionin Section 3.3.2.3 above.3.3.2.3.16Auxiliary Systems-Service and Seal Water System-Summary of AgingManagement Evaluation-Table 3.3.2-16The staff reviewed LRA Table 3.3.2-16, which summarizes the results of AMR evaluations forthe service and seal water system component groups.RAIs 3.3.2.3-3 and 3.3.2.3-4 discuss the staff evaluation with respect to aging effects for rubberexpansion joints exposed to plant indoor air and raw water environments in the service and seal water system.Based on the RAI evaluations, the staff found that the applicant has identified the appropriateAMP for the materials and environments associated with the above components in the serviceand seal water system. All other line items in this table are consistent with the GALL Report orare included in the discussion in Section 3.3.2.3 above.3.3.2.3.17Auxiliary Systems-Standby Liquid Control System-Summary of AgingManagement Evaluation-Table 3.3.2-17The staff reviewed LRA Table 3.3.2-17, which summarizes the results of AMR evaluations forthe SLC system component groups.RAI 3.3.2.3-5 discusses the staff evaluation with respect to aging effects for rubberaccumulators exposed to nitrogen gas and plant indoor air environments in the SLC system.Based on the evaluation of the response to the above RAI, the staff found that applicant hasidentified the appropriate AMP for the materials and environments associated with the abovecomponents in the SLC system. All other line items in this table are consistent with the GALLReport or are included in the discussion in Section 3.3.2.3 above.3.3.2.3.18Auxiliary Systems-Wells and Domestic Water System-Summary of AgingManagement Evaluation-Table 3.3.2-18The staff reviewed LRA Table 3.3.2-18, which summarizes the results of AMR evaluations forthe wells and domestic water system component groups.In LRA Table 3.3.2-18, the applicant proposed to manage loss of material due to crevice andpitting corrosion, MIC, and erosion of copper alloy materials for the component types of piping and fittings and valve bodies exposed to a raw water environment with the One-Time Inspection Program.The staff reviewed and evaluated the One-Time Inspection Program, as documented in SERSection 3.0.3.1.4. The new One-Time Inspection Program is consistent with therecommendations of GALL AMP XI.M32 and will confirm the absence of age degradation inselected components (e.g., flow restrictors, venturis, and small bore piping) within the scope of license renewal. The One-Time Inspection Program addresses concerns and provides confirmation for the potential long incubation period for certain aging effects on SCs. The 3-239applicant has noted in the LRA that in some cases in which aging effects/mechanisms are notexpected to be significant, the One-Time Inspection Program alone is credited with managing aging effects. The staff determined that the use of the One-Time Inspection Program alone isacceptable where the use of the Plant Chemistry Program is not a viable option. This AMP isappropriate for the aging effects/mechanisms identified and assures effective management of them through the period of extended operation.In LRA Table 3.3.2-18, the applicant proposed to manage loss of material due to crevicecorrosion, pitting corrosion, and MIC of Hastelloy (C-276) material for the component types of piping and fittings exposed to a raw water environment using the One-Time Inspection Program. In addition, the applicant stated that Hastelloy (C-276) in a concrete or plant indoor airenvironment has no AERM and therefore requires no AMP.The staff determined that Hastelloy (C-276) is a highly corrosion-resistant material, anddegradation is not expected in typical domestic water applications. Hastelloy (C-276) piping and fitting material exposed to concrete or an air environment in the absence of moisture with contaminants has no aging effects and requires no aging management. Similarly, degradation of Hastelloy (C-267) in a raw water internal environment is not expected. It is conservative to assume loss of material due to crevice and pitting corrosion and MIC in this environment with the potential for unknown contaminants. The staff's review found the One-Time InspectionProgram adequate to manage the aging effects of this corrosion-resistant material in this environment to confirm that degradation is not occurring.In LRA Table 3.3.2-18, the applicant proposed to manage loss of material due to selectiveleaching of copper alloy materials for the component types of piping and fittings and valve bodies exposed to a raw water environment with the Selective Leaching of Materials Program.The staff reviewed and evaluated the Selective Leaching of Materials Program, as documentedin SER Section 3.0.3.2.22. This new program includes a one-time visual inspection and hardness measurement to determine if selective leaching occurs for certain susceptible components. The staff's review found this AMP adequate for managing this material, environment, and aging effect.On the basis of its review of the applicant's programs, aging effects, and plant-specific andindustry operating experience, the staff determined that the One-Time Inspection Program andSelective Leaching of Materials Program effectively manage the aging effect of loss of material due to crevice and pitting corrosion, MIC, erosion, and selective leaching of copper alloy material exposed to a raw water (internal) environment. On this basis, the staff found management of loss of material due to crevice and pitting corrosion, MIC, erosion, and selective leaching, as given in LRA Table 3.3.2-18, acceptable.Conclusion. On the basis of its review, the staff found that the applicant appropriately evaluatedAMR results involving material, environment, AERM, and AMP combinations that are not evaluated in the GALL Report. The staff found that the applicant has demonstrated that theaging effects will be adequately managed so that intended functions will be maintainedconsistent with the CLB for the period of extended operation, as required by10 CFR 54.21(a)(3).
3-2403.3.3  ConclusionThe staff concluded that the applicant provided sufficient information to demonstrate that theaging effects for the auxiliary systems components that are within the scope of license renewaland subject to an AMR will be adequately managed so that intended functions will bemaintained consistent with the CLB for the period of extended operation, as required by10 CFR 54.21(a)(3).The staff also reviewed the applicable USAR supplement program summaries and concludedthat they adequately describe the AMPs credited with managing aging of the auxiliary systems,as required by 10 CFR 54.21(d).3.4  Aging Management of Steam and Power Conversion SystemThis section of the SER documents the staff's review of the applicant's AMR results for the SPCsystem components and component groups associated with the following systems:
* condensat e stor age syst em
* condensate and feedwater system
* main condenser system
* main steam system
* turbine generator system3.4.1  Summary of Technical Information in the Application In LRA Section 3.4, the applicant provided AMR results for the SPC system components andcomponent groups. In LRA Table 3.4.1, the applicant provided a summary comparison of its AMRs with the AMRs evaluated in the GALL Report for the SPC system components andcomponent groups.The applicant's AMRs incorporated applicable operating experience in the determination ofAERMs. These reviews included evaluation of plant-specific and industry operating experience.
The plant-specific evaluation included reviews of CRs and discussions with appropriate site personnel to identify AERMs. The applicant's review of industry operating experience included a review of the GALL Report and operating experience issues identified since the issuance of the GALL Report.3.4.2  Staff Evaluation The staff reviewed LRA Section 3.4 to determine if the applicant provided sufficient informationto demonstrate that the effects of aging for the SPC system components that are within thescope of license renewal and subject to an AMR will be adequately managed so that theintended functions will be maintained consistent with the CLB for the period of extendedoperation, as required by 10 CFR 54.21(a)(3).In addition, the staff performed an onsite audit of AMRs to confirm the applicant's claim thatcertain identified AMRs are consistent with the GALL Report. The staff did not repeat its reviewof the matters described in the GALL Report; however, the staff did verify that the material 3-241presented in the LRA is applicable and that the applicant identified the appropriate GALLReport AMRs. SER Section 3.0.3 documents the staff's evaluations of the AMPs. The MNGP audit and review report details the staff's audit evaluation, which are summarized in SER Section 3.4.2.1.The staff also performed an onsite audit of those selected AMRs that are consistent with theGALL Report and for which further evaluation is recommended. The staff confirmed that the applicant's further evaluations are consistent with the acceptance criteria in SRP-LR Section 3.4.2.2. The MNGP audit and review report documents the staff's audit evaluations,which are summarized in SER Section 3.4.2.2.The staff performed an onsite audit and conducted a technical review of the remaining AMRsthat are not consistent with, or not addressed in, the GALL Report. The audit and technicalreview included evaluating whether the applicant identified all plausible aging effects and whether the aging effects listed are appropriate for the combination of materials and environments specified. The MNGP audit and review report documents the staff's audit evaluations. SER Section 3.4.2.3 summarizes these audit evaluations and documents thestaff's evaluation of its technical review.Finally, the staff reviewed the AMP summary descriptions in the USAR supplement to ensurethat they adequately describe the programs credited with managing or monitoring aging for theSPC system components.Table 3.4-1 below summarizes the staff's evaluation of components, aging effects/mechanisms,and AMPs listed in LRA Section 3.4 that are addressed in the GALL Report.Table 3.4-1  Staff Evaluation for Steam and Power Conversion System Components inthe GALL ReportComponent GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff EvaluationPiping and fittings inmain feedwater line,steamline and AFWpiping (PWR only)(Item Number3.4.1-01)Cumulative fatiguedamageTLAA, evaluated inaccordance with10 CFR 54.21(c)TLAAThis TLAA isevaluated in Section4.3, Metal Fatigueof the RPV andInternals, andReactor CoolantPressure BoundaryPiping andComponents (seeSection 3.4.2.2.1)Piping and fittings,valve bodies andbonnets, pumpcasings, tanks,tubes, tubesheets,channel head andshell (except mainsteam system)(Item Number3.4.1-02)Loss of materialdue to general(carbon steel only),pitting, and crevicecorrosionWater chemistry,one-time inspectionOne-TimeInspection Program(B2.1.23), PlantChemistry Program(B2.1.25) Consistent withGALL Report, whichrecommends furtherevaluation (seeSection 3.4.2.2.2)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation3-242Auxiliary feedwater(AFW) piping(Item Number3.4.1-03)Loss of materialdue to general,pitting, and crevicecorrosion, MIC, andbiofoulingPlant specificNot applicable,PWR only (seeSection 3.4.2.2.3)Oil coolers in AFWsystem (lubricatingoil side possiblycontaminated withwater)(Item Number3.4.1-04)Loss of materialdue to general(carbon steel only),pitting, and crevicecorrosion and MICPlant specificNot applicable,PWR only (seeSection 3.4.2.2.3)External surface ofcarbon steelcomponents(Item Number3.4.1-05)Loss of materialdue to generalcorrosionPlant specificSystem ConditionMonitoring Program(B2.1.32)Consistent withGALL Report, whichrecommends furtherevaluation (seeSection 3.4.2.2.4)Carbon steel pipingand valve bodies(Item Number3.4.1-06)Wall thinning due toflow-acceleratedcorrosionFlow-acceleratedcorrosionFlow-AcceleratedCorrosion Program(B2.1.19)Consistent withGALL Report, whichrecommends nofurther evaluationCarbon steel pipingand valve bodies inmain steam system(Item Number3.4.1-07)Loss of materialdue to pitting andcrevice corrosionWater chemistryThis line item wasnot used at MNGP.See Item Number3.4.1-02Closure bolting inhigh-pressure orhigh-temperaturesystems(Item Number3.4.1-08)Loss of materialdue to generalcorrosion; crackinitiation and growthdue to cyclicloading and/or SCCBolting integrityBolting IntegrityProgram (B2.1.4)Consistent withGALL Report, whichrecommends nofurther evaluationHeat exchangersandcoolers/condensersserviced byopen-cycle coolingwater(Item Number3.4.1-09)Loss of materialdue to general(carbon steel only),pitting, and crevicecorrosion, MIC, andbiofouling; buildupof deposit due tobiofoulingOpen-cycle coolingwater systemNot applicable (seeSection 3.4.2.1.1)Heat exchangersandcoolers/condensersserviced byclosed-cycle coolingwater(Item Number3.4.1-10)Loss of materialdue to general(carbon steel only),pitting, and crevicecorrosionClosed-cyclecooling watersystemNot applicable.No heat exchangersserviced byclosed-cycle coolingwater Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation3-243External surface ofabovegroundcondensate storagetank(Item Number3.4.1-11)Loss of materialdue to general(carbon steel only),pitting, and crevicecorrosionAbove groundcarbon steel tanksNot applicable.MNGP condensatestorage tanks arenot within the scopeof license renewalExternal surface ofburied condensatestorage tank andAFW piping(Item Number3.4.1-12)Loss of materialdue to general,pitting, and crevicecorrosion and MICBuried piping andtanks surveillance or Buried piping andtanks inspectionBuried Piping &Tanks InspectionProgram (B2.1.5)Emergency dieselgenerators systemoil storage tankexternal surface ismanaged by theBuried Piping &Tanks InspectionProgramExternal surface ofcarbon steelcomponents(Item Number3.4.1-13)Loss of materialdue to boric acidcorrosionBoric acid corrosionNot applicable,PWR onlyThe staff's review of the MNGP component groups followed one of several approaches. Oneapproach, documented in SER Section 3.4.2.1, involves the staff's review of the AMR resultsfor components in the SPC system that the applicant indicated are consistent with the GALLReport and do not require further evaluation. Another approach, documented in SERSection 3.4.2.2, involves the staff's review of the AMR results for components in the SPCsystem that the applicant indicated are consistent with the GALL Report and for which furtherevaluation is recommended. A third approach, documented in SER Section 3.4.2.3, involves thestaff's review of the AMR results for components in the SPC system that the applicant indicatedare not consistent with, or not addressed in, the GALL Report. SER Section 3.0.3 documentsthe staff's review of AMPs that are credited to manage or monitor aging effects of the SPC system components.3.4.2.1  AMR Results That Are Consistent with the GALL Report Summary of Technical Information in the Application. In LRA Section 3.4.2.1, the applicantidentified the materials, environments, and AERMs. The applicant identified the following programs that manage the aging effects related to the SPC system components:
* Bolting Integrity Program (B2.1.4)
* Flow-Accelerated Corrosion Program (B2.1.19)
* One-Time Inspection Program (B2.1.23)
* Open-Cycle Cooling Water System Program (B2.1.24)
* Plant Chemistry Program (B2.1.25)
* Selective Leaching of Materials Program (B2.1.30)
* System Condition Monitoring Program (B2.1.32) 3-244Staff Evaluation. In LRA Tables 3.4.2-1 through 3.4.2-5, the applicant summarized the AMRsfor the SPC system components, and identified which AMRs it considered to be consistent withthe GALL Report.For component groups evaluated in the GALL Report for which the applicant has claimedconsistency with the GALL Report, and for which the GALL Report does not recommend further evaluation, the staff performed an audit and review to determine whether the GALL Reportevaluation bounds the plant-specific components contained in these GALL Report componentgroups.The applicant provided a note for each AMR line item. The notes described how the informationin the tables aligns with the information in the GALL Report. The staff audited those AMRs with Notes A through E, which indicate that 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 AMP identified in the GALL Report. The staff audited these line items to verify consistency with the GALL Report and the validity of the AMR for the site-specific conditions.Note B 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 AMP identified in the GALL Report. The staff audited these line items to verify consistency with the GALL Report. The staff verified that it had reviewed and accepted the identified exceptionsto the GALL Report AMPs. The staff also determined whether the AMP identified by the applicant is consistent with the AMP identified in the GALL Report and whether the AMR is validfor the site-specific conditions.Note C indicates that the component for the AMR line item, although different, is consistent withthe GALL Report for material, environment, and aging effect. In addition, the AMP is consistent with the AMP identified by the GALL Report. This note indicates that the applicant could not finda listing of some system components in the GALL Report. However, the applicant identified adifferent component in the GALL Report that has 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 determined whether the AMR line item of the different component applies to the component under review and whether the AMR is valid for the site-specific conditions.Note D indicates that the component for the AMR line item, although different, is consistent withthe GALL Report for material, environment, and aging effect. In addition, the AMP takes some exceptions to the AMP identified in the GALL Report. The staff audited these line items to verify consistency with the GALL Report. The staff verified whether the AMR line item of the different component applies to the component under review. The staff verified that it had reviewed and accepted the identified exceptions to the GALL Report AMPs. The staff also determined whether the AMP identified by the applicant is consistent with the AMP identified in the GALLReport and whether the AMR is 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 the applicant credited a different AMP. The staff audited these line items to verify consistency with the GALL Report. The staff also determined whether 3-245the identified AMP will manage the aging effect consistent with the AMP identified by the GALLReport and whether the AMR is valid for the site-specific conditions.The staff conducted an audit and review of the information provided in the LRA, as documentedin the MNGP audit and review report. The staff did not repeat its review of the matters described in the GALL Report; however the staff did verify that the material presented in the LRA is applicable and that the applicant identified the appropriate GALL Report AMRs. The following sections discuss the staff's evaluation.3.4.2.1.1Loss of Material Due to General, Pitting, and Crevice Corrosion, MIC, andBiofouling; Buildup of Deposit Due to BiofoulingIn LRA Table 3.4.1, Item 3.4.1-09, the applicant addressed the loss of material due to general,pitting, and crevice corrosion, MIC, and biofouling, and buildup of deposit due to biofouling for heat exchangers and coolers/condensers serviced by OCCW. The applicant stated that Item3.4.1-09 does not apply. The applicant stated that the management of aging effects of certaincomponents of the CDR with the intended function of plateout and holdup of radioactivematerial is not applicable because the CDR structural integrity is demonstrated continuouslyduring normal plant operation.During the audit and review, the staff noted that in LRA Table 3.4.2-3 the applicant presentedits AMR results for the CDR system. In the table, the applicant claimed consistency with theGALL Report for aging management of the internal and external surfaces of the carbon steel condenser shell. The table cited generic Note E (i.e., the component, material, and environment are consistent with the GALL Report recommendation but the applicant applied a differentAMP). However, the applicant claimed that an AMP is not required and referenced plant-specific Note 410. The staff questioned the applicant's use of Note E for these AMR entries as no AMP is credited.In response, the applicant stated that the structural integrity of the CDR required to perform itspost-accident intended function is demonstrated continuously during normal plant operation; therefore, no traditional AMP is required. The post-accident intended function of the CDR is toprovide a holdup volume and plateout surface for MSIV leakage. This intended function does not require the CDRs to be leak tight because the post-accident conditions in the CDRs areessentially atmospheric and there will be no challenge to their pressure boundary integrity.Normal plant operation assures adequate CDR pressure boundary integrity and thepost-accident intended function to provide pressure boundary and holdup volume and plateout surface.The staff noted that SRP-LR Section A.1.2.3.4 states that a program based solely on detectingSC failures is not considered an effective AMP. The staff then reviewed the applicant's justification and asked it to clarify why it had described no AMP for these components.The applicant stated that radioactive iodine is assumed to plate out on the interior surfaces ofthe CDR for both loss of coolant and control rod drop accidents. Aging management is notrequired for the CDR components that have only a plateout and holdup of radioactive materialintended function. For these components, the aging effects do not require aging managementas the condenser surface condition does not affect the deposition of iodine in the CDR. Tomaintain the intended function, the CDR and the components which make up the CDR complex 3-246simply have to remain intact. Condenser structural integrity is demonstrated continuously duringnormal operation when the condenser is required to maintain vacuum. When the condenser is required to perform its intended function following a DBA, the MSIVs will be closed andcondenser vacuum will be lost. The condenser will not be required to perform a pressureboundary function because essentially atmospheric conditions will exist inside the condenser.Since normal performance considerations, such as fouling and in-leakage (e.g., CWT or air leaks), place greater requirements on condenser operation than the post-accident plateout,then, as long as the condenser is intact and operational, the post-accident plateout and holdupof radioactive material will be maintained and no aging management is required.Additionally, as documented in its August 31, 2005, letter, the applicant revised plant-specificNote 410 to clarify the discussion of the intended function of the CDR:No traditional aging management of the main condenser for plateout and holdupis required. The main condenser is required to perform a post-accident intended function of plateout and holdup. This post-accident intended function does not require the main condenser to be leak tight and post-accident conditions in the main condenser would be essentially atmospheric. During normal plant operation, the main condenser continuously verifies its structural integrity by maintaining condenser vacuum that is constantly monitored and provides assurance that it will perform its post-accident intended function of iodineplateout and holdup.The staff's review of the applicant's response found that the CDR need not be leak-tight, aspost-accident conditions in the CDR are essentially atmospheric. During normal plantoperations, the applicant continuously monitors condenser vacuum to verify the integrity of the CDR. Degradation of its integrity to a loss of vacuum will require placement of the plant in amode that will obviate the post-accident intended function; therefore, acceptable performanceduring normal plant operation is adequate assurance that the CDR can perform the hol dup andplateout post-accident function.On this basis, the staff found that the applicant appropriately addressed the aging effect andmechanism as identified in the GALL Report.Conclusion. The staff evaluated the applicant's claim of consistency with the GALL Report. Thestaff also reviewed information pertaining to the applicant's consideration of recent operating experience and proposals for managing associated aging effects. The staff's review concluded that the AMR results, which the applicant claimed to be consistent with the GALL Report, areconsistent with the AMRs in the GALL Report; therefore, the staff concluded that the applicanthas demonstrated that the aging effects for these components will be adequately managed sothat their intended function(s) will be maintained consistent with the CLB for the period ofextended operation, as required by 10 CFR 54.21(a)(3).3.4.2.2AMR Results That Are Consistent with the GALL Report, for Which Further EvaluationIs RecommendedSummary of Technical Information in the Application. In LRA Section 3.4.2.2 the applicantprovided further evaluation of aging management as recommended by the GALL Report for the 3-247SPC system components. The applicant provided information concerning how it will m anage thefollowing aging effects:
* cumulative fatigue damage
* loss of material due to general, pitting, and crevice corrosion
* loss of material due to general, pitting, and crevice corrosion, microbiologicallyinfluenced corrosion, and biofouling
* general corrosion
* loss of material due to general, pitting, crevice, and microbiologically influencedcorrosionStaff Evaluation. For component groups evaluated in the GALL Report for which the applicanthas claimed consistency with the GALL Report, and for which the GALL Report recommends further evaluation, the staff audited and reviewed the applicant's evaluation to determinewhether it adequately addressed the issues that were further evaluated. In addition, the staffreviewed the applicant's further evaluations against the criteria contained in SRP-LR Section 3.4.2.2. The staff's audit and review report details the staff's audit. The following sections discuss the staff's evaluation of the aging effects.3.4.2.2.1  Cumulative Fatigue Damage In LRA Section 3.4.2.2.1, the applicant stated that fatigue is a TLAA, as defined in10 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 criteria in SRP-LR Section 3.4.2.2.2.In LRA Section 3.4.2.2.2 the applicant addressed loss of material due to general, pitting, andcrevice corrosion of carbon steel and cast iron piping and fittings, valve bodies and bonnets, pump casings, pump suction and discharge lines, tanks, tubesheets, channel heads, and shells except for MST system components in the SPC system. This section also addresses loss ofmaterial due to pitting and crevice corrosion of stainless steel components in the SPC system.SRP-LR Section 3.4.2.2.2 states the following:The management of loss of material due to general, pitting, and crevicecorrosion should be evaluated further for carbon steel piping and fittings, valve bodies and bonnets, pump casings, pump suction and discharge lines, tanks, tubesheets, channel heads, and shells except for main steam systemcomponents and for loss of material due to pitting and crevice corrosion for stainless steel tanks and heat exchanger/cooler tubes. The water chemistry program relies on monitoring and control of water chemistry based on the guidelines in BWRVIP-29 (EPRI guideline TR-103515) for water chemistry to manage the effects of loss of material due to general, pitting, or crevice corrosion. However, corrosion may occur at locations of stagnant flow conditions.
Therefore, the effectiveness of the chemistry control program should be verified to ensure that corrosion is not occurring. The GALL Report recommends further 3-248evaluation of programs to manage loss of material due to general, pitting, andcrevice corrosion to verify the effectiveness of the water chemistry program. A one-time inspection of select components and susceptible locations is an acceptable method to ensure that corrosion is not occurring and that thecomponent's intended function will be maintained during the period of extendedoperation.In LRA Section 3.4.2.2.2, the applicant stated that the One-Time Inspection Program and PlantChemistry Program manage the aging effect. Exceptions apply to GALL Report recommendations for the Plant Chemistry Program implementation (refer to LRA Section B2.1.25). The One-Time Inspection Program is a new AMP. The scope of this new AMP will incorporate activities to verify the effectiveness of the Plant Chemistry Program,including a sample of components where the flow of water is low or stagnant conditions exist (refer to LRA Section B2.1.23). Implementation of the One-Time Inspection Program, in conjunction with the Plant Chemistry Program, to manage the aging effect provides added assurance that the aging effect is not occurring at locations of stagnant or low flow; or that theaging effect is progressing very slowly such that the component's intended function will bemaintained during the period of extended operation.The applicant stated in the LRA that the Plant Chemistry Program manages the loss of materialfor carbon and stainless steel components in SPC systems, and that a one-time inspection ofselected components and susceptible locations will verify the efficacy of that program. SERSections 3.0.3.2.19 and 3.0.3.1.4 document the staff's evaluations of the Plant ChemistryProgram and One-Time Inspection Program, respectively.On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LRSection 3.4.2.2.2. For those line items that apply to LRA Secti on 3.4.2.2.2, the staff determinedthat the applicant's AMRs are consistent with the GALL Report and the applicant hasdemonstrated that the effects of aging will be adequately managed so that the intendedfunction(s) will be maintained consistent with the CLB during the period of extended operation,as required by 10 CFR 54.21(a)(3).3.4.2.2.3Loss of Material Due to General, Pitting, and Crevice Corrosion, MicrobiologicallyInfluenced Corrosion, and BiofoulingThe staff reviewed LRA Section 3.4.2.2.3 against the criteria in SRP-LR Section 3.4.2.2.3.In LRA Section 3.4.2.2.3, the applicant stated that this aging effect applies to PWRs only.SRP-LR Section 3.4.2.2.3 states that loss of material due to general, pitting, and crevicecorrosion, MIC, and biofouling could occur in carbon steel piping and fittings for untreated water from the backup water supply in the PWR auxiliary FW (AFW) system. SRP-LR Table 3.3-1states that further evaluation for this aging effect is for PWR plants only.The staff found that this aging effect is not applicable at MNGP.
3-2493.4.2.2.4  General CorrosionThe staff reviewed LRA Section 3.4.2.2.4 against the criteria in SRP-LR Section 3.4.2.2.4.In LRA Section 3.4.2.2.4 the applicant addressed loss of material due to general corrosion onthe external surfaces of carbon steel and cast iron components of the SPC system in air/gasenvironments.SRP-LR Section 3.4.2.2.4 states the following:Loss of material due to general corrosion could occur on the external surfaces ofall carbon steel structures and components, including closure bolting, exposed to operating temperature less that 212 F. The GALL Report recommends furtherevaluation to ensure that this aging effect is adequately managed.In LRA Section 3.4.2.2.4, the applicant stated that the System Condition Monitoring Programmanages the loss of material for carbon steel and cast iron components in SPC systems. TheSystem Condition Monitoring Program manages the aging effect on the external surfaces of carbon steel and cast iron components in air/gas environments. Management of the aging effect associated with certain components of the CDR with the plateout and holdup ofradioactive material intended function is not applicable, as the CDR structural integrity isdemonstrated continuously during normal plant operation. As documented in its August 31,2005, letter, the applicant stated that it will revise the LRA to eliminate reference to the pressureboundary function of the CDRs as this function is inappropriate for these components. TheSystem Condition Monitoring Program is an existing plant-specific program that manages aging effects for normally accessible external surfaces of piping, tanks, and other components and equipment within the scope of license renewal through visual inspection and monitoring of external surfaces for leakage and evidence of material degradation. Implementation of the System Condition Monitoring Program to manage corrosion adds assurance that corrosion does not occur and that the aging effect progresses so slowly that the component's intendedfunction will be maintained during the period of extended operation. SER Section 3.0.3.3.2documents the staff's review of the applicant's System Condition Monitoring Program.On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LRSection 3.4.2.2.4. For those line items that apply to LRA Secti on 3.4.2.2.4, the staff determinedthat the applicant's AMRs are consistent with the GALL Report and the applicant hasdemonstrated that the effects of aging will be adequately managed so that the intendedfunctions will be maintained consistent with the CLB during the period of extended operation, asrequired by 10 CFR 54.21(a)(3).3.4.2.2.5Loss of Material Due to General, Pitting, Crevice, and Microbiologically InfluencedCorrosionThe staff reviewed LRA Section 3.4.2.2.5 against the criteria in SRP-LR Section 3.4.2.2.5.The applicant stated in LRA Section 3.4.2.2.5.2 that MNGP CSTs are not SR and therefore notwithin the scope of licensing renewal. The applicant also stated in LRA Section 3.4.2.2.5.2 thatMNGP has no underground CSTs.
3-250Because the applicant has no components from this group, the staff concurred with theapplicant's determination that this aging effect is not applicable.Conclusion. On the basis of its review, for component groups evaluated in the GALL Report forwhich the applicant has claimed consistency with the GALL Report, and for which the GALL Report recommends further evaluation, the staff determined that the applicant adequatelyaddressed the issues that were further evaluated. The staff found that the applicant hasdemonstrated that the aging effects will be adequately managed so that the intended functionswill be maintained consistent with the CLB for the period of extended operation, as required by10 CFR 54.21(a)(3).3.4.2.3  AMR Results That Are Not Consistent with or Not Addressed in the GALL ReportSummary of Technical Information in the Application. In LRA Tables 3.4.2-1 through 3.4.2-5,the staff reviewed additional details of the results of the AMRs for material, environment, AERM, and AMP combinations that are not consistent with the GALL Report, or that are notaddressed in the GALL Report.In LRA Tables 3.4.2-1 through 3.4.2-5, the applicant indicated, via Notes F through J, that thecombination of component type, material, environment, and AERM does not correspond to a line item in the GALL Report and provided information concerning how it will manage the agingeffect. Specifically, Note F indicates that the GALL Report does not evaluate the material for the AMR line item component. Note G indicates that the GALL Report does not evaluate the environment for the AMR line item component and material. Note H indicates that the GALL Report does not evaluate the aging effect for the AMR line item component, material, and environment combination. Note I indicates that the aging effect identified in the GALL Report forthe line item component, material, and environment combination is not applicable. Note J indicates that the GALL Report does not evaluate either the component or the material andenvironment combination for the line item.Staff Evaluation. For component type, material, and environment combinations that the GALLReport does not evaluate, the staff reviewed the applicant's evaluation to determine whether theapplicant demonstrated that the effects of aging will be adequately managed so that theintended functions will be maintained consistent with the CLB during the period of extendedoperation. This section addresses AMR results for which LRA Tables 3.4.2-1 through 3.4.2-5 identified no aging effects. The discussion on each table addresses the other line items that arenot consistent with the GALL Report or not addressed in the GALL Report. The following sections discuss the staff's evaluation.In LRA Tables 3.4.2-1 through 3.4.2-5, the applicant identified AMR line items for which theaging review process identified no aging effects. Specifically, the applicant identified no aging effects for components fabricated from stainless steel and rubber materials that are exposed to a primary containment air, plant indoor air, instrument air, or gas environment or for components fabricated from carbon steel or stainless steel that are exposed to a lubricating oil environment. The applicant stated that a materials science evaluation for these materials inthese environments discovered no aging effects.Because stainless steels are highly resistant to corrosion in dry atmospheres in the absence ofcorrosive species, as cited in the Metals Handbook, Ninth Edition, the staff agreed that stainless 3-251steel in an indoor, uncontrolled air environment (e.g., plant indoor air) or in a gas environment(e.g., primary containment air inerted with nitrogen) exhibits no aging effect and that the SC will,therefore, remain capable of performing its intended functions consistent with the CLB for the period of extended operation. In addition, because both oxygen and moisture must be present to corrode steel, as cited in the Metals Handbook, the staff agreed that carbon steel or stainlesssteel in a lubricating oil internal environment with no water pooling exhibits no aging effect and that the SC will, therefore, remain capable of performing its intended functions consistent withthe CLB for the period of extended operation.As listed in the GALL Report, rubber that is not in an environment of elevated temperature (i.e.,above 95 F (35 C)) with additional factors such as exposure to ozone, oxidation, and radiationwill remain capable of performing intended functions consistent with the CLB for the period ofextended operation. Because specific ozone concentrations could not be determined, by letterdated November 17, 2005, the applicant stated that it will manage change in material propertiesdue to ozone for elastomers in an external air environment using the System Condition Monitoring Program. SER Section 3.4.2.3.3 documents the staff's evaluation.The staff's review of current industry research and operating experience found that plant indoorair, primary containment air, instrument air on stainless steel, or lubricating oil on stainless steel or carbon steel will not result in aging of concern during the period of extended operation;therefore, the staff concluded that the component, material, and environment combinationsdescribed in the preceding discussion have no applicable AERMs.The staff's review of current industry research and operating experience found that theapplicant demonstrated that no aging effects are predicted for the material and environmentalcombinations reported and that the SPC system components fabricated from these materials inthe environments listed above will maintain their intended functions consistent with the CLBduring the period of extended operation, as required by 10 CFR 54.21(a)(3).3.4.2.3.1Steam and Power Conversion System-Condensate Storage System-Summary ofAging Management Evaluation-Table 3.4.2-1The staff reviewed LRA Table 3.4.2-1, which summarizes the results of AMR evaluations for the condensate stor age system component groups.All line items in this table are consistent with the GALL Report or are included in the discussionin Section 3.4.2.3 above.3.4.2.3.2Steam and Power Conversion System-Condensate and FeedwaterSystem-Summary of Aging Management Evaluation-Table 3.4.2-2The staff reviewed LRA Table 3.4.2-2, which summarizes the results of AMR evaluations for thecondensate and FW system component groups.In LRA Table 3.4.2-2, the applicant proposed to manage cracking and change in materialproperties due to thermal exposure of rubber materials for the component types of expansion joints exposed to a treated water (internal) environment using the One-Time Inspection Program.
3-252SER Section 3.0.3.1.4 documents the staff's review of the One-Time Inspection Program. TheOne-Time Inspection Program is a new program consistent with the recommendations of GALL AMP XI.M32". This program will include measures to verify the effectiveness of the PlantChemistry Program and the Fuel Oil Chemistry Program and also will confirm the absence ofage degradation in selected components (e.g., flow restrictors, venturis, and small bore piping) within scope of license renewal. The One-Time Inspection Program addresses concerns and provides confirmation for the potential long incubation period for certain aging effects on SCs.
The applicant has noted in the LRA that in some cases in which aging effects/mechanisms are not expected to be significant, the One-Time Inspection Program alone is credited with managing aging effects. The staff's review determined that the use of the One-Time InspectionProgram alone is acceptable in certain cases in which the use of the Plant Chemistry Program is not a viable option. This AMP is appropriate for the aging effects/mechanisms identified and assures effective management of the aging effects through the period of extended operation.that the One-Time Inspection Program effectivelymanages the aging effects of cracking and change in material properties due to thermal exposure of rubber material exposed to a treated water (internal) environment. On this basis, the staff found that management of cracking due to thermal exposure, as given in LRA Table 3.4.2-2, is acceptable.3.4.2.3.3Steam and Power Conversion System-Main Condenser System-Summary ofAging Management Evaluation-Table 3.4.2-3The staff reviewed LRA Table 3.4.2-3, which summarizes the results of AMR evaluations for theCDR system component groups.In Table 3.4.2-2, the applicant identified no AERMs for rubber expansion joints intended tomaintain the pressure boundary function in a plant indoor air environment. The applicant stated that the GALL Report does not evaluate either the components or the material and environmentcombination. The applicant further stated that these elastomer components (e.g., neoprene,rubber) are indoors and not subject to UV rays or ozone, nor are they in locations subject to radiation exposure or to temperatures at which changes in material properties or cracking could occur (>95 F); therefore, the applicant contended that no aging management is required. Inindustry experience, however, elastomeric expansion joints degrade due to oxidation in environments that are not necessarily harsh, as discussed in EPRI Report 1008035 and EPRI Report 1007933.The staff's review of LRA Section 3.4 identified areas for which it needed additional informationto complete its evaluation of the applicant's results. The applicant responded to the staff's RAIs as discussed below.In RAI 3.4-1, dated July 20, 2005, the staff requested that the applicant discuss its inspectionprocedures for the rubber expansion joints related to preventive maintenance, for both externaland internal surfaces of the elastomer.
3-253In its response, by letter dated August 16, 2005, the applicant stated the following:EPRI Report 1008035, 'Expansion Joint Maintenance Guide,' Revision 1,May 2003, Table 5-4, rates elastomers against oxidation, tensile strength, andradiation. Elastomers, such as Neoprene, Natural Rubber, Chlorobutyl, Buna-N, Viton, and EPDM, are rated as good or better in the categories of oxidation, tensile strength, and radiation.EPRI Report 1007933, 'Aging Assessment Field Guide,' December 2003,pages 60 through 65, lists oxidation as a degradation mechanism brought on by the stressors: Thermal, Radiation, and Ultraviolet. As stated in the first paragraph of the question, these elastomers are not exposed to these stressors.Since these elastomers are not exposed to ultraviolet, radiation, or temperatures>95 degrees F, they are therefore not susceptible to oxidation and no aging management is required.In addition, the applicant referred to a related response to RAI 3.3.2.3-3, which addresses theoxidation effects and degradation of elastomers due to thermal, irradiation, and UV exposure.The staff also noted that the applicant's response to RAI 3.3.2.3-4, dated August 16, 2005, hadnot addressed degradation of rubber by oxidation resulting from exposure to ozone in air. The staff asked the applicant to provide the specific designation of the types of elastomers installed at the plant and the data related to exposure to ozone in air for each type, if available. Inaddition, the staff asked the applicant to explain its method for evaluating degradation causedby oxidation from exposure to ozone.The staff was concerned that some of the elastomers in question may not be long-livedcomponents designed for 60 years. The applicant's response had not clearly stated that thesecomponents are not long-lived and are replaced at specified intervals. The staff asked the applicant to confirm this and provide supporting data.In its response, by letter dated November 17, 2005, the applicant stated the following:After further evaluation of this issue, NMC has taken the conservative approachof managing change in material properties due to ozone for elastomers in an air environment, specifically for natural rubber. This is a result of the fact that neither representative ozone concentrations nor technically substantiated thresholds could be adequately or consistently determined, even though plantspecific operating experience has indicated that there has been no change in material properties due to ozone for these elastomer components. Further evaluation also revealed the inability to confirm that none of these componentsare fabricated from natural rubber.As a result, elastomers in an external air environment in the following LRA tableswill utilize the System Condition Monitoring Program to manage the potentialaging effect of changes in material properties due to ozone which shall be assigned to these components.
3-254
* Table 3.3.2-3 expansion joints in the Circulating Water System
* Table 3.3.2-5 piping and fittings in the Demineralized Water System
* Table 3.3.2-6 piping and fittings in the Emergency Diesel GeneratorsSystem
* Table 3.3.2-7 ventilation seals in the Emergency Filtration Train System
* Table 3.3.2-16 expansion joints in the Service and Seal Water System
* Table 3.4.2-2 expansion joints in the Condensate and Feedwater System(those which were not previously managed externally)Elastomers in Table 3.2.2-8 (ventilation seals in the Secondary ContainmentSystem) are presently being managed utilizing the One-Time InspectionProgram for the internal surfaces and the System Condition Monitoring Program for the external surfaces. These Aging Management Programs (AMPs) were initially credited to manage change in material properties and cracking due to thermal exposure, since a temperature threshold of greater than 95 F wasassigned to these components. Consequently, these same AMPs will alsomanage change in material properties due to ozone which shall be assigned to these components.Elastomers (expansion joints) in Table 3.4.2-3 (Main Condenser System) do notrequire aging management since these components do not serve a pressure boundary intended function but provide for plate-out and holdup of radioactive material during design basis events. Condenser integrity is continuously demonstrated during normal plant operation thus validating that this intendedfunction is maintained as stated in the plant-specific notes for these components in Section 3.4 of the LRA.Elastomers in an internal air environment in Table 3.3.2-6 (piping and fittings inthe Emergency Diesel Generators System) and Table 3.3.2-7 (ventilation sealsin the Emergency Filtration Train System) will utilize the One-Time Inspection Program to manage the potential aging effect of change in material properties due to ozone which shall be assigned to these components.Elastomers in both an internal and external air environment in Table 3.3.2-11(ventilation seals in the Heating and Ventilation System) were inadvertentlyomitted from this table. These components shall be managed for the potentialaging effect of change in material properties due to ozone utilizing the One-TimeInspection Program for the internal surfaces and the System Condition Monitoring Program for the external surfaces which shall be assigned to these components.All the elastomers addressed are long-lived components. Any component that isnot long-lived and replaced at specified intervals is eliminated from AMR consideration during the screening process. Although the expansion joints are presently under review for replacement on a fixed periodicity, this change has 3-255not been effected and they remain as and have been analyzed as long-livedcomponents.Any degradation of elastomer components in an air environment resulting fromchange in material properties due to ozone for the external surfaces of these components shall be evaluated as discussed in the response to RAI B2.1.32-02 which addresses the System Condition Monitoring AMP.The staff's review found the applicant's response acceptable, because the applicant added theSystem Condition Monitoring and One-Time Inspection Programs for the management of aging effects in elastomers. The applicant also satisfactorily addressed the staff's concern related to long-lived components. SER Sections 3.0.3.3.2 and 3.0.3.1.4 document the staff reviews of theSystem Condition Monitoring and One-Time Inspection Programs, respectively; therefore, the staff's concern described in RAI 3.3.2.3-4 is resolved.In RAI 3.4-2, dated July 20, 2005, the staff noted that in LRA Table 3.4.2-3 the applicantidentified the aging effects of changes in material properties and cracking due to irradiation and thermal exposure for rubber expansion joints in an internal steam environment. The intended function of the expansion joints is to maintain holdup of radioactive material. The applicant stated that the GALL Report does not evaluate either the components or the material andenvironment combination. The applicant further stated that the aging effect/mechanism isapplicable but requires no management as the intended function for this component is post-accident iodine plateout and holdup. According to the applicant, CDR structural integrity iscontinuously demonstrated during normal plant operation, thus maintaining the intendedfunction; however, the staff position is that this component type (rubber expansion joint) is within the scope of license renewal and its aging effects should be managed. The staff requested that the applicant provide the appropriate AMP to manage the aging effects ofchanges in material properties and cracking due to irradiation and thermal expansion of the rubber expansion joints in a steam environment.In its response, by letter dated August 16, 2005, the applicant further demonstrated that thepost-accident plateout and holdup of radioactive material intended function will be maintainedand no aging management is required. The applicant stated the following:For both a Loss of Coolant Accident (LOCA) and a Control Rod DropAccident (CRDA), radioactive iodine is assumed to be held up and plate-out onthe interior surfaces of the main condenser. 'Plate-out and holdup of radioactive material' is the only intended function assigned to the main condenser expansion joints.Aging management is not required for the main condenser components thathave only a plate-out and holdup of radioactive material intended function. For these components, the aging effects do not require aging management because the deposition of iodine in the main condenser is unaffected by the condenser surface condition. To maintain the intended function, the main condenser and the components, which make up the main condenser complex, simply have to remain intact.
3-256Condenser structural integrity is continuously demonstrated during normaloperation when the condenser is required to maintain vacuum. Following a design basis accident, when the condenser is required to perform its intended function, the main steam isolation valves will be closed and vacuum will be lost.The condenser will not be required to perform a pressure boundary functionbecause atmospheric conditions will exist inside the condenser.Since normal performance considerations such as fouling and in-leakage (e.g.,circulating water or air leaks) place greater requirements on condenser operation than the post-accident plate-out, then as long as the condenser is intact and operational, the post-accident plate-out and holdup of radioactive material intended function will be maintained and no aging management is required.The staff's review found the applicant's response to RAI 3.4-2 acceptable because thecondenser is likely to remain operational following a DBA as well as during normal operation, and no aging management is required; therefore, the staff's concern described in RAI 3.4-2 isresolved.3.4.2.3.4Steam and Power Conversion System-Main Steam System-Summary of AgingManagement Evaluation-Table 3.4.2-4The staff reviewed LRA Table 3.4.2-4, which summarizes the results of AMR evaluations for theMST system component groups.All line items in this table are consistent with the GALL Report or are included in the discussionin Section 3.4.2.3 above.3.4.2.3.5Steam and Power Conversion System-Turbine Generator System-Summary ofAging Management Evaluation-Table 3.4.2-5The staff reviewed LRA Table 3.4.2-5, which summarizes the results of AMR evaluations for theturbine generator system component groups.In LRA Table 3.4.2-5, the applicant proposed to manage the loss of material due to selectiveleaching of cast iron materials for the component types of steam traps exposed to a treated water or steam (internal) environment, or for copper alloy component types of heat exchangers exposed to a wet air or gas environment, or for component types of piping and fittings exposed to a raw water environment, using the Selective Leaching of Materials Program.SER Section 3.0.3.2.22 documents the staff's review and evaluation of the applicant's SelectiveLeaching of Materials Program. The Selective Leaching of Materials Program includes a one-time visual inspection and hardness measurement of certain components susceptible to selective leaching. In situations in which hardness testing is not practical, the applicant will use a qualitative approach by other NDE or metallurgical methods to determine the presence and extent of selective leaching. The program will determine if selective leaching occurs for certain components and ensure the integrity of components made of gray cast iron, bronze, brass, andother alloys exposed to a raw water, treated water, or ground-water environment that may cause selective leaching of one of the metal components.
3-257In LRA Table 3.4.2-5, the applicant proposed to manage the loss of material due to MIC, pitting,and crevice corrosion of copper alloy materials for the component types of gauges, piping and fittings, and valve bodies exposed to a treated water (internal) environment using the One-Time Inspection Program and the Plant Chemistry Program.SER Sections 3.0.3.2.19 and 3.0.3.1.4 document the staff's reviews of the applicant's PlantChemistry Program and the One-Time Inspection Program, respectively. The Plant Chemistry Program mitigates the aging effects on component surfaces that are exposed to water as the process fluid; chemistry programs are used to control water chemistry for impurities (e.g.,
chloride and sulfate) that accelerate corrosion or crack initiation and growth and that cause heat transfer degradation due to fouling in select heat exchangers. This program relies on monitoring and control of water chemistry to keep peak levels of various contaminants below system-specific limits. The One-Time Inspection Program is a new program consistent with therecommendations of GALL AMP XI.M32 and verifies the effectiveness of the Plant Chemistry Program. The One-Time Inspection Program addresses concerns and provides confirmation for the potential long incubation period for certain aging effects on SCs. The staff review determined that the Plant Chemistry Program supplemented by the One-Time InspectionProgram is adequate for managing these combinations of material, environment, and aging effects.In LRA Table 3.4.2-5, the applicant proposed to manage loss of material due to MIC, pitting,and crevice corrosion of copper alloy materials for the component types of heat exchangers exposed to a wet air or gas (external) environment using the System Condition Monitoring Program.SER Section 3.0.3.3.2 documents the staff's review and evaluation of the applicant's SystemCondition Monitoring Program.that the Plant Chemistry Program, One-Time Inspection Program, and System Condition Monitoring Program effectively manage the aging effect of loss of material due to MIC, pitting, and crevice corrosion of copper alloy material exposed to wet air or gas, or treated water environment. The Selective Leaching of Materials Program effectively manages the loss of material due to selective leaching of cast iron material exposed to treated water environment, and copper alloy exposed to wet air or gas and raw water environments. The staff found that the applicant's program to manage loss of material due to MIC, pitting, crevice corrosion, and selective leaching, as given in LRA Table 3.4.2-5, is acceptable.Conclusion. On the basis of its review, the staff found that the applicant appropriately evaluatedAMR results involving material, environment, AERMs, and AMP combinations that the GALL Report does not evaluate. The staff found that the applicant has demonstrated that the effectsof aging will be adequately managed so that the intended functions will be maintainedconsistent with the CLB for the period of extended operation, as required by10 CFR 54.21(a)(3).
3-2583.4.3  ConclusionThe staff concluded that the applicant provided sufficient information to demonstrate that theeffects of aging for the SPC system components that are within the scope of license renewaland subject to an AMR will be adequately managed so that the intended functions will bemaintained consistent with the CLB for the period of extended operation, as required by10 CFR 54.21(a)(3).The staff also reviewed the applicable USAR supplement program summaries and concludedthat they adequately describe the AMPs credited for managing aging of the SPC system, asrequired by 10 CFR 54.21(d).3.5  Aging Management of Containments, Structures, and Component SupportsThis section of the SER documents the staff's review of the applicant's AMR results for thecontainments, structures, and component supports components and component groups associated with the following systems:
* cranes, heavy loads, rigging
* diesel fuel oil transfer house
* emergency diesel generator building
* emergency filtration train building
* fire protection barriers commodity group
* hangers and supports commodity group
* HPCI building
* intake structure
* miscellaneous SBO yard structures
* offgas stack
* offgas storage and compressor building
* plant control and cable spreading structure
* primary containment
* radioactive waste building
* reactor building
* structures affecting safety
* turbine building
* underground duct bank3.5.1  Summary of Technical Information in the Application In LRA Section 3.5, the applicant provided AMR results for the containments, structures, andcomponent supports components and component groups. In LRA Table 3.5.1, the applicantprovided a summary comparison of its AMRs with the AMRs evaluated in the GALL Report for the containments, structures, and component supports components and component groups.The applicant's AMRs incorporated applicable operating experience in the determination ofAERMs. These reviews included evaluation of plant-specific and industry operating experience.
The plant-specific evaluation included reviews of CRs and discussions with appropriate site personnel to identify AERMs. The applicant's review of industry operating experience included a 3-259review of the GALL Report and operating experience issues identified since the issuance of theGALL Report.3.5.2  Staff Evaluation The staff reviewed LRA Section 3.5 to determine if the applicant provided sufficient informationto demonstrate that the aging effects for the containments, structures, and component supportssystem components that are within the scope of license renewal and subject to an AMR will beadequately managed so that the intended functions will be maintained consistent with the CLBfor the period of extended operation, as required by 10 CFR 54.21(a)(3).In addition, the staff performed an onsite audit of AMRs to confirm the applicant's claim thatcertain identified AMRs are consistent with the GALL Report. The staff did not repeat its reviewof the matters described in the GALL Report; however, the staff did verify that the material presented in the LRA is applicable and that the applicant had identified the appropriate GALLReport AMRs. SER Section 3.0.3 documents the staff's evaluations of the AMPs. The MNGP audit and review report details the staff's audit evaluation, as summarized in SER Section 3.5.2.1.The staff also performed an onsite audit of those selected AMRs that are consistent with theGALL Report and for which further evaluation is recommended. The staff confirmed that the applicant's further evaluations are consistent with the acceptance criteria in SRP-LR Section 3.5.2.2. The MNGP audit and review report documents the staff's audit evaluations,which and are summarized in SER Section 3.5.2.2.The staff performed an onsite audit and conducted a technical review of the remaining AMRsthat are not consistent with, or not addressed in, the GALL Report. The audit and technicalreview included evaluating whether the applicant identified all plausible aging effects and whether the aging effects listed are appropriate for the combination of materials and environments specified. The MNGP audit and review report documents the staff's audit evaluations. SER Section 3.5.2.3 summarizes these audit evaluations and documents thestaff's technical review.Finally, the staff reviewed the AMP summary descriptions in the USAR supplement to ensurethat they adequately describe the programs credited with managing or monitoring aging for thecontainments, structures, and component supports system components.Table 3.5-1 below summarizes the staff's evaluation of components, aging effects/mechanisms,and AMPs listed in LRA Section 3.5 that are addressed in the GALL Report.
3-260Table 3.5-1  Staff Evaluation for Containments, Structures, and Component Supports inthe GALL ReportComponent GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff EvaluationCommon Components of All Types of PWR and BWR ContainmentPenetrationsleeves, penetrationbellows, anddissimilar metalwelds(Item Number3.5.1-01)Cumulative fatiguedamage (CLBfatigue analysisexists)TLAA, evaluated inaccordance with10 CFR 54.21(c)TLAAThis TLAA isevaluated in Section4.3, Metal Fatigueof the RPV andInternals, andReactor CoolantPressure BoundaryPiping andComponents andSection 4.6, FatigueAnalysis of thePrimaryContainment,Attached Piping,and ComponentsPenetrationsleeves, bellows,and dissimilar metalwelds(Item Number3.5.1-02)Cracking due tocyclic loading, orcrack initiation andgrowth due to SCCContainment ISI,containment leak-rate test 10 CFR 50,Appendix JProgram (B2.1.1),PrimaryContainmentIn-ServiceInspection Program(B2.1.26) Consistent withGALL Report, whichrecommends furtherevaluation (seeSection 3.5.2.2.1)Penetrationsleeves, penetrationbellows, anddissimilar metalwelds(Item Number3.5.1-03)Loss of materialdue to corrosionContainment ISI,containment leak-rate test 10 CFR 50,Appendix JProgram (B2.1.1),PrimaryContainmentIn-ServiceInspection Program(B2.1.26)Consistent withGALL Report, whichrecommends nofurther evaluationPersonnel airlockand equipmenthatch(Item Number3.5.1-04)Loss of materialdue to corrosionContainment ISI,containment leak-rate test 10 CFR 50,Appendix JProgram (B2.1.1),PrimaryContainmentIn-ServiceInspection Program (B2.1.26) Consistent withGALL Report, whichrecommends nofurther evaluationPersonnel airlockand equipmenthatch(Item Number3.5.1-05)Loss of leaktightness in closedposition due tomechanical wear oflocks, hinges, andclosure mechanismContainment leak-rate test, plantTechnicalSpecifications 10 CFR 50,Appendix JProgram (B2.1.1)Consistent withGALL Report, whichrecommends nofurther evaluation Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation3-261Seals, gaskets, andmoisture barriers(Item Number3.5.1-06)Loss of sealant andleakage throughcontainment due todeterioration of jointseals, gaskets, andmoisture barriersContainment ISI,containment leak-rate test 10 CFR 50,Appendix JProgram (B2.1.1),PrimaryContainmentIn-ServiceInspection Program(B2.1.26)Consistent withGALL Report, whichrecommends nofurther evaluationPWR Concrete (Reinforced and Prestressed) and Steel ContainmentBWR Concrete (Mark II and III) and Steel (Mark I, II, and III) ContainmentConcrete elements-foundation, walls,dome(Item Number3.5.1-07)Aging of accessibleand inaccessibleconcrete areas dueto leaching ofcalcium hydroxide,aggressivechemical attack,and corrosion ofembedded steelContainment ISINot applicable toMNGP Mark IcontainmentConcrete elements-foundation(Item Number3.5.1-08)Cracks, distortion,and increases incomponent stresslevel due tosettlementStructuresMonitoringNot applicable toMNGP Mark IcontainmentConcrete elements-foundation(Item Number3.5.1-09)Reduction infoundation strengthdue to erosion ofporous concretesubfoundationStructuresMonitoringNot applicable toMNGP Mark IcontainmentConcrete elements-foundation, dome,and wall(Item Number3.5.1-10)Reduction ofstrength andmodulus due toelevatedtemperaturePlant specificNot applicable toMNGP Mark IcontainmentPrestressedcontainment-tendons andanchoragecomponents(Item Number3.5.1-11)Loss of prestressdue to relaxation,shrinkage, creep,and elevatedtemperatureTLAA, evaluated inaccordance with10 CFR 54.21(c)Not applicable toMNGP Mark IcontainmentSteel elements-liner plate,containment shell(Item Number3.5.1-12)Loss of materialdue to corrosion inaccessible andinaccessible areasContainment ISI,containment leak-rate test 10 CFR 50,Appendix JProgram (B2.1.1),PrimaryContainmentIn-ServiceInspection Program(B2.1.26)Consistent withGALL Report, whichrecommends furtherevaluation(seeSection 3.5.2.2.1)
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation3-262Steel elements-vent header,drywell head, torus,downcomers, poolshell(Item Number3.5.1-13)Cumulative fatiguedamage (CLBfatigue analysisexists)TLAA, evaluated inaccordance with10 CFR 54.21(c)TLAAThis TLAA isevaluated in Section4.3, Metal Fatigueof the RPV andInternals, andReactor CoolantPressure BoundaryPiping andComponents andSection  4.6,Fatigue Analysis ofthe PrimaryContainment,Attached Piping,and ComponentsSteel elements-protected by coating(Item Number3.5.1-14)Loss of materialdue to corrosion inaccessible areasonlyProtective coatingmonitoring andmaintenance 10 CFR 50,Appendix JProgram (B2.1.1),PrimaryContainmentIn-ServiceInspection Program(B2.1.26),Protective CoatingMonitoring &MaintenanceProgram (B2.1.27)Consistent withGALL Report.Protective CoatingMonitoring &MaintenanceProgram is notrelied upon formanaging loss ofmaterial due tocorrosion, but iscredited forpreventingdegradation ofcoatings that couldlead to clogging ofECCS suppressionpool suctionstrainersPrestressedcontainment-tendons andanchoragecomponents(Item Number3.5.1-15)Loss of materialdue to corrosion ofprestressingtendons andanchoragecomponentsContainment ISINot applicable toMNGP Mark Icontainment. Thereare no prestressedcontainmenttendons andanchoragecomponentsConcrete elements-foundation, dome,and wall(Item Number3.5.1-16)Scaling, cracking,and spalling due tofreeze-thaw;expansion andcracking due toreaction with aggregateContainment ISINot applicable toMNGP Mark Icontainment Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation3-263Steel elements-vent line bellows,vent headers,downcomers(Item Number3.5.1-17)Cracking due tocyclic loads or crackinitiation and growthdue to SCCContainment ISI,containment leak-rate test 10 CFR 50,Appendix JProgram (B2.1.1),PrimaryContainmentIn-ServiceInspection Program(B2.1.26) Consistent withGALL Report, whichrecommends furtherevaluation (seeSection 3.5.2.2.1)Steel elements-suppressionchamber liner(Item Number3.5.1-18)Crack initiation andgrowth due to SCCContainment ISI,containment leak-rate testNot applicable toMNGP Mark IcontainmentSteel elements-drywell head anddowncomer pipes(Item Number3.5.1-19)Fretting and lockupdue to wearContainment ISINot applicable to MNGP.Components notsubject to relativemotionClass I StructuresAll groups exceptGroup 6-accessibleinterior/exteriorconcrete and steelcomponents(Item Number3.5.1-20)All types of agingeffectsStructuresMonitoringStructuresMonitoring Program(B2.1.31)Consistent withGALL Report, whichrecommends furtherevaluation(seeSection 3.5.2.2.2)Groups 1-3, 5, 7-9-inaccessibleconcretecomponents, suchas exterior wallsbelow grade andfoundation(Item Number3.5.1-21)Aging ofinaccessibleconcrete areas dueto aggressivechemical attack,and corrosion ofembedded steelPlant specificNoneMNGP meets thecriteria specified inthe GALL ReportConsistent withGALL Report, whichrecommends furtherevaluation (seeSection 3.5.2.2.2)Group 6-allaccessible/inaccessibleconcrete, steel, and earthencomponents(Item Number3.5.1-22)All types of agingeffects, includingloss of material dueto abrasion,cavitation, andcorrosionInspection ofwater-controlstructures orFERC/U.S. ArmyCorp of Engineersdam inspection andmaintenanceStructuresMonitoring Program(B2.1.31)Consistent withGALL Report, withenhancements inthe StructuresMonitoring Programto includeRG 1.127,Inspection of Water-Control StructuresAssociated withNuclear PowerPlants.
Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation3-264Group 5-liners(Item Number3.5.1-23)Crack initiation andgrowth from SCCand loss of materialdue to crevicecorrosionWater chemistryand monitoring ofspent fuel poolwater levelPlant ChemistryProgram (B2.1.25),PrimaryContainmentIn-ServiceInspection Program(B2.1.26), andSystem ConditionMonitoring Program(B2.1.32)Consistent withGALL Report, whichrecommends nofurther evaluationGroups 1-3, 5, 6-all masonry blockwalls(Item Number3.5.1-24)Cracking due torestraint, shrinkage,creep, andaggressiveenvironmentMasonry wallFire ProtectionProgram (B2.1.17),StructuresMonitoring Program(B2.1.31)Consistent withGALL Report, withenhancements inthe StructuresMonitoring Programto include masonrywallsGroups 1-3, 5, 7-9-foundation(Item Number3.5.1-25)Cracks, distortion,and increases incomponent stresslevel due tosettlementStructuresmonitoringStructuresMonitoring Program(B2.1.31) only forthe fuel oil transferhouseConsistent withGALL Report(seeSection 3.5.2.2.1)Groups 1-3, 5-9-foundation(Item Number3.5.1-26)Reduction infoundation strengthdue to erosion ofporous concretesubfoundationStructuresmonitoring NoneMNGP meets thecriteria specified inthe GALL ReportConsistent withGALL Report(seeSection 3.5.2.2.1)Groups 1-5-concrete(Item Number3.5.1-27)Reduction ofstrength andmodulus due toelevatedtemperaturePlant specificNoneConcretetemperatures do notexceed GALLReportrecommended limitsConsistent withGALL Report, whichrecommends furtherevaluation(seeSection 3.5.2.2.1)Groups 7, 8-liners(Item Number3.5.1-28)Crack initiation andgrowth due to SCC;loss of material dueto crevice corrosionPlant specificNot applicable.MNGP has noGroup 7 (concretetanks) or Group 8(steel tanks) withlinersComponent Supports Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation3-265All groups-supportmembers-anchorbolts, concretesurrounding anchorbolts, welds, groutpad, boltedconnections, etc.(Item Number3.5.1-29)Aging of componentsupportsStructuresMonitoringBuried Piping &Tanks InspectionProgram (B2.1.5),PrimaryContainmentIn-ServiceInspection Program(B2.1.26),StructuresMonitoring Program(B2.1.31), SystemConditionMonitoring Program(B2.1.32) Consistent withGALL Report, whichrecommends furtherevaluation(seeSection 3.5.2.2.3)Groups B1.1, B1.2,and B1.3-supportmembers-anchorbolts, welds(Item Number3.5.1-30)Cumulative fatiguedamage (CLBfatigue analysisexists)TLAA, evaluated inaccordance with10 CFR 54.21(c)This TLAA isevaluated in Section4.3, Metal Fatigueof the RPV andInternals, andReactor CoolantPressure BoundaryPiping andComponentsAll groups-supportmembers-anchorbolts, welds(Item Number3.5.1-31)Loss of materialdue to boric acidcorrosionBoric acid corrosionNot applicable,PWR onlyGroups B1.1, B1.2,and B1.3-supportmembers-anchorbolts, welds, springhangers, guides,stops, and vibrationisolators(Item Number3.5.1-32)Loss of materialdue toenvironmentalcorrosion; loss ofmechanical functiondue to corrosion,distortion, dirt,overload, etc.ISIASME Section XI,Subsection IWFProgram (B2.1.3)Consistent withGALL Report, whichrecommends nofurther evaluationGroup B1.1-high-strength low-alloybolts(Item Number3.5.1-33)Crack initiation andgrowth due to SCCBolting integrityNot applicable toMNGP. There areno high-strengthlow-alloy bolts inuse at MNGP forstructural applications  The staff's review of the MNGP component groups followed one of several approaches. Oneapproach, documented in SER Section 3.5.2.1, involves the staff's review of the AMR resultsfor components in the containments, structures, and component supports that the applicantindicated are consistent with the GALL Report and do not require further evaluation. Anotherapproach, documented in SER Section 3.5.2.2, involves the staff's review of the AMR resultsfor components in the containments, structures, and component supports that the applicant 3-266indicated are consistent with the GALL Report and for which further evaluation isrecommended. A third approach, documented in SER Section 3.5.2.3, involves the staff'sreview of the AMR results for components in the containments, structures, and component supports that the applicant indicated are not consistent with, or not addressed in, the GALLReport. Section 3.0.3 documents the staff's review of AMPs that are credited to manage ormonitor aging effects of the containments, structures, and component supports components.3.5.2.1  AMR Results That Are Consistent with the GALL Report Summary of Technical Information in the Application. In LRA Section 3.5.2.1, the applicantidentified the materials, environments, and AERMs. The applicant identified the following programs that manage the aging effects related to the containments, structures, andcomponent supports system components:
* 10 CFR 50, Appendix J Program (B2.1.1)
* ASME Section XI, Subsection IWF Program (B2.1.3)
* Buried Piping & Tanks Inspection Program (B2.1.5)
* Fire Protection Program (B2.1.17)
* Inspection of Overhead Heavy Load and Light Load (Related to Refueling) HandlingSystems Program (B2.1.22)
* One-Time Inspection Program (B2.1.23)
* Plant Chemistry Program (B2.1.25)
* Primary Containment In-Service Inspection Program (B2.1.26)
* Protective Coating Monitoring & Maintenance Program (B2.1.27)
* Structures Monitoring Program (B2.1.31)
* System Condition Monitoring Program (B2.1.32)Staff Evaluation. In LRA Tables 3.5.2-1 through 3.5.2-18, the applicant summarized the AMRsfor the containments, structures, and component supports components and identified which AMRs it considered to be consistent with the GALL Report.For component groups evaluated in the GALL Report for which the applicant has claimedconsistency with the GALL Report, and for which the GALL Report does not recommend further evaluation the staff performed an audit and review to determine whether the GALL Report evaluation bounds the plant-specific components contained in these GALL Report componentgroups.The applicant provided a note for each AMR line item. The notes describe how the informationin the tables aligns with the information in the GALL Report. The staff audited those AMRs with Notes A through E, which indicate that 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 AMP 3-267identified in the GALL Report. The staff audited these line items to verify consistency with theGALL Report and the 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 AMP identified in the GALL Report. The staff audited these line items to verify consistency with the GALL Report. The staff verified that it had reviewed and accepted the identified exceptionsto the GALL Report AMPs. The staff also determined whether the AMP identified by the applicant is consistent with the AMP identified in the GALL Report and whether the AMR is validfor the site-specific conditions.Note C indicates that the component for the AMR line item, although different, is consistent withthe GALL Report for material, environment, and aging effect. In addition, the AMP is consistent with the AMP identified by the GALL Report. This note indicates that the applicant could not finda listing of some system components in the GALL Report; however, the applicant identified adifferent component in the GALL Report that has 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 determined whether the AMR line item of the different component applies to the component under review and whether the AMR is valid for the site-specific conditions.Note D indicates that the component for the AMR line item, although different, is consistent withthe GALL Report for material, environment, and aging effect. In addition, the AMP takes some exceptions to the AMP identified in the GALL Report. The staff audited these line items to verify consistency with the GALL Report. The staff verified whether the AMR line item of the different component applies to the component under review. The staff verified that it had reviewed and accepted the identified exceptions to the GALL Report AMPs. The staff also determined whether the AMP identified by the applicant is consistent with the AMP identified in the GALLReport and whether the AMR is 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 the applicant credited a different AMP. The staff audited these line items to verify consistency with the GALL Report. The staff also determined whether the identified AMP will manage the aging effect consistent with the AMP identified by the GALLReport and whether the AMR is valid for the site-specific conditions.The staff conducted an audit and review of the information provided in the LRA, as documentedin the MNGP audit and review report. The staff did not repeat its review of the matters described in the GALL Report; however, the staff did verify that the material presented in the LRA is applicable and that the applicant identified the appropriate GALL Report AMRs. The following sections discuss the staff's evaluation.3.5.2.1.1  Loss of Material Due to Corrosion in Accessible Areas In reviewing entries in LRA Table 3.5.2-13 for carbon steel and low-alloy steel in treated waterand air/gas environments, the staff identified some discrepancies in notes for AMR line items that reference GALL Report line item II.B.1.1.1-a. The discrepancies resulted because theapplicant credited different AMPs from those recommended by the GALL Report and used 3-268exceptions where none existed. The staff asked the applicant to resolve these discrepancies. Inits response, by letter dated August 11, 2005, the applicant stated the following:LRA line II.B.1.1.1-a for the component structural steel in a treated waterenvironment for the AMP Primary Containment Inservice Inspection program, the note should have been
'C' and not 'D.'LRA line II.B.1.1.1-a for the component structural steel in a treated waterenvironment for the AMP Plant Chemistry program, the note should have been
'E' and not 'D.'LRA line II.B.1.1.1-a for the component support members, welds, boltedconnections, torus internal catwalk support columns in a treated water environment for the AMP Primary Containment Inservice Inspection program, the note should have been
'C' and not 'D.'LRA line II.B.1.1.1-a for the component support members, welds, boltedconnections, torus internal catwalk support columns in a treated water environment for the AMP Plant Chemistry Program, the note should have been
'E' and not 'D.'LRA line II.B.1.1.1-a for the component structural steel inside torus, torus internalcatwalk in an air/gas environment, for the AMP Primary Containment Inservice Inspection Program, the note should have been
'C' and not 'D.'Because the components, material, and AMP identified in the LRA are consistent with the GALLReport, the staff concluded that the applicant appropriately addressed aging management forthe above components.The staff's review found that the applicant appropriately addressed the agingeffects/mechanisms, as recommended by the GALL Report.Conclusion. The staff evaluated the applicant's claim of consistency with the GALL Report. Thestaff also reviewed information pertaining to the applicant's consideration of recent operating experience and proposals for managing associated aging effects. The staff's review concluded that the AMR results, which the applicant claimed to be consistent with the GALL Report, areconsistent with the AMRs in the GALL Report; therefore, the staff concluded that the applicanthas demonstrated that the aging effects for these components will be adequately managed sothat their intended functions will be maintained consistent with the CLB for the period ofextended operation, as required by 10 CFR 54.21(a)(3).3.5.2.2AMR Results That Are Consistent with the GALL Report, for Which Further EvaluationIs RecommendedSummary of Technical Information in the Application. In LRA Section 3.5.2.2, the applicantprovided further evaluation of aging management as recommended by the GALL Report for the containments, structures, and component supports components. The applicant provided information concerning how it will manage the following aging effects for PWR and BWRcontainments:
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* aging of inaccessible concrete areas
* cracking, distortion, and increase in component stress level due to settlement; reductionof foundation strength 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 corrosion in inaccessible areas of steel containment shell or linerplate
* loss of prestress due to relaxation, shrinkage, creep, and elevated temperature
* cumulative fatigue damage
* cracking due to cyclic loading and SCCThe applicant also provided information on its management of the following aging effects forClass 1 structures:
* aging of structures not covered by the Structures Monitoring Program
* aging management of inaccessible areasFinally, the applicant provided information on its management of aging effects for componentsupports:
* aging of supports not covered by the Structures Monitoring Program
* cumulative fatigue damage due to cyclic loadingStaff Evaluation. For component groups evaluated in the GALL Report for which the applicanthas claimed consistency with the GALL Report, and for which the GALL Report recommends further evaluation, the staff audited and reviewed the applicant's evaluation to determinewhether it adequately addresses the issues that were further evaluated. In addition, the staffreviewed the applicant's further evaluations against the criteria contained in SRP-LR Section 3.5.2.2. The staff's audit and review report details the staff's audit. The following sections discuss the staff's evaluation of the aging effects.3.5.2.2.1  PWR and BWR Containments The staff reviewed LRA Section 3.5.2.2.1 against the criteria in SRP-LR Section 3.5.2.2.1,which addresses several areas discussed below.Aging of Inaccessible Concrete Areas. The staff reviewed LRA Section 3.5.2.2.1.1 against thecriteria in SRP-LR Section 3.5.2.2.1.1.In LRA Section 3.5.2.2.1.1, the applicant addressed aging of inaccessible concrete areas.SRP-LR Section 3.5.2.2.1.1 states the following:Cracking, spalling, and increases in porosity and permeability due to leaching ofcalcium hydroxide and aggressive chemical attack; and cracking, spalling, loss 3-270of bond, and loss of material due to corrosion of embedded steel could occur ininaccessible areas of PWR concrete and steel containments; BWR Mark II concrete containments; and Mark III concrete and steel containments. The GALLReport recommends further evaluation of plant-specific programs to manage the aging effects for inaccessible areas if specific criteria defined in the GALL Report cannot be satisfied.In LRA Section 3.5.2.2.1.1, the applicant stated that these aging effects/mechanisms do notapply to the MNGP containment because it is a BWR Mark I design, which does not include concrete as part of the containment structure. The staff found that these agingeffects/mechanisms do not apply for the MNGP containment.Cracking, Distortion, and Increase in Component Stress Level Due to Settlement; Reduction ofFoundation Strength Due to Erosion of Porous Concrete Subfoundations, If Not Covered by theStructures Monitoring Program. The staff reviewed LRA Section 3.5.2.2.1.2 against the criteriain SRP-LR Section 3.5.2.2.1.2.In LRA Section 3.5.2.2.1.2, the applicant addressed cracking, distortion, and increase incomponent stress level due to settlement as well as reduction of foundation strength due to erosion of porous concrete subfoundations.SRP-LR Section 3.5.2.2.1.2 states the following:Cracking, distortion, and increase in component stress level due to settlementcould occur in PWR concrete and steel containments and BWR Mark II concrete containments and Mark III concrete and steel containments. Also, reduction offoundation strength due to erosion of porous concrete subfoundations could occur in all types of PWR and BWR containments. Some plants may rely on a de-watering system to lower the site ground-water level. If the plant's CLB creditsa de-watering system, the GALL Report recommends verification of thecontinued functionality of the de-wateri ng system during the period of extendedoperation. The GALL Report recommends no further evaluation if this activity is included in the scope of the applicant's structures monitoring program.In LRA Section 3.5.2.2.1.2, the applicant addressed aging effects due to settlement, specificallywhether it needs to manage the aging effects/mechanisms based on a plant-specific review of the conditional requirements outlined in the GALL Report.This subsection mainly concerns PWR and BWR Mark II and III concrete containments;however, the settlement criteria presented apply to all concrete foundations. The plant initial licensing basis did not include a program to monitor settlement. With the exception of the diesel fuel oil transfer house, no significant settlement has been observed on any major structure, and de-watering systems are not used. These circumstances satisfy the GALL Reportrecommendations on concrete settlement and, therefore, with the exception of the diesel fuel oiltransfer house, cracks, distortion, and increase in component stress levels due to settlementrequire no aging management.The diesel fuel oil transfer house is a moderate-weight structure exerting a mean bearingpressure of about 1100 pounds per square foot (lb/ft
: 2) on the underlying foundation material.
3-271The foundation material of compacted granular backf ill underlain by stiff clay lenses andsandstone bedrock should not be susceptible to settlement under the load imposed. However, the diesel fuel oil transfer house has undergone significant differential settlement. According to plant records and settlement data, the diesel fuel oil transfer house settled rapidly following construction, which the applicant stated probably resulted from washout after a rainstorm and was long ago effectively complete. Data recorded annually since 1992 show no significant continued settlement of the structure.The Structures Monitoring Program manages the aging effects for the diesel fuel oil transferhouse. As part of the Structures Monitoring Program, the applicant performs an annual inspection of the diesel fuel oil transfer house for settlement to manage the aging effects of cracks, distortion, and increase in component stress level due to settlement. The inspectionadds assurance that the aging effects do not occur or progress so slowly that the component'sintended function will be maintained during the period of extended operation.SER Section 3.0.3.2.23 documents the staff's evaluation of the Structures Monitoring Program.The staff found this program acceptable for managing the aging effects of cracks, distortion,and increase in component stress level due to settlement as it inspects for settlement.The applicant also addressed the aging effects of all types of PWR and BWR containments dueto erosion of porous concrete subfoundations, specifically whether it needs to manage the aging effects/mechanisms based on a plant-specific review of the conditional requirements outlined in the GALL Report. The applicant's response to erosion of cement from porous concrete subfoundations, as described in IN 97-11, "Cement Erosion from Containment Subfoundations at Nuclear Power Plants," dated March 21, 1997, and IN 98-26, "SettlementMonitoring and Inspection of Plant Structures Affected by Degradation of Porous Concrete Subfoundations," dated July 24, 1998, concluded that foundation materials contain no porouslayers. The concrete base or lean concrete fill material beneath major building foundationscontains no high-alumina cement. The applicant does not rely on a de-wateri ng system to lowersite ground water.The applicant concluded that the GALL Report recommendations are satisfied for porousconcrete subfoundations and therefore the aging effects due to erosion of porous concrete subfoundations necessitate no aging management.during inspections under theStructures Monitoring Program, (2) the applicant has no porous concrete subfoundations, and (3) the applicant does not employ a de-watering system.On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LRSection 3.5.2.2.1.2. For those line items that apply to LRA Section 3.5.2.2.1.2, the staffdetermined that the applicant's AMRs are consistent with the GALL Report and the applicanthas demonstrated that the effects of aging will be adequately managed so that the intendedfunctions will be maintained consistent with the CLB during the period of extended operation, asrequired by 10 CFR 54.21(a)(3).
3-272Reduction of Strength and Modulus of Concrete Structures Due to Elevated Temperature. Thestaff reviewed LRA Section 3.5.2.2.1.3 against the criteria in SRP-LR Section 3.5.2.2.1.3.In LRA Section 3.5.2.2.1.3, the applicant addressed reduction of strength and modulus ofconcrete structures due to elevated temperature.SRP-LR Section 3.5.2.2.1.3 states the following:Reduction of strength and modulus of elasticity due to elevated temperaturescould occur in PWR concrete and steel containments and BWR Mark II concrete containments and Mark III concrete and steel containments. The GALL Reportrecommends further evaluation if any portion of the concrete containment components exceeds specified temperature limits (i.e., general area temperature
 
66 C [150F] and local area temperature 93 C [200 F]).The applicant stated that this aging effect mainly concerns PWR and BWR Mark II and IIIconcrete containments; however, the temperature criteria presented in this section apply to all concrete. Plant documents confirm that concrete elements are not subject to elevatedtemperatures in excess of 150 F generally and 200 F locally. Plant areas that bound high-temperature considerations are the drywell general area and biological shield wall piping penetration local area, which experience temperatures of 135 F and 179 F, respectively.The staff's review determined that the applicant has evaluated the temperatures of hot pipingpenetrations considering the presence of insulation, which is credited with maintaining the penetration temperatures below the local limits of 200 F. Insulation is included within the scopeof license renewal and is subject to an AMR.The staff found the applicant's AMRs consistent with the GALL Report in demonstrating that thetemperatures do not exceed the temperatures recommended in the GALL Report for which evaluation is required.On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LRSection 3.5.2.2.1.3. For those line items that apply to LRA Section 3.5.2.2.1.3, the staffdetermined that the applicant's AMRs are consistent with the GALL Report and the applicanthas demonstrated that the effects of aging will be adequately managed so that the intendedfunctions will be maintained consistent with the CLB during the period of extended operation, asrequired by 10 CFR 54.21(a)(3).Loss of Material Due to Corrosion in Inaccessible Areas of Steel Containment Shell or LinerPlate. The staff reviewed LRA Section 3.5.2.2.1.4 against the criteria in SRP-LRSection 3.5.2.2.1.4.In LRA Section 3.5.2.2.1.4, the applicant addressed loss of material due to corrosion for thedrywell shell and the drywell support skirt in inaccessible areas (i.e., embedded in concrete).SRP-LR Section 3.5.2.2.1.4 states the following:Loss of material due to corrosion could occur in inaccessible areas of the steelcontainment shell or the steel liner plate for all types of PWR and BWR 3-273containments. The GALL Report recommends further evaluation of plant-specificprograms to manage this aging effect for inaccessible areas if specific criteria defined in the GALL Report cannot be satisfied.In LRA Section 3.5.2.2.1.4, the applicant stated that MNGP satisfies t; therefore, aplant-specific AMP for loss of material due to corrosion of steel elements in inaccessible areas is not required.The applicant also stated that the Protective Coating Monitoring & Maintenance Program is notcredited with managing loss of material due to corrosion but with preventing degradation of coatings that could lead to clogging of ECCS suppression pool suction strainers.
Implementation of this program to manage the aging effect adds assurance that the agingeffect does not occur or progresses so slowly that the component's intended function will bemaintained during the period of extended operation.The staff reviewed LRA Section 3.5.2.2.1.4 and determined that the applicant satisfied thespecific criteria defined in the GALL Report for preventing loss of material due to corrosion for the drywell shell and the drywell support skirt in inaccessible areas (i.e., embedded in concrete).
The staff's review of applicant documents specifying that (1) plant concrete meets ACI 318 or 349 criteria, (2) the Structures Monitoring Program inspects the concrete around the inside of the drywell adjacent to the moisture barrier, (3) the scope of the Primary Containment In-Service Inspection Program includes the moisture barrier, and (4) borated water leaks do not apply for BWR plants. Therefore, the staff determined that further evaluation is not necessary.The staff found that the applicant is consistent with the GALL Report, and a plant-specific AMPfor loss of material is not required. SER Section 3.5.2.3.6 documents further discussion of thestaff's review of loss of material due to corrosion for the drywell shell in inaccessible areas.On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LRSection 3.5.2.2.1.4. For those line items that apply to LRA Section 3.5.2.2.1.4, the staffdetermined that the applicant's AMRs are consistent with the GALL Report and the applicanthas demonstrated that the effects of aging will be adequately managed so that the intendedfunctions will be maintained consistent with the CLB during the period of extended operation, asrequired by 10 CFR 54.21(a)(3).Loss of Prestress Due to Relaxation, Shrinkage, Creep, and Elevated Temperature. The staffreviewed LRA Section 3.5.2.2.1.5 against the criteria in SRP-LR Section 3.5.2.2.1.5.In LRA Section 3.5.2.2.1.5, the applicant addressed loss of prestress due to relaxation,shrinkage, creep, and elevated temperature.SRP-LR Section 3.5.2.2.1.5 states the following:Loss of prestress forces due to relaxation, shrinkage, creep, and elevatedtemperature for PWR prestressed concrete containments and BWR Mark II prestressed concrete containments is a TLAA as defined in 10 CFR 54.3. TLAAs are required to be evaluated in accordance with 10 CFR 54.21(c).
3-274In LRA Section 3.5.2.2.1.5, the applicant stated that this aging effect applies to Mark II BWRcontainments only.Because MNGP is not a PWR and has no BWR Mark II containment, the staff found this agingeffect not applicable.Cumulative Fatigue Damage. In LRA Section 3.5.2.2.1.6, the applicant stated that fatigue is aTLAA as defined in 10 CFR 54.3. Applicants must evaluate TLAAs in accordance with 10 CFR 54.21(c)(1). SER Sections 4.3 and 4.6 document the staff's review of the applicant'sevaluation of this TLAA.Cracking Due to Cyclic Loading and SCC. The staff reviewed LRA Section 3.5.2.2.1.7 againstthe criteria in SRP-LR Section 3.5.2.2.1.7.In LRA Section 3.5.2.2.1.7, the applicant addressed cracking due to cyclic loading and SCC.SRP-LR Section 3.5.2.2.1.7 states the following:Cracking of containment penetrations (including penetration sleeves, penetrationbellows, and dissimilar metal welds) due to cyclic loading or SCC could occur in all types of PWR and BWR containments. Cracking could also occur in vent line bellows, vent headers, and downcomers due to SCC for BWR containments. A visual VT-3 examination would not detect such cracks. The GALL Reportrecommends further evaluation of the inspection methods implemented to detect these aging effects.In LRA Section 3.5.2.2.1.7, the applicant listed components associated with primarycontainment that require aging management for cracking due to cyclic loading because theiroriginal design bases did not include CLB fatigue analyses. Specifically, components requiring aging management for cracking due to cyclic loading include drywell penetrations, drywell penetration sleeves, and associated dissimilar metal welds. These components are designed to stress levels without requiring fatigue analyses and thus fine cr acks are unlikely to occur;therefore, existing requirements for leak-rate testing pursuant to the 10 CFR 50, Appendix JProgram and surface inspections pursuant to the Primary Containment In-Service Inspection Program are adequate to detect cracking due to cyclic loading.The applicant also listed components associated with primary containment that require agingmanagement for crack initiation and growth due to SCC, specifically the stainless steel vent line bellows and drywell penetration bellows. The GALL Report states that weld Examination Categories E-B (pressure retaining welds, VT-1 examination method) and E-F (dissimilar pressure retaining welds, surface examination method) for vent line and other penetration bellows assemblies are warranted for the extended period of operations.The applicant stated that its operating history on bellows replacements is limited to bellowsX-16B. Leakage was identified during local leak-rate testing and not from cracks observedduring a visual examination. The leakage was identified at the outer-most bellows from a smallfailure underneath the outer-most collar of the expansion joint. The applicant did not identify anycracks in the weld metal. Industry operating history has identified cracks of the bellows but nonein the weld metal. Welds for bellows assemblies are in a sheltered, noncorrosive environment.
3-275Additionally, bellows assemblies are located outside primary containment in an air/gasenvironment with temperatures not expected to exceed threshold limits for SCC. Because of the nonaggressive environmental exposures and plant-specific and industry operating histories, the applicant stated that weld examinations using optional Examination Categories E-B and E-F arenot warranted. The applicant stated that existing requirements for visual examinations, inaccordance with ASME Code, Section XI (Subsection IWE), Examination Category E-A, and Appendix J leak-rate testing, Examination Category E-P, should be sufficient to detect cracking of the bellows assemblies.The applicant concluded that implementation of these programs to manage aging effects addsassurance that the aging effects do not occur or progress so slowly that the component'sintended function will be maintained during the period of extended operation.SER Sections 3.0.3.1.6 and 3.0.3.2.1 document the staff's reviews of the applicant's PrimaryContainment In-Service Inspection Program and the 10 CFR 50, Appendix J Program, respectively. The NRC staff found these programs acceptable for managing cracking due tocyclic loading and SCC in accessible areas.The staff reviewed industry operating experience on cracking of containment penetrations(including penetration sleeves, penetration bellows, and dissimilar metal welds) due to cyclicloading and SCC and found it to be similar to the applicant's operating experience. The staff concluded that the applicant appropriately addressed further evaluation of this aging effect.On the basis of its review, the staff concluded that, based on the programs identified above, theapplicant has met the criteria of SRP-LR Section 3.5.2.2.1.7. For those line items that apply toLRA Section 3.5.2.2.1.7, the staff determined that the applicant's AMRs are consistent with theGALL Report and the applicant has demonstrated that the effects of aging will be adequatelymanaged so that the intended functions will be maintained consistent with the CLB during theperiod of extended operation, as required by 10 CFR 54.21(a)(3).3.5.2.2.2  Class 1 Structures The staff reviewed LRA Section 3.5.2.2.2 against the criteria in SRP-LR Section 3.5.2.2.2,which addresses several areas discussed below.Aging of Structures Not Covered by Structures Monitoring Program. The staff reviewed LRASection 3.5.2.2.2.1 against the criteria in SRP-LR Section 3.5.2.2.2.1.In LRA Section 3.5.2.2.2.1, the applicant addressed various aging effects for concrete andcarbon steel components. The applicant specifically addressed whether it needs to manage the aging effects/mechanisms based on plant-specific review of the conditional requirements outlined in the GALL Report.SRP-LR Section 3.5.2.2.2.1 states the following:The GALL Report recommends further evaluation of certain structure/agingeffect combinations if they are not covered by the Structures Monitoring Program. This includes (1) scaling, cracking, and spalling due to repeatedfreeze-thaw for Groups 1-3, 5, 7-9 structures; (2) scaling, cracking, spalling and 3-276increase in porosity and permeability due to leaching of calcium hydroxide andaggressive chemical attack for Groups 1-5, 7-9 structures; (3) expansion and cracking due to reaction with aggregates for Groups 1-5, 7-9 structures; (4) cracking, spalling, loss of bond, and loss of material due to corrosion of embedded steel for Groups 1-5, 7-9 structures; (5) cracks, distortion, andincrease in component stress level due to settlement for Groups 1-3, 5, 7-9 structures; (6) reduction of foundation strength due to erosion of porous concrete subfoundation for Groups 1-3, 5-9 structures; (7) loss of material due to corrosion of structural steel components for Groups 1-5, 7-8 structures; (8) loss of strength and modulus of concrete structures due to elevated temperatures for Groups 1-5; and (9) crack initiation and growth due to SCC and loss of material due to crevice corrosion of stainless steel liner for Groups 7 and 8 structures.
Further evaluation is necessary only for structure/aging effect combinations not covered by the structures monitoring program. Technical details of the aging management issue are presented in SRP-LR Subsection 3.5.2.2.1.2 for items (5)and (6) and Subsection 3.5.2.2.1.3 for item (8).The applicant stated that, in accordance with the GALL Report for carbon steel in accessibleareas, loss of material due to corrosion requires aging management. It performs aging management of carbon steel in accessible areas within the Structures Monitoring Program through general visual inspections. Protective coatings, including galvanization, are not relied upon to manage the aging effects.The applicant also stated that the underground duct bank and intake structures includebelow-grade steel components. As the below-grade sides of the carbon steel components are not accessible, the condition of the accessible sides of the carbon steel components located inan atmosphere/weather, air/gas, or raw water environment, will be used to evaluate thecondition of the inaccessible sides of the carbon steel components.The applicant stated that, in accordance with the GALL Report and ISG-03, concrete inaccessible areas requires aging management for the aging mechanisms of freeze-thaw, leaching of calcium hydroxide, reaction with aggregates, corrosion of embedded steel, and aggressive chemical attack. The applicant performs aging management of concrete in accessible areas through general visual inspections within the Structures Monitoring Program.The applicant stated that concrete in inaccessible areas requires no aging management andprovided justification in the following paragraphs from LRA Section 3.5.2.2.2.1:MNGP is located in a severe weathering region according to Figure 1 of ASTMC33-90, and therefore a freeze-thaw evaluation is required. Plant documentsconfirm that the concrete has an air content between 3 and 6%, and subsequentinspections performed on concrete in accessible areas did not exhibit degradation related to freeze-thaw. This evaluation satisfies GALL Report and ISG-03 condition requirements for concrete in inaccessible areas, and therefore loss of material and cracking due to freeze-thaw do not require aging management.Plant documents confirm that the concrete was constructed in accordance withthe recommendations in ACI 201.2R-77 for durability. Additionally, there is no 3-277flowing water acting on any below-grade concrete basemat or concrete wall.Building foundations may or may not fall below the ground-water table. For those below the ground-water table, evaluation shows that ground-water flow velocity is well below the threshold at which any significant erosion or leaching of calcium hydroxide is possible. This evaluation satisfies the GALL Report and ISG-03 condition requirements for concrete in inaccessible areas, and therefore increase in porosity and permeability and loss of strength due to leaching of calciumhydroxide do not require aging management.Tests and petrographic examinations performed according to ASTM C289-64and ASTM C295 verified that aggregates used are not reactive. This satisfies the GALL Report and ISG-03 condition requirements for concrete in inaccessible areas, and therefore expansion and cracking due to reaction with aggregates do not require aging management.The GALL Report and ISG-03's description of an aggressive environment is pH< 5.5, chlorides >500 ppm, or sulfates > 1500 ppm. Plant documents confirm that the below-grade environment is not aggressive (MNGP data indicates thatthe pH is > 7.0, the chlorides are < 100 ppm and the sulfates are < 100 ppm).The Structures Monitoring Program includes examinations of below-grade concrete when excavated for any reason. To ensure the below-grade environment remains non-aggressive, ground-water chemistry is monitored periodically for the above parameters as part of the Structures Monitoring Program. This satisfies the GALL Report and ISG-03 condition requirements for concrete in inaccessible areas, and therefore cracking, loss of bond, and loss of material due to corrosion of embedded steel do not require aging management.
Based on the above rationale, increase in porosity and permeability, cracking,and loss of material due to aggressive chemical attack do not require aging management.Finally, the applicant stated in LRA Section 3.5.2.2.2.1 that implementation of the StructuresMonitoring Program to manage aging effects/mechanisms adds assurance that the aging effects do not occur or progress so slowly that the component's intended function will bemaintained during the period of extended operation.SER Section 3.0.3.2.23 documents the staff's evaluation of the Structures Monitoring Program.The staff reviewed component/aging effect combinations and the need to manage the agingeffects/mechanisms based on plant-specific review of the conditional requirements outlined in the GALL Report and determined that the applicant appropriately addressed these conditions.The staff's review of the applicant's evaluations found them acceptable.On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LRSection 3.5.2.2.2.1. For those line items that apply to LRA Section 3.5.2.2.2.1, the staffdetermined that the applicant's AMRs are consistent with the GALL Report and the applicanthas demonstrated that the effects of aging will be adequately managed so that the intendedfunctions will be maintained consistent with the CLB during the period of extended operation, asrequired by 10 CFR 54.21(a)(3).
3-278Aging Management of Inaccessible Areas. The staff reviewed LRA Section 3.5.2.2.2.2 againstthe criteria in SRP-LR Section 3.5.2.2.2.2.In LRA Section 3.5.2.2.2.2, the applicant addressed aging management of inaccessible areasfor Class 1 structures.SRP-LR Section 3.5.2.2.2.2 states the following:Cracking, spalling, and increases in porosity and permeability due to aggressivechemical attack, and cracking, spalling, loss of bond, and loss of material due tocorrosion of embedded steel could occur in below-grade inaccessible concrete areas. The GALL Report recommends further evaluation to manage these aging effects in inaccessible areas of Groups 1-3, 5, 7-9 structures, if specific criteria defined in the GALL Report cannot be satisfied.In LRA Section 3.5.2.2.2.2 the applicant stated that it has no Group 7 or 8 structures; therefore,discussion of the aging effects for these structures is not required. For other structures, the applicant concluded that concrete in inaccessible areas requires no aging management for corrosion of embedded steel and aggressive chemical attack and provided justification in LRA Section 3.5.2.2.2.1.The staff reviewed LRA Section 3.5.2.2.2.1 and found the specific criteria defined in the GALLReport satisfied; therefore, further evaluation is not necessary.On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LRSection 3.5.2.2.2.2. For those line items that apply to LRA Section 3.5.2.2.2.2, the staffdetermined that the applicant's AMRs are consistent with the GALL Report and the applicanthas demonstrated that the effects of aging will be adequately managed so that the intendedfunctions will be maintained consistent with the CLB during the period of extended operation, asrequired by 10 CFR 54.21(a)(3).3.5.2.2.3  Component Supports The staff reviewed LRA Section 3.5.2.2.3 against the criteria in SRP-LR Section 3.5.2.2.3,which addresses several areas discussed below.Aging of Supports Not Covered by the Structures Monitoring Program. The staff reviewed LRASection 3.5.2.2.3.1 against the criteria in SRP-LR Section 3.5.2.2.3.1.In LRA Section 3.5.2.2.3.1, the applicant discussed aging of component supports, specificallywhether it needs to manage the aging effects/mechanisms based on a plant-specific review of the conditional requirements outlined in the GALL Report.SRP-LR Section 3.5.2.2.3.1 states the following:The GALL Report recommends further evaluation of certain componentsupport/aging effect combinations if they are not covered by the Structures Monitoring Program. This includes (1) reduction in concrete anchor capacity due to degradation of the surrounding concrete, for Groups B1-B5 supports; (2) loss 3-279of material due to environmental corrosion, for Groups B2-B5 supports; and (3)reduction/loss of isolation function due to degradation of vibration isolation elements, for Group B4 supports. Further evaluation is necessary only for structure/aging effect combinations not covered by the Structures Monitoring Program.The applicant stated that component supports include structural elements connected to thebuilding or its structures and extending to a system or system component for support orrestraint. Component supports include support members, anchor bolts, welds, bolted connections, grout pads, and building concrete at locations of expansion and at grouted anchors. This boundary definition includes any vibration isolation elements. Spray or drip shields for equipment are included with component supports. In addition, electrical and instrumentation racks, electrical panels, cabinets and enclosures, lighting fixtures, tube track,conduit, and cable trays provide support and, thus, are included with component supports.
Miscellaneous steel structures such as platforms, stairs, whip restraints, and masonry wall supports are parts of the structures in which they are located.The applicant stated in the LRA that the AERM for carbon steel components is loss of material.In accordance with EPRI 1002950 guidelines, only general corrosion is an aging mechanism applicable to loss of material for carbon steel in air/gas or atmosphere/weather environments.
The EPRI guidelines also indicate that general, crevice, and pitting corrosion and MIC are aging mechanisms applicable to loss of material for carbon steel in treated water and below-grade environments. Therefore, as the applicant stated in the LRA, management of this aging effect isrequired:The aging effect requiring management for reinforced concrete and groutcomponents is reduction in concrete anchor capacity due to local concrete degradation. The only mechanism applicable to this aging effect is service-induced cracking or other concrete aging mechanism. Operating experience has shown that service-induced cracking can occur in concrete and grouted foundations. Concrete expansion bolts (anchors) can lose anchor capacity due to concrete or grout degradation. Therefore, management of this aging effect is required.The aging effect requiring management for elastomers (rubber, neoprene, silicone, etc.) is reduction or loss of isolation function. The aging mechanismsapplicable to this aging effect are radiation hardening, temperature, humidity, and sustained vibratory loading. Operating experience has also shown that elastomer materials can degrade over time. Therefore, management of this aging effect is required.Concerning AMPs used in addressing aging management, the applicant stated the following inthe LRA:The System Condition Monitoring Program is used to identify and correct agingconcerns for component supports in an air/gas or atmosphere/weather environment. Through general visual inspections, the System Condition Monitoring Program identifies and evaluates general corrosion of carbon steel components, service-induced cracking of grout and concrete local to support 3-280anchorage as well as degradation due to radiation hardening, temperature,humidity, and sustained vibratory loading of vibration isolation elements.The Structures Monitoring Program is used to identify and correct agingconcerns with miscellaneous steel components in an air/gas environment.
Through general visual inspections, the Structures Monitoring Program identifies and evaluates general corrosion of carbon steel components as well as service-induced cracking and degradation of grout and concrete local to the anchorage.The Buried Piping & Tanks Inspection Program is used to identify loss ofmaterial for carbon steel conduit and the Diesel Fuel Oil Storage Tank flood tie-downs in a below-grade environment through internal inspections of buried tanks, system functional testing, and periodic inspections of buried pipe. Acondition assessment evaluation is made of the buried conduit and the Diesel Fuel Oil Storage Tank flood tie-downs such that repairs can be made, if necessary, prior to loss of intended function.Access to the components inside the torus is limited. Since the PrimaryContainment In-Service Inspection Program inspects components inside the torus when available, it is relied upon to manage the aging effects of the miscellaneous steel components, support members, welds, and bolted connections located inside the torus. Through general visual inspections, the Primary Containment In-Service Inspection Program identifies and evaluates general (environmental), crevice, galvanic, MIC, and pitting corrosion of carbon steel components in treated water and general corrosion in air/gas.Finally, the applicant stated that implementation of these programs to manage agingeffects/mechanisms provides added assurance that the aging effects do not occur or progress so slowly that the component's intended function will be maintained during the period ofextended operation.The staff reviewed component support/aging effect combinations not addressed by theStructures Monitoring Program and determined that other AMPs address them. The staff concluded that the applicant used the appropriate AMPs.SER Section 3.0.3.2.23 documents the staff's evaluation of the Structures Monitoring Program.SER Section 3.0.3.3.2 documents the staff's evaluation of the System Condition MonitoringProgram. SER Section 3.0.3.2.5 documents the staff's evaluation of the Buried Piping & TanksInspection Program. Finally, SER Section 3.0.3.1.6 documents the staff's evaluation of thePrimary Containment In-Service Inspection Program.On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LRSection 3.5.2.2.3.1. For those line items that apply to LRA Section 3.5.2.2.3.1, the staffdetermined that the applicant's AMRs are consistent with the GALL Report and the applicanthas demonstrated that the effects of aging will be adequately managed so that the intendedfunctions will be maintained consistent with the CLB during the period of extended operation, asrequired by 10 CFR 54.21(a)(3).
3-281Cumulative Fatigue Damage Due to Cyclic Loading. Cumulative fatigue is a TLAA, as defined in10 CFR 54.3. TLAAs are required to be evaluated in accordance with 10 CFR 54.21(c)(1). SER Section 4.3 documents the evaluation of this TLAA.Conclusion. On the basis of its review, for component groups evaluated in the GALL Report forwhich the applicant has claimed consistency with the GALL Report, and for which the GALL Report recommends further evaluation, the staff determined that the applicant adequatelyaddressed the issues that were further evaluated. The staff found that the applicant hasdemonstrated that the aging effects will be adequately managed so that the intended functionswill be maintained consistent with the CLB for the period of extended operation, as required by10 CFR 54.21(a)(3).3.5.2.3  AMR Results That Are Not Consistent with or Not Addressed in the GALL ReportSummary of Technical Information in the Application. In LRA Tables 3.5.2-1 through 3.5.2-18,the staff reviewed additional details of the results of the AMRs for material, environment, AERM, and AMP combinations that are not consistent with the GALL Report, or that are notaddressed in the GALL Report.In LRA Tables 3.5.2-1 through 3.5.2-18, the applicant indicated, via Notes F through J, that thecombination of component type, material, environment, and AERM does not correspond to a line item in the GALL Report and provided information concerning how it will manage the agingeffect. Specifically, Note F indicates that the GALL Report does not evaluate the material for the AMR line item component. Note G indicates that the GALL Report does not evaluate the environment for the AMR line item component and material. Note H indicates that the GALL Report does not evaluate the aging effect for the AMR line item component, material, and environment combination. Note I indicates that the aging effect identified in the GALL Report forthe line item component, material, and environment combination is not applicable. Note J indicates that the GALL Report does not evaluate either the component or the material andenvironment combination for the line item.Staff Evaluation. For component type, material, and environment combinations that are notevaluated in the GALL Report, the staff reviewed the applicant's evaluation to determinewhether the applicant demonstrated that the aging effects will be adequately managed so thatintended functions will be maintained consistent with the CLB during the period of extendedoperation. The following sections discuss the staff's evaluation.In LRA Tables 3.5.2-1 through 3.5.2-18, the applicant identified AMR result line items for whichthe aging review process identified no aging effects. The applicant stated that it identified noaging effects for components fabricated from the materials and exposed to the environments described below.No aging effects were considered applicable to components fabricated from stainless steelmaterial exposed to air/gas environments. On the basis of the staff's review of current industry research and operating experience, stainless steel in dry air or gas (such as nitrogen, carbon dioxide, freon, and halon) exhibits no aging effect and the SC will therefore remain capable ofperforming its intended functions consistent with the CLB for the period of extended operation.Based on the Metals Handbook, Ninth Edition, Volumes 3 and 13, stainless steels are highlyresistant to corrosion in dry atmospheres in the absence of corrosive species, as will be the 3-282case for the gases referenced; therefore, the staff found that stainless steel in an air/gasenvironment will not result in aging that will be of concern during the period of ext endedoperation. The staff concluded that no AERMs apply for stainless steel components exposed to air or gas environments.In RAI 3.5.2-1, dated September 28, 2005, the staff noted that the applicant listed below-gradeconcrete (foundation, walls) as requiring no AMP in Tables 3.5.2-2, 3.5.2-3, 3.5.2-4, 3.5.2-6,3.5.2-7, 3.5.2-9, 3.5.2-11, 3.5.2-12, 3.5.2-13, 3.5.2-15, 3.5.2-16, and 3.5.2-17. The applicantstated that an AMP is not required to manage aging because, as described in Note 501, plant documents confirm that the concrete had an air content between 3 and 6 percent andinspections performed on concrete in accessible areas did not exhibit degradation related to freeze-thaw. The staff noted that the GALL Report recommends that concrete have awater-to-cement ratio of 0.35:0.45 to ensure no aging degradation related to freeze-thaw;therefore, the staff requested that the applicant verify the water-to-cement ratio or provide anappropriate AMP if the ratio does not meet the GALL Report recommendation. The staff raised the same question for below-grade concrete (foundations, walls, lean concrete) listed in Table 3.5.2-8.In its response, by letter dated October 28, 2005, the applicant stated the following:Note:  This response applies to Tables 3.5.2-2, 3.5.2-3, 3.5.2-4, 3.5.2-6, 3.5.2-7,3.5.2-8, 3.5.2-9, 3.5.2-10, 3.5.2-11, 3.5.2-12, 3.5.2-14, 3.5.2-15, 3.5.2-16,3.5.2-17 and 3.5.2-18 but is not applicable to Table 3.5.2-13 (i.e. not applicablesince there is no below grade concrete inside drywell).The criteria used to evaluate concrete located below grade were consistent withNRC Staff final position issued for Interim Staff Guidance (ISG)-03 (see LRASection 2.1.4.3). ISG-03 provided the following criteria for the aging effects loss of material (spalling, scaling) and cracking due to freeze-thaw for concrete in inaccessible areas (i.e. exterior locations below grade and foundations).'Inaccessible Areas:
Evaluation is needed for plants that are located in moderate to severeweathering conditions (weathering index>100 day-inch/yr) (NUREG-1557).Documented evidence to confirm that the in-place concrete had the air content between 3 percent to 6 percent and the subsequent inspectionsperformed did not exhibit degradations related to freeze-thaw should be considered a part of the evaluation.'LRA Note 501 and Table 1, item 3.5.1-20, and further evaluation for 3.5.2.2.2.1included the following statement.'MNGP is located in a severe weathering region according to Figure 1 ofASTM C33-90, and therefore freeze-thaw evaluation is required. Plant documents confirm that the concrete had an air content between 3 percentand 6 percent, and subsequent inspections performed on concrete in accessible areas did not exhibit degradation related to freeze-thaw. This evaluation satisfies NUREG-1801 and ISG-03 condition requirements for 3-283concrete in inaccessible areas, and therefore loss of material and crackingdue to freeze-thaw do not require aging management.'All criteria of ISG-03 have been satisfied including an aging effect evaluation dueto severe weather location, documentation confirming that the concrete had anair content between 3 percent and 6 percent, and plant inspection findings thatdid not exhibit degradation related to freeze-thaw.Additionally, ISG-03 was one of five ISG guidance documents issued forimplementation by the NRC prior to the LRA submittal. Under this guidance, theStaff removed the water-to-cement ratio and replaced it with the statement,
'subsequent inspections performed did not exhibit degradations related to freeze-thaw'. This substitution is consistent with ACI 318, DurabilityRequirements that state, 'Since it is difficult to accurately determine the water-cementitious materials ratio of concrete during production, the f'c specified should be reasonably consistent with the water-cementitious materials ratio required for durability. Selection of an f'c that is consistent with thewater-cementitious ratio selected for durability will help ensure that the requiredwater-cementitious materials ratio is actually obtained in the field.' ACI 318 also states that the quality and production of concrete must be considered. At MNGP, all in place concrete met or exceeded the design required strength (f'c).
Concrete inspections continue to show no evidence of degradation due to freeze-thaw. Plant concrete design specifications (Specification for Purchase of Off-Site Concrete for the MNGP, Specification for Forming, Placing, Finishing and Curing of Concrete, and Specification for Materials Testing Services, etc.)
include requirements that satisfy ACI 318 standards for materials, durability,concrete quality, mixing, and placing. Plant documents confirm that the concretewas constructed in accordance with the recommendations in ACI 201.2R for durability and therefore able to resist freeze-thaw and other age relateddegradation. Materials used in the concrete mix design conformed to ASTM specifications (C-94, C-150, etc.) that ensured consistent, proportional,non-porous concrete of quality materials. Aggregates conformed to the requirements of ASTM C-33 and were accepted based on ASTM C-295 (petrographic) C-289 (reactivity) and other tests. Mixing and delivering of concrete was in accordance with ACI standards for hot and cold weather conditions (ACI 305, ACI 306) and appropriate air entrainment, adequate curing, and special attention to construction practices were maintained with reference to ASTM C-260, C-494 and C-618. Utilizing industry construction standardsensured good workmanship and quality control practices (i.e., the requirements of ACI 304, 308, 309, ASTM C-94, etc.).Compliance with the above industry code requirements and guidelines ensuresthat freeze-thaw is not significant as proven by the absence of freeze-thawdegradation.The staff's review found the applicant's response to RAI 3.5.2-1 acceptable. The staff foundthat the applicant provided sufficient information to conclude that its below-grade concrete willnot require an AMP for loss of material due to the freeze-thaw aging mechanism; therefore, the staff's concern described in RAI 3.5.2-1 is resolved.
3-284In RAI 3.5.2-2, dated September 28, 2005, the staff noted that the applicant listed below-gradeconcrete (foundation, walls) as requiring no AMP in Tables 3.5.2-3, 3.5.2-4, 3.5.2-6, 3.5.2-7,3.5.2-9, 3.5.2-11, 3.5.2-12, 3.5.2-13, 3.5.2-15, 3.5.2-16, and 3.5.2-17. The applicant stated thatno AMP is required to manage aging because, as described in Note 506, (1) the plant initial licensing basis did not include a program to monitor settlement, (2) no significant settlement has been observed, and (3) de-watering systems are not used. The applicant's statement isinconsistent with ISG-03, which requires a "Structural Monitoring Program" based on the requirement of 10 CFR 50.65 (Maintenance Rule) for accessible areas and a "plant-specific program for inaccessible areas." Therefore, the staff requested that the applicant provide anappropriate AMP for this component group and below-grade concrete (foundation, walls, lean concrete) listed in Table 3.5.2-8.In its response, by letter dated October 28, 2005, the applicant stated the following:Note:  This response applies to Tables 3.5.2-3, 3.5.2-4, 3.5.2-6, 3.5.2-7, 3.5.2-8,3.5.2-9, 3.5.2-10, 3.5.2-11, 3.5.2-12, 3.5.2-14, 3.5.2-15, 3.5.2-16, 3.5.2-17 and3.5.2-18 but is not applicable to Table 3.5.2-13 (i.e. not applicable since there isno below grade concrete inside drywell).ISG-03 did not include an evaluation for the aging effects cracks, distortion, andincrease in component stress level due to settlement and therefore NUREG-1801 (2001) was used to evaluate the plant specific applicability of thisaging effect. Settlement is a condition that directly affects the concrete foundation components (see NUREG-1557 page B-154 and Electric PowerResearch Institute (EPRI) 103842 page 4-88), and thus applicable to inaccessible concrete. NUREG-1801 (2001) states that,'The initial Licensing Basis for some plants included a program to monitorsettlement. If no settlement was evident during the first decade or so, the NRC may have given the licensee approval to discontinue the program.However, if a de-wateri ng system is relied upon for control of settlement,then the licensee is to ensure proper functioning of the de-watering systemthrough the period of extended operation.'LRA Note 506, Table 3.5.1 item number 3.5.1-25, and further evaluation3.5.2.2.1.2 included the following statement.'The plant initial Licensing Basis did not include a program to monitorsettlement. No significant settlement has been observed on any major structure and de-watering systems are not used. This satisfies NUREG-1801condition requirements on concrete settlement, and therefore cracks,distortion, and increase in component stress levels due to settlement do not require aging management.'The NUREG-1801 criteria used to evaluate concrete for settlement consists ofan initial Licensing Basis program to monitoring settlement, evident of settlement during the first decade, and a de-watering system relied upon for settlementcontrol. All are not applicable to the MNGP. The initial licensing basis did not include a settlement monitoring program, no significant settlement has ever been 3-285observed on any major structure, and de-watering systems were not used (seediscussion on the Diesel Fuel Oil Transfer House that follows).Additionally, the MNGP USAR, Section 12.2.1.11 includes a discussion onfoundation design and construction. The USAR provides conclusions on foundation designs based on soil bearing values. Major building structures were constructed on bedrock, compacted granular fill, or stiff clay. No unusual orunforeseen foundation construction problems were encountered. A survey traverse of points on the buildings was established to monitor foundation settlement. This survey determined that settlement was uniform and within the predicted values. The reactor building, the turbine building and other structures are supported on mat foundations. The stack and control and cable spreading building are also on mat foundations, and the emergency diesel generator building is constructed on a continuous footing foundation. The emergency filtration train building rests on a combination of mat and caisson foundations.The MNGP review is consistent with NUREG-1801 condition requirements forsettlement, similar to the review performed in the Dresden and Quad Cities Safety Evaluation Report (SER), NUREG-1796. NUREG-1796 stated that, 'noaging management is required' and the Staff responded with, 'The Staff finds the applicant's explanation to be acceptable because there has been no requirement to monitor settlement as part of the licensing basis for all four units, and there are no de-watering systems in place.'Although not managed for cracks, distortion, and increase in component stresslevel due to settlement (except for the Diesel Fuel Oil Transfer House, see below), all accessible concrete is managed for aging effects including cracks,loss of material, etc. Additionally, whenever an inaccessible area is excavated, exposed or modified, an inspection is performed.As stated above, settlement has not been observed at any major structures. TheDiesel Fuel Oil Transfer House, a small structure north of the Emergency Diesel Generator Building has experienced settlement. The structure is rectangular with external dimensions of 11'-6" (N-S) x 14' (E-W) x 13'-6" high. Walls are 1'-6" thick. It is a moderate weight structure exerting a mean bearing pressure of about 1,100 lb. / ft.
2 on the underlying foundation material. The foundationmaterial is compacted granular backf ill underlain by stiff clay lenses andsandstone bedrock, and should not be susceptible to settlement under the load imposed. However the Diesel Fuel Oil Transfer House has undergone significant differential settlement. Based on plant records and settlement data, settlement of the Diesel Fuel Oil Transfer House occurred rather rapidly following construction and was probably due to washout after a rainstorm and was long ago effectively complete. Settlement data recorded annually since 1992 continues to show no significant settlement of the structure. A Nonconformance Report root cause analysis concluded there was insufficient foundation support to prevent settling.
Measurements taken in 1976, 1979 and 1991 show settlement has continued over the years since construction but at an extremely low rate. Surveys determined that the entire building has settled about 3/4" to 1" on the east sideand about 5 1/4" to 5 1/2" on the west side. No evidence of cracks or distortion has 3-286been observed by the Structures Monitoring Program inspections performed in1996 and 2002. The Diesel Fuel Oil Transfer House is monitored for the aging effects of cracks, distortion, and increase in component stress level due tosettlement now on an annual basis as part of the Structures Monitoring Program
 
and will be managed throughout the period of extended operation.In conclusion, cracks, distortion, and increase in component stress level due tosettlement is not an applicable aging mechanism for any in scope structure with the exception of the Diesel Fuel Oil Transfer House which is managed for aging effects due to settlement.The staff's review found the applicant's response to RAI 3.5.2-2 acceptable. The applicantprovided sufficient information to justify that, except for the diesel fuel oil transfer house, which is managed for aging effects due to settlement, other building structures need no management for aging effects due to settlement. The staff found the applicant's statement reasonable and acceptable regarding its management of all accessible concrete for aging effects, including cracks and loss of material, and its inspection of inaccessible areas whenever they areexcavated, exposed, or modified; therefore, the staff's concern described in RAI 3.5.2-2 isresolved.The staff's audit and review of the applicant's program found that the applicant demonstratedthat the aging effects will be adequately managed so that the intended functions will bemaintained during the period of extended operation as required by 10 CFR 54.21(a)(3).3.5.2.3.1Structures and Component Supports-Cranes, Heavy Loads, Rigging-Summary ofAging Management Evaluation-Table 3.5.2-1The staff reviewed LRA Table 3.5.2-1, which summarizes the results of AMR evaluations for thecranes, heavy loads, and rigging component groups.All line items in this table are consistent with the GALL Report or are included in the discussionin Section 3.5.2.3 above.3.5.2.3.2Structures and Component Supports-Diesel Fuel Oil Transfer House-Summary ofAging Management Evaluation-Table 3.5.2-2The staff reviewed LRA Table 3.5.2-2, which summarizes the results of AMR evaluations for thediesel fuel oil transfer house component groups.All line items in this table are consistent with the GALL Report or are included in the discussionin Section 3.5.2.3 above.3.5.2.3.3Structures and Component Supports-Emergency Diesel GeneratorBuilding-Summary of Aging Management Evaluation-Table 3.5.2-3The staff reviewed LRA Table 3.5.2-3, which summarizes the results of AMR evaluations for theEDG building component groups.
3-287All line items in this table are consistent with the GALL Report or are included in the discussionin Section 3.5.2.3 above.3.5.2.3.4Structures and Component Supports-Emergency Filtration TrainBuilding-Summary of Aging Management Evaluation-Table 3.5.2-4The staff reviewed LRA Table 3.5.2-4, which summarizes the results of AMR evaluations for theemergency filtration train building component groups.All line items in this table are consistent with the GALL Report or are included in the discussionin Section 3.5.2.3 above.3.5.2.3.5Structures and Component Supports-Fire Protection Barrier-Summary of AgingManagement Evaluation-Table 3.5.2-5The staff reviewed LRA Table 3.5.2-5, which summarizes the results of AMR evaluations for theFP barrier commodity groups.The staff also reviewed LRA Section 3.5.2.1.5, which identified the materials, environments,AERMs, and AMPs for the FP barrier commodity group. The staff conducted its review, described below, in accordance with SRP-LR Section 3.5 and the GALL Report.The staff's review of LRA Table 3.5.2-5 identified areas for which it needed additionalinformation to complete its evaluation of the applicant's results. The applicant responded to the staff's RAIs as discussed below.In RAI 3.5.2.1.5-1, dated August 18, 2005, the staff noted that LRA Table 3.5.2-5 refers to theFire Protection Program as the AMP to manage loss of material for carbon steel in air/gas.
Therefore, the staff requested that the applicant justify this conclusion.In its response, by letter dated September 16, 2005, the applicant stated that LRA Table 3.5.2-5refers to the Fire Protection Program as the AMP for carbon steel with a fire barrier intended function in an air/gas environment. The scope of the program described in Fire Protection Program PBD/AMP-013, Table 7.1, includes fire barriers with specific reference to carbon steel with an aging effect of loss of material in a plant indoor air environment (i.e., air/gas environment). This description is consistent with LRA Table 3.5.2-5.The staff's review found the applicant's response to RAI 3.5.2.1.5-1 acceptable because thescope of the Fire Protection Program includes fire barriers with specific reference to carbon steel with an aging effect of loss of material in a plant indoor air environment, as described in Fire Protection Program PBD/AMP-013, Table 7.1. The staff's review of the applicant's Fire Protection Program, including Table 7.1 of PBD/AMP-013, found that it provides reasonable assurance that carbon steel components in an air/gas environment in the FP system will bemanaged for aging effects during the period of extended operation. Therefore, the staff'sconcern described in RAI 3.5.2.1.5-1 is resolved.In RAI 3.5.2.1.5-2, dated August 18, 2005, the staff noted that LRA Tables 3.5.2-5, 3.5.2-15,and 3.5.2-17 refer to the Fire Protection Program as the AMP for fibrous fire wraps (thermal insulating wool/fiber), cementitious fireproofing (thermal insulating mastic), and rigid board 3-288(thermal insulating board) in air/gas; therefore, the staff requested that the applicant justify thisconclusion.In its response, by letter dated September 16, 2005, the applicant stated that LRATables 3.5.2-5, 3.5.2-15, and 3.5.2-17 refer to the Fire Protection Program as the AMP formanaging aging effects for fibrous fire wraps, cementitious fireproofing, and rigid board with a fire barrier intended function in an air/gas environment. The scope of the Fire Protection Program, as described in Fire Protection Program PBD/AMP-013, Table 7.1, includes fire barriers with specific reference to fibrous fire wraps, cementitious fireproofing, and rigid board with the aging effects of cracking, delamination, and loss of material in an air/gas environment.
This description is consistent with LRA Tables 3.5.2-5, 3.5.2-15, and 3.5.2-17.The staff's review found the applicant's response to RAI 3.5.2.1.5-2 acceptable because thescope of the Fire Protection Program includes fire barriers with specific reference to fibrous fire wraps, cementitious fireproofing, and rigid board with the aging effects of cracking, delamination, and loss of material in an air/gas environment, as described in Fire Protection Program PBD/AMP-013, Table 7.1. The staff's review of the applicant's Fire Protection Program, including PBD/AMP-013, Table 7.1, found that it provides reasonable assurance thatfibrous fire wraps, cementitious fireproofing, and rigid board in an air/gas environment in the FP system will be managed for aging effects during the period of extended operation. Therefore,the staff's concern described in RAI 3.5.2.1.5-2 is resolved.The staff's review of the applicant's programs, the aging effects, and the plant-specific andindustry operating experience determined that the applicant adequately identified applicableaging effects and the AMPs credited with managing them for the fire barrier commodity group not addressed by the GALL Report. The staff found the applicant's AMR results for the fire barrier commodity group acceptable.3.5.2.3.6Structures and Component Supports-Hangers and Supports-Summary of AgingManagement Evaluation-Table 3.5.2-6The staff reviewed LRA Table 3.5.2-6, which summarizes the results of AMR evaluations for thehangers and supports commodity groups.The applicant proposed to manage loss of material due to MIC, pitting, and crevice corrosion ofstainless steel materials for supports for ASME Code Class MC components (i.e., vent header column support pins exposed to treated water environment) using the ASME Section XI, Subsection IWF Program.SER Section 3.0.3.2.3 documents the staff's review of the ASME Section XI, Subsection IWFProgram. The ASME Section XI, Subsection IWF Program is part of the ASME Section XI In-Service Inspection Program. It provides for condition monitoring of Class 1, 2, 3, and MC component supports. The applicant will enhance it to inspect Class MC component supportsconsistent with the GALL Report, Chapter III, Section B1.3. The parameters monitored orinspected are loss of material and loss of mechanical function. The NDE technique used is the VT-3 method to detect unacceptable conditions such as loss of material and loss of mechanical function.
3-289In RAI 3.5.2-3, dated September 28, 2005, the staff noted that the Table 3.5.2-6 lists below-grade concrete (diesel fuel oil storage tank deadmen) as requiring no AMP. The applicant stated that no AMP is required to manage aging because, as described in Note 552, "NUREG-1801 lists inside or outside containment as the environment. Consider that thisenvironment includes atmosphere/weather and below grade." The applicant's statement isinconsistent with ISG-03, which requires a "Structural Monitoring Program" based on the requirement of 10 CFR 50.65 (Maintenance Rule) for accessible areas and a "plant-specific program for inaccessible areas." Therefore, the staff requested that the applicant provide anappropriate AMP for this component group.In its response, by letter dated October 28, 2005, the applicant stated the following:The buried Diesel Fuel Oil Storage Tank is anchored to a concrete foundation.To account for this condition, NUREG-1801 line item III.B4.3-a, 'buildingconcrete at locations of expansion and grouted anchors' was used. Although probably not the best usage of line III.B4.3-a, it was chosen to address thisunique condition. Note 552 was provided to clarify the different environment used than that specified in NUREG-1801 (i.e., below grade rather than theNUREG-1801 environment, inside or outside containment). The LRA AMP alsodiffered from that specified in NUREG-1801. Generic Note 'I' was used todescribe these differences since it was considered the 'best' note available to describe this unique condition. The aging effect, 'reduction in concrete anchor capacity due to local degradation' for the inaccessible location was evaluated by considering all possible concrete degradation mechanisms including freeze-thaw (III.A3.1-a), leaching of calcium hydroxide (III.A3.1-b), reaction with aggregate (III.A3.1-c), corrosion of embedded steel (III.A3.1-e), aggressivechemical attack (III.A3.1-g), settlement (III.A3.1-h), and erosion of porousconcrete sub-foundations (III.A3.1-h). The evaluation concluded that thesemechanisms did not require aging management (see page 3-686 of the LRA).
Service induced cracking was also not applicable since vibration/movement of the tank is not expected and the fact that the tank is surrounded by soil/fillmaterial. Therefore reduction in concrete anchor capacity due to local degradation was determined insignificant and aging management not required.The staff's review found the applicant's response to RAI 3.5.2-3 acceptable. The applicant'sresponse stated that it had evaluated all the possible aging mechanisms/effects and concluded that they did not require an AMP. The staff found the applicant's conclusion reasonable andacceptable; therefore, the staff's concern described in RAI 3.5.2-3 is resolved.In RAI 3.5.2-7, dated September 28, 2005, the staff noted that Table 3.5.2-6 identifies two lineitems related to carbon steel and low-alloy steel embedded in concrete as not requiring aging management. Note 549 states, "Requirements specified in NUREG-1801 for concrete quality,inspections, and housekeeping are satisfied for steel elements in inaccessible areas." Based on the industry-wide experience related to corrosion of the drywell shell in the sand pocket region, the staff requested that the applicant provide information regarding its inspections andhousekeeping related to carbon steel and low-alloy steel embedded in concrete and explain why these activities should not be a part of an existing AMP. The embedded items are included in an existing program to look for evidence of environment change (e.g., sand drains not 3-290working properly) in accessible areas that will indicate potential degradation in inaccessibleareas.The same question applied to carbon steel and low-alloy steel embedded in concrete listed inTable 3.5.2-13.In its response, by letter dated October 28, 2005, the applicant stated the following:Components in Table 3.5.2-6 refer to the embedded anchorage of the drywellsupport skirt, the embedded components of the female stabilizers, andembedded conduit. The evaluation of the embedded portions of the drywell shell and drywell support skirt is provided in Table 3.5.2-13.The applicant deliberated how these components meet the following four recommendations inGALL Report line item II.B1.1.1-a:  (224)Concrete meeting the requirements of ACI 318 or 349 and theguidance of ACI 201.2R was used for the containment concrete in contact with the embedded containment shell or liner.  (225)The concrete is monitored to ensure that it is free of penetratingcracks that provide a path for water seepage to the surface of thecontainment shell or liner.  (226)The moisture barrier, at the junction where the shell or linerbecomes embedded, is subject to aging management activities in accordance with IWE requirements.  (227)Borated water spills and water ponding on the containmentconcrete floor are not common and when detected are cleaned up in a timely manner.The applicant provided the following plant-specific evaluation:  (228)Concrete meeting the following requirements was used for thecontainment concrete in contact with the embedded containment shell and skirt. The MNGP concrete design specifications for Purchase of Off-Site Concrete for the MNGP, Specification for Forming, Placing, Finishing and Curing of Concrete, Specification for Materials Testing Services and others specifications include requirements that satisfy ACI 318 standards for materials, durability, concrete quality, mixing and placing. Plant documentsconfirm that the concrete was constructed in accordance with the recommendations in ACI 201.2R for durability and therefore ableto resist weathering action, chemical attack, abrasion, leaching of calcium hydroxide, corrosion of reinforcement, and chemical reactions of aggregates. Materials used in the concrete mix design conformed to ASTM specifications (C-94, C-150, etc.) that ensure consistent, proportional, non-porous concrete of quality materials. Aggregates conformed to the requirements of ASTM C-33 and were accepted based on ASTM C-295 (petrographic)
C-289 (reactivity) and other tests. Mixing and delivering of 3-291concrete was in accordance with ACI standards for hot and coldweather conditions (ACI 305, ACI 306) and appropriate air entrainment, adequate curing, and special attention to construction practices were maintained (ASTM C-260, C-494 and C-618). MNGP construction specifications ensure good workmanship and quality control practices (ACI 304, 308, 309, ASTM C-94, etc.).  (229)For accessible concrete inside drywell, the Structures MonitoringProgram inspects for cracking adjacent to the moisture barrier, at the concrete floor, and RPV Pedestal. Inspections ensure that the concrete is free of penetrating cra cks that provide a path for waterseepage to the containment shell. The bioshield wall is completely encased in steel and therefore inaccessible for inspection.AMPs will be used to manage the drywell to reactor building refueling sealbellows assembly located between the drywell outer shell and the reactor building concrete (See Table 3.5.2-15). By managing this assembly for aging degradation and water leakage (during refueling activities), any water seepage past the assembly to the drywell shell, sand pocket, embedded shell, and embedded skirt will be prevented, or detected and corrected. Therefore, loss ofmaterial due to corrosion for these components will be insignificant. Agingmanaged for the drywell to reactor building refueling seal bellows assembly willbe provided by the Primary Containment In-Service Inspection Program and the Structures Monitoring Program. These Programs ensure that degradation of the assembly or any water leakage past the assembly will be detected andcorrected before loss of intended function. These programs ensure that,  - the drywell air gap drain outlets and sand pocket drain outlets are notobstructed prior to refueling  - the drain lines that are incorporated into the refueling bellows assemblyare monitored for leaks  - the drywell air gap drain outlets and drywell sand pocket drain outletsare inspected for signs of leakage during refueling, and  - aging effects including loss of material are detected.The Plant Chemistry Program is also used to manage the assembly byensuring that the water chemistry remains within design parameters.MNGP operating history showed no evidence of refueling seal leakage, nowater observed in air gap during construction, and no water used to extinguish a fire in the air gap or for any other reason. Plant engineering and maintenance personnel confirmed the absence of leakage at the drywell air gap drains, and the sand pocket drains. Plant specific operating history has proven that inspection and monitoring activities adequately manage aging effects to ensure no loss of intended function.The applicant further asserted that the Primary Containment In-Service Inspection Programmanages aging effects associated with the moisture barrier and that borated water inside the 3-292drywell is not a concern for BWR plants. With these assertions, the applicant pointed out thatloss of material due to corrosion is not significant.The staff evaluated the information provided above, and the information provided to the NRC'saging management inspection team on the status of the drywell shell, and made the followingfindings:
* The operating history confirmed that there is no indication of water in the air gapbetween the shell and the shield concrete.
* The UT measurements taken, in mid-1986 and at the end of 1987, indicate that themetal thickness in the sand pocket region varies from 1.065 inches to 1.13 inches, and the design thickness in this area of the drywell shell is 1.0 inch.
* In response to NRC GL 87-05, "Request for Additional Information Assessment ofLicensee Measures to Mitigate and/or Identify Potential Degradation of Mark I Drywells,"
the applicant made sure that the three drain paths (i.e., the drain that would preventpotential leakages from refueling seal areas, the drains at the sand pocket areas above the sealed sand pocket area, and the drains at the bottom of the sand pocket area) are clear of any obstruction. The applicant has been monitoring these drains and plans to continue the practice during the period of extended operation.
* The entire refueling seal area is within the scope of license renewal.
* During the 1987 visual examination, some surface corrosion was noted where theconcrete floor meets the inside surface of the drywell shell. This was attributed to the joint sealant used during initial construction. The sealant was removed and replaced with nonshrink grout and a new type of sealant that would prevent corrosion. The applicant will periodically examine this area as required by Subsection IWE of Section XIof the ASME Code.Based on the above findings, the staff concluded that MNGP will adequately manage theinaccessible areas of the drywell shell during the period of extended operation, and the concernexpressed in RAI 3.5.2-7 is resolved.In RAI 3.5.2-8, dated September 28, 2005, the staff noted that recent experience with toruscracking at Fitzpatrick indicates HPC discharge configuration in the torus as a cause of cracking; therefore, the staff requested that the applicant describe its HPC configuration thatcould affect torus integrity during the period of extended operation.In its response, by letter dated October 28, 2005, the applicant stated the following:The HPCI turbine exhaust discharge pipe configuration at MNGP is significantlydifferent than that at Fitzpatrick.  - The HPCI turbine exhaust at Fitzpatrick is located near the torus ringgirder (end bay) while the MNGP HPCI turbine exhaust is located approximately mid-bay between torus ring girders  - The Fitzpatrick HPCI exhaust pipe incorporates a 90 degree elbow, isrelatively short with no holes, and discharges vertically in the vicinity of the torus ring girder and stiffener plates that are part of the torus external 3-293column support system. The Fitzpatrick torus crack was observedadjacent to these stiffener plates. The MNGP exhaust pipe is considerably longer with a submerged sparger that consist of a pipe, capped at one end, with a large number of holes in the lower portion which increases the area available for steam condensation compared to a straight pipe discharge. The MNGP pipe is not a vertical run, but instead, incorporates a 60 degree elbow.Based on the above comparison, the HPCI Turbine Exhaust configuration andlocation at MNGP is unlike that at Fitzpatrick. The MNGP pipe configuration and location are believed to be less susceptible to cracking and therefore less likely to affect torus integrity during the period of extended operation.The staff's review found the applicant's response to RAI 3.5.2-8 acceptable. Based on thereview of the root cause analysis of the through-wall crack at Fitzpatrick, the configuration ofHPC steam discharge (using spargers), and the location of HPC exhaust pipe, the staff found the applicant's torus is not prone to such cracking. Therefore, the staff's concern described in RAI 3.5.2-8 is resolved.In RAI 3.5.2-9, dated September 28, 2005, the staff noted that three line items in Table 3.5.2-6indicate that lubrite plates have been used at several locations in hangers and supports. The staff's position is that an inspection of the accessible portion of the lubrite bearing is needed to ensure proper functioning during postulated environmental conditions; therefore, the staff requested that the applicant incorporate an examination of the accessible portion of the lubritebearings in an appropriate AMP.In its response, by letter dated October 28, 2005, the applicant stated the following:Industry guidance provided in EPRI-1002950, Aging Effects for Structures andStructural Components, Revision 1 dated August 2003 for lubrite or similar material states that, 'An extensive search of industry operating experience did not identify any instances of lubrite plate degradation or failure to perform its intended function.' Additionally EPRI states that, 'Lubrite material resists deformation, has a low coefficient of friction, resists softening at elevated temperatures, absorbs grit and abrasive particles, is not susceptible to corrosion, withstands high intensities of radiation, and will not score or mar. Lubriteproducts are solid, permanent, completely self lubricating, and require no maintenance for the design life of the product. The lubrite lubricants used in nuclear applications are designed specifically for the environments to which they are exposed.'Review of the MNGP pipe support and MC component support drawings whereLubrite or similar material was used reveals that the sliding surfaces are sandwiched between plates, and therefore, inaccessible for inspection. Plant specific operating experience found no evidence of age-related degradation for Lubrite or similar material during support overhaul activities, and no pipe or pipe support failures attributed to the inability of sliding surface material to function asdesigned.
3-294However, the applicant stated that aging effects for lubrite or similar materials are notsignificant, and although no aging management is required, the ASME Section XI, Subsection IWF Program inspects the supports in LRA Table 3.5.2-6 incorporating the use of lubrite or similar materials.The staff's review found the applicant's response to RAI 3.5.2-9 acceptable. The staffrecognized the operating experience with the use of lubrite bearings and found the applicant's approach to inspect them under its ASME Section XI, Subsection IWF program acceptable.
Therefore, the staff's concern described in RAI 3.5.2-9 is resolved.On the basis of its review of the applicant's programs, aging effects, and plant-specific andindustry operating experience, the staff determined that the ASME Section XI, Subsection IWFProgram effectively manages the loss of material due to MIC, pitting, and crevice corrosion of stainless steel materials for supports for ASME Code Class MC components (i.e., vent header column support pins exposed to treated water environment), as given in LRA Table 3.5.2-6.3.5.2.3.7Structures and Component Supports-HPC Building-Summary of AgingManagement Evaluation-Table 3.5.2-7The staff reviewed LRA Table 3.5.2-7, which summarizes the results of AMR evaluations for theHPC building component groups.All line items in this table are consistent with the GALL Report or are included in the discussionin Section 3.5.2.3 above.3.5.2.3.8Structures and Component Supports-Intake Structure-Summary of AgingManagement Evaluation-Table 3.5.2-8The staff reviewed LRA Table 3.5.2-8, which summarizes the results of AMR evaluations for theintake structure component groups.All line items in this table are consistent with the GALL Report or are included in the discussionin Section 3.5.2.3 above.3.5.2.3.9Structures and Component Supports-Miscellaneous Station Blackout YardStructures-Summary of Aging Management Evaluation-Table 3.5.2-9The staff reviewed LRA Table 3.5.2-9, which summarizes the results of AMR evaluations for themiscellaneous SBO yard structures component groups.All line items in this table are consistent with the GALL Report or are included in the discussionin Section 3.5.2.3 above.3.5.2.3.10Structures and Component Supports-Offgas Stack-Summary of AgingManagement Evaluation-Table 3.5.2-10The staff reviewed LRA Table 3.5.2-10, which summarizes the results of AMR evaluations forthe offgas stack component groups.
3-295In RAI 3.5.2-4, dated September 28, 2005, the staff noted that Table 3.5.2-10 lists below-gradeconcrete (Pedestal) as requiring no AMP. The applicant stated that no AMP is required to manage aging because, as described in Notes 501 and 506, (1) the plant initial licensing basis did not include a program to monitor settlement, (2) no significant settlement has been observed, (3) de-watering systems are not used, and (4) plant documents confirm that theconcrete had an air content between 3 and 6 percent and inspection of concrete in accessible areas found no degradation related to freeze-thaw. The GALL Report recommends that concrete should have a water-to-cement ratio of 0.35-0.45 to ensure no aging degradation related to freeze-thaw; therefore, the staff requested that the applicant verify thewater-to-cement ratio as 0.35-0.45. The staff noted that the applicant's statement isinconsistent with ISG-03, which requires a "Structural Monitoring Program" based on the requirement of 10 CFR 50.65 (Maintenance Rule) for accessible areas and a "plant-specific program for inaccessible areas." The staff raised the same question for below-grade concrete (foundation, walls, slabs, grout) listed in Table 3.5.2-18.In its response, by letter dated October 28, 2005, the applicant stated that the responses toRAIs 3.5.2-1 and 3.5.2-2 are applicable to this question. The staff's review found the applicant'sresponse to RAI 3.5.2-4 acceptable. The staff's evaluation of these responses is described inSER Section 3.5.2.3. Therefore, the staff's concern described in RAI 3.5.2-4 is resolved.3.5.2.3.11Structures and Component Supports-Offgas Storage and CompressorBuilding-Summary of Aging Management Evaluation-Table 3.5.2-11The staff reviewed LRA Table 3.5.2-11, which summarizes the results of AMR evaluations forthe offgas storage and compressor building component groups.All line items in this table are consistent with the GALL Report or are included in the discussionin Section 3.5.2.3 above.3.5.2.3.12Structures and Component Supports-Plant Control and Cable SpreadingStructure-Summary of Aging Management Evaluation-Table 3.5.2-12The staff reviewed LRA Table 3.5.2-12, which summarizes the results of AMR evaluations forthe plant control and cable spreading structure component groups.All line items in this table are consistent with the GALL Report or are included in the discussionin Section 3.5.2.3 above.3.5.2.3.13Structures and Component Supports-Primary Containment-Summary of AgingManagement Evaluation-Table 3.5.2-13The staff reviewed LRA Table 3.5.2-13, which summarizes the results of AMR evaluations forthe primary containment component groups.The applicant proposed to manage loss of material due to MIC, pitting, and crevice corrosion ofstainless steel materials for thermowells exposed to a treated water environment using the Plant Chemistry, Primary Containment In-Service Inspection, and 10 CFR Part 50, Appendix J Programs.
3-296The SER documents the staff's reviews and evaluations of the Plant Chemistry Program, thePrimary Containment In-Service Inspection Program, and the 10 CFR 50, Appendix J Program in Sections 3.0.3.2.19, 3.0.3.1.6, and 3.0.3.2.1, respectively.Pitting of stainless steel components relates primarily to the presence of detrimental ionicspecies like chlorides, fluorides, and sulfates. Crevice corrosion of stainless steel components relates primarily to the presence of significant levels of dissolved oxygen. The Plant Chemistry Program manages these aging effects by ensuring that corrosive ion concentrations do not exceed acceptance limits and that pH remains within an acceptable range. In addition, this program controls the growth of organic substances, thus eliminating MIC.The Primary Containment In-Service Inspection Program specifies visual examination ofaccessible surfaces on the containment pressure-retaining boundary, internal vent system , andsteel components within the torus to detect indications of damage or deterioration that could adversely affect the intended functions of the containment system.The 10 CFR 50, Appendix J Program specifies pneumatic pressure tests and visualexaminations to verify the structural and leak integrity of the primary containment.In RAI 3.5.2-5, dated September 28, 2005, the staff noted that, in describing the intendedfunctions of the three items in Table 3.5.2-13 related to concrete in air/gas, the applicant statedthat one of the intended functions is "non-safety support." Therefore, the staff requested thatthe applicant clarify this characterization in terms of the CLB safety classification as well as in terms of the criteria in 10 CFR 54.4, "Scope," and provide examples of how the components provide nonsafety support.In its response, by letter dated October 28, 2005, the applicant explained:The primary containment in scope concrete components subject to an AMR withthe intended function, 'non-safety support' were identified in Table 2.4.13-1 with AMR results provided in Table 3.5.2-13. Table 2.1-1 of the LRA included the definition as,'Provide structural support to non-safety related components whose failurecould prevent satisfactory accomplishment of any of the required safety related functions.'This component-level intended function was the specific function of thecomponent that suppor ted system-level functions that formed the basis forincluding the primary containment structure within the scope of license renewal.
The scoping methodology utilized by the NMC for the MNGP was consistent withthe guidance provided by the NRC in NUREG-1800 and by the industry inNuclear Energy Institute (NEI) 95-10.In terms of the MNGP CLB, this function was characterized in a license renewaltechnical report as,'The MNGP CLB includes a number of topics that identify NSR SSCscredited for preventive or mitigative functions in support of safe shutdown for 3-297special events (e.g., external floods) or whose failure could preventsatisfactory accomplishment of a Scoping Criterion 1 function (e.g.,
Seismic II/I considerations). Based on a review of the CLB, those topics that meet Scoping Criterion 2 are, High Energy Line Break (HELB)...Flooding Events...Missile Hazards...Overhead Handling Systems...Seismic Interaction.'In terms of 10 CFR 54.4, this function was characterized in a technical report forlicense renewal as,'[Non-safety related] NSR SSCs directly connected to Scoping Criterion 1SSCs: The in-scope boundary for license renewal extends into the NSR portion of the piping and supports up to and including the first equivalent anchor beyond the safety/nonsafety interface. For Monticello, the first equivalent anchor is that point beyond which failure of the piping system willnot prevent the satisfactory accomplishment of the Scoping Criterion 1 function of the connected SSCs.NSR structures attached to, or next to, Scoping Criterion 1 structures are inscope for license renewal if their failure could prevent a Scoping Criterion 1 SSC from performing its intended function.NSR SSCs that are not directly connected to Scoping Criterion 1 SSCs: TheNSR SSCs may be in-scope if their failure could prevent the performance of a Scoping Criterion 1 function.'The license renewal technical report included further discussion on NSR SSCsthat are not directly connected to Scoping Criterion 1 SSCs with detailed information on the identification process of spatial interactions, a process to determine which NSR conduits, trays, junction boxes, and lighting fixtures to consider in scope for license renewal, and the process for determining in scope NSR HVAC ducts and supports.An example of how concrete components provide nonsafety support would be anattachment to the concrete of NSR light fixtures or NSR HVAC duct routed near/above scoping Criteria 1 components.The staff's review found the applicant's response to RAI 3.5.2-5 acceptable. The applicantdescribed the scoping process for NSR components (including the components that function assupports). This description is sufficient to explain the nonsafety characterization of the components, and the staff found the scoping process used in this context acceptable.
Therefore, the staff's concern described in RAI 3.5.2-5 is resolved.In RAI 3.5.2-6, dated September 28, 2005, the staff noted that Table 3.5.2-13 lists severalstructural components (e.g., drywell equipment foundation, bioshield wall, RPV pedestal) under the component type concrete in air/gas. LRA Section 3.5.2.2.1.3 and Note 508 describe andjustify the elevated temperatures around the reactor vessel based on the estimated temperatures in the drywell; therefore, the staff requested that the applicant provide (1) asummary description of the cooling system installed to control the temperatures inside the 3-298drywell and (2) the operating experience related to the effectiveness of the cooling system.Relevant to this request, the staff inquired whether the shield wall temperatures or any other parameter monitored will detect malfunctioning of the cooling system.Furthermore, following the discussion of the elevated temperatures in and around the bioshieldwall in LRA Section 3.5.2.2.1.3, the staff agreed that the concrete properties will not be affectedsignificantly if the actual temperatures around the shield wall remain within the estimated limits;however, additional shrinkage and loss of moisture due to radiation could degrade the concrete in the long term. In this context the staff requested that the applicant summarize the results ofthe last two inspections performed for (1) the bioshield wall, (2) RPV pedestal, (3) anchorages of seismic stabilizer frame, and (4) masonry walls (if any) inside the drywell.In its response, by letter dated October 28, 2005, the applicant provided the followingdiscussion:gggggggggg)Drywell fan coolers are used to control temperatures inside thedrywell. USAR Section 5.2 states that, 'The primary containment ventilating and cooling system consists of four air coolers whichcool the atmosphere to below a 135 F bulk average drywelltemperature during normal plant operation. The drywell atmosphere is circulated through the drywell and the air coolers by fans, and the reactor building closed cooling water system isemployed to remove heat from the air coolers.'hhhhhhhhhh)Plant daily operating data confirms that the general areamaximum normal operating temperature inside drywell is below the NUREG-1801 limit of 150 F. Therefore the drywell fan coolershave proven their effectiveness in controlling the drywell air temperature. Plant calculations determined that the biologicalshield wall pipe penetrations were sufficiently designed in size, insulation characteristics, and air gap to limit the local area maximum normal operating temperatures to 179 F, less than theNUREG-1801 threshold local area temperature of 200 F. iiiiiiiiii)Results of the 1996, 1998 and 2002 Periodic Structural InspectionReports found all concrete at the RPV Pedestal to be acceptable with no deficiencies observed. The bioshield wall is complete encased in steel and therefore cannot be inspected. Drywell structural steel components were found acceptable with no deficiencies observed including stabilizerattachment welds to the plated bioshield wall. USAR Section 12 states that the primary function of the bioshield wall is, 'to protect equipment inside the drywell against radiation and thermal effects. The structure is capable of transmitting loads due to seismic and jet forces acting on it.
The biological shield is composed of two steel cylinders interconnected with 27 WF (177 lb/ft) columns and is filled with concrete. Because of theradiation and temperature effects on the concrete only the lower 12 feet of concrete, up to the 959 foot elevation, has been designed as structural concrete capable of resisting forces and shears. Above the 959 foot elevation the two steel cylinders and 27 WF columns are structurally 3-299adequate and the concrete fill has not been considered as adding to thesupport.'The staff's review found the applicant's response to RAI 3.5.2-6 acceptable. The responseadequately describes the temperatures in the drywell and the effectiveness of the coolingsystem in keeping temperatures within the threshold limits. The response also describes thecondition of the vital concrete and structural components in the drywell. The staff found the applicant's method of cooling the drywell atmosphere and monitoring the structural componentsin the drywell acceptable; therefore, the staff's concern described in RAI 3.5.2-6 is resolved.In RAI 3.5.2-10, dated September 28, 2005, the staff noted that a recent breakage ofT-quencher support bolts at the Edwin I. Hatch plant indicated that the Plant ChemistryProgram that controls the chemistry of treated water may not be adequate for managing theaging of submerged support components; therefore, the staff requested that the applicantaddress the adequacy of the Plant Chemistry Program alone to manage the aging degradation of the submerged supports. The staff further noted that this RAI applies to all line items in Table 3.5.2-13 identifying the Plant Chemistry Program as the sole AMP.In its response, by letter dated October 28, 2005, the applicant confirmed the following:All line items in Table 3.5.2-13 in a treated water environment (submerged) aremanaged by the Plant Chemistry Program, in addition to the MNGP Primary Containment In-Service Inspection Program, and in many cases, are also managed by a third program, 10 CFR 50, Appendix J. Therefore, the applicant asserted this RAI is not applicable to MNGP.Additionally, the MNGP Primary Containment In-Service Inspection Programincludes activities that perform periodic visual inspections by divers (when the torus is not drained) and by engineers (when drained) for submerged components, including their support members, bolted connections, and welds.
Components inspected include such items as T-quenchers, SRV piping and supports, ECCS strainers, vent header supports, catwalk supports, and other submerged piping and supports not included in the IWE, VT-3 inspection.
Inspections are conducted periodically at intervals not to exceed five (5) years.
The MNGP Primary Containment In-Service Inspection Program manages aging effects for visible degradation such as deformation, cracks, corrosion, loosebolts, etc.The staff's review found the applicant's response to RAI 3.5.2-10 acceptable. The responseindicates that the applicant plans to use the Primary Containment In-Service InspectionProgram and the 10 CFR Part 50, Appendix J Program, as appropriate, for managing aging of components in these line items. The staff found the applicant's approach to managing the aging of these components acceptable; therefore, the staff's concern described in RAI 3.5.2-10 isresolved.In RAI 3.5.2-11, dated September 28, 2005, the staff noted that for a number of items inTable 3.5.2-13, the applicant identified the 10 CFR Part 50, Appendix J Program as the AMP tomanage aging. Option B of Appendix J will permit the applicant to conduct Type B leakage ratetests of penetrations at 10-year intervals; therefore, the staff requested that the applicant 3-300address the plant-specific process (e.g., test frequency and operating experience) credited withmanaging degradation and leak tightness of the pressure boundary penetrations, including vent bellows.In its response, by letter dated October 28, 2005, the applicant stated the following:Type B tests, which are conducted at performance-based intervals not exceeding120 months (plus an extension of 15 months if required by the refueling schedule), are performed to assess leakage through individual penetration isolation barriers other than valves. Pursuant to NEI 94-01, air lock tests must be performed at intervals not exceeding 30 months and at other times as determined by air lock use. Also, bolted access-way cover seals are always tested following end-of-outage closures of the access-ways. The default interval between Type B tests is 30 months. The interval may be extended to 60 months following two (2) consecutive tests with results that meet performance leakage acceptance criteria and to 120 months following three (3) consecutive tests that meet these criteria. The interval reverts to the default interval following a test failure.The MNGP operating history on bellow leakage/replacement is limited to one,2-ply bellow. Leakage was identified during LLRT and not a result of cracks observed during a visual examination. Leakage was identified at the outer-mostbellows from a small failure underneath the outer collar of the expansion joint and consequently the bellow was replaced. No cracks in the weld metal wereidentified. Industry operating history has also identified cracked bellows, but no cracks in the weld metal.The staff's review found the applicant's response to RAI 3.5.2-11 acceptable. The operatinghistory of the penetrations and vent bellows demonstrates that the applicant applies CLBrequirements for leak-rate testing of these pressure-retaining components; therefore, the stafffound the approach used by the applicant in ensuring the leak tightness of these componentsacceptable, and the staff's concern described in RAI 3.5.2-11 is resolved.In RAI 3.5.2-12, dated September 28, 2005, the staff noted that three line items inTable 3.5.2-13 indicate that lubrite plates had been used at several locations in the primarycontainment. In Note 556, the applicant stated that graphite plate material is not used fordrywell head and downcomers; therefore, the staff requested that the applicant clarify howlubrite plates were used for drywell head and downcomers. In Note 559, the applicant stated that beam seats in the drywell consist of carbon steel plate over a bronze plate lubricated withgraphite packed into trepanned depressions. The steel plate covers the graphite packing and protects it from particulate contaminants. The staff believes that if the lubrite bearing is qualified generally for use in the sustained temperatures and radiation existing in the drywell, the accessible part of the bearing should be inspected to ensure proper functioning during postulated environmental conditions. The staff requested the applicant to incorporate anexamination of the accessible portion of the lubrite bearings in an appropriate AMP.In its response, by letter dated October 28, 2005, the applicant stated the following:
3-301Lubrite type material is not used for the drywell head or downcomers.Table 3.5.2-13 line entry was necessary to demonstrate that aging effects in NUREG-1801 line item II.B1.1.1-e were evaluated. The evaluation provided inTable 3.5.2-13, note 556 stated that, 'The drywell head and downcomer pipesare carbon steel material. Graphite plate material is not used for these components and therefore the aging effect is not applicable.'NUREG-1801 line item II.B1.1.1-e also includes fretting due to mechanical wearof carbon steel. EPRI-1002950, Structural Tools, evaluated fretting as loss of material occurring as a result of the relative motion between two components.
EPRI concluded that thermal cycling during plant heat-up, cool down (refuelingoperations) and normal operation have insufficient relative motion and frequency to result in significant wear. EPRI concluded that wear of carbon steel is a design issue that incorporates sliding surfaces into the design. In accordance with the EPRI evaluation, the drywell head and downcomers do not require aging management for fretting. Note that the drywell head and downcomers are managed for loss of material due to corrosion consistent with NUREG-1801line II.B1.1.1-a. See Table 3.5.2-13 for this evaluation.On the subject of lubrite plates, the applicant explained the following:Lubrite material incorporated into radial beam seat connections is used insidedrywell to connect platform steel to the drywell shell. The beam seat Lubrite plate is sandwiched between larger steel plates which overhang it, and therefore, inspection is not possible. These beam seats are well over 20 feet from the reactor pressure vessel and outside the bioshield wall. This is the only application of Lubrite type material in use inside the drywell where the higher gamma radiation levels are expected. According to EPRI-1002950 the only aging effect for Lubrite is change in material properties, and only if Lubrite is exposed to at least 10 4 Rads. Radiation levels outside the bioshield wall at the perimeterof the drywell would be significantly less that the EPRI threshold limit. All other Lubrite type material applications are outside the drywell where radiation levels would typically be significantly less than inside the drywell.The staff's review found the applicant's response to RAI 3.5.1-12 acceptable. The applicantclarified its intention and approach in managing the line item components. The staff found the applicant's aging management of lubrite materials acceptable; therefore, the staff's concerndescribed in RAI 3.5.2-12 is resolved.The staff's review of the applicant's programs, the aging effects, and plant-specific and industryoperating experience determined that the Plant Chemistry Program, the Primary ContainmentIn-Service Inspection Program, and the 10 CFR Part 50, Appendix J Program effectively manage the aging effect of loss of material due to MIC, pitting, and crevice corrosion of stainless steel material exposed to a treated water environment. On this basis, the staff found the applicant's management of loss of material due to MIC, pitting, and crevice corrosion in primary containment acceptable.
3-3023.5.2.3.14Structures and Component Supports-Radioactive Waste Building-Summary ofAging Management Evaluation-Table 3.5.2-14The staff reviewed LRA Table 3.5.2-14, which summarizes the results of AMR evaluations forthe radioactive waste building component groups.All line items in this table are consistent with the GALL Report or are included in the discussionin Section 3.5.2.3 above.3.5.2.3.15Structures and Component Supports-Reactor Building-Summary of AgingManagement Evaluation-Table 3.5.2-15The staff reviewed LRA Table 3.5.2-15, which summarizes the results of AMR evaluations forthe reactor building component groups.The staff also reviewed LRA Section 3.5.2.1.15, which identifies the materials, environments,AERMs, and AMPs for the reactor building component group. The staff conducted its review, described below, in accordance with SRP-LR Section 3.5 and the GALL Report.The applicant has proposed to manage the reduction of neutron absorbing capacity and loss ofmaterial due to corrosion of boral with the Plant Chemistry Program in conjunction with a one-time inspection.The applicant stated that the Plant Chemistry Program manages the aging effects of boral in atreated water environment due to crevice, galvanic, and pitting corrosion and MIC, and the aging effect of cracking due to SCC, by ensuring that corrosive ion concentrations do not exceed acceptable limits and by limiting the amount of impurities in the water. The applicant further stated that plant test results and industry experience indicate that use of the PlantChemistry Program during the period of extended operation will continue to manage the loss ofneutron absorption capacity aging effect effectively. The applicant will apply the One-TimeInspection Program for added assurance that aging effects do not occur.The staff's review of LRA Table 3.5.2-15 and LRA Section 3.5.2.1.15 identified areas in whichthe staff needed additional information to complete its evaluation of the applicant's results. The applicant responded to the staff's RAIs as discussed below.In RAI 3.5.2.1.15-1, dated August 18, 2005, the staff requested that the applicant providedetails of the plant's Boral Coupon Surveillance Program.In its response, by letter dated September 16, 2005, the applicant stated the following:...The program placed seven sets of coupons in the fuel pool to be removed on aperiodic basis and tested for degradation. To date, six of the seven coupon sets have been removed and tested and no degradation has been found (see response to RAI 3.5.2.1.15-3 for test results). Testing methods include physical observations; neutron attenuation tests; weight, specific gravity, dimensional checks; and analysis for boron content. The final (seventh) coupon set will beremoved and tested before the period of extended operation to satisfy the requirement for a one-time inspection. No further testing is proposed during the 3-303period of extended operation pending acceptable results from the finalinspection.The applicant based its election not to continue coupon testing into the period of extendedoperation partly on the results of the six previously tested coupons, which represent over 20 years of operating experience.In response to staff RAI 3.5.2.1.15-3, dated September 16, 2005, the applicant provided testresults for the past coupon inspections indicating that all coupons have retained the required level of neutron absorption capability with no discernable degradation.The staff needed additional information to complete its evaluation for the aging management ofboral. The applicant will not test boral coupons into the period of extended operation. For thisreason, the staff requested that the applicant provide details on its ability to identify a potentialaging effect in the plant's boral. Because the applicant will not test actual boral samples, it must provide assurance that it will be able to identify and mitigate any degradation of boral over theperiod of extended operation.In a supplemental response, dated November 17, 2005, the applicant stated that it will removethe unclad coupon in the final (seventh) coupon set from the pool and visually examine it before the period of extended operation to satisfy the requirement for a one-time inspection. The applicant will return the unclad coupon to the spent fuel pool immediately following the visualexamination, and the entire set of coupons will remain in the spent fuel pool until they areremoved for surveillance testing sometime during the period of extended operation.The applicant's operating experience indicates that it is unlikely that the final boral coupon setwill exhibit degradation if tested before the period of extended operation. The applicantmaintains that the final coupon set will provide greater assurance of boral performance if it istested during the period of extended operation. The applicant's visual inspection of the uncladcoupon will satisfy the requirement for a one-time inspection and will provide additionalassurance that the boral has not experienced significant degradation since the examination ofthe last coupon set.The staff found the applicant's response to RAI 3.5.2.1.15-3 acceptable based on the conductof a one-time inspection of the remaining coupon to determine if there is any unacceptable degradation of the neutron absorption capability. Therefore, the staff's concern described inRAI 3.5.2.1.15-3 is resolved.In RAI 3.5.2.1.5-3, dated August 18, 2005, the staff noted that LRA Tables 3.5.2-15 and3.5.2-17 refer to the Structures Monitoring Program as the AMP to manage aging effects for rigid board (thermal insulating board) in an air/gas environment; therefore, the staff requested that the applicant justify this conclusion.In its response, by letter, dated September 16, 2005, the applicant stated the following:LRA Tables 3.5.2-15 and 3.5.2-17 refer to the Structures Monitoring Program asthe AMP for managing the aging effects for gypsum board walls (rigid board) with fire barrier and HELB barrier intended functions in an air/gas environment.
The scope of the Structures Monitoring Program described in the Structures 3-304Monitoring Program PBD/AMP-027, Table 7.1 includes rigid board with the agingeffect loss of material in an air/gas environment. This is consistent with LRA Tables 3.5.2-15 and 3.5.2-17.Since gypsum board walls perform fire barrier and HELB intended functions,both the Structures Monitoring Program and the Fire Protection Program willmanage the aging effects, ensuring the intended functions will be maintainedconsistent with the CLB for the period of extended operation.The staff's review found the applicant's response to RAI 3.5.2.1.5-3 acceptable because thescope of the Fire Protection Program in PBD/AMP-013, Table 7.1, includes gypsum board walls (rigid board) with fire barrier and HELB barrier intended functions in an air/gas environment.
The staff's review of the applicant's Fire Protection Program, including PBD/AMP-013, Table 7.1, found that components of the FP system will be managed for aging effects duringthe period of extended operation. The applicant also stated that both the Structures MonitoringProgram and the Fire Protection Program will manage the aging effect of gypsum board walls;therefore, the staff's concern described in RAI 3.5.2.1.5-3 is resolved.The staff's review of the applicant's programs, the aging effects, and the plant-specific andindustry operating experience determined that the applicant adequately identified applicableaging effects and the AMPs credited with managing them for the reactor building component group not addressed by the GALL Report. The staff found the applicant's AMR results for the reactor building component group acceptable.3.5.2.3.16Structures and Component Supports-Structures Affecting Safety-Summary ofAging Management Evaluation-Table 3.5.2-16The staff reviewed LRA Table 3.5.2-16, which summarizes the results of AMR evaluations forthe structures affecting safety component groups.All line items in this table are consistent with the GALL Report or are included in the discussionin Section 3.5.2.3 above.3.5.2.3.17Structures and Component Supports-Turbine Building-Summary of AgingManagement Evaluation-Table 3.5.2-17The staff reviewed LRA Table 3.5.2-17, which summarizes the results of AMR evaluations forthe turbine building component groups.The staff also reviewed LRA Section 3.5.2.1.17, which identifies the materials, environments,AERMs, and AMPs for the turbine building component group. The staff conducted its review, described below, in accordance with SRP-LR Section 3.5 and the GALL Report.As discussed in the resolution to RAI 3.5.2.1.5-3, the staff found that the Structures MonitoringProgram will properly manage the aging effects for gypsum board walls (rigid board) in anair/gas environment.The staff's review of the applicant's programs, the aging effects, and the plant-specific andindustry operating experience determined that the applicant adequately identified applicable 3-305aging effects and the AMPs credited with managing them for the turbine building componentgroup not addressed by the GALL Report. The staff found the applicant's AMR results for the turbine building component group acceptable.3.5.2.3.18Structures and Component Supports-Underground Duct Bank-Summary of AgingManagement Evaluation-Table 3.5.2-18The staff reviewed LRA Table 3.5.2-18, which summarizes the results of AMR evaluations forthe underground duct bank component groups.All line items in this table are consistent with the GALL Report or are included in the discussionin Section 3.5.2.3 above.Conclusion. On the basis of its review, the staff found that the applicant appropriately evaluatedAMR results involving material, environment, AERMs, and AMP combinations that are not evaluated in the GALL Report. The staff found that the applicant has demonstrated that theeffects of aging will be adequately managed so that the intended functions will be maintainedconsistent with the CLB for the period of extended operation, as required by10 CFR 54.21(a)(3).3.5.3  Conclusion The staff concluded that the applicant provided sufficient information to demonstrate that theeffects of aging for the containments, structures, and component supports system componentsthat are within the scope of license renewal and subject to an AMR will be adequately managedso that the intended functions will be maintained consistent with the CLB for the period ofextended operation, as required by 10 CFR 54.21(a)(3).The staff also reviewed the applicable USAR supplement program summaries and concludedthat they adequately describe the AMPs credited with managing aging of the containments,structures, and component supports, as required by 10 CFR 54.21(d).3.6  Aging Management of Electrical and Instrumentation and ControlsThis section of the SER documents the staff's review of the applicant's AMR results for theelectrical and instrumentation and controls (I&C) components associated with the following:
* electrical penetrations commodity group
* fuse holders commodity group
* non-environmental qualification (EQ) cables and connections commodity group
* offsite power/SBO recovery path commodity group3.6.1  Summary of Technical Information in the Application In LRA Section 3.6, the applicant provided AMR results for the electrical and I&C components.In LRA Table 3.6.1, the applicant provided a summary comparison of its AMRs with the AMRs evaluated in the GALL Report for the electrical and I&C components.
3-306The applicant's AMRs incorporated applicable operating experience in the determination ofAERMs. These reviews included evaluation of plant-specific and industry operating experience.
The plant-specific evaluation included reviews of CRs and discussions with appropriate site personnel to identify AERMs. The applicant's review of industry operating experience included a review of the GALL Report and operating experience issues identified since the issuance of the GALL Report.3.6.2  Staff Evaluation The staff reviewed LRA Section 3.6 to determine if the applicant provided sufficient informationto demonstrate that the effects of aging for the electrical and I&C components that are withinthe scope of license renewal and subject to an AMR will be adequately managed so that theintended functions will be maintained consistent with the CLB for the period of extendedoperation, as required by 10 CFR 54.21(a)(3).In addition, the staff performed an onsite audit of AMRs to confirm the applicant's claim thatcertain identified AMRs are consistent with the GALL Report. The staff did not repeat its reviewof the matters described in the GALL Report; however, the staff did verify that the material presented in the LRA is applicable and that the applicant identified the appropriate GALLReport AMRs. SER Section 3.0.3 documents the staff's evaluations of the AMPs. The MNGP audit and review report details the staff's audit evaluation, summarized in SER Section 3.6.2.1.The staff also performed an onsite audit of those selected AMRs that are consistent with theGALL Report and for which further evaluation is recommended. The staff confirmed that the applicant's further evaluations are consistent with the acceptance criteria in SRP-LR Section 3.6.2.2. The MNGP audit and review report documents the staff's audit evaluations,summarized in SER Section 3.6.2.2.The staff performed an onsite audit and conducted a technical review of the remaining AMRsthat are not consistent with, or not addressed in, the GALL Report. The audit and technicalreview included evaluating whether the applicant identified all plausible aging effects and whether the aging effects listed are appropriate for the combination of materials and environments specified. The MNGP audit and review report documents the staff's audit evaluations. SER Section 3.6.2.3 summarizes the staff's audit evaluations and documents thestaff's technical review.Finally, the staff reviewed the AMP summary descriptions in the USAR supplement to ensurethat they adequately describe the programs credited with managing or monitoring aging for theelectrical and I&C components.Table 3.6-1 below summarizes the staff's evaluation of components, aging effects/mechanisms,and AMPs listed in LRA Section 3.6 that are addressed in the GALL Report.
3-307Table 3.6-1  Staff Evaluation for Electrical and Instrumentation and Controls Componentsin the GALL ReportComponent GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff EvaluationElectricalequipment subjectto 10 CFR 50.49environmentalqualification (EQ)requirements(Item Number3.6.1-01)Degradation due tovarious agingmechanismsEnvironmentalqualification ofelectric componentsTLAAThis TLAA isevaluated in Section4.7, EnvironmentalQualification ofElectricalEquipment (EQ)Electrical cablesand connections notsubject to10 CFR 50.49 EQrequirements(Item Number3.6.1-02)Embrittlement,cracking, melting,discoloration,swelling, or loss ofdielectric strengthleading to reducedinsulationresistance (IR);electrical failurecaused by thermal/thermoxidativedegradation oforganics; radiolysisand photolysis[ultraviolet (UV)sensitive materialsonly] of organics;radiation-inducedoxidation; moistureintrusionAging managementprogram forelectrical cablesand connections notsubject to10 CFR 50.49 EQrequirementsElectrical Cables &Connections NotSubject to10 CFR 50.49EnvironmentalQualificationRequirementsProgram (B2.1.15)Consistent withGALL Report, whichrecommends nofurther evaluationElectrical cablesused ininstrumentationcircuits not subjectto 10 CFR 50.49EQ requirementsthat are sensitive toreduction inconductor insulationresistance (IR)(Item Number3.6.1-03)Embrittlement,cracking, melting,discoloration,swelling, or loss ofdielectric strengthleading to reducedIR; electrical failurecaused by thermal/thermoxidativedegradation oforganics;radiation-inducedoxidation; moistureintrusionAging managementprogram forelectrical cablesused ininstrumentation circuits not subjectto 10 CFR 50.49EQ requirementsElectrical CablesNot Subject to10 CFR 50.49EnvironmentalQualificationRequirements Usedin InstrumentationCircuits Program(B2.1.16) Consistent withGALL Report, whichrecommends nofurther evaluation Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation3-308Inaccessiblemedium-voltage(2 kV to 15 kV)cables (e.g.,installed in conduitor direct buried) notsubject to10 CFR 50.49 EQrequirements(Item Number3.6.1-04)Formation of watertrees, localizeddamage leading toelectrical failure(breakdown ofinsulation), watertress caused bymoisture intrusionAging managementprogram forinaccessiblemedium-voltagecables not subjectto 10 CFR 50.49EQ requirementsInaccessibleMedium Voltage(2kV to 34.5kV)Cables Not Subjectto 10 CFR 50.49EQ RequirementsProgram (B2.1.21 ) Consistent withGALL Report, whichrecommends nofurther evaluationElectricalconnectors notsubject to10 CFR 50.49 EQrequirements thatare exposed toborated waterleakage(Item Number3.6.1-05)Corrosion ofconnector contactsurfaces caused byintrusion of boratedwaterBoric acid corrosionNot applicable,PWR onlyThe staff's review of the MNGP component groups followed one of several approaches. Oneapproach, documented in SER Section 3.6.2.1, involves the staff's review of the AMR resultsfor electrical and I&C components that the applicant indicated are consistent with the GALLReport and do not require further evaluation. Another approach, documented in SERSection 3.6.2.2, involves the staff's review of the AMR results for electrical and I&C componentsthat the applicant indicated are consistent with the GALL Report and for which furtherevaluation is recommended. A third approach, documented in SER Section 3.6.2.3, involves thestaff's review of the AMR results for electrical and I&C components that the applicant indicated are not consistent with, or not addressed in, the GALL Report. SER Section 3.0.3 documentsthe staff's review of AMPs that are credited to manage or monitor aging effects of the electrical and I&C components.3.6.2.1  AMR Results That Are Consistent with the GALL Report Summary of Technical Information in the Application. In LRA Section 3.6.2.1, the applicantidentified the materials, environments, and AERMs. The applicant identified the following programs that manage the aging effects related to the electrical and I&C components:
* Bus Duct Inspection Program (B2.1.6)
* Electrical Cables & Connections Not Subject to 10 CFR 50.49 EnvironmentalQualification Requirements Program (B2.1.15)
* Electrical Cables Not Subject to 10 CFR 50.49 Environmental QualificationRequirements Used in Instrumentation Circuits Program (B2.1.16)
* Inaccessible Medium Voltage (2kV to 34.5kV) Cables Not Subject to 10 CFR 50.49 EQRequirements Program (B2.1.21 )
3-309Staff Evaluation. In LRA Tables 3.6.2-1 through 3.6.2-4, the applicant summarized the AMRsfor the electrical and I&C components and identified which AMRs it considered to be consistent with the GALL Report.For component groups evaluated in the GALL Report for which the applicant has claimedconsistency with the GALL Report, and for which the GALL Report does not recommend further evaluation, the staff performed an audit and review to determine whether the GALL Reportevaluation bounds the plant-specific components contained in these GALL Report componentgroups.The applicant provided a note for each AMR line item. The notes describe how the informationin the tables aligns with the information in the GALL Report. The staff audited those AMRs with Notes A through E, which indicate that 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 AMP identified in the GALL Report. The staff audited these line items to verify consistency with the GALL Report and the validity of the AMR for the site-specific conditions.Note B 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 AMP identified in the GALL Report. The staff audited these line items to verify consistency with the GALL Report. The staff verified that it had reviewed and accepted the identified exceptionsto the GALL Report AMPs. The staff also determined whether the AMP identified by the applicant is consistent with the AMP identified in the GALL Report and whether the AMR is validfor the site-specific conditions.Note C indicates that the component for the AMR line item, although different, is consistent withthe GALL Report for material, environment, and aging effect. In addition, the AMP is consistent with the AMP identified by the GALL Report. This note indicates that the applicant could not finda listing of some system components in the GALL Report; however, the applicant identified adifferent component in the GALL Report that has 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 determined whether the AMR line item of the different component applies to the component under review and whether the AMR is valid for the site-specific conditions.Note D indicates that the component for the AMR line item, although different, is consistent withthe GALL Report for material, environment, and aging effect. In addition, the AMP takes some exceptions to the AMP identified in the GALL Report. The staff audited these line items to verify consistency with the GALL Report. The staff verified whether the AMR line item of the different component applies to the component under review. The staff verified whether it had reviewed and accepted the identified exceptions to the GALL Report AMPs. The staff also determinedwhether the AMP identified by the applicant is consistent with the AMP identified in the GALLReport and whether the AMR is 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 the applicant credited a different AMP. The staff audited 3-310these line items to verify consistency with the GALL Report. The staff also determined whetherthe identified AMP will manage the aging effect consistent with the AMP identified by the GALLReport and whether the AMR is valid for the site-specific conditions.The staff conducted an audit and review of the information provided in the LRA, as documentedin the MNGP audit and review report. The staff did not repeat its review of the matters described in the GALL Report; however, the staff did verify that the material presented in the LRA is applicable and that the applicant identified the appropriate GALL Report AMRs.The staff reviewed the LRA to confirm that the applicant (1) provided a brief description of thesystem, components, materials, and environment; (2) stated that the GALL Report reviewed theapplicable aging effects, and (3) identified those aging effects for the electrical and I&C components that are subject to an AMR. On the basis of its audit and review the staff determined that, for AMRs not requiring further evaluation, as identified in LRA Table 3.6.1, theapplicant's references to the GALL Report are acceptable and no further staff review is required.Conclusion. The staff evaluated the applicant's claim of consistency with the GALL Report. Thestaff also reviewed information pertaining to the applicant's consideration of recent operating experience and proposals for managing associated aging effects. The staff's review concluded that the AMR results, which the applicant claimed to be consistent with the GALL Report, areconsistent with the AMRs in the GALL Report. Therefore, the staff concluded that the applicanthas demonstrated that the effects of aging for these components will be adequately managedso that their intended functions will be maintained consistent with the CLB for the period ofextended operation, as required by 10 CFR 54.21(a)(3).3.6.2.2AMR Results That Are Consistent with the GALL Report, for Which Further EvaluationIs RecommendedSummary of Technical Information in the Application. In LRA Section 3.6.2.2, the applicantprovided further evaluation of aging management as recommended by the GALL Report for the electrical and I&C components. The applicant provided information concerning how it willmanage the aging effects in electrical equipment subject to EQ.Staff Evaluation. For component groups evaluated in the GALL Report for which the applicanthas claimed consistency with the GALL Report, and for which the GALL Report recommends further evaluation, the staff audited and reviewed the applicant's evaluation to determinewhether it adequately addresses the issues that were further evaluated. In addition, the staffreviewed the applicant's further evaluations against the criteria contained in SRP-LR Section 3.6.2.2. The staff's audit and review report details the staff's audit. The following sections discuss the staff's evaluation of the aging effects.3.6.2.2.1  Electrical Equipment Subject to Environmental QualificationIn LRA Section 3.6.2.2.1, the applicant stated that EQ 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 4.7 documents the staff's review of the applicant's evaluation of this TLAA.
3-311Conclusion. On the basis of its review, for component groups evaluated in the GALL Report forwhich the applicant has claimed consistency with the GALL Report, and for which the GALL Report recommends further evaluation, the staff determined that the applicant adequatelyaddressed the issues that were further evaluated. The staff found that the applicant hasdemonstrated that the effects of aging will be adequately managed so that the intendedfunctions will be maintained consistent with the CLB for the period of extended operation, asrequired by 10 CFR 54.21(a)(3).3.6.2.3  AMR Results That Are Not Consistent with or Not Addressed in the GALL ReportSummary of Technical Information in the Application. In LRA Tables 3.6.2-1 through 3.6.2-4,the staff reviewed additional details of the results of the AMRs for material, environment, AERM, and AMP combinations that are not consistent with the GALL Report, or that are notaddressed in the GALL Report.In LRA Tables 3.6.2-1 through 3.6.2-4, the applicant indicated, via Notes F through J, that thecombination of component type, material, environment, and AERM does not correspond to a line item in the GALL Report and provided information concerning how it will manage the agingeffect. Specifically, Note F indicates that the GALL Report does not evaluate the material for the AMR line item component. Note G indicates that the GALL Report does not evaluate the environment for the AMR line item component and material. Note H indicates that the GALL Report does not evaluate the aging effect for the AMR line item component, material, and environment combination. Note I indicates that the aging effect identified in the GALL Report forthe line item component, material, and environment combination is not applicable. Note J indicates that the GALL Report does not evaluate either the component or the material andenvironment combination for the line item.Staff Evaluation. For component type, material, and environment combinations that are notevaluated in the GALL Report, the staff reviewed the applicant's evaluation to determinewhether the applicant demonstrated that the effects of aging will be adequately managed sothat the intended functions will be maintained consistent with the CLB during the period ofextended operation. The following sections discuss the staff's evaluation.In LRA Tables 3.6.2-1 through 3.6.2-4, the applicant identified AMR line items for which theaging review process identified no aging effects. The applicant stated that it identified no agingeffects for components fabricated from the materials and exposed to the environments described below.3.6.2.3.1Electrical Components-Electrical Penetrations Commodity Group-Summary ofAging Management Evaluation-Table 3.6.2-1The staff reviewed LRA Table 3.6.2-1, which summarizes the results of AMR evaluations for theelectrical penetrations commodity group component groups.In LRA Table 3.6.2-1, the applicant stated that no aging effects occur when componentsfabricated from epoxy, fiberglass, and hypalon paint material are exposed to heat, radiation, and moisture environment. The applicant further stated that GE supplied the non-EQ penetrations and that they are manufactured and tested to the same specifications as the GE-supplied EQ penetrations.
3-312The materials subject to aging that are installed in the penetrations are epoxy, fiberglass, andhypalon paint. The applicant evaluated these materials as part of the EQ calculation associatedwith GE penetrations. Fiberglass is a spun glass inert material not susceptible to significant thermal degradation. Of the two organic materials, epoxy and hypalon paint, epoxy is considered more susceptible to radiation effects. In accordance with the applicant's EQ calculation, the lifetime of these two materials exceeds the required 60-year service life.Because the evaluated temperature and radiation levels of the organic materials exceed thoseto which the materials are actually exposed (service conditions for the drywell are 135 F and1.58x10 7 Rads), the materials are shown to have an expected lifetime in excess of 60 years.When a component's expected lifetime exceeds its intended service life, there are no agingeffects which require management because the component remains capable of performing its intended function; therefore, no aging effects are considered applicable to components fabricated from epoxy, fiberglass, and hypalon paint material exposed to heat, radiation, and moisture environments.The staff's review of the applicant's programs, the aging effects, and the plant-specific andindustry operating experience determined that heat, radiation, or moisture on epoxy, fiberglass, and hypalon paint will not result in aging that will be of concern during the period of ext endedoperation. Therefore, the staff concluded that epoxy, fiberglass, and hypalon paint componentsexposed to a heat, radiation, and moisture environment have no applicable AERMs and that the applicant has demonstrated that the effects of aging will be adequately managed so that theintended functions will be maintained during the period of extended operation, as required by10 CFR 54.21(a)(3).3.6.2.3.2Electrical Components-Fuse Holders Commodity Group-Summary of AgingManagement Evaluation-Table 3.6.2-2The staff reviewed LRA Table 3.6.2-2, which summarizes the results of AMR evaluations for thefuse holders commodity group component groups.In LRA Table 3.6.2-2, the applicant identified AMR line items for which the aging review processidentified no aging effects. Specifically, the applicant stated that it identified no aging effects for(1) components fabricated from various insulating materials (e.g., Phenolic or Melamine) exposed to heat and radiation environments and (2) components fabricated from copper, brass, and steel material exposed to thermal cycling, vibration, electrical transients, mechanicalstresses, corrosion, chemical contamination, and oxidation environments.Components Fabricated from Various Insulating Materials such as Phenolic or MelamineExposed to Heat or Radiation. The average temperature where fuse holders are located is 85 F and the radiation exposure is 1.11x10 5 Rads. These temperature and radiation levels areless than the insulating material 60-year service-limiting temperature of 205 F and radiationdose of 5x10 7 Rads. Operating experience demonstrates no aging effect when insulatingmaterials such as Phenolic or Melamine are exposed for 60 years at a service-limiting temperature of 205 F and radiation dose of 5x10 7 Rads. No aging effects are consideredapplicable for components fabricated from various insulating materials (e.g., Phenolic or Melamine) exposed to heat and radiation environments.On the basis of its review of current industry research and operating experience, the staff foundthat heat and radiation on various insulating materials like Phenolic or Melamine will not result 3-313in aging that will be of concern during the period of extended operation. The applicant's fuseholders are not exposed to temperatures at which operating experience demonstrates aging effects of embrittlement, cracking, melting, or discoloration; therefore, the staff concluded thatinsulating materials such as Phenolic or Melamine exposed to heat and radiation environments have no applicable AERMs.Components Fabricated from Copper, Brass, and/or Steel Exposed to Thermal Cycling,Vibration, Electrical Transients, Mechanical Stress, Corrosion, Chemical Contamination, orOxidation.Effect of thermal cycling-Thermal cycling is an aging effect associated with power circuitoperations. Operating low-current fuse holders below the design-current rating will eliminate theaging effect of thermal cycling. Typically, control fuse holders are rated far in excess of the fuse rating. The fuse will limit the current to values well below the rating of the fuse holder. The low current values experienced by control circuits typically do not create thermal cycling effects. No aging effects are considered to apply to components fabricated from copper, brass, and/or steel material exposed to a thermal cycling environment.On the basis of its review of current industry research and operating experience, the staff foundthat thermal cycling on copper, brass, and/or steel will not result in aging that will be of concernduring the period of extended operation. Fuse holders at MNGP are low current, and operatingexperience shows that low currents do not create thermal cycling effects; therefore, the staffconcluded that copper, brass, and/or steel components exposed to a thermal cyclingenvironment have no applicable AERMs.Effect of vibration-Vibration is a result of rapid mechanical movement about a specific point atan elevated frequency. Fuse holders at MNGP are mounted on rigid walls and are not subject to vibration. No aging effects are considered applicable to components fabricated from copper, brass, and/or steel material exposed to a vibration environment.On the basis of its review of current industry research and operating experience, the staff foundthat vibration on the fuse holder's metallic clamp fabricated from copper, brass, and/or steel willnot result in aging that will be of concern during the period of extended operation. Fuse holdersat MNGP are mounted on rigid walls and not subject to vibration; therefore, the staff concludedthat copper, brass, and/or steel components exposed to a vibration environment have noAERMs.Effect of electrical transients-Electrical transients of power applications (i.e., large-surgecurrent transformers and power cables) create aging effects. These transients affect the insulation of the device and if sufficiently frequent may weaken the insulation over time. Fuse holders subject to an AMR at MNGP provide electrical power to fire detection components.
These components are low-voltage and low-current applications. No aging effects are considered applicable to components fabricated from copper, brass, and/or steel material exposed to electrical transients.On the basis of its review of current industry research and operating experience, the staff foundthat electrical transients on copper, brass, and/or steel will not result in aging that will be ofconcern during the period of extended operation. Electrical transients in the low-currentapplication of fuse holders at MNGP are not sufficient to cause aging effects; therefore, the 3-314staff concluded that copper, brass, and/or steel components exposed to an electrical transientenvironment have no applicable AERMs.Effect of mechanical stress-Frequent manipulation is a result of removing and reinstalling thefuse from the fuse holder in a frequent time period. Aging effects resulting from frequent manipulation have a correlation to fatigue. Fuse holders at MNGP have no fuses removed and reinstalled on a frequent basis. No aging effects are considered applicable to components fabricated from copper, brass, and/or steel material exposed to a mechanically stressful environment.On the basis of its review of current industry research and operating experience, the staff foundthat mechanical stress on copper, brass, and/or steel will not result in aging that will be ofconcern during the period of extended operation. Fuses at MNGP are not frequently removedand installed; therefore, the staff concluded that copper, brass, and/or steel componentsexposed to a mechanically stressful environment have no applicable AERMs.Effect of corrosion, chemical contamination, and oxidation-The aging stressors chemicalcontamination, corrosion, and oxidation are related to environments in which chemical watervapors create adverse localized environments. The indoor air environment is a controlled, mild environment with no significant concentrations of chemical vapors and moisture to create an adverse environment. Fuse holders at MNGP operate in an indoor air environment. No aging effects are considered applicable to components fabricated from copper, brass, and/or steel material exposed to chemical contamination, corrosion, and oxidation environments.On the basis of its review of current industry research and operating experience, the staff foundthat chemical contamination, corrosion, and oxidation on copper, brass, and/or steel will notresult in aging that will be of concern during the period of extended operation. Fuse holders atMNGP are protected from moisture and chemical contamination. Therefore, the staff concludedthat copper, brass, and/or steel components exposed to chemical contamination, corrosion, andoxidation environments have no applicable AERMs.The staff's review of the applicant's programs, the aging effects, and the plant-specific andindustry operating experience determined that the applicant demonstrated that the effects ofaging for fuse holders will be adequately managed so that the intended functions will bemaintained during the period of extended operation, as required by 10 CFR 54.21(a)(3).3.6.2.3.3Electrical Components-Non-EQ Cables and Connections CommodityGroup-Summary of Aging Management Evaluation-Table 3.6.2-3The staff reviewed LRA Table 3.6.2-3, which summarizes the results of AMR evaluations for thenon-EQ cables and connections commodity group component groups.In LRA Table 3.6.2-3, the applicant stated that it identified no aging effects for componentsfabricated from various metal materials exposed to thermal cycling, ohmic heating, electrical transients, vibration, chemical contamination, corrosion, and oxidation environments. Assupported by SAND96-0344, "Aging Management Guideline for Commercial Nuclear Power Plants-Electrical Cable and Terminations," issued September 1996, and the applicant'soperating experience, the likelihood of substantially increased effects or failure rates is considered low from thermal cycling, ohmic heating, electrical transients, mechanical stress 3-315(vibration), chemical contamination, corrosion, and oxidation. No aging effects are consideredapplicable to components fabricated from various metal materials exposed to thermal cycling,ohmic heating, electrical transients, vibration, chemical contamination, corrosion, and oxidationenvironments.The staff noted that operating experience shows loosening of metallic parts of cableconnections. Review of several licensee event reports revealed loose connections due to corrosion, vibration, thermal cycling, and other factors. In RAI 3.6-2, dated November 7, 2005,the staff requested that the applicant provide technical justification for not providing an AMP forcable connections.In its response, by letter dated December 7, 2005, the applicant stated that SAND96-0344categorizes aging mechanisms as either "significant" or "significant and observed."  According to SAND96-0344, the aging mechanism listed is  "significant."Section 4.2 of SAND96-0344 emphasizes that "the applicability of some aging mechanisms toactual cable systems (cable and connections) may be very limited or the frequency of theiroccurrence may be extremely low." After a consideration of all stressors and the reported incidence of their effects in the industry, SAND96-0344 concluded the following:...the likelihood of substantially increased effects or failure rate resulting fromaging mechanisms currently categorized only as 'significant' is considered low.This assessment, which is based on industry-wide observations, provides reasonableassurance that these aging mechanisms will cause no loss of intended function if leftunmanaged during the period of extended operation. Based on the above, the applicant statedthat industry and plant-specific operating experience does not support the presence of agingeffects from thermal cycling, ohmic heating, electric transients, vibration, chemical contamination, corrosion, and oxidation on the metallic parts of cable connections.In a January 12, 2006, teleconference, the staff informed the applicant that its justification fornot having an AMP for cable connections was inadequate because the operating experience shows loosening of metallic parts of cable connections. The staff recommended that theapplicant implement an AMP for the metallic parts of cable connections in accordance withGALL AMP XI.E6, "Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements." The applicant stated that it had implemented a plant-specificthermography program for equipment that presents a significant risk to core protection, isnecessary to maintain full power production, or has the potential to reduce power. This equipment, monitored at least semiannually, includes but is not limited to substation equipment, 4-kV breakers, load centers, motor control centers, control centers, control panels, direct current equipment, motors, or generators. The licensee stated that it will consider expandingthe current thermography program to include cable connectors and switchyard bus connections as well as transmission conductor connections that are within the scope of license renewal.In its letter dated February 28, 2006, the applicant committed to implementing a new programconsistent with GALL AMP XI.E6, documented as commitment 55 in Table A.5. The staff foundthis response acceptable, as it will provide assurance that the effects of aging on electricalconnections will be adequately managed. Therefore, the staff's concern described in RAI 3.6-2is resolved.
3-316On the basis of the staff's review of the applicant's programs, the aging effects, and theplant-specific and industry operating experience, the staff determined that the applicantdemonstrated that the effects of aging for non-EQ cables and connections will be adequatelymanaged so that the intended functions will be maintained during the period of extendedoperation, as required by 10 CFR 54.21(a)(3).3.6.2.3.4Electrical Components-Offsite Power/Station Blackout Recovery Path CommodityGroup-Summary of Aging Management Evaluation-Table 3.6.2-4The staff reviewed LRA Table 3.6.2-4, which summarizes the results of AMR evaluations for theoffsite power/SBO recovery path commodity group component groups.The applicant proposed to manage embrittlement, cracking, discoloration, oxidation, andloosening of bolted connections for nonsegregated phase bus made from various metals and organic polymers, porcelain, fiberglass, and silicon rubber in an indoor and outdoor airenvironment using the Bus Duct Inspection Program. SER Section 3.0.3.3.1 documents thestaff evaluation of the Bus Duct Inspection Program.Nonsegregated Phase BusA nonsegregated phase bus connects two or more elements of an electrical power circuit and isnormally used to connect active electrical components such as generators, breakers, and transformers. The intended function of a nonsegregated phase bus is to provide electrical connections to specified sections of an electrical circuit to deliver voltage, current, or signals.The applicant has identified the Bus Duct Inspection Program to manage aging effects in thenonsegregated phase bus. SER Section 3.0.3.3.1 documents the staff evaluation of the BusDuct Inspection Program.High-Voltage InsulatorsIn LRA Table 3.6.2-4, the applicant stated that it identified no aging effects for high-voltageinsulators fabricated from porcelain, cement, and metal material exposed to an outdoor air environment.Effect of surface contamination on porcelain-The applicant stated that MNGP is located in arural area not close to saltwater environments. The nearest industrial facility discharging anysignificant amount of airborne particulates is about 5 miles northwest of the plant. Since the plant began operation in 1971, plant personnel have not conducted regularly scheduledmaintenance to remove surface contamination from the switchyard or transmission line insulators. Additionally, operating experience indicates no age-related degradation of the high-voltage insulators from surface contamination. No aging effects are considered applicable to components fabricated from porcelain material exposed to an outdoor air environment.On the basis of its review of current industry research and operating experience, the staff foundthat porcelain in an outdoor air environment will not result in aging that will be of concern duringthe period of extended operation. The applicant's high-voltage insulators are not located in anarea subject to airborne contaminants. Therefore, the staff concluded that porcelaincomponents exposed to an outdoor air environment have no AERMs.
3-317Effect of cracking on porcelain-Cracks have also been known to occur in insulators used instrain applications when the cement that binds the parts together expands enough to crack theporcelain. This phenomenon, known as cement growth, is caused by improper manufacturing process or materials that increase the cement's susceptibility to moisture penetration. Porcelaincracking caused by cement growth has occurred only in isolated bad batches of insulators used in strain applications. The dates of manufacture and brands of these problem insulators are known and they have been removed from service. Cracking is not considered applicable to components fabricated from porcelain and cement material exposed to an outdoor air environment.On the basis of its review of current industry research and operating experience, the staff foundthat porcelain and cement in an outdoor air environment will not result in aging that will be ofconcern during the period of extended operation. Operating experience using properlymanufactured cement shows no aging effects. Therefore, the staff concluded that porcelain and cement components exposed to an outdoor air environment have no applicable AERMs.Effect of loss of material due to wear-Loss of material due to mechanical wear is an agingeffect for strain and suspension insulators if they are subject to significant movement. Although this mechanism is possible, experience shows that transmission conductors do not normally swing, and when they do, because of strong winds, they dampen quickly once the wind subsides. Routine inspections of high-voltage insulators have not identified wear, and loss of material due to wear is not considered applicable for components fabricated from metal material exposed to an outdoor air environment.On the basis of its review of current industry research and operating experience, the staff foundthat metal in an outdoor air environment will not result in loss of material due to wear that will beof concern during the period of extended operation. Transmission conductors and high-voltage insulators are not subject to significant movement; therefore, the staff concluded that metalcomponents exposed to an outdoor air environment have no applicable AERMs.The staff's review of the applicant's programs, the aging effects, and the plant-specific andindustry operating experience determined that the applicant had demonstrated that the effectsof aging for high-voltage insulators will be adequately managed so that the intended functionswill be maintained during the period of extended operation, as required by 10 CFR 54.21(a)(3).High-Voltage Switchyard BusIn LRA Table 3.6.2-4, the applicant stated that it identified no aging effects for high-voltageswitchyard buses fabricated from aluminum and steel material exposed to an outdoor air environment.Effect of vibration on switchyard bus-Switchyard buses connected to flexible conductors thatnormally do not vibrate are supported by insulators and ultimately by static, structural components like concrete footings and structural steel. With no connections to moving or vibrating equipment, vibration is not an applicable stressor. No aging effects are considered to be applicable to components fabricated from aluminum and steel exposed to outdoor air and vibration environments.
3-318On the basis of its review of current industry research and operating experience, the staff foundthat outdoor air and vibration of aluminum and steel will not result in aging that will be ofconcern during the period of extended operation. Switchyard bus is not subject to vibration.Therefore, the staff concluded that for aluminum and steel components exposed to outdoor airdue to vibration have no applicable AERMs.Effect of oxidation on switchyard bus and connections-All switchyard bus connections withinthe offsite power/SBO recovery path boundaries are bolted, welded, or, for jumper cables,crimped aluminum connections. Aluminum bus, solid and flexible connectors, and ground straps are highly conductive but do not make good contact surfaces as aluminum exposed to air forms nonconductive aluminum oxide on the surface. To prevent formation of aluminum oxide, the connections are cleaned with a wire brush (to remove existing aluminum oxide) and covered with No-Ox grease to prevent air from contacting the aluminum surface. After the connection is completed, additional compound is applied and forced into every irregularity and opening to seal the joint completely against moisture and corrosion. The grease prevents oxidation of the aluminum surface, thereby maintaining good conductivity at the bus connections. The grease is a consumable that is replaced during bus routine maintenance.
Routine maintenance thermography inspections monitor substation connections, which include the SBO recovery path equipment connections, on a semiannual basis. These inspections identify connections where conditions exist that have resulted in increased resistance and a subsequent rise in temperature. The applicant schedules the inspections in the work controlprocess and performs them on a repetitive basis as part of routine maintenance. The inspections have been effective in identifying conditions before any loss of the component intended function. Oxidation is not considered applicable to components fabricated from aluminum and steel exposed to outdoor air.On the basis of its review of current industry research and operating experience, the staff foundthat aluminum and steel in an outdoor air environment will not result in aging that will be ofconcern during the period of extended operation. The application of grease and its periodic replacement eliminates the effects from air on switchyard bus connections. In addition, the applicant periodically inspects connections using thermography. Therefore, the staff concluded that aluminum and steel components exposed to an outside air environment have no applicable AERMs.High-Voltage Transmission ConductorsIn LRA Table 3.6.2-4, the applicant stated that it identified no aging effects for high-voltagetransmission conductors fabricated from aluminum and steel material exposed to an outdoor air environment.Effect of loss of conductor strength due to corrosion-For transmission conductors, degradationbegins as a loss of zinc from the galvanized steel core wires. Corrosion rates depend largely on air quality, which includes suspended particles chemistry, sulfur dioxide concentration in air, precipitation, fog chemistry, and meteorological conditions. Corrosion of transmission conductors is a very slow process that is even slower in rural areas with generally fewer suspended particles and sulfur dioxide concentrations in the air than urban areas. MNGP is located in a rural area with low airborne particle and sulfur dioxide concentrations. No aging effects are considered applicable to components fabricated from aluminum and steel exposed to outdoor air.
3-319On the basis of its review of current industry research and operating experience, the staff foundthat aluminum and steel in an outdoor air environment will not result in aging that will be ofconcern during the period of extended operation. Corrosion is a slow process and is slower in rural areas, where MNGP is located. Therefore, the staff concluded that loss of conductor strength due to corrosion is not an applicable AERM for aluminum and steel components exposed to an outside air environment.Effect of vibration-Wind loading can cause transmission conductor vibration. Wind loading isconsidered in the initial design and field installation of transmission conductors and high-voltage insulators throughout the transmission and distribution network. Loss of material due to wear and fatigue that could be caused by transmission conductor vibration or sway is not considered an applicable aging effect because experience throughout the industry shows no significant failures of this type. No aging effects are considered applicable to components fabricated from aluminum and steel material exposed to an outdoor air environment.On the basis of its review of current industry research and operating experience, the staff foundthat aluminum and steel in an outdoor air environment will not result in aging that will be ofconcern during the period of extended operation. There is no operating experience for failure of transmission conductors due to vibration. Therefore, the staff concluded that vibration will notresult in any applicable AERMs for aluminum and steel components exposed to an outside air environment.Electrical Cables and Connections Not Subject to 10 CFR 50.49 EQ RequirementsSER Section 3.6.2.3.3 documents the staff evaluation for this area.The staff's review of the applicant's programs, the aging effects, and the plant-specific andindustry operating experience determined that the applicant had demonstrated that the effectsof aging will be adequately managed so that the intended functions will be maintained duringthe period of extended operation, as required by 10 CFR 54.21(a)(3).Conclusion. On the basis of its review, the staff found that the applicant appropriately evaluatedAMR results involving material, environment, AERMs, and AMP combinations that are not evaluated in the GALL Report. The staff found that the applicant has demonstrated that theeffects of aging will be adequately managed so that the intended functions will be maintainedconsistent with the CLB for the period of extended operation, as required by10 CFR 54.21(a)(3).3.6.3  Conclusion The staff concluded that the applicant provided sufficient information to demonstrate that theeffects of aging for the electrical and I&C components that are within the scope of license renewal and subject to an AMR will be adequately managed so that the intended functions willbe maintained consistent with the CLB for the period of extended operation, as required by10 CFR 54.21(a)(3).
3-320The staff also reviewed the applicable USAR supplement program summaries and concludedthat they adequately describe the AMPs credited for managing aging of the electrical and I&Ccomponents, as required by 10 CFR 54.21(d).3.7  Conclusion for Aging Management Review ResultsThe staff reviewed the information in LRA Section 3 and Appendix B to the LRA. On the basisof its review of the AMR results and AMPs, the staff concluded that the applicant has demonstrated that the aging effects will be adequately managed so that the intended functionswill be maintained consistent with the CLB for the period of extended operation, as required by10 CFR 54.21(a)(3). The staff also reviewed the applicable USAR supplement program summaries and concluded that the USAR supplement adequately describes the AMPs credited for managing aging, as required by 10 CFR 54.21(d).
4-1SECTION 4TIME-LIMITED AGING ANALYSES4.1  Identification of Time-Limited Aging AnalysesThis section discusses the identification of time-limited aging analyses (TLAAs). NuclearManagement Company, LLC (NMC or the applicant), discusses the TLAAs in Sections 4.2 through 4.10 of its license renewal application (LRA). Sections 4.2 through 4.11 of this safety evaluation report (SER) document the review of the TLAAs conducted by the staff of the U.S.Nuclear Regulatory Commission (NRC or the staff).TLAAs are certain plant-specific safety analyses that involve time-limited assumptions definedby the current operating term. Pursuant to Title 10, Section 54.21(c)(1), of the Code of FederalRegulations (10 CFR 54.21(c)(1)), the applicant for license renewal must provide a list ofTLAAs, as defined in 10 CFR 54.3(a), and demonstrate that (i) the analyses will remain valid forthe period of extended operation, (ii) the analyses have been projected to the end of the periodof extended operation, or (iii) the effects of aging on the intended functions will be adequatelymanaged for the period of extended operation. In accordance with 10 CFR 54.3(a), TLAAs are those licensee calculations and analyses that meet the following six criteria:  (252)involve systems, structures, and components (SSCs) within the scope of licenserenewal, as delineated in 10 CFR 54.4(a)  (253)consider the effects of aging  (254)involve time-limited assumptions defined by the current operating term, for example,40 years  (255)were considered to be relevant by the licensee in making a safety determination  (256)involve conclusions or provide the basis for conclusions related to the capability of theSSC to perform its intended functions, as delineated in 10 CFR 54.4(b)  (257)are contained or incorporated by reference in the current licensing basis (CLB)In addition, pursuant to 10 CFR 54.21(c)(2), an applicant must provide a list of plant-specificexemptions granted under 10 CFR 50.12, "Specific Exemptions," that are based on TLAAs. Forany such exemptions, the applicant must provide an evaluation that justifies the continuation ofthe exemptions for the period of extended operation.4.1.1  Summary of Technical Information in the ApplicationTo identify the TLAAs, the applicant evaluated calculations for the Monticello NuclearGenerating Plant (MNGP) against the six criteria specified in 10 CFR 54.3, "Definitions."  The applicant indicated that it had identified the calculations that met the six criteria by searching theCLB, which includes the Updated Safety Analysis Report (USAR), engineering calculations, technical reports, engineering work requests, licensing correspondence, and applicable vendor 4-2reports. In LRA Table 4.1-1, "List of MNGP Time-Limited Aging Analyses (TLAAs)," theapplicant listed the applicable TLAAs in the following categories:
* neutron embrittlement of the reactor vessel and internals
* metal fatigue-RPV, internals and pressure boundary
* neutron embrittlement
* environmental fatigue
* fatigue of primary containment, piping, and components
* environmental qualification
* loss of preload
* plant-specific TLAAsPursuant to 10 CFR 54.21(c)(2), the applicant stated that it did not identify any exemptionsgranted under 10 CFR 50.12 that were based on a TLAA, as defined in 10 CFR 54.3.4.1.2  Staff Evaluation In LRA Section 4.1, the applicant identified the TLAAs applicable to MNGP; the applicant alsodiscussed exemptions based on these TLAAs. The staff reviewed the information to determine whether the applicant had provided adequate information to meet the requirements of10 CFR 54.21(c)(1) and 10 CFR 54.21(c)(2).The applicant provided a list of common TLAAs from NUREG-1800, "Standard Review Plan forReview of License Renewal Applications for Nuclear Power Plants," dated July 2001. The applicant listed those TLAAs that are applicable to MNGP in LRA Table 4.1-1.As required by 10 CFR 54.21(c)(2), an applicant must provide a list of all the exemptionsgranted under 10 CFR 50.12 that are based on a TLAA and evaluated and justified for continuation through the period of extended operation. In its LRA, the applicant stated that itreviewed each active exemption to determine whether the exemption was based on a TLAA.
The applicant did not identify any TLAA-based exemptions. On the basis of the information provided by the applicant with regard to the process used to identify TLAA-based exemptions, as well as the results of the applicant's search, the staff concluded that the applicant did notidentify any TLAA-based exemptions that are justified for continuation through the period ofextended operation, in accordance with 10 CFR 54.21(c)(2).4.1.3  Conclusion On the basis of its review, the staff concluded that the applicant provided an acceptable list ofTLAAs, as required by 10 CFR 54.21(c)(1). The staff also confirmed that no exemptions under 10 CFR 50.12 have been granted on the basis of a TLAA, as required by 10 CFR 54.21(c)(2).4.2  Neutron Embrittlement of the Reactor Vessel and InternalsThe materials of the reactor pressure vessel (RPV) and internals are subject to embrittlementresulting from high energy (E > 1 million electron volts (MeV)) neutron exposure. Embrittlementmeans the material has lower toughness (i.e., will absorb less strain energy during a crack orrupture), thus allowing a crack to propagate more easily under thermal and/or pressure loading.
4-3Toughness (indirectly measured in foot-pounds (ft-lb) of absorbed energy in a Charpy impacttest) is temperature dependent in ferritic materials. An initial nil-ductility reference temperature (RTNDT), the temperature associated with the transition from ductile to brittle behavior, isdetermined for vessel materials through a combination of Charpy and drop weight testing.
Toughness increases with temperature up to a maximum value called the "upper-shelf energy" (USE). Neutron embrittlement causes an increase in the RTNDT and a decrease in the USE ofRPV steels. The increase or shift in the initial nil ductility reference temperature (RTNDT) meanshigher temperatures are required for the material to continue to act in a ductile manner. To reduce the potential for brittle fracture during RPV operation by accounting for the changes inmaterial toughness as a function of neutron radiation exposure (fluence), operating pressure-temperature (P-T) limit curves are included in plant technical specifications (TSs). The P-T curves account for the decrease in material toughness associated with a given fluence, which is used to predict the loss in toughness of the RPV materials. Based on the projected drop in toughness for a given fluence, the P-T curves are generated to provide a minimum temperature limit associated with the vessel pressure. The P-T curves are determined by the
 
RTNDT and RTNDT values for the licensed operating period, along with appropriate margins.4.2.1  RPV Materials USE Reduction Due to Neutron Embrittlement 4.2.1.1  Summary of Technical Information in the ApplicationIn LRA Section 4.2.1, the applicant summarized the evaluation of the RPV materials USEreduction from neutron embrittlement for the period of extended operation. USE is the standardindustry parameter used to indicate the maximum toughness of a material at high temperature.
Appendix G, "Fracture Toughness Requirements," to 10 CFR Part 50, "Domestic Licensing of Production and Utilization Facilities," requires the predicted end-of-life Charpy impact test USEfor RPV materials to be at least 50 ft-lb (absorbed energy), unless an approved analysis supports a lower value. Initial unirradiated test data are available for only one plate heat for the MNGP RPV to demonstrate a minimum 50 ft-lb USE by standard methods. End-of-life fracture energy was evaluated by using an equivalent margin analysis (EMA) methodology approved by the NRC in NEDO-32205-A, Revision 1, "10 CFR 50 Appendix G Equivalent Margin Analysis forLow Upper Shelf Energy in BWR/2-6 Vessels," February 1994. This analysis confirmed that an adequate margin of safety against fracture, equivalent to the requirements of Appendix G to 10 CFR Part 50, does exist. The end-of-life USE calculations satisfy the criteria of 10 CFR 54.3(a), as described in SER Section 4.1. As such, these calculations are a TLAA.Fluence was calculated for the MNGP RPV for the extended 60-year (54 effective full-poweryears (EFPY)) licensed operating period using the methodology of NEDC-32983P, "General Electric (GE) Methodology for Reactor Pressure Vessel Fast Neutron Flux Evaluation,"
approved by the NRC in a letter dated September 14, 2001, from S.A. Richards, NRC, to J.F.Klapproth, GE. The NRC found that, in general, this methodology adheres to the guidance inRegulatory Guide (RG) 1.190, "Calculational and Dosimetry Methods for Determining Pressure Vessel Neutron Fluence," March 2001, for neutron flux evaluation. For MNGP, 54 EFPY is equivalent to 3.90x10 8 megawatt hours (MWh) through the end of Cycle 22 at 1775 megawattsthermal (MWt) plus 4.76x10 8 MWh at 1880 MWt. Peak fluence was calculated at the RPV innersurface (inner diameter) to evaluate USE. The value of neutron fluence was also calculated for the 1/4-thickness (1/4T) location into the RPV wall measured radially from the inside diameter (ID), using Equation 3 from Paragraph 1.1 of RG 1.99, Revision 2, "Radiation 4-4Embrittlement of Reactor Vessel Materials." This 1/4T depth is recommended in the AmericanSociety of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code Section XI, Appendix G, Subarticle G-2120 as the maximum postulated defect depth for calculating P-T curves.4.2.1.2  Staff Evaluation The staff reviewed LRA Section 4.2.1, pursuant to 10 CFR 54.21(c)(1)(ii), to verify that theanalyses have been projected to the end of the period of extended operation.Neutron Fluence EvaluationLRA Section 4.2.1 indicates that the applicant calculated neutron fluence for the MNGP RPV forthe extended 60-year (54 EFPY) licensed operating period based on 3.90x10 8 MWh throughCycle 22 at 1775 MWt plus 4.76x10 8 MWh at 1880 MWt. This calculation results in a peakneutron fluence of 5.17x10 18 neutrons per square centimeter (n/cm
: 2) (E>1.0 MeV), a peak 1/4Tfluence of 3.82x10 18 n/cm 2 (E>1.0 MeV) for the RPV, and a neutron fluence at the inside of theshroud of 3.84x10 21 n/cm 2 (E>1.0 MeV) at the end of the extended operating period. Originally,MNGP was licensed for 1670 MWt and uprated to 1775 MWt in October 1998 during fuel cycle 19.The staff's review of LRA Section 4.2.1 identified areas for which it needed additionalinformation to complete its evaluation of the applicant's neutron fluence evaluation. The applicant responded to the staff's requests for additional information (RAIs) as discussed below.In RAI 4.2-1, dated September 28, 2005, the staff requested that the applicant provide the basisfor the neutron flux estimates in the TLAA.In its response, by letter dated October 28, 2005, the applicant explained the following:Flux estimates for the MNGP were performed in accordance with the GeneralElectric methodology for neutron flux calculation documented in Licensing Topical Report (LTR) NEDC-32983P-A which has been approved by the NRC. Ingeneral, this methodology adheres to the guidance in Regulatory Guide 1.190 for neutron flux evaluation. A key input to this calculation was the total integratedpower (MWDth) through the first 22 cycles of operation. In addition, Cycle 22core data was used as a basis for the calculation. Flux profiles were generated from this data and, using the maximum flux, the integrated fluence at 54 EFPYwas determined. Fluence estimates at 54 EFPY were conservatively determined using 1775 MWt for Cycles 1 through 22 (previous to rerate implementation in the fall of 1998 the rated power was 1670 MWt) and 1880 MWt for the remainder of the license renewal period of extended operation (54 EFPY). This resulted in EFPYs of 25.09 and 28.91 respectively.In addition to the conservative methodology described above, a bias adjustmentderived from extensive benchmarking of the methodology against measured data as well as an uncertainty related to the flux calculation was incorporated. To account for variations in operation (e.g. capacity factor, core design, etc.), a 4-5multiplier of 1.3 was applied to the reactor pressure vessel to obtain a boundingfluence...In addition, in a letter dated June 10, 2005, the applicant confirmed that the 54 EFPY used inthe TLAA bounds plant-specific operation:NMC has determined that the 54 Effective Full Power Years (EFPY) used forTime-Limited Aging Analyses bounds the plant-specific EFPY for MNGP based on a conservative evaluation of plant history and projected capacity factors. This evaluation results in an expectation of less than 49.5 EFPY at the end of the license renewal period of extended operation. Assuming a 100 percent capacity factor over the same operating period also results in a projected less than 54 EFPY for MNGP.Based on its review, the staff found the applicant's response to RAI 4.2-1 acceptable. Becausethe applicant projected neutron fluence at the expiration of the extended period of operation byan NRC-approved methodology using conservative inputs, the staff considered the neutronfluence projection adequate for TLAA use for the RPV and shroud. Therefore, the staff's concern described in RAI 4.2-1 is resolved.USE EvaluationAppendix G to 10 CFR Part 50, provides the staff's criteria for maintaining acceptable levels ofCharpy USE for the RPV beltline materials throughout the licensed lives of operating facilities.The rule requires a minimum 75 ft-lb Charpy USE value for RPV beltline materials in the unirradiated condition and a 50 ft-lb minimum Charpy USE value throughout the life of the facility, unless analysis demonstrates that lower USE values will provide acceptable margins ofsafety against fracture equivalent to those required by ASME Code Section XI, Appendix G.
The rule also requires methods for calculating Charpy USE values to account for the effects of neutron irradiation on those values for the materials and to incorporate any relevant RPVsurveillance capsule data reported through a plant's RPV material surveillance program,created pursuant to Appendix H, "Reactor Vessel Material Surveillance ProgramRequirements," to 10 CFR Part 50.RG 1.99, Revision 2, expands the discussion regarding the calculation of Charpy USE valuesand describes two methods for calculating Charpy USE values for RPV beltline materials depending on whether a given RPV beltline material is included in the plant's RPV Material Surveillance Program (i.e., 10 CFR Part 50, Appendix H Program). If surveillance data are notavailable, Charpy USE is determined in accordance with regulatory position 1.2 in RG 1.99, Revision 2. If surveillance data are available, Charpy USE should be determined in accordance with regulatory position 2.2 in RG 1.99, Revision 2. These methods refer to RG 1.99,Revision 2, Figure 2, which indicates that the percentage drop in Charpy USE depends on the amount of copper in the material and the neutron fluence. Since the analyses performed inaccordance with Appendix G to 10 CFR Part 50 are based on a flaw with a depth equal to 1/4T, the neutron fluence used in the Charpy USE analysis is at the 1/4T depth location.By letter dated April 30, 1993, the Boiling Water Reactor Owners Group (BWROG) submittedNEDO-32205-A to demonstrate that boiling-water reactor (BWR) RPVs could meet margins ofsafety against fracture equivalent to those required by ASME Code Section XI, Appendix G, for 4-6Charpy USE values less than 50 ft-lb. In a letter dated December 8, 1993, the staff concludedthat the topical report demonstrated that the evaluated materials have margins of safety againstfracture equivalent to ASME Code Section XI, Appendix G, in accordance with Appendix G to 10 CFR Part 50. In that report, the BWROG derived through statistical analysis the unirradiatedCharpy USE values for materials that originally had no documented unirradiated Charpy USE values. Using these statistically derived Charpy USE values, the BWROG predicted the Charpy USE values through 40 years of operation, in accordance with RG 1.99, Revision 2. The BWROG analysis determined that the minimum allowable Charpy USE value in the transverse direction for base metal and along the weld for weld material was 35 ft-lb.Electric Power Research Institute (EPRI) Topical Report (TR)-113596, "BWR Vessel andInternals Project (BWRVIP) BWR Reactor Pressure Vessel Inspection and Flaw Evaluation Guidelines," BWRVIP-74, issued September 1999, documents the GE updated Charpy USEevaluation. An October 18, 2001, letter from Mr. C.I. Grimes to Mr. C. Terry documented staff review and approval of EPRI TR-113596. The analysis in EPRI TR-113596 used the methodology in RG 1.99, Revision 2, to determine the reduction in the unirradiated Charpy USEfrom neutron irradiation. Using this methodology and a correction factor of 65 percent for conversion of the longitudinal properties to transverse properties, the lowest Charpy USE at 54 EFPY for all BWR/3-6 plates was projected to be 45 ft-lb. The correction factor for specimen orientation in plates is based on NRC Branch Technical Position MTEB 5-2, "Fracture Toughness Requirements."  EMA acceptance criteria specified in the staff-approved report BWRVIP-74 using the methodology in RG 1.99, Revision 2, are based on the percent reductionin the unirradiated Charpy USE values from neutron radiation. The acceptance criteria specifiedin the BWRVIP-74 report indicate that the maximum allowable percent reduction in USE value is 23.5 percent for the plates and 39 percent for the welds.In RAI 4.2-2, dated September 28, 2005, the staff noted that because the analysis inBWRVIP-74 is generic, the applicant submitted plant-specific information in LRA Tables 4.2.1-1 and 4.2.1-2 for the limiting MNGP plates and welds to demonstrate that the RPV limiting beltlinematerials meet the criteria in the BWRVIP-74 report for the end of the license renewal period.
These tables do not include an evaluation of surveillance plate and weld data. Surveillance datawere submitted to the NRC in a letter dated December 21, 1998, containing Report SIR-97-003,Revision 2, "Review of the Results of Two Surveillance Capsules, and Recommendations for the Materials Properties and P-T Curves to be Used for the Monticello Reactor Pressure Vessel," which indicates that unirradiated Charpy USE data were available for surveillance plates, but not for surveillance welds. Therefore, Charpy USE evaluations using surveillance data could be performed for the plates but not the welds. The staff requested that the applicantdetermine the impact of the surveillance plate data on the limiting beltline plate USE andevaluate what impact, if any, these data have on the validity of the plate EMA.In its response, by letter dated October 28, 2005, the applicant stated the following:Using the '1 st Capsule' data for plate C2220-2 identified in Table 2-1 ofSIR-97-003, Revision 2 results in a measured decrease of 18.3 percent as opposed to an 11.5 percent predicted decrease using RG 1.99 Figure 2 as noted in LRA Table 4.2.1-1 at a fluence of 2.93x10 17 n/cm 2. Correspondingly, at the54 EFPY 1/4T fluence of 3.82x10 18 with an 18.3 percent measured decrease theRG1.99 Position 2.2 adjusted decrease is 33.5 percent which exceeds the margin to safety requirement of 23.5 percent defined in BWRVIP-74-A.
4-7Based on its review, the staff found the applicant's response to RAI 4.2-2 acceptable; however,in this response, the applicant demonstrated that the adjusted percent reduction obtained usingRG 1.99, position 2.2, also results in a 54 EFPY USE greater than 50 ft-lb for plate C2220-2. Asdescribed above, using data from SIR-97-003 results in a position 2.2 Charpy USE reduction of 33.5 percent at the expiration of the extended period of operation. With a transverseunirradiated USE of 86.5 ft-lb (0.65 x 133 ft-lbs), a 33.5 percent reduction results in a 54 EFPY Charpy USE of 57.5 ft-lb, which exceeds the 50 ft-lb minimum identified in Appendix G to 10 CFR Part 50. Because the projected USE exceeds the minimum recommended by Appendix G to 10 CFR Part 50, the staff found the applicant's response acceptable. Therefore, the staff'sconcern described in RAI 4.2-2 is resolved.There are four plates in the MNGP RPV beltline, one with USE greater than 50 ft-lbs, asdiscussed in the previous paragraph. The other three plates have no surveillance data;however, the applicant has used the RG 1.99, Revision 2, methodology to demonstrate thatthese three plates will have less than a 23.5 percent reduction in Charpy USE value at theexpiration of the extended period of operation. Therefore, these plates satisfy BWRVIP-74-Acriteria and the margins of safety against fracture equivalent to ASME Code Section XI, Appendix G, in accordance with Appendix G to 10 CFR Part 50.In RAI 4.2-3, dated September 28, 2005, the staff noted that the weld materials used in theMNGP RPV beltline were fabricated using the shielded metal arc weld (SMAW) process. Such welds are low in copper because the weld electrodes used in this process are not copper coated; therefore, the staff requested that the applicant calculate the projected Charpy USE forthe limiting weld and plate in the reactor vessel beltline at the 1/4T depth using the neutronfluence at the end of the period of extended operation.In its response, by letter dated October 28, 2005, the applicant analyzed the impact of neutronradiation on the RPV beltline welds. In this analysis, the weld material was projected to have a Charpy USE at the expiration of the extended period of operation of 68 ft-lb. The applicantutilized an unirradiated Charpy USE of 84.5 ft-lb, which is the lower 95/95 confidence value forthe SMAW database reported in BWRVIP-74-A. The drop in Charpy USE was calculated by the RG 1.99, Revision 2, methodology and a 0.10 percent copper. As the RPV beltline welds areprojected to have a Charpy USE at the expiration of the extended period of operation greaterthan 50 ft-lb, the RPV beltline weld material meets the criteria of Appendix G to 10 CFR Part 50 criteria at that point.LRA Table 4.2.2-1 indicates that N2 nozzles are within the beltline of the RPV. The MNGP N2nozzles were fabricated as forgings. In a letter dated February 27, 2006, the applicant provided additional data to demonstrate that, at the end of the period of extended operation, the N2nozzles will have Charpy USE values greater than 50 ft-lb. The applicant indicated:Given the hot working normally associated with the fabrication of forgings(resulting in a more refined grain structure), it is expected that the fracture toughness properties of the A 508 Class 2 forging materials would be equivalent, if not better than, the corresponding A 533 Grade B plate materials typically used to fabricate beltline shell courses. 508 Class 2 forging materials (or equivalent) have been used throughout the industry for fabrication of reactor vessel components, including the MNGP recirculation inlet (N2) nozzles, and as such, a 4-8significant amount of data has been reported on the fracture toughness of thesematerials.The applicant performed a study using the NRC Reactor Vessel Integrity Database, Revision 2(RVID2), to determine a generic Charpy USE for A 508 Class 2 forgings. The study indicates that the mean of the USE data for the forgings is 108 ft-lb, with a minimum observed USE of70 ft-lb and a standard deviation of 24 ft-lb. As defined in NUREG-1475, "Applying Statistics,"for 95/95 confidence with a data set consisting of 67 data points, the  value is 1.9996. Thisresults in a Mean- of 60 ft-lb. Using the RG 1.99 methodology for determining the impact ofneutron radiation on Charpy USE, the applicant determined that at the expiration of theextended license the Charpy USE will be 52 ft-lb. The staff has confirmed this value.The applicant compared the generic Charpy USE data from forgings with the generic CharpyUSE from plate material. The mean equivalent transverse Charpy USE was reported as 82.5 ft-lb for plate material in BWRVIP-74-A. The minimum observed Charpy USE was 59 ft-lb and the Mean- was 64.5 ft-lb for the plate material.The applicant also evaluated the RVID2 database surveillance capsule results for forgingmaterials with respect to plate materials. These results indicate that application of the RG 1.99 prediction to forgings adequately predicts the irradiated behavior of these materials.The applicant concluded the following:Therefore, it has been demonstrated that the forging materials meet or exceedthe requirements for plate materials, and that the MNGP N2 nozzle case is bounded by the [equivalent margins analysis] EMA plate requirements described in BWRVIP-74-A. Further, it has been demonstrated that, in general, irradiated forging materials behave in a manner consistent with the predictions of RG 1.99.
Based on the results of this evaluation, the USE of the N2 nozzle forgings will be adequate for the period of extended operation.The staff concluded that the analysis provided for the MNGP N2 nozzles demonstrates that thenozzles will have Charpy USE greater than 50 ft-lb and will meet the requirements of AppendixG to 10 CFR Part 50 at the expiration of the extended license. Therefore, the staff's concerndescribed in RAI 4.2-3 is resolved.Table 4.2.1-1 of this SER summarizes the staff's review of the calculated USE values.Table  4.2.1-1 Reactor Vessel Upper-Shelf Energy Analysis SummaryRV Beltline ComponentAcceptance Criterion for USEComponent Value for 54 EFPYC2220-2 Limiting Plate> 50 ft-lb57.5 ft-lbWelds-shielded metal arc> 50 ft-lb68 ft-lbN2 Nozzle-forging> 50 ft-lb52 ft-lb 4-94.2.1.3  USAR SupplementThe applicant provided a USAR supplement summary description of its TLAA evaluation of RPVmaterials USE reduction from neutron embrittlement in LRA Section A3.1. On the basis of its review of the USAR supplement, the staff concluded that the summary description of the applicant's actions to address the RPV materials USE reduction from neutron embrittlement is
 
adequate.4.2.1.4  Conclusion The staff concluded that the applicant provided an acceptable demonstration, pursuant to10 CFR 54.21(c)(1)(ii), that the analyses of the RPV materials Charpy USE reduction from neutron embrittlement have been projected to the end of the period of extended operation. Thestaff also concluded that the USAR supplement contains an appropriate summary description of this TLAA evaluation, sufficient to satisfy the requirements of 10 CFR 54.21(d).4.2.2Adjusted Reference Temperature for RPV Materials Due to Neutron Embrittlement 4.2.2.1  Summary of Technical Information in the ApplicationIn LRA Section 4.2.2, the applicant summarized the evaluation of the adjusted referencetemperature (ART) for RPV materials from neutron embrittlement for the period of extended operation. The initial RTNDT is the temperature at which a nonirradiated metal (ferritic steel)changes in fracture characteristics, going from ductile to brittle behavior. The applicant evaluated the RTNDT according to the procedures in ASME Code, Paragraph NB-2331. Neutronembrittlement raises the initial RTNDT. Appendix G to 10 CFR Part 50 defines the fracturetoughness requirements for the life of the vessel. The RTNDT is evaluated as the difference inthe 30 ft-lb index temperatures from the average Charpy curves measured before and after irradiation. This increase (RTNDT) means that higher temperatures are required for the materialto continue to act in a ductile manner. The ART is defined as RTNDT + RTNDT + margin. Themargin is defined in RG 1.99. The P-T curves are developed from the ART for the RPV materials. These are determined by the unirradiated RTNDT and by the RTNDT calculations forthe licensed operating period. RG 1.99 defines the calculation methods for RTNDT, ART, andend-of-life USE. The RTNDT and ART calculations meet the criteria of 10 CFR 54.3(a). As such,they are TLAAs.4.2.2.2  Staff Evaluation The staff reviewed LRA Section 4.2.2, pursuant to 10 CFR 54.21(c)(1)(ii), to verify that theanalyses have been projected to the end of the period of extended operation.LRA Table 4.2.2-1 provides the ART values for all beltline materials at the expiration of theextended operating period. The materials with the highest ART values are the C2220-1 and C2220-2 plates, which have 0.17 percent copper and 0.65 percent nickel. Using the RG 1.99,Revision 2, methodology and a neutron fluence of 3.82x10 18 n/cm 2 (E>1 MeV) at the 1/4Tlocation, the ART for these plates is 157 F at the expiration of the extended operating period.
4-10The weld material, which has 0.10 percent copper and 0.99 percent nickel, has an ART of 97 Fat the expiration of the extended operating period.The N2 nozzles have an ART of 117 F. The certified material test report includes nickelcontent and initial RTNDT data, but not copper content data. The copper value (0.18 percent) inthe analysis is generic, derived from data from nine nozzles in other BWR beltline nozzles. The value in the analysis is the mean plus one standard deviation value and is acceptable to the staff because it is consistent with the RG 1.99, Revision 2, criteria when copper is not reportedfor the material.The copper and nickel values for the plates and weld material are consistent with thosereported in RVID2. The staff confirmed the applicant's projected values of ART. These ART values are used in the P-T limits evaluation. P-T limits in the MNGP TSs are periodically updated (discussed in SER Section 4.2.5).4.2.2.3  USAR Supplement The applicant provided a USAR supplement summary description of its TLAA ART evaluationfor RPV materials from neutron embrittlement in LRA Section A3.1. On the basis of its review of the USAR supplement, the staff concluded that the summary description of the applicant'sactions to address the ART for RPV materials from neutron embrittlement is adequate.4.2.2.4  Conclusion The staff concluded that the applicant provided an acceptable demonstration, pursuant to10 CFR 54.21(c)(1)(ii), that the analyses of the ART for RPV materials from neutron embrittlement have been projected to the end of the period of extended operation. The staffalso concluded that the USAR supplement contains an appropriate summary description of this TLAA evaluation, sufficient to satisfy the requirements of 10 CFR 54.21(d).4.2.3  Reflood Thermal Shock Analysis of the RPV 4.2.3.1  Summary of Technical Information in the ApplicationIn LRA Section 4.2.3, the applicant summarized the evaluation of the reflood thermal shockanalysis of the RPV for the period of extended operation. The MNGP USAR includes an end-of-life thermal shock analysis performed on the RPV for a design-basis loss-of-coolant accident (LOCA) followed by a low-pressure coolant injection (LPCI). The effects of neutron embrittlement assumed by this thermal shock analysis will change with an increase in thelicensed operating period. This analysis satisfies the criteria of 10 CFR 54.3(a). As such, this analysis is a TLAA.4.2.3.2  Staff Evaluation The staff reviewed LRA Section 4.2.3, pursuant to 10 CFR 54.21(c)(1)(ii), to verify that theanalyses have been projected to the end of the period of extended operation.
4-11The peak fluence at the RPV wall is 5.17x10 18 n/cm 2 (E>1.0 MeV) for 54 EFPY of operation.Based on this fluence value, the previous reflood thermal shock analysis of the RPV is not bounding for the period of extended operation. The original analysis has been superseded by an analysis for BWR-6 RPVs that is applicable to the MNGP BWR-3 RPV.The BWR-6 RPV analysis applies to MNGP because it uses a bounding main steamline breakevent and an RPV thickness similar to that of the MNGP RPV. This analysis assumes end-of-license material toughness, which in turn depends on the end-of-license ART. The critical location for the fracture mechanics analysis is at 1/4T RPV thickness. For the main steamline break event, the peak stress intensity occurs approximately 300 seconds after initiation of the event. The analysis shows that at that point in the thermal shock event, thetemperature of the vessel wall at 1.5 inches deep (1/4T depth for the BWR-6 RPV) is approximately 400 F. For the MNGP vessel, the 1/4T depth is 1.26 inches.The staff's review of LRA Section 4.2.3 identified an area for which it needed additionalinformation to complete its evaluation of the applicant's neutron fluence evaluation. The applicant responded to the staff's RAI as discussed below.In RAI 4.2-4, dated September 28, 2005, the staff requested that the applicant provide thefracture toughness (peak stress intensity value) required to prevent fracture of the RPV resulting from reflood thermal shock.In its response, dated October 28, 2005, the applicant identified the maximum applied stressintensity for the thermal shock event as 103 kilopounds per square inch times the square root of inches (ksi-in1/2). Fracture toughness at approximately 300 seconds after initiation of the eventwas estimated to be 200 ksi-in1/2. In its response, the applicant stated the following:Paper G1/5, 'Fracture Mechanics Evaluation of a Boiling Water Reactor VesselFollowing a Postulated Loss of Coolant Accident,' Ranganath, S., Fifth International Conference on Structural Mechanics in Reactor Technology, Berlin, Germany, August 1979, defines the basis for this evaluation. As noted in the MNGP LRA submittal, the BWR/6 example in the paper referenced above bounds the conditions at the MNGP. This was demonstrated in the submittal by comparison of the parameters for the BWR/6 case versus the plant-specific MNGP case. As shown in the submittal, the plant-specific temperature at 1/4T depth into the vessel wall was determined to be 370 F at 300 seconds into thethermal shock event. It was also stated that using the highest 60 year Adjusted Reference Temperature (ART), the beltline material reaches upper shelf (200 ksi-in1/2) at 261 oF. Since this temperature is significantly lower than 370 oF, itis assured that the beltline material remains at upper shelf at 300 seconds into the thermal shock event. Figure 5 of 'Fracture Mechanics Evaluation of a BoilingWater Reactor Vessel Following a Postulated Loss of Coolant Accident,'
Ranganath, S., Fifth International Conference on Structural Mechanics in Reactor Technology, Berlin, Germany, August 1979, Paper GI/5, further demonstrates that at 300 seconds into the thermal shock event and at 1/4Tdepth into the vessel wall, the maximum applied stress intensity is 103 ksi-in1/2.Therefore, there is sufficient margin to prevent fracture due to reflood thermal shock.
4-12On the basis of its review, the staff found the applicant's response to RAI 4.2-4 acceptablebecause the applicant demonstrated that the beltline materials will have adequate fracturetoughness (applied stress intensity is less than upper-shelf fracture toughness) at 300 seconds into the event through the period of extended operation. The revised analysis demonstrates thatthe reflood thermal shock analysis of the RPV applies for the extended period of operation.Therefore, the staff's concern described in RAI 4.2-4 is resolved.4.2.3.3  USAR Supplement The applicant provided a USAR supplement summary description of its TLAA evaluation ofreflood thermal shock analysis of the RPV in LRA Section A3.1. On the basis of its review of the USAR supplement, the staff concluded that the summary description of the applicant's actions to address the reflood thermal shock analysis of the RPV is adequate.4.2.3.4  Conclusion The staff concluded that the applicant provided an acceptable demonstration, pursuant to10 CFR 54.21(c)(1)(ii), that the analyses of the reflood thermal shock analysis of the RPV havebeen projected to the end of the period of extended operation. The staff also concluded that theUSAR supplement contains an appropriate summary description of this TLAA evaluation, sufficient to satisfy the requirements of 10 CFR 54.21(d).4.2.4  Reflood Thermal Shock Analysis of the RPV Core Shroud 4.2.4.1  Summary of Technical Information in the ApplicationIn LRA Section 4.2.4, the applicant summarized the evaluation of the reflood thermal shockanalysis of the RPV core shroud for the period of extended operation. Radiation embrittlementmay affect the ability of RPV internals, particularly the core shroud, to withstand an LPCIthermal shock transient. The analysis of core shroud strain from reflood thermal shock is a TLAA because it is part of the CLB, supports a safety determination, and is based on the calculated lifetime neutron fluence.4.2.4.2  Staff Evaluation The staff reviewed LRA Section 4.2.4, pursuant to 10 CFR 54.21(c)(1)(ii), to verify that theanalyses have been projected to the end of the period of extended operation.Before license renewal, the RPV core shroud was evaluated for an LPCI reflood thermal shocktransient considering embrittlement effects of a 40-year radiation exposure (32 EFPY). The core shroud receives the maximum irradiation on the inside surface opposite the midpoint of the fuel centerline. The total integrated neutron flux at the end of 40 years of operation was2.7x10 20 n/cm 2 (greater than 1 MeV). The maximum thermal shock stress in this region is155,700 pounds per square inch (psi), equivalent to 0.57-percent strain. This strain range of 0.57 percent was calculated at the midpoint of the shroud, the zone of highest neutronirradiation.
4-13However, using the approved fluence methodology discussed in SER Section 4.2.1.2, theapplicant revised the analysis for the period of extended operation by calculating the 54 EFPYfluence at the most irradiated point on the core shroud to be 3.84x10 21 n/cm 2. The applicantindicated that the measured value of percent elongation for stainless steel weld metal is4 percent for a temperature of 297 C (567 F) with a neutron fluence of 8x10 21 n/cm 2 (greaterthan 1 MeV), while the average value for base metal at 290 C (554 F) is 20 percent. Thecalculated strain range of 0.57 percent represents a considerable margin of safety relative to measured values of percent elongation for annealed Type 304 stainless steel irradiated to 8x10 21 n/cm 2 (greater than 1 MeV). Because the measured value of elongation bounds thecalculated thermal shock strain amplitude of 0.57 percent, the calculated thermal shock strainat the most irradiated location is acceptable, considering the embrittlement effects for a 60-yearoperating period.The revised analysis demonstrates that the reflood thermal shock analysis of the RPV coreshroud applies for the extended period of operation and satisfies 10 CFR 54.21(c)(1)(ii) because the applicant provided additional data to justify operation to a higher neutron fluence to the end of the period of extended operation.4.2.4.3  USAR Supplement The applicant provided a USAR supplement summary description of its TLAA evaluation ofreflood thermal shock analysis of the RPV core shroud in LRA Section A3.1. On the basis of its review of the USAR supplement, the staff concluded that the summary description of the applicant's actions to address the reflood thermal shock analysis of the RPV core shroud is
 
adequate.4.2.4.4  Conclusion The staff concluded that the applicant provided an acceptable demonstration, pursuant to10 CFR 54.21(c)(1)(ii), that the reflood thermal shock analyses of the RPV core shroud have been projected to the end of the period of extended operation. The staff also concluded that theUSAR supplement contains an appropriate summary description of this TLAA evaluation, sufficient to satisfy the requirements of 10 CFR 54.21(d).4.2.5  RPV Thermal Limit Analysis:  Operating Pressure-Temperature Limits 4.2.5.1  Summary of Technical Information in the ApplicationIn LRA Section 4.2.5, the applicant summarized the evaluation of the RPV thermal limitanalysis: operating P-T limits for the period of extended operation. The RPV thermal limitanalysis provides operating P-T limits for the period of extended operation and is dependent on the ART. The ART is the value of initial RTNDT + RTNDT + margins (for uncertainties) at aspecific location. Neutron embrittlement increases the ART. Thus, the minimum metal temperature at which an RPV is allowed to be pressurized increases. The ART of the limiting beltline material is used to correct the beltline P-T limits to account for irradiation effects.
Appendix G to 10 CFR Part 50 requires RPV thermal limit analyses to determine operating P-T limits for boltup, hydrotest, pressure tests, and normal operating and anticipated operationaloccurrences. Operating limits for pressure and temperature are required for three categories of 4-14operation-(1) hydrostatic pressure tests and leak tests, referred to as Curve A, (2) nonnuclearheatup/cooldown and low-level physics tests, referred to as Curve B, and (3) core-critical operation, referred to as Curve C. P-T limits are developed for three vessel regions, the upper vessel region, the core beltline region, and the lower vessel bottom head region. The calculations associated with generation of the P-T curves satisfy the criteria of 10 CFR 54.3(a).
As such, this topic is a TLAA.4.2.5.2  Staff Evaluation The staff reviewed LRA Section 4.2.5, pursuant to 10 CFR 54.21(c)(1)(ii), to verify that theanalyses have been projected to the end of the period of extended operation.The MNGP TSs include P-T limit curves for core-critical operation, nonnuclearheatup/cooldown, inservice leakage, and hydrostatic testing. They also limit the maximum rate of change of reactor coolant temperature. The criticality curves provide limits for both heatup and criticality calculated for a 32-EFPY operating period. The current TSs contain P-T curves developed using the 1989 edition of the ASME Boiler and Pressure Vessel Code, incorporating the effects of the 1998 power uprate, and ASME Code Case N-640, "Alternative Reference Fracture Toughness for Development of P-T Limit Curves Section XI, Division 1."P-T limit curves in the MNGP TS are updated periodically, most recently in a February 24, 2003, NRC letter. The staff's February 24, 2003, safety evaluation (SE) indicates that the staffperformed an independent assessment of the proposed curves. The assessment concluded that the irradiated P-T limit curves for 32 EFPY generated at the plant will be at least asconservative as those that will be generated with ASME Code Section XI, Appendix G, criteriaand methods, as modified by ASME Code Case N-640, and the limit curves met the minimum temperature requirements in Table 1 of Appendix G to 10 CFR Part 50. The assessment was performed for P-T limit curves in which the 1/4T ART value was 157 F. Because SERSection 4.2.2.2 indicates a 1/4T ART value of 157 F at the expiration of the extended operatingperiod, the TS P-T limit curves apply to the end of the period of extended operation. Thisconclusion will be reevaluated when surveillance data for the RPV are withdrawn and tested aspart of the BWRVIP Integrated Surveillance Program.4.2.5.3  USAR Supplement The applicant provided a USAR supplement summary description of its TLAA evaluation of RPVthermal limit analysis-operating P-T limits in LRA Section A3.1. On the basis of its review of the USAR supplement, the staff concluded that the summary description of the applicant'sactions to address the RPV thermal limit analysis-operating P-T limits is adequate.4.2.5.4  Conclusion The staff concluded that the applicant provided an acceptable demonstration, pursuant to10 CFR 54.21(c)(1)(ii), that the RPV thermal limit analysis-operating P-T limits analyses have been projected to the end of the period of extended operation. The staff also concluded that theUSAR supplement contains an appropriate summary description of this TLAA evaluation, sufficient to satisfy the requirements of 10 CFR 54.21(d).
4-154.2.6  RPV Circumferential Weld Examination Relief4.2.6.1  Summary of Technical Information in the ApplicationIn LRA Section 4.2.6, the applicant summarized the evaluation of the RPV circumferential weldexamination relief for the period of extended operation. Relief from RPV circumferential weldexamination requirements under Generic Letter 98-05, "Boiling Water Reactor Licensees Useof the BWRVIP-05 Report to Request Relief from Augmented Inspection," is based on probabilistic assessments that predict an acceptable pr obability of failure per reactor operatingyear. The analysis is based on RPV metallurgical conditions, as well as flaw indication sizes and frequencies of occurrence that are expected at the end of a licensed operating period.MNGP has received this relief for the remaining 40-year licensed operating period. The circumferential weld examination relief analysis meets the requirements of 10 CFR 54.3(a). Assuch, it is a TLAA.4.2.6.2  Staff Evaluation The staff reviewed LRA Section 4.2.6, pursuant to 10 CFR 54.21(c)(1)(ii), to verify that theanalyses have been projected to the end of the period of extended operation.The technical basis for relief is discussed in the staff's final SER concerning the BWRVIP-05report, "BWR Vessel and Internals Project (BWRVIP), BWR Reactor Pressure Vessel Weld Inspection Requirements," enclosed in the letter dated July 28, 1998, from Mr. G.C. Laines, NRC, to Mr. C. Terry, the BWRVIP Chairman. In this letter, the staff concluded that, becausethe 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, continued inspection of the RPV circumferential welds will result ina negligible decrease in an already acceptably low rate of RPV failure; therefore, elimination of the inservice inspection (ISI) for RPV circumferential welds is justified. The staff's letter indicated that BWR applicants may request relief from 10 CFR 50.55a(g) ISI requirements for volumetric examination of circumferential RPV welds by demonstrating that (1) through the expiration of the license period, the circumferential welds satisfy the limiting conditional failure probability for circumferential welds in the NRC staff's July 28, 1998, evaluation and(2) implementation of operator training and established procedures that limit the frequency ofcold overpressure events to the frequency specified in the staff's SER. The letter indicated that the requirements for inspection of circumferential RPV welds during an additional 20-year license renewal period will be reassessed, on a plant-specific basis, as part of any BWR LRA;therefore, the applicant must request relief from inspection of circumferential welds during the license renewal period, pursuant to 10 CFR 50.55a.Section A.4.5 of the BWRVIP-74 report indicates that the staff's SER of the BWRVIP-05 reportconservatively evaluated the BWR RPVs to 64 EFPY, which is 10 EFPY greater than realistically expected for the end of the license renewal period. In the July 28, 1998, SER, thestaff used the mean RTNDT value for materials to evaluate failure probability of BWRcircumferential welds at 32 and 64 EFPY. The neutron fluence at the clad-weld (inner) interface was used for this evaluation.
4-16Since the staff analysis discussed in the BWRVIP-74 report is generic, the applicant submittedplant-specific information to demonstrate that the MNGP RPV beltline materials meet the criteria specified in the report. To demonstrate that the MNGP RPV has not become embrittled beyond the basis for the relief, the applicant, in LRA Table 4.2.6.1, compared 54 EFPY materialdata for the limiting MNGP circumferential weld with that of the 64 EFPY reference case in Appendix E to the staff's SER on the BWRVIP-05 report. The MNGP material data included amounts of copper and nickel, chemistry factor, the neutron fluence, RTNDT, initial RTNDT , andmean RTNDT of the limiting circumferential weld at the end of the renewal period. The staff hasverified the data for the copper and nickel contents and the initial RTNDT values for the MNGPcircumferential beltline weld material by comparing them with the corresponding data in RVID.
The 54 EFPY mean RTNDT value for the MNGP circumferential beltline weld is 47.4 F. The staffchecked the applicant's calculations for the 54 EFPY mean RTNDT values for the limiting MNGPcircumferential welds using the data presented in LRA Table 4.2.6.1 and found them to beaccurate. This 54 EFPY mean RTNDT value for MNGP is bounded by the 64 EFPY mean RTNDTvalue of 70.6 F used by the NRC to determine conditional failure probability of a circumferentialweld in a Chicago Bridge and Iron (CB&I) fabricated RPV. The 64 EFPY mean RTNDT valuefrom the staff SER dated July 28, 1998, is for a CB&I weld because CB&I welded the circumferential welds in the RPV. Because the 54 EFPY mean RTNDT value is less than the64 EFPY value from the staff SER dated July 28, 1998, the staff concluded that the NRCanalysis bounds the MNGP RPV conditional failure probability.The applicant stated that the procedures and training used to limit cold overpressure events willbe the same as those approved by the NRC when MNGP requested relief for the currentlicense period. A request for relief during the period of extended operation will be submitted tothe NRC before the period of extended operation.SER Table 4.2.6-1 summarizes the results of the staff's evaluation regarding the RPVcircumferential weld examination relief.Table 4.2.6-1  Effects of Irradiation on RPV Circumferential Weld Properties for MNGPValueCB&I 64 EFPYMNGP 54 EFPYCu (%)0.100.10Ni (%)0.990.99CF134.9138.5Fluence x 10 19 (n/cm 2)1.020.52 DRT NDT (F)135.6113 RT NDT (F)-65-65.6Mean RT NDT (F)70.647.4Probability of a failure event (NRC)1.78x10
-5Note 1Note 1. If the plant-specific mean RTNDT is less than the mean RTNDT associated withthe limiting case study, the staff concludes that the probability of failure for theplant-specific circumferential weld under review will be less than the conditionalprobability of failure value for the limiting circumferential weld in the limiting case study.
4-174.2.6.3  USAR SupplementThe applicant provided a USAR supplement summary description of its TLAA evaluation of RPVcircumferential weld examination relief in LRA Section A3.1. On the basis of its review of the USAR supplement, the staff concluded that the summary description of the applicant's actions to address the RPV circumferential weld examination relief is adequate.4.2.6.4  Conclusion The staff concluded that the applicant provided an acceptable demonstration, pursuant to10 CFR 54.21(c)(1)(ii), that the analyses of the RPV circumferential weld examination reliefhave been projected to the end of the period of extended operation. The staff also concludedthat the USAR supplement contains an appropriate summary description of this TLAA evaluation, sufficient to satisfy the requirements of 10 CFR 54.21(d).4.2.7  RPV Axial Weld Failure Probability 4.2.7.1  Summary of Technical Information in the ApplicationIn LRA Section 4.2.7, the applicant summarized the evaluation of the RPV axial weld failureprobability for the period of extended operation. The BWRVIP recommendations for inspectionof RPV shell welds contain generic analyses supporting an NRC SER conclusion that thegeneric-plant axial weld failure rate is no more than 5x10
-6 per reactor year. BWRVIP-05showed that this axial weld failure rate of 5x10
-6 per reactor year is orders of magnitude greaterthan the 40-year end-of-life circumferential weld failure probability and this analysis justifiedrelief from inspection of the circumferential welds, as described in Section 4.2.6. MNGP received relief from the circumferential weld inspections for the remaining 40-year licensed operating period. The axial weld failure probability analysis meets the requirements of10 CFR 54.3(a). As such, it is a TLAA.4.2.7.2  Staff Evaluation The staff reviewed LRA Section 4.2.7, pursuant to 10 CFR 54.21(c)(1)(ii), to verify that theanalyses have been projected to the end of the period of extended operation.In its July 28, 1998, letter to Mr. C. Terry, the BWRVIP Chairman, the staff identified a concernabout the failure frequency of axially oriented welds in BWR RPVs. 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 SER on these analyses is enclosed in a March 7, 2000, letter from Mr. J. Strosnider (NRC) to Mr. C. Terry, BWRVIP Chairman. The staffperformed a generic analysis using Pilgrim as a model for BWR RPVs. The staff analysis identified as Mod 2 that the vessel failure frequency will be 5.02 x 10
-6 at a mean RTNDT at thevessel inside surface of 114 F.LRA Table 4.2.7-1 compared 54 EFPY material data for the limiting RPV axial weld with that ofMod 2 from the staff's SE in the March 7, 2000, letter. The MNGP material data included copper and nickel amounts, chemistry factor, neutron fluence, RTNDT, initial RTNDT, and mean RTNDT of the limiting axial weld at the end of the renewal period. The applicant calculated, and 4-18the staff confirmed, that the limiting axial weld mean RTNDT at the inside surface at theexpiration of the extended operating period is 47.4 F. Because the mean RTNDT at the vesselinside surface for the limiting axial weld is less than the value in the staff's Mod 2 analysis, the failure frequencies for the MNGP RPV will be less than 5 x 10
-6 per reactor year of operation atthe end of the period of extended operation; therefore, this analysis is acceptable.SER Table 4.2.7-1 summarizes the results of the staff's evaluation regarding the RPV axialweld failure probability.Table 4.2.7-1  Effects of Irradiation on RPV Axial Weld Properties for MNGPValueMod 2MNGP 54 EFPYCu (%)0.2190.10Ni (%)0.9960.99 CF138.5Fluence x 10 19 (n/cm 2)0.1480.52 DRT NDT (F)116113 RT NDT (F)-2-65.6Mean RT NDT (F)11447.4Probability of a failure event (NRC)5.02x10
-6Note 1Note 1. If the plant-specific mean RTNDT is less than the mean RTNDT associated withthe limiting case study, the staff concluded that probability of failure for the plant-specificaxial weld under review will be less than the conditional probability of failure value for thelimiting axial weld in the limiting case study.4.2.7.3  USAR Supplement The applicant provided a USAR supplement summary description of its TLAA evaluation of RPVaxial weld failure probability in LRA Section A3.1. On the basis of its review of the USARsupplement, the staff concluded that the summary description of the applicant's actions to address the RPV axial weld failure probability is adequate.4.2.7.4  Conclusion The staff concluded that the applicant has provided an acceptable demonstration, pursuant to10 CFR 54.21(c)(1)(ii), that the RPV axial weld failure probability analyses have been projectedto the end of the period of extended operation. The staff also concluded that the USARsupplement contains an appropriate summary description of this TLAA evaluation, sufficient to satisfy the requirements of 10 CFR 54.21(d).
4-194.3Metal Fatigue of the RPV and Internals, and Reactor Coolant Pressure BoundaryPiping and ComponentsA metal component subject to cyclic loads less than the static design load may fail from fatigue.Metal fatigue of components may have been evaluated based on an assumed number of transients or cycles for the current operating term. The validity of such metal fatigue analysis isreviewed for the period of extended operation.The specific criterion for fatigue analysis of ASME Code Section III components involvescalculating the cumulative usage factor (CUF). The fatigue damage in the component caused by each thermal or pressure transient depends on the magnitude of the stresses caused by the transient. The CUF sums the fatigue damage from each transient. The ASME Code Section III criterion requires that the CUF not exceed 1.0.4.3.1  RPV Fatigue Analyses 4.3.1.1  Summary of Technical Information in the ApplicationIn LRA Section 4.3.1, the applicant discussed that the  RPV was designed to ASME Code,Section III. RPV fatigue analyses were performed for the vessel support skirt, shell, upper andlower heads, closure flanges, nozzles and penetrations, nozzle safe ends, and closure studs.
The end of the 40-year license fatigue usage was determined for the normal and upset pressure and thermal cycle events. After the original stress analyses, several hardwarechanges, operational changes (e.g., the 1998 power rerate), and/or stress analysis revisions have affected usage factors. Calculation of fatigue usage factors is part of the CLB and used to support safety determinations. The RPV fatigue analyses are TLAAs.The applicant stated that the 1998 MNGP power rerate included a reanalysis of the RPV. LRATable 4.3.1-1 lists the limiting design CUFs for the RPV components. The applicant stated thatthe fatigue usage factors in Table 4.3.1-1 were determined using the actual transient cyclesfrom its Fatigue Monitoring Program (FMP). On the basis of the actual transient accumulation rate, the applicant concluded that fatigue usage of the RPV components is not expected toexceed the allowable limit of 1.0 during the period of extended operation. The applicant alsostated that the Fatigue Monitoring Program will monitor transients contributing to fatigue usage,as described in Appendix B to the LRA.4.3.1.2  Staff Evaluation The staff reviewed LRA Section 4.3.1, pursuant to 10 CFR 54.21(c)(1)(iii), to verify that theeffects of aging on the intended functions will be adequately managed for the period ofextended operation, and, pursuant to 10 CFR 54.21(c)(1)(ii), that the analyses have beenprojected to the end of the period of extended operation.The RPV components were analyzed using the ASME Code fatigue requirements. LRATable 4.3.1-1 lists the design transients for the fatigue analysis of the RPV components. USARTable 4.2-1 lists the design transients for the RPV fatigue analysis. The staff confirmed that the transients in LRA Table 4.3.1-1 are the same as those in USAR Table 4.2-1.
4-20The staff's review of LRA Section 4.3.1 identified an area for which it needed additionalinformation to complete its evaluation of the RPV fatigue analysis. The applicant responded to the staff's RAI as discussed below.Table 4.3.1-1 also provides the estimated 60-year fatigue usage factors for the RPVcomponents, which are all less than the ASME Code Section III allowable limit of 1.0. Theapplicant indicated that these usage factors include the results of a reanalysis of RPVcomponents performed as part of the 1998 power rerate. The applicant also indicated that the fatigue usage factors were determined from the FMP.In RAI 4.3.1-1, dated June 21, 2005, the staff requested that the applicant describe how it hadcalculated the revised fatigue usage factors.In its response, dated July 21, 2005, the applicant stated that GE Document SASR 89-77,"Accumulated Fatigue Usage for the Monticello Nuclear Generating Station Reactor Pressure,"tabulates thermal transient (TT) cycles experienced by MNGP through July 1989. As discussedin SASR 89-77, the number of transient cycles through July 1989 was determined from a reviewof operator log books and plant records. The applicant stated that its FMP updates the numberof TT cycles once per refueling cycle. The applicant used t hese updated cycles to compute thefatigue usage factors in LRA Table 4.3.1-1.Based on its review, the staff found the applicant's response to RAI 4.3.1-1 acceptable becauseuse of the actual TT cycles to estimate the fatigue usage factors for the period of extendedoperation is reasonable; therefore, the staff's concern described in RAI 4.3.1-1 is resolved.The applicant will rely on its FMP to assure that the fatigue usage of the RPV components willremain within ASME Code Section III allowable limits during the period of extended operation.4.3.1.3  USAR Supplement The applicant provided a USAR supplement summary description of its TLAA evaluation of RPVfatigue analyses in LRA Section A3.2. On the basis of its review of the USAR supplement, the staff concluded that the summary description of the applicant's actions to address the RPV fatigue analyses is adequate.4.3.1.4  Conclusion The staff reviewed the applicant's TLAA regarding the RPV fatigue analyses, as summarized inLRA Section 4.3.1. The staff concluded that the applicant has demonstrated that, pursuant to10 CFR 54.21(c)(1)(iii), the effects of aging on the intended functions will be adequatelymanaged for the period of extended operation, and, pursuant to 10 CFR 54.21(c)(1)(ii), theanalyses have been projected to the end of the period of extended operation. The staff alsoconcluded that the USAR supplement contains an appropriate summary description of this TLAA evaluation sufficient to satisfy 10 CFR 54.21(d) requirements.
4-214.3.2  Fatigue Analysis of RPV Internals4.3.2.1  Summary of Technical Information in the ApplicationIn LRA Section 4.3.2, the applicant discussed the fatigue analysis of the reactor vesselinternals (RIT), indicating that the analysis was performed using  ASME Code, Section III criteria. The applicant stated that the most significant fatigue loading occurs at the jet pumpdiffuser-to-baffle plate weld location. The original 40-year calculation showed a CUF of approximately 0.33. The applicant estimated the 60-year RIT fatigue usage by multiplying the 40-year fatigue usage by 1.5. The applicant concluded that the fatigue usage of the RIT willremain below the allowable limit of 1.0 through the period of extended operation.4.3.2.2  Staff Evaluation The staff reviewed LRA Section 4.3.2, pursuant to 10 CFR 54.21(c)(1)(ii), to verify that theanalyses have been projected to the end of the period of extended operation.The applicant stated that the RIT fatigue analysis was guided by ASME Code Section IIIcriteria. The applicant indicated that the most significant fatigue loading occurs at the jet pumpdiffuser-to-baffle plate weld location. The applicant's evaluation included three transients, (1) normal startup and shutdown, (2) improper start of a recirculation loop, and (3) design-basis accident (DBA).The applicant stated that the 60-year fatigue usage of the RIT was estimated by multiplying theoriginal fatigue usage by a factor of 1.5.The staff's review of LRA Section 4.3.2 identified an area for which it needed additionalinformation to complete its evaluation of the RIT fatigue analysis. The applicant responded to the staff's RAI as discussed below.In RAI 4.3.2-1, dated June 21, 2005, the staff requested that the applicant confirm that theextrapolation bounded the number of startup/shutdown design cycles listed in LRASection 4.3.1.In its response, dated July 21, 2005, the applicant reiterated that the most significant fatiguelocation for the RIT is at the jet pump diffuser-to-baffle plate weld. The applicant stated that thestartup/shutdown cycles had a negligible impact on fatigue usage at this location. The applicantstated that the only significant contributor to fatigue for the jet pump-to-baffle plate weld is thetransient that includes improper recirculation pump startup and post-DBA flooding. USAR Section 3.6.3.3 indicates that the RIT were originally evaluated for three improper recirculationpump starts. The applicant evaluated the impact of the updated number of design cycles listedin LRA Section 4.3.1 and found that the increase in the number of improper recirculation pumpstarts had no significant impact on fatigue usage. Therefore, the applicant concluded that theuse of the 1.5 factor to estimate the 60-year fatigue usage was conservative.Since the number of postulated DBA events does not increase for the period of extendedoperation and the increase in the number of improper recirculation pump starts has no 4-22significant impact on fatigue usage, the staff concluded that the applicant had adequatelyevaluated the RIT.Based on its review, the staff found the applicant's response to RAI 4.3.2-1 acceptable becausethe applicant performed an acceptable evaluation of the RIT for the period of extendedoperation, in accordance with the 10 CFR 54.21(c)(1)(ii) requirements; therefore, the staff'sconcern described in RAI 4.3.2-1 is resolved.4.3.2.3  USAR Supplement The applicant provided a USAR supplement summary description of its TLAA evaluation offatigue analysis of RPV internals in LRA Section A3.2. On the basis of its review of the USAR supplement, the staff concluded that the summary description of the applicant's actions to address the fatigue analyses of RPV internals is adequate.4.3.2.4  Conclusion The staff reviewed the applicant's TLAA regarding the fatigue analysis of RPV internalssummarized in LRA Section 4.3.2 and concluded that the applicant has provided an acceptabledemonstration, pursuant to 10 CFR 54.21(c)(1)(ii), that the analyses have been projected to theend of the period of extended operation. The staff also concluded that the USAR supplementcontains an appropriate summary description of this TLAA evaluation sufficient to satisfy 10 CFR 54.21(d) requirements.4.3.3ASME Section III Class 1 Reactor Coolant Pressure Boundary (RCPB) Piping andFatigue Analysis4.3.3.1  Summary of Technical Information in the ApplicationIn LRA Section 4.3.3, the applicant summarized the evaluation of the ASME Code Section IIIClass 1 reactor coolant pressure boundary (RCPB) piping and fatigue analysis for the period of extended operation. Piping systems were originally designed in accordance with AmericanStandards Association (ASA) B31.1 and United States of America Standard (USAS) B31.1.0which did not require an explicit fatigue analysis. The applicant concluded that the analyses demonstrate that the 40-year CUFs for the limiting components in all affected systems arebelow the ASME Code Section III allowable value of 1.0.4.3.3.2  Staff Evaluation The staff reviewed LRA Section 4.3.3, pursuant to 10 CFR 54.21(c)(1)(iii), to verify that theeffects of aging on the intended functions will be adequately managed for the period ofextended operation.The applicant indicated that RCPB piping was originally designed in accordance withASA B31.1 and USAS B31.1.0, which did not require explicit fatigue analyses of piping components. The applicant stated that portions of the RCPB required fatigue analysis, in accordance with ASME Code Section III for Nuclear Class 1 piping.
4-23The staff's review of LRA Section 4.3.3 identified an area for which it needed additionalinformation to complete its evaluation of the fatigue analysis. The applicant responded to the staff's RAI as discussed below.In RAI 4.3.3-1, dated June 21, 2005, the staff requested that the applicant provide the basis forthe requirement that RCPB portions be analyzed for fatigue, in accordance with the ASME Code Section III for Nuclear Class 1 piping. The staff also requested that the applicant indicatewhether the number of TT cycles used to estimate the 60-year fatigue usage of the core spray(CSP) valve joint is consistent with the number of TT cycles obtained from the FMP and used toestimate the 60-year fatigue usage of the CSP nozzle.In its response, dated July 21, 2005, the applicant indicated that replaced portions of the REC,CSP, and residual heat removal (RHR) systems were evaluated using ASME Code Section IIIfatigue analysis guidelines. Replacement of ASA B31.1 components with ASME Code Section III components is acceptable. Replaced components must then satisfy ASME Coderequirements, including those for fatigue.The applicant stated that the design fatigue usage at the limiting location for RCPB CSP pipingis less than 0.65 (CSP valve joint). The applicant estimated the 60-year fatigue usage by multiplying the design value by 1.5 to obtain a fatigue usage slightly below the allowable limit of 1.0; however, in LRA Table 4.3.1-1, the applicant indicated that the projected 60-year fatigueusage of the CSP nozzle is 0.65 based on the number of TT cycles counted by the FMP. Inresponding to RAI 4.3.3-1, the applicant stated that portions of the CSP piping were replaced in1986 and that, as discussed above, the replaced piping was evaluated using ASME Code Section III fatigue guidelines. The applicant indicated that the evaluation considered 100startup/shutdown cycles; therefore, extrapolation of the CSP piping usage factor by a factor of1.5 should represent 150 startup/shutdown cycles. LRA Section 4.3.1 projects 207startup/shutdown cycles for 60 years of plant operation. The staff reviewed data provided inSASR 89-77 indicating that the most significant TT affecting the CSP nozzle fatigue usage is startup/shutdown cycles. SASR 89-77 also indicated that 86 startup/shutdown cycles had accumulated before the CSP piping replacement. Therefore, the number of expected startup/shutdown cycles for the replaced CSP piping is 121 through the period of extendedoperation.Based on its review, the staff found the applicant's response to RAI 4.3.3-1 acceptable becausethe applicant's evaluation of the CSP valve joint represents a conservative estimate for the number of startup/shutdown cycles; therefore, the staff's concern described in RAI 4.3.3-1 isresolved.The applicant's FMP tra cks the number of design cycles for RPV com ponents. As discussed inAppendix B to the LRA, the FMP scope also includes RCPB piping. The staff concluded that the FMP provides an acceptable program to manage the fatigue usage of the RCPB components during the period of extended operation, in accordance with the requirements of10 CFR 54.21(c)(1)(iii).4.3.3.3  USAR Supplement The applicant provided a USAR supplement summary description of its TLAA evaluation ofASME Code Section III Class 1 RCPB piping and fatigue analysis in LRA Section A3.3. On the 4-24basis of its review of the USAR supplement, the staff concluded that the summary descriptionof the applicant's actions to address the fatigue analysis of ASME Code Section III Class 1RCPB piping is adequate.4.3.3.4  Conclusion The staff reviewed the applicant's TLAA regarding the fatigue analysis of ASME CodeSection III Class 1 RCPB piping, as summarized in LRA Section 4.3.3, and concluded that theapplicant has provided an acceptable demonstration that, pursuant to 10 CFR 54.21(c)(1)(iii),the effects of aging on the intended functions will be adequately managed for the period ofextended operation. The staff also concluded that the USAR supplement contains anappropriate summary description of this TLAA evaluation, sufficient to satisfy 10 CFR 54.21(d) requirements.4.3.4  RCPB Section III Class 2 and 3 Piping and Components4.3.4.1  Summary of Technical Information in the ApplicationIn LRA Section 4.3.4, the applicant summarized the evaluation of the RCPB ASME CodeSection III Class 2 and 3 piping and components for the period of extended operation. Thesecomponents were designed to ASA B31.1 and USAS B31.1.0 criteria, which did not require explicit fatigue analyses of the piping components, but did require application of a stress reduction factor to the allowable thermal bending stress range, if the number of full-range cycles exceeds 7000. The applicant stated that the number of thermal cycles experienced bythese systems is not expected to exceed 7000 during the period of extended operation;therefore, the applicant concluded that the analyses will remain valid for that period.4.3.4.2  Staff Evaluation The staff reviewed LRA Section 4.3.4, pursuant to 10 CFR 54.21(c)(1)(i), to verify that theanalyses will remain valid for the period of extended operation.The applicant indicated that the remaining piping and components were designed to codes thatdid not require explicit fatigue analyses. As discussed previously, the applicant performed fatigue analyses of the replaced portions of the RCPB piping. The design of the remaining piping systems is governed by the ASA B31.1 and USAS B31.1.0 criteria that limit the numberof full-range stress cycles from thermal bending to 7000. The applicant stated that the projectednumber of thermal bending cycles will not exceed 7000 for any non-ASME Code Section IIIClass 1 piping during the period of extended operation based on an assessment of the number of thermal cycles for the FW nozzle. The applicant selected the FW nozzle because it wassubject to the largest number of TT cycles in the RPV nozzle fatigue analyses. The applicantmultiplied the number of FW nozzle TT design cycles by 1.5 to provide a bounding estimate forthe non-ASME Class 1 piping.On the basis of its review, the staff concluded that the applicant's evaluation provides areasonable upper bound estimate of the number of full-range thermal bending cycles fornon-ASME Class 1 piping systems because the evaluation bounds the expected number ofTTs, including the number of expected startup/shutdown cycles for the facility. Therefore, the 4-25staff concluded that the applicant has adequately demonstrated that the analyses of thenon-ASME Class 1 piping and components will remain valid for the period of ext endedoperation, in accordance with the requirements of 10 CFR 54.21(c)(1)(i).4.3.4.3  USAR Supplement The applicant provided a USAR supplement summary description of its TLAA evaluation ofASME Code Section III Class 2 and 3 piping and components in LRA Section A3.4. On thebasis of its review of the USAR supplement, the staff concluded that the summary description of the applicant's actions to address the RCPB Section III Class 2 and 3 piping and componentsis adequate.4.3.4.4  Conclusion The staff reviewed the applicant's TLAA regarding the RCPB Section III Class 2 and 3 pipingand components, summarized in LRA Section 4.3.4, and concluded that the applicant providedan acceptable demonstration, pursuant to 10 CFR 54.21(c)(1)(i), that the analyses will remainvalid for the period of extended operation. The staff also concluded that the USAR supplementcontains an appropriate summary description of this TLAA evaluation, sufficient to satisfy 10 CFR 54.21(d) requirements.4.4  Irradiation-Assisted Stress-Corrosion Cracking (IASCC)4.4.1  Summary of Technical Information in the Application In LRA Section 4.4, the applicant summarized the evaluation of irradiation-assisted stresscorrosion cracking (IASCC) for the period of extended operation. Austenitic stainless steel RPV internal components exposed to a neutron fluence greater than 5x10 20 n/cm 2 (E > 1 MeV) aresusceptible to IASCC in the BWR environment. As described in the SER to BWRVIP-26, IASCC of RPV internals is a TLAA.4.4.2  Staff Evaluation The staff reviewed LRA Section 4.4, pursuant to 10 CFR 54.21(c)(1)(iii), to verify that the agingeffects from IASSC on the intended functions will be adequately managed for the period ofextended operation.The staff reviewed the information in the LRA and noted that the austenitic stainless steelcomponents exposed to a neutron fluence greater than 5x10 20 n/cm 2 (E >1 MeV) areconsidered susceptible to IASCC. These RPV internal components include the top guide, the shroud, and the incore instrumentation dry tubes and guide tubes. The staff reviewed thefluence calculations for the RPV and verified that other RPV internal components (e.g., the coreplate) are not expected to exceed a neutron fluence of 5x10 20 n/cm 2 and thus are considerednot to be susceptible to IASCC. In the LRA, the applicant stated that the aging effects fromIASCC of these RPV components are managed by three aging management programs (AMPs),
B2.1.2, ASME Section XI In-Service Inspection, Subsections IWB, IWC, and IWD; B2.1.12, BWR Vessel Internals; and B2.1.25, Plant Chemistry. The applicant stated that implementationof these three AMPs will manage the aging effects from IASCC such that the RPV internal 4-26components will continue to perform their intended functions consistently with the licensingbasis for the period of extended operation.The staff reviewed other applicant documents pertaining to the RPV, BWRVIP documents, andEPRI topical reports applying to generic RPVs. The staff observed that, while fluence level was the primary contributor to IASCC, additional factors also contributed or increased component susceptibility to IASCC. The staff observed that BWRVIP-41, "BWR Jet Pump Assembly lnspection and Flaw Evaluation Guidelines," states that materials like austenitic stainless steel used in jet pumps are not greatly susceptible to IASCC due to the low fluence levels in the annulus region."  The staff also observed that the June 5, 2001, SER that acceptedBWRVIP-41 stated that materials in a nonoxygenated environment are also not greatlysusceptible to IASCC, which becomes a concern only when cr acks are already present in acomponent. Thus, the SER stated that, when an applicant can show that cra cks hav e notoccurred in components, loss of fracture toughness from IASCC will not be a significant agingeffect.The staff asked the applicant to clarify its actions regarding the above additional factors. As tothe aggressive oxygenated environment, the applicant responded that it had implementedhydrogen water chemistry (HWC) in 1989, which reduces the oxidizing environment of the reactor coolant system (RCS) by injecting excess hydrogen to combine with free oxygenproduced by radiolysis. The dissolved oxygen content of FW is regulated to 20-50 parts per billion (ppb) during power operation, which minimizes corrosion potential. The staff reviewedhistorical data from the Water Chemistry Program and verified the low dissolved oxygen content.In a letter, dated June 10, 2005, the applicant stated that, in addition to those examinationsrequired by the ISI Program, which includes all pertinent examinations required by the BWRVIP program, it will examine the top guide grid high-fluence locations using the EVT-1 visualexamination method. In the same letter, the applicant committed to inspections of 10 percent ofthese locations within 12 years. The staff reviewed the applicant's operational experience and observed that, to date, it has inspected 25 percent of the high-fluence locations of the top guidegrid and detected no evidence of cracking.The staff reviewed the fluence calculations for the RPV internals and observed that there was afactor of 30 percent that was added to the calculated fluence level results. The staff asked the applicant to clarify the purpose of this added factor. The applicant stated that this factor was added for conservatism.The staff reviewed the RPV components for IASCC, considering that (1) these componentswere composed of a material that was identified in BWRVIP-41 as not highly susceptible to IASCC, (2) these components are in a nonaggressive, low-dissolved-oxygen environment, so, as stated in the SER, the susceptibility of these components to IASCC is reduced, (3) noevidence of cra cks has been detected in the RPV inspections to date, so as stated in the SER,significant loss of fracture toughness will not result, and (4) the fluence calculations thatdetermined the three RPV components susceptible to IASCC add a factor of 30 percent, for conservatism. The staff concluded that the applicant's AMP B2.1.2, ASME Section XI In-Service Inspection, Subsections IWB, IWC, and IWD; B2.1.12, BWR Vessel Internals; and B2.1.25, Plant Chemistry, will adequately manage the aging effects from IASCC for the periodof extended operation.
4-27During the audit and review, the staff identified an additional issue that required furtherclarification by the applicant. The applicant has committed to perform additional top guide examinations within the first 12 years of the period of extended operation; however, there is nocommitment to perform examinations during the remaining period of extended operation, nor acommitment as to what the applicant will do if any RPV examination detects an indication. In RAI 4.1-1, the staff requested that the applicant describe its actions for the remainder of theperiod of extended operation.In its response, by letter dated November 22, 2005, the applicant stated that it will perform aninspection of a sampling of top guide high-fluence locations (i.e., where fluence exceeds 5.0x10 20 n/cm 2) consistent with the lower plenum inspection and flaw evaluation guidelinesdescribed in BWRVIP-47. Ten percent of the total high-fluence population will be inspectedwithin 12 years, with a minimum of 5 percent inspected within the first 6 years. If flaws are detected, inspection of an additional 5 percent of the total high-fluence population will becompleted. This process will be repeated until no new flaws are detected. Any flaw exceedinginspection limits will be evaluated and necessary corrective actions made that may include, butare not limited to, accept as-is, accept as-is with required periodic reinspection, or remove indication by metal removal. All corrective actions will be performed in accordance withapproved procedures. Indication mapping and sizing will be documented for use in industryresolution of any related concerns. Reinspection scope and frequency during the entire period of extended operation will depend on initial inspection results, as well as on related industryexperience. Therefore, the staff concluded this TLAA is acceptable and consistent with theGALL Report, and the staff's concern described in RAI 4.1-1 is resolved.4.4.3  USAR Supplement The applicant provided a USAR supplement summary description of its TLAA evaluation ofIASCC in LRA Section A3.5. On the basis of its review of the USAR supplement, the staff concluded that the summary description of the applicant's actions to address the IASCC is
 
adequate.4.4.4  Conclusion The staff concluded that the applicant provided an acceptable demonstration, pursuant to10 CFR 54.21(c)(1)(iii), that the aging effects from IASSC on the intended functions will beadequately managed for the period of extended operation. The staff also concluded that theUSAR supplement contains an appropriate summary description of this TLAA evaluation, sufficient to satisfy the requirements of 10 CFR 54.21(d).4.5  Effects of Reactor Coolant Environment4.5.1  Summary of Technical Information in the Application In LRA Section 4.5, the applicant summarized its evaluation of the effects of the reactor coolantenvironment for the period of extended operation. The applicant evaluated the impact of thereactor coolant environment on the fatigue life of the locations addressed in NUREG/CR-6260,"Application of NUREG/CR-5999 Interim Fatigue Curves for Selected Nuclear Power PlantComponents."  The applicant's evaluation indicated that the environmental fatigue usage for all 4-28locations is less than the allowable limit of 1.0 for the period of extended operation. Theapplicant concluded that the effects of environmentally assisted fatigue were shown to be acceptable through the period of extended operation. The applicant further indicated that theFMP periodically reviews and updates fatigue analyses to ensure continued compliance with the fatigue acceptance criteria.4.5.2  Staff Evaluation The staff reviewed LRA Section 4.5, pursuant to 10 CFR 54.21(c)(1)(ii), to verify that theanalyses have been projected to the end of the period of extended operation.The applicant stated that the FMP will continue during the period of extended operation toassure that design cycle limits are not exceeded. The applicant's FMP tracks transients andcycles of RCS components with explicit design transient cycles to assure that thesecomponents remain within their design bases. Generic Safety Issue (GSI)-166, "Adequacy of the Fatigue Life of Metal Components," raised concerns about the conservatism of the fatigue curves used in the design of the RCS components. Although GSI-166 was resolved for the current 40-year design life of operating components, the staff identified GSI-190, "FatigueEvaluation of Metal Components for 60-Year Plant Life," to address license renewal. The NRC closed GSI-190 in December 1999, after concluding the following:The results of the probabilistic analyses, along with the sensitivity studiesperformed, the iterations with industry (NEI and EPRI), and the different approaches available to the licensees to manage the effects of aging, lead to the conclusion that no generic regulatory action is required, and that GSI-190 isclosed. This conclusion is based primarily on the negligible calculated increases in core damage frequency in going from 40 to 60-year lives. However, the calculations supporting resolution of this issue, which included consideration of environmental effects, and the nature of age-related degradation indicate the potential for an increase in the frequency of pipe leaks as plants continue to operate. Thus, the staff concluded that, consistent with existing requirements in10 CFR 54.21, licensees should address the effects of coolant environment on component fatigue life as aging management programs are formulated in support of license renewal.The staff compared the usage factors provided by the applicant with those in NUREG/CR-6260for the older vintage BWR. NUREG/CR-6260 identified several locations for which theenvironmental usage factor was projected to exceed 1.0, including the CSP nozzle safe end, the FW nozzle, the FW line reactor core isolation cooling (RCIC) tee connection, and the RHRreturn line tee.The staff's review of LRA Section 4.5 identified an area for which it needed additionalinformation to complete its evaluation of the effects of the reactor coolant environment. The applicant responded to the staff's RAI as discussed below.The environmental fatigue usage for the CSP nozzle (safe end) in LRA Section 4.5 is muchlower than the fatigue usage of the CSP nozzle (without environmental effects) in LRA Table 4.3.1-1. In RAI 4.5-1, dated June 21, 2005, the staff requested that the applicant provide 4-29the basis for the reported usage factors in LRA Section 4.5. In addition, the staff requested thatthe applicant discuss the calculation of the F en multipliers used for each of the NUREG/CR-6260locations.In its response, dated August 16, 2005, the applicant stated that the fatigue usage reported inLRA Table 4.3.1-1 for the CSP nozzle was based on cycle counting, whereas, theenvironmental usage factor in LRA Section 4.5 was based on a detailed stress analysis. During a followup discussion on September 1, 2005, the applicant stated that the fatigue usage inTable 4.3.1-1 resulted from considering all load cycles at the maximum stress, and the usagefactor in LRA Section 4.5 resulted from separating the individual load cycles by stress level. Thestaff found this explanation reasonable.The applicant indicated that MNGP used HWC. The NUREG/CR-6260 components wereevaluated for a high oxygen environment without HWC. Oxygen concentration has a significant impact on the fatigue life of carbon and low-alloy steel components. HWC lowers the oxygen concentration in BWRs to reduce the stress-corrosion cracking potential of stainless steel components. The reduced oxygen concentration significantly reduces the environmental impact on the fatigue life of carbon and low-alloy steel components compared to equivalent NUREG/CR-6260 carbon and low-alloy steel components.NUREG/CR-6260 identified high environmental fatigue usage at the stainless steel CSP nozzlesafe end. The applicant replaced the CSP safe ends in 1986. The applicant stated that thereplaced CSP safe ends are carbon steel. Because the applicant has implemented an HWC program, the environmental impact on the fatigue usage of the carbon steel safe ends is not significant; therefore, the staff concluded that the applicant's calculated environmental fatigueusage for the CSP nozzle safe ends is reasonable and acceptable.Because the applicant uses HWC, usage factors for the FW nozzle and the FW line RCIC teeconnection are not directly comparable to the NUREG/CR-6260 values. The applicant statedthat it had recently evaluated these locations in detail for environmental fatigue. The applicantalso stated that the environmental factors for the evaluations considered both the times HWChad and had not been in operation. Since the FW nozzle safe ends were replaced in the 1980s, the lower environmental factor reflects the greater operating exposure to HWC. Considering the applicant's use of HWC and replacement of the FW nozzle safe ends in the 1980s, the reported environmental factors are reasonable; therefore, the staff found the applicant's evaluation of theenvironmental fatigue usage of the FW nozzle and the FW line RCIC tee connection acceptable.The applicant also evaluated the RHR piping tapered transition and RHR return line tee in detailfor environmental fatigue. The RHR return line tee was the bounding fatigue usage location.Since the RHR return line tee was replaced in the 1980s, it will be subject to fewer years ofservice than the component evaluated in NUREG/CR-6260. In addition, the environmentalfatigue criteria for the stainless evaluations in NUREG/CR-6260 were independent oftemperature. Later criteria in NUREG/CR-5704 found that the environmental effect on fatigueusage is insignificant at temperatures less than 200 C. The staff noted that RHR shutdowncooling initiates at less than 200 C. Considering the items discussed above, the applicant'senvironmental fatigue usage of the RHR return line tee is reasonable. Therefore, the staff foundthe applicant's evaluation of the environmental fatigue usage of the RHR return line teeacceptable.
4-30Based on its review, the staff found the applicant's response to RAI 4.5-1 acceptable becausethe applicant reasonably evaluated the environmental impact on the fatigue life of RCPBcomponents for the period of extended operation; therefore, the staff's concern described inRAI 4.5-1 is resolved.4.5.3  USAR Supplement The applicant provided a USAR supplement summary description of its TLAA evaluation of theeffects of the reactor coolant environment in LRA Section A3.7. On the basis of its review of the USAR supplement, the staff concluded that the summary description of the applicant's actions to address the effects of the reactor coolant environment is adequate.4.5.4  Conclusion The staff reviewed the applicant's TLAA regarding the effects of reactor coolant environment,as summarized in LRA Section 4.5, and concluded that the applicant provided an acceptabledemonstration, pursuant to 10 CFR 54.21(c)(1)(ii), that the analyses have been projected to theend of the period of extended operation. The staff also concluded that the USAR supplementcontains an appropriate summary description of this TLAA evaluation, sufficient to satisfy the requirements of 10 CFR 54.21(d).4.6  Fatigue Analyses of the Primary Containment, Attached Piping, and ComponentsThe Mark I containment consists of a freestanding steel containment drywell, vent system , andsteel pressure suppression chamber (torus). Large-scale testing of the Mark III containmentand in-plant testing of Mark I primary containment systems identified additional hydrodynamicloads not considered in the original containment design. The Mark I Owners Group initiated the Mark I Containment Program to develop a generic load definition and structural analysis techniques. The staff evaluation of the generic load definition and structural assessment techniques is in NUREG-0661, "Safety Evaluation Report, Mark I Containment Long TermProgram, Resolution of Generic Technical Activity A-7," July 1980. The Mark I Containment Long-Term Program evaluation of hydrodynamic loads included fatigue analyses of the torus
 
and vent system and of the torus attached piping (TAP).The containment liner plates, penetration sleeves (including dissimilar metal welds), andpenetration bellows may be designed in accordance with the ASME Code, Section III,requirements. If a plant's code of record requires a fatigue analysis, it may be a TLAA and must be evaluated in accordance with 10 CFR 54.21(c)(1) to ensure adequate management of the effects of aging on the intended functions for the period of extended operation.The staff reviewed the adequacy for the period of extended operation of the fatigue analyses ofthe metal containment, containment liner plates (including welded joints), penetration sleeves, dissimilar metal welds, and penetration bellows. SER Section 4.3 reviews the fatigue analyses of the pressure boundary of process piping, following the guidance in SRP-LR Section 4.3.
4-314.6.1  Fatigue Analysis of the Suppression Chamber, Vents, and Downcomers4.6.1.1  Summary of Technical Information in the ApplicationIn LRA Section 4.6.1, the applicant discussed the suppression chamber and vent systemfatigue analysis. New hydrodynamic loads were identified subsequent to the original design of the containment suppression chamber vents. These loads result from blowdown into the suppression chamber during a postulated LOCA and during safety relief valve (SRV) operation for plant transients. The applicant identified the vent header-downcomer intersection and the torus shell as the limiting locations in terms of fatigue usage. The applicant stated that the onlycontribution to fatigue usage during normal operation is from SRV operation and that the number of SRV actuations is not expected to exceed the design number through the period ofextended operation.4.6.1.2  Staff Evaluation The staff reviewed LRA Section 4.6.1, pursuant to 10 CFR 54.21(c)(1)(i), to verify that theanalyses will remain valid for the period of extended operation, and, pursuant to10 CFR 54.21(c)(1)(iii), to verify that the effects of aging on the intended functions will beadequately managed for the period of extended operation.The applicant stated that the Mark I Containment Program evaluated the suppression chamberand vent header system, including fatigue analyses of the torus shell and vent header system.The applicant's Mark I Containment Program Plant Unique Analysis Report summarized these analyses. The applicant subsequently reevaluated these locations for the increased number of SRV actuations postulated as a result of the 1998 power rerate. The resulting fatigue usage, considering the increase in SRV cycles, was less than the 1.0 allowable limit. The applicantestimated that the number of SRV cycles will not exceed the number used for the evaluation ofthe suppression chamber and vent header system during the period of extended operation. Inaddition, the applicant indicated that the Fatigue Monitoring Program monitors the number ofSRV lifts to assure that the usage factor remains below 1.0 for the limiting components.The staff found that the applicant's FMP will ensure that fatigue usage of the suppressionchamber vents and downcomers will remain below 1.0 for the period of extended operation, inaccordance with the requirements of 10 CFR 54.21(c)(1)(iii).4.6.1.3  USAR Supplement The applicant provided a USAR supplement summary description of its TLAA evaluation offatigue analysis of the suppression chamber, vents, and downcomers in LRA Section A3.8. On the basis of its review of the USAR supplement, the staff concluded that the summary description of the applicant's actions to address the fatigue analysis of the suppression chamber, vents, and downcomers is adequate.4.6.1.4  Conclusion The staff reviewed the applicant's TLAA regarding the fatigue analysis of the suppressionchamber, vents, and downcomers, as summarized in LRA Section 4.6.1, and concluded that 4-32the applicant has provided an acceptable demonstration, pursuant to 10 CFR 54.21(c)(1)(i), thatthe analyses will remain valid for the period of extended operation. In addition, the staffconcluded that, pursuant to 10 CFR 54.21(c)(1)(iii), the effects of aging on the int endedfunctions will be adequately managed for the period of extended operation. The staff alsoconcluded that the USAR supplement contains an appropriate summary description of this TLAA evaluation, sufficient to satisfy 10 CFR 54.21(d) requirements.4.6.2Fatigue Analysis of the SRV Piping Inside the Suppression Chamber and InternalStructures4.6.2.1  Summary of Technical Information in the ApplicationIn LRA Section 4.6.2, the applicant discussed the suppression chamber piping and internalsstructure fatigue evaluations. The reactor pressure relief system includes SRVs located on themain steamlines within the drywell between the reactor vessel and the first isolation valve. Theapplicant stated that it had not performed fatigue analyses for torus internal structures (i.e.,
catwalk and monorail). The applicant indicated that it had performed fatigue analyses for the SRV piping inside the torus. The applicant also stated that the SRV piping analyses will remainvalid for the period of extended operation.4.6.2.2  Staff Evaluation The staff reviewed LRA Section 4.6.2, pursuant to 10 CFR 54.21(c)(1)(ii), to verify that theanalyses have been projected to the end of the period of extended operation.The applicant stated that the fatigue analyses of the torus internal SRV piping had been part ofthe Mark I Containment Program. The applicant also indicated that the piping had beenevaluated for the 26-percent increase in the number of SRV cycles resulting from the 1998power rerate. The resulting 40-year fatigue usage was well below the allowable limit of 1.0. The applicant multiplied the resulting 40-year fatigue usage by 1.5 to estimate the fatigue usage for 60 years of plant operation.Because the applicant indicated that the number of SRV cycles used in the power rerateevaluation is conservative for 40 years of plant operation, the 1.5 factor provides a conservative estimate for the period of extended operation; therefore, the staff found that the applicantadequately demonstrated that the fatigue usage of the torus SRV piping will remain withinacceptable limits for the period of extended operation, in accordance with the requirements of10 CFR 54.21(c)(1)(ii).4.6.2.3  USAR Supplement The applicant provided a USAR supplement summary description of its TLAA evaluation offatigue analysis of the SRV piping inside the suppression chamber and internal structures in LRA Section A3.8. On the basis of its review of the USAR supplement, the staff concluded that the summary description of the applicant's actions to address the fatigue analysis of the SRV piping inside the suppression chamber and internal structures is adequate.
4-334.6.2.4  ConclusionThe staff reviewed the applicant's TLAA regarding the fatigue analysis of the SRV piping insidethe suppression chamber and internal structures, as summarized in LRA Section 4.6.2, and concluded that the applicant provided an acceptable demonstration, pursuant to10 CFR 54.21(c)(1)(ii), that the analyses have been projected to the end of the period ofextended operation. The staff also concluded that the USAR supplement contains anappropriate summary description of this TLAA evaluation, sufficient to satisfy 10 CFR 54.21(d) requirements.4.6.3  Fatigue Analysis of Suppression Chamber External Piping and Penetrations 4.6.3.1  Summary of Technical Information in the ApplicationIn LRA Section 4.6.3, the applicant discussed the fatigue analysis of suppression chamberexternal piping and penetrations. These analyses included the large- and small-bore TAP, suppression chamber penetrations, and the emergency core cooling system (ECCS) suctionheader and were based on cycles postulated to occur within the 40-year operating life of theplant. The applicant stated that these analyses will remain valid for the period of ext endedoperation.4.6.3.2  Staff Evaluation The staff reviewed LRA Section 4.6.3, pursuant to 10 CFR 54.21(c)(1)(ii), to verify that theanalyses have been projected to the end of the period of extended operation and, pursuant to10 CFR 54.21(c)(1)(iii), that the effects of aging on the intended functions will be adequatelymanaged for the period of extended operation.The applicant stated that fatigue effects were specifically addressed for the suppressionchamber TAP penetrations and the suction header in the Mark I Containment Program. The applicant indicated that it evaluated the TAP penetration fatigue analyses for the 26-percentincrease in SRV cycles resulting from the 1998 power uprate. The resulting 40-year fatigueusage was less than the allowable limit of 1.0. The applicant indicated that the FatigueMonitoring Program monitors the number of SRV lifts to assure that the usage factor remains below 1.0 for the limiting components.Because the number of SRV lifts is monitored, the staff found that the applicant's FMP willassure that the TAP penetrations fatigue usage will remain below 1.0 for the period of ext endedoperation, in accordance with the requirements of 10 CFR 54.21(c)(1)(iii).The applicant also stated that the Mark I Owner's Group had generically addressed TAP pipingfor all Mark I plants. The applicant identified the SRV piping as the limiting location and evaluated it for a 26-percent increase in the number of SRV cycles as a result of the 1998power rerate. The resulting 40-year fatigue usage was well below the 1.0 allowable limit. The applicant multiplied the resulting 40-year fatigue usage by 1.5 to estimate fatigue usage for 60 years of plant operation.
4-34Because the applicant indicated that the number of SRV cycles used in the power rerateevaluation is conservative for 40 years of plant operation, the 1.5 factor provides a conservative estimate for the period of extended operation; therefore, the staff found that the applicantadequately demonstrated that the fatigue usage of the torus SRV piping will remain withinacceptable limits for the period of extended operation, in accordance with the requirements of10 CFR 54.21(c)(1)(ii).4.6.3.3  USAR Supplement The applicant provided a USAR supplement summary description of its TLAA evaluation of thefatigue analysis of suppression chamber external piping and penetrations in LRA Section A3.8.
On the basis of its review of the USAR supplement, the staff concluded that the summary description of the applicant's actions to address the fatigue analysis of the suppression chamber external piping and penetrations is adequate.4.6.3.4  Conclusion The staff reviewed the applicant's TLAA regarding the fatigue analysis of the suppressionchamber external piping and penetrations, as summarized in LRA Section 4.6.3, and concluded that the applicant provided an acceptable demonstration, pursuant to 10 CFR 54.21(c)(1)(ii),that the analyses have been projected to the end of the period of extended operation. Inaddition, pursuant to 10 CFR 54.21(c)(1)(iii), the staff concluded that the effects of aging on theintended functions will be adequately managed for the period of extended operation. The staffalso concluded that the USAR supplement contains an appropriate summary description of this TLAA evaluation, sufficient to satisfy 10 CFR 54.21(d) requirements.4.6.4  Drywell-to-Suppression Chamber Vent Line Bellows Fatigue Analysis 4.6.4.1  Summary of Technical Information in the ApplicationIn LRA Section 4.6.4, the applicant discussed the fatigue analysis of the drywell-to-suppressionchamber vent line bellows. The applicant stated that the vent line bellows stresses are primarilycaused by differential thermal expansion during startup/shutdown and accident conditions. Theapplicant projected that the number of startup/shutdown cycles in the design will not be exceeded during the period of extended operation; therefore, the applicant concluded that theanalysis remains valid for that period.4.6.4.2  Staff Evaluation The staff reviewed LRA Section 4.6.4, pursuant to 10 CFR 54.21(c)(1)(i), to verify that theanalyses will remain valid for the period of extended operation.The applicant stated that the drywell-to-suppression chamber vent line bellows stresses areprimarily caused by differential thermal expansion of the reactor suppression chamber and drywell during normal startup and shutdown operations. The applicant stated that the designassumes 300 startup/shutdown cycles. As indicated in LRA Section 4.3, the applicant projectedfewer than 300 startup/shutdown cycles through the period of extended operation.
4-354.6.4.3  USAR SupplementThe applicant provided a USAR supplement summary description of its TLAA evaluation ofdrywell-to-suppression chamber vent line bellows fatigue analysis in LRA Section A3.8. On the basis of its review of the USAR supplement, the staff concluded that the summary description of the applicant's actions to address the drywell-to-suppression chamber vent line bellows fatigue analysis is adequate.4.6.4.4  Conclusion The staff reviewed the applicant's TLAA regarding the drywell-to-suppression chamber vent linebellows fatigue analysis, as summarized in LRA Section 4.6.4, and concluded that the applicant provided an acceptable demonstration, pursuant to 10 CFR 54.21(c)(1)(i), that the analyses willremain valid for the period of extended operation. The staff also concluded that the USARsupplement contains an appropriate summary description of this TLAA evaluation, sufficient to satisfy the requirements of 10 CFR 54.21(d).4.6.5  Primary Containment Process Penetration Bellows Fatigue Analysis 4.6.5.1  Summary of Technical Information in the ApplicationIn LRA Section 4.6.5, the applicant discussed the primary containment process bellows fatigueanalysis. Containment pipe penetrations required to accommodate thermal movement have expansion bellows. The applicant stated that these containment process bellows involve pipingsystems that penetrate the drywell shell and that these bellows were designed for a minimum of7000 operating cycles. The applicant indicated that the number of expected operati ng cycl esthrough the period of extended operation is much fewer than 7000; therefore, the applicantconcluded that the analysis of the containment process bellows will remain valid for the periodof extended operation.4.6.5.2  Staff Evaluation The staff reviewed LRA Section 4.6.5, pursuant to 10 CFR 54.21(c)(1)(i), to verify that theanalyses will remain valid for the period of extended operation.The applicant stated that the containment process piping penetration bellows were designed toASME Code Section III, Class B requirements, which do not require a formal fatigue analysis;however, the criteria for the attached process piping limit the number of full-range bending cycles. As discussed in SER Section 4.3, the applicant indicated that the number of expectedoperating cycles for the process piping is much fewer than 7000; therefore, the applicantconcluded that the analyses of the containment process piping bellows will remain valid for theperiod of extended operation.The staff found that the applicant's evaluation of the process piping provides a reasonableupper-bound estimate of the number of full-range thermal bending cycles for the process pipingpenetration bellows because the evaluation bounds the expected number of TTs, including the number of expected startup/shutdown cycles, for the facility.
4-364.6.5.3  USAR SupplementThe applicant provided a USAR supplement summary description of its TLAA evaluation ofprimary containment process penetration bellows fatigue analysis in LRA Section A3.8. On the basis of its review of the USAR supplement, the staff concluded that the summary description of the applicant's actions to address the primary containment process penetration bellows fatigue analysis is adequate.4.6.5.4  Conclusion The staff reviewed the applicant's TLAA of the primary containment process penetrationbellows fatigue analysis summarized in LRA Section 4.6.5 and concluded that the applicant provided an acceptable demonstration, pursuant to 10 CFR 54.21(c)(1)(i), that the analyses willremain valid for the period of extended operation. The staff also concluded that the USARsupplement contains an appropriate summary description of this TLAA evaluation, sufficient to satisfy the requirements of 10 CFR 54.21(d).4.7  Environmental Qualification of Electrical Equipment (EQ)4.7.1  Summary of Technical Information in the Application The 10 CFR 50.49, "Environmental Qualification of Electric Equipment Important to Safety forNuclear Power Plants," environmental qualification (EQ) program has been identified as a TLAA for the purposes of license renewal. The TLAA of EQ electrical components includes all long-lived, passive electrical components and instrumentation and controls (I&C) components that are important to safety and located in a harsh environment. The harsh environments of the plant are those areas that are subject to environmental effects by a LOCA or a high-energy line break (HELB). The EQ equipment comprises safety-related (SR) and Q-list equipment, nonsafety-related (NSR) equipment whose failure could prevent satisfactory accomplishment of any SR function, and necessary post-accident monitoring equipment.The applicant's EQ Program manages component thermal, radiation, and cyclic aging throughaging evaluations based on 10 CFR 50.49(f) qualification methods. Environmentally qualified equipment must be refurbished, replaced, or have its qualification extended before reaching the aging limits established in the aging evaluation. Aging evaluations for environmentally qualifiedequipment that specify the qualified life of at least 40 years are considered TLAAs for license renewal.4.7.2  Staff Evaluation The staff reviewed LRA Section 4.7, pursuant to 10 CFR 54.21(c)(1)(iii), to verify that theeffects of aging on the intended functions will be adequately managed for the period ofextended operation.The results of the electrical equipment EQ in LRA Section 4.7 indicate that the aging effects ofelectrical equipment EQ identified in the TLAA will be managed during the extended period ofoperation under 10 CFR 54.21(c)(1)(iii); however, the applicant did not submit information onthe attribute of a reanalysis of an aging evaluation to extend the qualification life of such 4-37electrical equipment identified in the TLAA. The important attributes of a reanalysis are theanalytical methods, the data collection and reduction methods, the underlying assumptions, the acceptance criteria, and the corrective actions. In RAI 4.7-1, dated November 7, 2005, the staffrequested that the applicant provide information about the important attributes of reanalysis ofan aging evaluation of electrical equipment identified in the TLAA to extend the qualificationunder 10 CFR 50.49(e).In its response, by letter dated December 7, 2005, the applicant stated that the reanalysis of anaging evaluation normally extends the qualification by reducing excess conservatism incorporated in the prior evaluation. The staff reviewed this information and found the applicant's response satisfactory; therefore, the staff's concern described in RAI 4.7-1 is resolved.The staff also reviewed the EQ Program to determine whether it will assure that the electricalcomponents covered under this program will continue to perform their intended functionconsistently with the CLB for the period of extended operation. The staff's evaluation of thecomponent qualification focused on how the program manages the aging effects through effective incorporation of the following 10 elements-program scope, preventive action, parameters monitored or inspected, detection of aging effects, monitoring and trending, acceptance criteria, corrective actions, confirmation process, administrative controls, and operating experience.Program Scope Pursuant to 10 CFR 50.49, the EQ Program evaluates harsh environments in which electricalequipment important to safety may be required to operate. The applicant stated that anequipment master list, maintained at MNGP, includes SR electrical equipment, NSR equipment whose failure could prevent accomplishment of safety functions, and certain post-accident monitoring equipment. The staff considered the scope of the program acceptable.Preventive Actions The ongoing EQ Program ensures that electrical equipment important to safety is capable ofperforming its intended function in a harsh environment, in accordance with 10 CFR 50.49.
Although 10 CFR 50.49 does not require actions that prevent aging effects, EQ Programactions that could be viewed as preventive actions include (1) establishing the component service condition tolerance and aging limits (e.g., qualified life or condition limit) and (2) where applicable, requiring specific installation, inspection, monitoring, or periodic maintenance actions to manage equipment aging effects within the qualification. The staff considered these actions acceptable because 10 CFR 50.49 does not require actions that prevent aging effects.Parameters Monitored or Inspected The applicant stated that qualified life is not based on condition or performance monitoring.Pursuant to 10 CFR 50.49(e), the qualification must include and be based on temperature and pressure, humidity, chemical effects, radiation, aging, submergence, synergistic effects, and margins. Pursuant to RG 1.89, Revision 1, "Environmental Qualification of Certain Electric Equipment Important to Safety for Nuclear Power Plants," issued June 1984, monitoring or inspection of certain environmental conditions or component parameters may be used to ensure that the component is within the bounds of its qualification basis or as a means to modify the qualified life. The applicant's EQ Coordinator is responsible for reviewing program 4-38data and industry information. Deviations are documented in the Corrective Action Program(CAP) and actions to correct identified issues may include monitoring, inspection, reanalysis, or testing. For example, the EQ Coordinator monitors radiation protection surveys for changes inradiation levels and has initiated a temperature monitoring program in areas containing EQ equipment. The staff considered this monitoring approach appropriate because the program objective is to ensure that the established qualified life of devices is not exceeded.Detection of Aging Effects 10 CFR 50.49 does not require the detection of aging effects for inservice components. Theapplicant stated that the CAP, the Preventive Maintenance Program, and the Quality ControlProgram will identify any aging effects of EQ equipment and initiate corrective action required tomaintain equipment qualification. In addition, monitoring and inspection of certain environmental conditions or component parameters may be used to ensure that the component is within the bounds of its qualification basis, or as a means to modify the qualified life. The staff considered the applicant's above programs to detect aging effects acceptable.Monitoring and Trending 10 CFR 50.49 does not require monitoring and trending of component condition or performanceparameters of inservice components to manage the effects of aging. The EQ Program actions that could be viewed as monitoring include monitoring how long qualified components have been installed. Monitoring or inspecting certain environmental, condition, or component parameters may be used to ensure that a component is within its qualification or as a means to modify the qualification. The staff considered this program acceptable because 10 CFR 50.49 does not require monitoring and trending of component condition or performance parameters of inservice components to manage the effects of aging.Acceptance Criteria 10 CFR 50.49 acceptance criteria require that an inservice EQ component is maintained withinits qualification including its (a) established aging limits and (b) continued qualification for the projected accident conditions. 10 CFR 50.49 requires refurbishment, replacement, or requalification before exceeding the aging limits of each installed device. The applicant stated that its program has identified all components subject to the 10 CFR 50.49 acceptance criteriaon an SR equipment master list. The EQ Coordinator maintains calculations supporting equipment qualification, which include such information as location, environmental conditions, qualification methods, and acceptance criteria. Before reaching the end of qualified life, affected components are refurbished, requalified, or replaced to ensure continued functionality of the installed components. The staff considered this program acceptable since it is consistent with 10 CFR 50.49 requirements of refurbishment, replacement, or requalification before exceeding the qualified life of each installed device.Corrective Actions, Confirmation Process, and Administrative Controls The applicant stated that if an EQ component is found to be outside the bounds of itsqualification basis, it implements corrective actions in accordance with the station's CAP. When operational or maintenance activities identify unexpected adverse conditions affecting the environment of a qualified component, it is evaluated and the applicant takes appropriate corrective actions, which may include changes to the qualification bases and conclusions.
When an emerging industry aging issue is identified that affects the qualification of an EQ 4-39component, it is evaluated and the applicant takes appropriate corrective actions, which mayinclude changes to the qualification bases and conclusions. The staff considered this acceptable because the corrective actions are implemented in accordance with the requirements of Appendix B to 10 CFR Part 50, which ensures the adequacy of corrective actions. SER Section 3.0.4 addresses the evaluations of these program elements.Operating Experience The EQ Program includes monitoring and assessment of industry information to assess itsimpact on EQ components. The applicant stated that the EQ Coordinator is responsible forreviewing the disposition of such information, as well as subsequent assignment of actions to be taken on such information and confirmation that the completion of the actions satisfactorily address potential EQ aging issues. The staff found that the applicant adequately addressedoperating experience.4.7.3  USAR Supplement The applicant provided a USAR supplement summary description of its TLAA evaluation ofelectrical equipment EQ in LRA Section A3.9. On the basis of its review of the USAR supplement, the staff concluded that the summary description of the applicant's actions to address electrical equipment EQ is adequate.4.7.4  Conclusion The staff concluded that the applicant provided an acceptable demonstration regardingelectrical equipment EQ, pursuant to 10 CFR 54.21(c)(1)(iii), that the effects of aging on theintended functions will be adequately managed for the period of extended operation. The staffalso concluded that the USAR supplement contains an appropriate summary description of this TLAA evaluation, sufficient to satisfy the requirements of 10 CFR 54.21(d).4.8  Stress Relaxation of Rim Holddown Bolts4.8.1  Summary of Technical Information in the ApplicationIn LRA Section 4.8, the applicant summarized the evaluation of the stress relaxation of rimholddown bolts for the period of extended operation. As described in the SER to BWRVIP-25, plants must consider relaxation of the rim holddown bolts as a TLAA issue. Because MNGP has not installed core plate wedges, the loss of preload must be considered in the TLAA evaluation.4.8.2  Staff Evaluation The staff reviewed LRA Section 4.8, pursuant to 10 CFR 54.21(c)(1)(ii), to verify that theanalyses have been projected to the end of the period of extended operation.The LRA states that, for the period of extended operation, the expected preload loss for the rimholddown bolts was assumed to be 19 percent, which bounds the original BWRVIP analysis.
With a 19-percent preload loss, the core plate will maintain sufficient preload to prevent slidingunder both normal and accident conditions.In a letter dated June 10, 2005, the applicant provided additional details of the analysis for therim holddown bolts:
4-40To more accurately address MNGP for License Renewal, a plant-specificcalculation was performed that incorporated the MNGP core plate geometry, anoperating temperature of 288 C (550 F) and a MNGP fluence calculation thatwas performed specifically for License Renewal in accordance with guidance provided in Regulatory Guide 1.190, 'Calculational and Dosimetry Methods for Determining Pressure Vessel Neutron Fluence,' March 2001, (LRA Section 4.2.1). The maximum fluence applicable to the bolts in the highest fluence region of the core plate was determined to be 2.2x10 19 n/cm 2 at the endof the 60-year plant life. The resultant relaxation was determined to be 8 percent based on GE Design Documents. The analysis assumed that all of the bolts were at this fluence even though many bolts experience a lower fluence depending on their specific location...In RAI 4.8-2, dated September 28, 2005, the staff requested that the applicant provide thestress relaxation curves, information regarding the material type, the loads used to develop the stress relaxation curves, and show that the axial and bending stresses for the mean and highest loaded holddown bolts will not exceed the ASME allowable stresses.In its response, dated October 28, 2005, the applicant provided, "The Relaxation of IrradiatedAustenitic Steels and Ni-GE Mean Design Curve," based on a model that assumed a stress-linear, primary plus secondary creep law form and was fit to the shown data using stepwise multiple regression.The rim holddown bolts are Type 304 stainless steel. The data used to develop the curveinclude several austenitic materials. The applicant analyzed the impact of austenitic material type on stress relaxation from neutron radiation. In its letter, dated October 28, 2005, the applicant stated the following:Relaxation of irradiated, structural materials from radiation creep is much lesssensitive to 'normal material variations' (e.g., in austenitic stainless steels) than other radiation properties. Radiation segregation and hardening characteristics are similar for all austenitic stainless steels, although some experience presegregation (from annealing). Also, neutron relaxation is among the most consistent and reproducible phenomenon, and little variation is observed in stainless steel (e.g., 304, 316, 321, 347/8, L-grade and nuclear grade). The relaxation behavior of these stainless steels is often used for many different austenitic alloys such as Nitronic 50, Alloy X-750 and Alloy 718.To support the conclusion that the GE design curves apply to Type 304 stainless steel, theapplicant presented stress relaxation data from the BWRVIP-99 report, "Crack Growth Rates in Irradiated Stainless Steels in BWR Internal Components," and from J.P. Foster and Halden.
The GE design curve predicts higher relaxation levels (i.e., lower fraction of load remaining) than observed from the Foster and Halden data and is thus conservative compared to these
 
data.The analysis included the impact of test temperature and neutron flux on stress relaxation:More than 80 percent of the tests, shown in Figure 1, were conducted at atemperature of 550 F and a majority of these were conducted in an operatingBWR environment. The other tests, were conducted at either 570 or 600 Fwhich is expected to produce more relaxation. Since such a large portion of the 4-41data was conducted at typical BWR operating conditions, the data temperature isconsidered fully representative of the core plate bolts.While the cumulative fluence information was available as part of the original testreports and the GE Design Curve documentation, the flux conditions were not directly available. Many of the tests were associated with springs which had reached fluences ranging from 8x10 20 to 8x10 21 n/cm 2. Based on a reasonableexposure time, the flux will be expected to range from 7x10 12 to 9x10 13 n/cm 2/s.The fluxes defined for two of the smaller sets of test data were 2.7x10 14 and2x10 17 n/cm 2/s, respectively. Review of the data over these four orders ofmagnitude showed no discernable flux dependence; however, the neutron flux levels were at least 100 times higher than that experienced by the core plate bolts. As described above, the temperature data are representative for use in the core plate bolt evaluation. The neutron flux data, however, was measured in specimens subject to fluxes ranging from 1x10 13 to 2x10 17 n/cm 2/s, which ishigher than the 8.5x10 9 n/cm 2/s average flux experienced by the core plate boltsthemselves. Given the large range of higher flux for which the properties are the same, the impact of the lower flux to which the bolts are exposed is viewed as negligible.Based on the analysis and supporting data, the staff agreed with the applicant that the GEdesign curves apply to Type 304 stainless steel used in the core plate bolts.Based on the GE design curves and a neutron fluence of 2.2x10 19 n/cm 2 (E > 1.0 MeV), theapplicant determined that the amount of stress relaxation at the end of the period of extendedoperation would be 8 percent. This neutron fluence was calculated using a procedure which is in accordance with the guidance in RG 1.190 and corresponds to the maximum fluence applicable to the bolts at the end of the period of extended operation.The applicant also performed a plant-specific analysis to show that the axial and bendingstresses in the core plate holddown bolts, considering the loss of preload (8 percent) at the endof the period of extended operation, will not exceed the ASME Code, Section III allowable Pm(membrane) and Pm + Pb (membrane + bending) stresses. The analysis was based on the assumption that sufficiently high frictional forces, resulting from the preload forces in the bolts and coefficient of static friction test data between the rim and the support surfaces, will beinduced between the core plate rim and the shroud support to prevent sliding of the core plateunder design-basis loading resulting from maximum horizontal and vertical seismic and accident loads. Under this scenario, no bending stresses are induced in the holddown bolts.
The only stresses sustained by the holddown bolts are axial, resulting from the preload and the vertical loading (differential pressure and seismic) on the plate. These stresses were shown to be considerably lower than the ASME Section III allowable Pm stress.The staff evaluated this analysis and concluded that the postulated coefficient of static frictionwas not applicable under the reactor fluid operating environment because of other coefficientsof friction data indicating that a lower value may be appropriate. A smaller coefficient of static friction permits sliding of the core plate under horizontal acceleration and induces bending stresses in the bolts. This analysis was, therefore, found to be unacceptable.Inspection and flaw evaluation guidelines of BWR core support plates were previouslysubmitted to the NRC in BWRVIP-25, "BWR Core Plate Inspection and Flaw EvaluationGuidelines," issued December 1996. Appendix A to this report contains a prototypical core plate 4-42holddown bolt analysis under representative horizontal and vertical seismic and accident-loading conditions. The analysis was based on a finite element analysis of the core plate and the holddown bolts and did not credit friction between the core rim and the shroud support. This analysis demonstrated that the mean axial and axial + bending stresses in the holddown bolts meet the ASME Section III bolt stress criteria in the report under typical accident loading. Thestaff reviewed this report and found it acceptable for referencing in LRAs, as stated by letter dated September 6, 2000. Therefore, the staff requested that the applicant perform an analysis,consistent with the methodology used in Appendix A to BWRVIP-25, and demonstrate that thebolt axial and bending stresses meet the ASME Section III Pm and Pm + Pb stress criteria inthe report.By letter dated February 27, 2006, the applicant provided GE technical reportGE-NE-0000-0050-5900P, "Comparative Evaluation of the Monticello Core Plate Rim Hold-down Bolts and BWRVIP-25, Appendix A Analysis," issued February 2006. This analysis demonstrates that the MNGP mean axial and bending core plate holddown bolt stresses, considering holddown bolt stress relaxation, were bounded by the analysis approved in BWRVIP-25. However, the horizontal and vertical loads used in the analysis were considerably smaller than those used in the BWRVIP-25 analysis, resulting from the exclusion of certain accident loads, such as SRV hydrodynamic loads, that were considered in the BWRVIP-25 analysis. The staff requested that the applicant provide justification for the exclusion of theseloads. In its response, dated March 31, 2006, the applicant stated that all applicable DBA loadsspecific to the MNGP core plate were applied and provided the horizontal and vertical accelerations at the core plate level. The applicant justified the exclusion of the hydrodynamic loads on the basis that these are not applicable to the MNGP vessel and internals since theMNGP is a BWR/3 Mark I design. The Mark I torus is structurally isolated from the containment by the use of flexible bellows, and the hydrodynamic loads caused by SRV lift and LOCA are, therefore, not transmitted to the containment or the vessel. The staff found this justificationreasonable and acceptable.The BWRVIP-25 analysis is based on a finite element analysis of the core plate and holddownbolts. It was originally performed to help utilities determine a strategy for core plate inspections, wherein conservative geometric conditions and bounding, postulated worst-case scenarios were considered. Because of the similarities in the MNGP and the BWRVIP-25 plates, the applicant/GE used data from the BWRVIP-25 core plate finite element analysis, an analytical procedure, and a comparison to the MNGP specific core plate and loads to extrapolate the BWRVIP-25 analysis to the MNGP core plate and holddown bolts. The applicant showed that the mean core plate bolt axial and axial + bending stresses met the ASME Section III stresscriteria in BWRVIP-25. However, the BWRVIP-25 analysis also indicated that not all holddown bolts are uniformly loaded under horizontal and vertical loading. Based on data shown in BWRVIP-25, the staff also determined that the axial + bending stresses in the highest loadedMNGP holddown bolts could exceed the Pm + Pb stress criterion of BWRVIP-25, but by an insignificant margin. However, the applicant's analysis also included bending stresses in the holddown bolts from core plate bowing, which the BWRVIP-25 analysis did not consider. The staff evaluated the applicant's analysis and concluded that it is acceptable because it conformswith accepted structural analysis practice. Therefore, the staff's concern described in RAI 4.8-2 is resolved.4.8.3  USAR Supplement The applicant provided a USAR supplement summary description of its TLAA evaluation ofstress relaxation of rim holddown bolts in LRA Section A3.6. In its letter, dated April 10, 2006, 4-43the applicant provided a revised USAR supplement description which summarized the results ofthe analysis provided in the GE technical report. On the basis of its review of the USAR supplement description provided in the applicant's letter, dated April 10, 2006, the staffconcluded that the summary description of the applicant's actions to address the stress relaxation of rim holddown bolts adequately describes the analysis characterized in the GE technical report.4.8.4  Conclusion The staff concluded that the applicant provided an acceptable demonstration, pursuant to10 CFR 54.21(c)(1)(ii), that the stress relaxation of rim holddown bolts analyses have been projected to the end of the period of extended operation. The staff also concluded that theUSAR supplement contains an appropriate summary description of this TLAA evaluation, sufficient to satisfy the requirements of 10 CFR 54.21(d).4.9  Reactor Building Crane Load Cycles4.9.1  Summary of Technical Information in the Application In LRA Section 4.9, the applicant summarized the evaluation of the reactor building crane loadcycles for the period of extended operation. The MNGP reactor building cr ane system consistsof an 85-ton bridge crane. The crane is capable of handling the drywell head, reactor vessel head, pool plugs, and spent fuel pool shipping cask. A refueling service platform, with necessary handling and grappling fixtures, services the refueling area and the spent fuel pool.
The reactor building cr ane system has been modified to incorporate redundant safety featureswhich were not a part of the original design. The modification consists of a new trolley with redundant design features and a capacity of 85 tons on the main hook with redundancy features and an auxiliary 5-ton capacity hook. This modification was implemented for handlingheavy loads, both during refueling operations and during operations involving the offsite shipment of spent fuel. Such offsite shipments of fuel can take place when the plant is operating or shut down. The redundant crane was installed to reduce the probability of a heavyload drop to the category of an incredible event. NUREG-0612 suggests that cranes should bedesigned to meet the applicable criteria and guidelines of Chapter 2-1 of American National Standards Institute (ANSI) B30.2-1976, "Overhead and Gantry Cranes," and of CraneManufacturers Association of America (CMAA)-70, "Specifications for Electric Overhead Traveling Cranes."  The reactor building crane, manufactured before the issuance of CMAA-70 and ANSI B30.2-1976, was designed to meet Electric Overhead Crane Institute (EOCI) 61.
Since the evaluati on used, as a basis, an expected number of load cycles over the 40-year lifeof the plant, reactor building crane load cycles are a TLAA.4.9.2  Staff Evaluation The staff reviewed LRA Section 4.9, pursuant to 10 CFR 54.21(c)(1)(i), to verify that theanalyses will remain valid for the period of extended operation.In LRA Section 4.9, which is related to the reactor building crane load cycles TLAA, theapplicant stated that the current analysis of the fatigue life remains valid for the 60-yearextended operating period. It is the staff's understanding that this crane will also handle spentfuel pool shipping casks. A refueling service platform with handling and grappling fixturesservices the refueling area and the spent fuel pool.
4-44The staff's review of LRA Section 4.9 identified an area for which it needed additionalinformation to complete its evaluation of the applicant's results. The applicant responded to the staff's RAI as discussed below.In RAI 4.9-1, dated July 20, 2005, the staff indicated concerns regarding the fatigue analysis forthe reactor building crane. Therefore, the staff requested that the applicant provide a fatigueanalysis associated with lifts of spent fuel casks and explain how the heavy-load fatigueanalysis in LRA Section 4.9 governs the TLAA.In its response, dated August 16, 2005, the applicant stated the following:Section 4.9 of the LRA accounted for cycles due to anticipated lifts of spent fuel casks by the addition of heavy lift cycles. The current analysis conservativelyassumed 1,120 cycles (for 40 years of operation) due to lifts of reactor buildingshield blocks and plugs, the reactor vessel head, the drywell vessel head, thesteam separator assembly, and the steam dryer assembly. The difference between 1,120 to 2,000 cycles identified in Section 4.9 includes consideration ofadditional spent fuel cask lifts, as well as additional current design basis lifts attributable to the license renewal period of extended operation.The reactor building crane is currently being upgraded from 85 tons to 105 tonsin anticipation of spent fuel cask duty. Crane calculations are being performed in accordance with CMAA 70-1975, which identifies stress ranges and allowable cycles. Preliminary calculations demonstrate that the maximum stress range forthe upgrade design is less than the allowable stress range for the most severe crane classification operating up to 100,000 cycles. The remaining cranecomponents are being designed with a 5:1 safety factor, which assures that the fatigue threshold for 100,000 cycles will not be exceeded. Assuming thatoffloading of fuel to a spent fuel storage facility must begin with the next refuelingoutage at a rate equal to fuel replenishments, as well as spent fuel pool offloading due to decommissioning activities, the total number of additional cycles is not expected to exceed 120. This includes the conservativeconsideration that both cask placement for acceptance of spent fuel and removalof the loaded cask to the spent fuel transfer vehicle are at fully loaded conditions.
This results in a total number of cycles, at maximum load for 60 years ofoperation, of 1,800 out of 70,000 allowable cycles identified in the LRA.The crane upgrade calculations have not been completed. Upon completion ofthe modification analysis, an evaluation will be made to determine the effect, ifany, on Section 4.9. If the results are not bounded by the current LRA evaluation/disposition, a revised Section 4.9 will be included with the first AnnualLRA Supplement required by 10 CFR 54, &sect; 54.21(b).In its letter, dated February 28, 2006, the applicant verified that the new calculations werecompleted and were bounded by the original evaluation; therefore, the staff's concern describedin RAI 4.9-1 is resolved.4.9.3  USAR Supplement The applicant provided a USAR supplement summary description of its TLAA evaluation ofreactor building crane load cycles in LRA Section A3.10. On the basis of its review of the USAR 4-45supplement, the staff concluded that the summary description of the applicant's actions toaddress the reactor building crane load cycles is adequate.4.9.4  Conclusion The staff concluded that the applicant provided an acceptable demonstration, pursuant to10 CFR 54.21(c)(1)(i), that the reactor building crane load cycles analyses will remain valid forthe period of extended operation. The staff also concluded that the USAR supplement containsan appropriate summary description of this TLAA evaluation, sufficient to satisfy 10 CFR 54.21(d) requirements.4.10  Fatigue Analyses of HPCI and RCIC Turbine Exhaust Penetrations4.10.1  Summary of Technical Information in the Application In LRA Section 4.10, the applicant discussed the evaluation of the high-pressure coolantinjection (HPCI) and RCIC turbine exhaust penetrations fatigue analyses. The applicant evaluated these penetrations for the combination of SRV actuations, LOCA loads, andoperational testing of the turbines and concluded that the fatigue usage of the HPCI and RCICturbine exhaust penetrations will remain below 1.0 during the period of extended operation.4.10.2  Staff Evaluation The staff reviewed LRA Section 4.10, pursuant to 10 CFR 54.21(c)(1)(ii), to verify that theanalyses have been projected to the end of the period of extended operation.The applicant evaluated the HPCI and RCIC turbine exhaust penetrations for an increasednumber of SRV cycles resulting from the 1998 power rerate. The applicant combined thefatigue usage from SRV actuations with the LOCA and operating-basis earthquake (OBE) fatigue usage. The resulting 40-year fatigue usage was well below the 1.0 allowable limit. The applicant multiplied the resulting 40-year fatigue usage by 1.5 to estimate the fatigue usage for 60 years of plant operation. The resulting fatigue usage was well below the 1.0 allowable limit.Based on its review, the staff concluded that the 1.5 factor provides a conservative estimate ofthe fatigue usage from SRV actuations, simultaneously with a LOCA and OBE, for the period ofextended operation.The applicant evaluated the fatigue usage from operational testing of the HPCI and RCICturbines separately. The applicant instrumented these nozzles to measure temperatures during the operational tests and calculated the maximum fatigue usage for the RCIC turbine exhaust penetration from these operational tests. The RCIC turbine exhaust penetration had the greatest fatigue usage. The applicant determined that the total fatigue usage will be acceptable,considering more than five RCIC turbine tests per month over the 60-year extended life.
Therefore, the applicant concluded that the analyses of the HPCI and RCIC turbine exhaustpenetrations will remain valid for the period of extended operation. The staff agreed that thenumber of HPCI and RCIC turbine tests will average fewer than five per month.Based on its review of the applicant's analysis, the staff found that the applicant adequatelydemonstrated that the fatigue usage of the HPCI and RCIC turbine exhaust penetrations willremain within acceptable limits for the period of extended operation, in accordance with 10 CFR 54.21(c)(1)(ii) requirements.
4-464.10.3  USAR SupplementThe applicant provided a USAR supplement summary description of its TLAA evaluation offatigue analyses of HPCI and RCIC turbine exhaust penetrations in LRA Section A3.11. On the basis of its review of the USAR supplement, the staff concluded that the summary description of the applicant's actions to address the fatigue analyses of HPCI and RCIC turbine exhaust penetrations is adequate.4.10.4  Conclusion The staff reviewed the applicant's TLAA regarding the fatigue analyses of HPCI and RCICturbine exhaust penetrations, as summarized in LRA Section 4.10, and concluded that the applicant has provided an acceptable demonstration, pursuant to 10 CFR 54.21(c)(1)(ii), thatthe analyses have been projected to the end of the period of extended operation. The staff alsoconcluded that the USAR supplement contains an appropriate summary description of this TLAA evaluation, sufficient to satisfy the requirements of 10 CFR 54.21(d).4.11  Conclusion for Time-Limited Aging AnalysesThe staff reviewed the information in LRA Section 4, "Time-Limited Aging Analyses." On thebasis of its review, the staff concluded that the applicant provided an adequate list of TLAAs, as defined in 10 CFR 54.3. Further, the staff concluded that the applicant demonstrated that(1) the TLAAs will remain valid for the period of extended operation, as required by10 CFR 54.21(c)(1)(i), (2) the TLAAs have been projected to the end of the period of extendedoperation, as required by 10 CFR 54.21(c)(1)(ii), or (3) that the aging effects will be adequatelymanaged for the period of extended operation, as required by 10 CFR 54.21(c)(1)(iii). The staffalso reviewed the USAR supplement for the TLAAs and found that the USAR supplement contains descriptions of the TLAAs sufficient to satisfy the requirements of 10 CFR 54.21(d). In addition, the staff concluded that no plant-specific exemptions are in effect that are based onTLAAs, as required by 10 CFR 54.21(c)(2).
5-1SECTION 5REVIEW BY THE ADVISORY COMMITTEE ON REACTORSAFEGUARDSIn accordance with Title 10, Section 54.25, "Report of the Advisory Committee on ReactorSafeguards," of the Code of Federal Regulations (10 CFR 54.25), the Advisory Committee onReactor Safeguards (ACRS) will review the license renewal application (LRA) for the MonticelloNuclear Generating Plant. The ACRS Subcommittee on Plant License Renewal will continue itsdetailed review of the LRA after this safety evaluation report (SER) is issued. The applicant and the staff from the U.S. Nuclear Regulatory Commission (the staff) will meet with thesubcommittee and the full committee to discuss issues associated with the review of the LRA.After the ACRS completes its review of the LRA and the SER, the full committee will issue areport discussing the results of the review. An update to this SER will include the ACRS report.This update will also include the staff's response to any issues and concerns identified in theACRS report.
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6-1SECTION 6CONCLUSIONThe staff of the U.S. Nuclear Regulatory Commission (NRC or the staff) reviewed the licenserenewal application (LRA) for the Monticello Nuclear Generating Plant (MNGP), in accordance with the NRC regulations and NUREG-1800, "Standard Review Plan for Review of LicenseRenewal Applications for Nuclear Power Plants," dated July 2001. Title 10, Section 54.29, "Standards for Issuance of a Renewed License," of the Code of Federal Regulations(10 CFR 54.29) provides the standards for issuance of a renewed license.On the basis of its review, the staff concluded that the applicant adequately identified thosesystems and components that are within the scope of license renewal, as required by10 CFR 54.4(a), and those systems and components that are subject to an aging managementreview, as required by 10 CFR 54.21(a)(1). The staff also concluded that the applicant demonstrated that the aging effects will be adequately managed so that the intended functionswill be maintained consistent with the current licensing basis (CLB) for the period of extendedoperation, as required by 10 CFR 54.21(a)(3). Further, the staff concluded that the applicantdemonstrated that (1) the time-limited aging analyses (TLAAs) will remain valid for the period ofextended operation, as required by 10 CFR 54.21(c)(1)(i), (2) the TLAAs had been projected tothe end of the period of extended operation, as required by 10 CFR 54.21(c)(1)(ii), or (3) thatthe aging effects will be adequately managed for the period of extended operation, as requiredby 10 CFR 54.21(c)(1)(iii). On the basis of its evaluation of the LRA, the staff determi ned thatthe requirements of 10 CFR 54.29(a) have been met, that there is reasonable assurance thatthe activities authorized by the renewed license will continue to be conducted in accordancewith the CLB, and that any changes made to the plant's CLB in order to comply with this paragraph are in accord with the Act and the Commission's regulations.The staff notes that any requirements of Subpart A, "National Environmental PolicyAct-Regulations Implementing Section 102(2)," of 10 CFR Part 51, "Environmental Protection Regulations for Domestic Licensing and Related Regulatory Functions," are documented in draft Supplement 26 to NUREG-1437, "Generic Environmental Impact Statement for LicenseRenewal of Nuclear Plants:  Regarding Monticello Nuclear Generating Plant Final Report,"
dated January 23, 2006.
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A-1APPENDIX ACOMMITMENTS FOR LICENSE RENEWAL OF MNGPDuring the review of the Monticello Nuclear Generating Plant license renewal application, theapplicant made commitments to manage the aging effects of structures and components before the period of extended operation. The following table lists these commitments, along with theimplementation schedule and the source of the commitment.
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A-3APPENDIX A:  COMMITMENTS FOR LICENSE RENEWAL OF MNGPItem No.CommitmentImplementationScheduleSource1Each year, following the submittal of the MNGP LicenseRenewal Application and at least 3 months before the scheduledcompletion of the NRC review, NMC will submit amendments tothe MNGP application pursuant to 10 CFR 54.21(b). Theserevisions will identify any changes to the CLB that materiallyaffect the contents of the LRA, including the USAR supplementsand any other aspects of the application.AnnuallyLRA Section 1.42In accordance with the guidance of Appendix A.3.2.1.2 toNUREG-1800, Appendix B to the latest issued supplement toNUREG-0933 will be reviewed for new GSls desi gnated asUSI-, HIGH-, or MEDIUM-priority. Any GSIs identified thatinvolve TLAAs or aging effects for structures and componentssubject to an aging management review will be included in theannual update of the LRA. AnnuallyLRA Section 3.0.73Inspection of the steam dryer is to be accomplished using theguidelines in the approved BWRVIP topical report(s) for steamdryer inspection. In the event a new steam dryer is installed,NMC will reevaluate the inspection requirements.As RequiredLRA Table3.1.2-3, Note 1364The interior of the diesel fire pump house masonry block walls iscovered with insulation. The MNGP Structures MonitoringProgram will require the interior surfaces of the walls to beexamined if exterior wall surfaces show evidence of significantaging effects.As RequiredLRA Table3.5.2-8, Note 516 APPENDIX A:  COMMITMENTS FOR LICENSE RENEWAL OF MNGPItem No.CommitmentImplementationScheduleSourceA-45The procedures and training used to limit RPV coldoverpressure events will be the same as those approved by the NRC when MNGP requested approval of the BWRVIP-05technical alternative for the term of the current operatinglicense. A request for extension for the 60-yearextended operating period will be submitted to the NRC beforethe period of extended operation.As RequiredLRA Section 4.2.66MNGP site-specific administrative work instructions will beapplicable to both safety- and nonsafety-related systems,structures, and components that are subject to an agingmanagement review consistent with the current licensing basisduring the period of extended operation.Prior to Period ofExtended OperationLRA Section B1.37Site documents that implement aging management activities forlicense renewal will be enhanced to ensure that an AR isprepared in accordance with plant procedures whenevernonconforming conditions are found (i.e., the acceptance criteriais not met).Prior to Period ofExtended OperationLRA Section B1.38Revisions will be made to procedures and instructions thatimplement or administer aging management programs and/oractivities for the purpose of managing the associated agingeffects for the duration of extended operation.Prior to Periodof ExtendedOperationLRA Section B1.39The MNGP ASME Section XI, Subsection IWF Program will beenhanced to provide inspections of Class MC componentsupports consistent with NUREG-1801, Chapter III, Section B1.3.Prior to Periodof ExtendedOperationLRA Section B2.1.3 APPENDIX A:  COMMITMENTS FOR LICENSE RENEWAL OF MNGPItem No.CommitmentImplementationScheduleSourceA-510The guidance for performing visual bolting inspections containedin EPRI TR-104213, Bolted Joint Maintenance & ApplicationGuide, and the Good Bolting Practices Handbook (EPRINP-5067 Volumes I and 2) will be included in the Bus DuctInspection Program, Inspection of Overhead Heavy Load andLight Load (Related to Refueling) Handling Systems Program,Structures Monitoring Program, and the System ConditionMonitoring Program.Prior to Periodof ExtendedOperationLRA Section B2.1.411The Buried Piping and Tanks Inspection Program will update theimplementing procedures to include inspections of buriedcomponents when they are uncovered.Prior to Periodof Extended OperationLRA Section B2.1.512The diesel fuel oil storage tank, T-44, internal inspection will beadded to the list of scheduled inspections in the Buried Pipingand Tanks Inspection Program.Prior to Periodof ExtendedOperationLRA Section B2.1.513The Buried Piping and Tanks Inspection Program will be revisedto include a provision that if evaluations of pipe wall thicknessshow a susceptibility to corrosion, further evaluation as to theextent of susceptibility will be performed.Prior to Periodof ExtendedOperationLRA Section B2.1.514The Buried Piping and Tanks Inspection Program will be revisedto specify a 10-year buried pipe inspection frequency.Prior to Periodof ExtendedOperationLRA Section B2.1.515The Buried Piping and Tanks Inspection Program will be revisedto specify a 10-year inspection frequency for diesel fuel oilstorage tank, T-44.Prior to Periodof ExtendedOperationLRA Section B2.1.5 APPENDIX A:  COMMITMENTS FOR LICENSE RENEWAL OF MNGPItem No.CommitmentImplementationScheduleSourceA-616The Buried Piping and Tanks Inspection Program will be revisedto include a review of previous buried piping issues to determinepossible susceptible locations.Prior to Periodof Extended OperationLRA Section B2.1.517The Bus Duct Inspection Program will be implementedconsistent with the appropriate 10 elements described inAppendix A to NUREG-1800, Standard Review Plan for Reviewof License Renewal Applications for Nuclear PowerPlants.Prior to Periodof ExtendedOperationLRA Section B2.1.618The BWR Feedwater Nozzle Program will be enhanced so theparameters monitored and inspected are consistent with therecommendations of GE NE-523-A71-0594-A, Revision 1.Prior to Periodof ExtendedOperationLRA Section B2.1.819The BWR Feedwater Nozzle Program will be enhanced so theregions being inspected, examination techniques, personnelqualifications, and inspection schedule are consistent with therecommendations of GE NE-523-A71-0594-A, Revision 1.Prior to Periodof ExtendedOperationLRA Section B2.1.820The BWR Feedwater Nozzle Program will be enhanced so thatinspections will be scheduled in accordance with therecommendations of GE NE-523-A71-0594-A, Revision 1.Prior to Periodof ExtendedOperationLRA Section B2.1.821The repair/replacement guidelines in BWRVIP-16, 19, 44, 45, 50, 51, 52, 57, and 58 will be added, as applicable, to theMNGP BWR Vessel Internals Program.Prior to Periodof ExtendedOperationLRA Section B2.1.1222NMC will perform top guide grid inspections, using the EVT-1method of examination, for the high-fluence locations (gridbeam and beam-to-beam crevice slot locations with fluenceexceeding 5.0x10 20 n/cm 2). Ten percent of the total populationwill be inspected within 12 years, with a minimum of 5 percentinspected within the first 6 years.During thePeriod ofExtendedOperationLRA Section B2.1.12 APPENDIX A:  COMMITMENTS FOR LICENSE RENEWAL OF MNGPItem No.CommitmentImplementationScheduleSourceA-723A one-time inspection will be performed to monitor the effects ofcorrosion on select portions of closed-cycle cooling watersystems that perform a pressure-integrity intended function.Prior to Periodof ExtendedOperationLRA Section B2.1.1324The Compressed Air Monitoring Program procedures will berevised to include corrective action requirements, if theacceptance limits for water vapor, oil content, or particulate arenot met. In addition, the acceptance criteria for oil contenttesting will be clarified and the basis for the acceptance limits forthe water vapor, oil content, and particulate tests will beprovided.Prior to Periodof ExtendedOperationLRA Section B2.1.1425The Compressed Air Monitoring Program will be revised toinclude inspection of air distribution piping based on therecommendations of EPRI TR-108147.Prior to Periodof ExtendedOperationLRA Section B2.1.1426The MNGP Electrical Cables & Connections Not Subject To10 CFR 50.49 Environmental Qualification RequirementsProgram will be implemented as a new program consistent withthe recommendations of GALL AMP XI.EI. The program willmanage the aging of conductor insulation material on cables,connectors, and other electrical insulation materials that areinstalled in an adverse localized environment caused by heat,radiation, or moisture.Prior to Periodof ExtendedOperationLRA Section B2.1.1527The Electrical Cables Not Subject to 10 CFR 50.49Environmental Qualification Requirements Used inInstrumentation Circuits Program will be implemented as a newprogram. With exceptions, it will be consistent with therecommendations of GALL AMP XI.E2.Prior to Periodof ExtendedOperationLRA Section B2.1.16 APPENDIX A:  COMMITMENTS FOR LICENSE RENEWAL OF MNGPItem No.CommitmentImplementationScheduleSourceA-828The MNGP Fire Protection Program will be revised to incl ude avisual inspection of the halon fire suppression system to detectany signs of degradation, such as corrosion and mechanicaldamage. This visual inspection will provide aging managementfor external surfaces of the halon fire suppression system.Prior to Periodof ExtendedOperationLRA Section B2.1.1729The Fire Protection Program plan document will be revised toinclude qualification criteria for individuals performing visualinspections of penetration seals, fire barriers, and fire doors.The qualification criteria will be in accordance with VT-1 orequivalent and VT-3 or equivalent, as applicable.Prior to Periodof ExtendedOperationLRA Section B2.1.1730The Fire Water System Program implementing procedures willbe revised to include the extrapolation of inspection results tobelow-grade fire water piping with similar conditions that existwithin the above-grade fire water piping.Prior to Periodof ExtendedOperationLRA Section B2.1.1831The Fire Water System Program sprinkler heads will beinspected and tested based on NFPA requirements or replacedbefore the end of the 50-year sprinkler head service life and at10-year intervals thereafter during the extended period ofoperation to ensure that signs of degradation, such ascorrosion, are detected in a timely manner.Prior to Periodof ExtendedOperationLRA Section B2.1.1832NMC will verify the procedures to be used for agingmanagement activities of the fire water system and apply testingin accordance with applicable NFPA codes and standards.Relevant procedures will be revised, as appropriate.Prior to Periodof ExtendedOperationLRA Section B2.1.1833The MNGP procedures related to the diesel fuel oil system willbe revised to include requirements to check for general, pitting,crevice, galvanic, MIC, and cracking.Prior to Periodof ExtendedOperationLRA Section B2.1.20 APPENDIX A:  COMMITMENTS FOR LICENSE RENEWAL OF MNGPItem No.CommitmentImplementationScheduleSourceA-934The MNGP Fuel Oil Chemistry Program procedures will berevised to require tank draining, cleaning, and inspection, ifdeemed necessary based on the trends indicated by the resultsof the diesel fuel oil analysis, or as recomm ended by t he syst emengineer based on equipment operating experience.Prior to Periodof ExtendedOperationLRA Section B2.1.2035Existing procedures in the MNGP Fuel Oil Chemistry Programwill be developed or revised to require periodic tank inspectionsof the diesel fuel oil tanks.Prior to Periodof ExtendedOperationLRA Section B2.1.2036The MNGP Inaccessible Medium Voltage (2 kV to 34.5 kV)Cables Not Subject to 10 CFR 50.49 EQ Requirements Programwill be implemented as a new program consistent with therecommendations of GALL AMP XI.E3.Prior to Periodof ExtendedOperationLRA Section B2.1.2137The Inspection of Overhead Heavy Load and Light Load(Related to Refueling) Handling Systems Program will beenhanced to specify a 5-year inspection frequency for the fuelpreparation machines.Prior to Periodof ExtendedOperationLRA Section B2.1.2238The MNGP One-Time Inspection Program will be implementedas a new program consistent with the recommendations ofGALL AMP XI.M32, "One-Time Inspection." This program willinclude measures to verify the effectiveness of the followingaging management programs: Plant Chemistry Program andFuel Oil Chemistry Program. This program will also confirm theabsence of age degradation in selected components (e.g., flowrestrictors, venturis) within the scope of license renewal.Prior to Periodof ExtendedOperationLRA Section B2.1.2339The MNGP Protective Coating Maintenance and MonitoringProgram procedures will be updated to include inspection of allaccessible painted surfaces inside containment.Prior to Periodof ExtendedOperationLRA Section B2.1.27 APPENDIX A:  COMMITMENTS FOR LICENSE RENEWAL OF MNGPItem No.CommitmentImplementationScheduleSourceA-1040The MNGP Protective Coating Maintenance and MonitoringProgram will be revised to include a preinspection review of theprevious two inspection reports so that trends can be identified.Prior to Periodof ExtendedOperationLRA Section B2.1.27 41The MNGP Protective Coating Maintenance and MonitoringProgram implementation procedures will be revised to includeprovisions for analysis of suspected reasons for coating failure.Prior to Periodof ExtendedOperationLRA Section B2.1.27 42NMC intends to use the Integrated Surveillance Program forMNGP during the period of extended operation by implementingthe requirements of BWRVIP-116, which is currently beingreviewed by the NRC.Prior to Periodof ExtendedOperationLRA Section B2.1.2943NMC will retain the capsules removed from the MNGP reactorvessel as part of the Reactor Vessel Surveillance Program.Prior to andDuring thePeriod ofExtendedOperationLRA Section B2.1.2944The MNGP Selective Leaching of Materials Program will beimplemented as a new program consistent, with exceptions, tothe recommendations of GALL AMP XI.M33. The program willbe developed and implemented before the start of the period ofextended operation. The program includes a one-time visualinspection and hardness measurement of selected componentsthat are susceptible to selective leaching. In situations in whichhardness testing is not practical, a qualitative method by otherNDE or metallurgical methods will be used to determine thepresence and extent of selective leaching. Theprogram will determine whether selective leaching is occurringfor selected components.Prior to Periodof ExtendedOperationLRA Section B2.1.30 APPENDIX A:  COMMITMENTS FOR LICENSE RENEWAL OF MNGPItem No.CommitmentImplementationScheduleSourceA-1145The MNGP Structures Monitoring Program will be ex panded, asnecessary, to include inspections of structures and structuralelements within the scope of license renewal that are notinspected as part of another aging management program.Prior to Periodof ExtendedOperationLRA Section B2.1.3146The MNGP Structures Monitoring Program implementingprocedures will be enhanced to ensure that structuralinspections are performed on submerged portions of the intakestructure from the service water bays to the wing walls.Prior to Periodof ExtendedOperationLRA Section B2.1.3147The MNGP Structures Monitoring Program implementingprocedures will be revised to include the monitoring/inspectionparameters for structural components within the scope oflicense renewal.Prior to Periodof ExtendedOperationLRA Section B2.1.3148The MNGP Structures Monitoring Program will be enhanced toinclude a requirement to sample groundwater for pH, chlorideconcentration, and sulfate concentration.Prior to Periodof ExtendedOperationLRA Section B2.1.3149The MNGP Structures Monitoring Program will be enhanced toinclude concrete evaluations of inaccessible areas ifdegradation of accessible areas is detected.Prior to Periodof ExtendedOperationLRA Section B2.1.3150The MNGP Structures Monitoring Program implementingprocedures will be enhanced to include acceptance criteria forstructural inspections of submerged portions of the intakestructure.Prior to Periodof ExtendedOperationLRA Section B2.1.3151Implementing instructions and procedures for the SystemCondition Monitoring Program will be revised to describespecific age degradation parameters to be monitored andinspected. Acceptance criteria will also be incl uded.Prior to Periodof ExtendedOperationLRA Section B2.1.32 APPENDIX A:  COMMITMENTS FOR LICENSE RENEWAL OF MNGPItem No.CommitmentImplementationScheduleSourceA-1252Requirements for inclusion of NUREG/CR-6260 locations will beincorporated in the implementing procedures for the MNGPThermal Fatigue Monitoring Program.Prior to Periodof ExtendedOperationLRA Section B3.253The NMC fleet procedure for the Flow Accelerated CorrosionProgram will be revised to include the accepted 87.5 percent ofnominal pipe wall thickness for nonsafety-related piping as atrigger point for engineering analysis.Prior to Periodof ExtendedOperationLRA Section B2.1.1954Prior to the period of extended operation, coating inspectors willmeet the requirements of ANSI N45.2.6.Prior to Periodof ExtendedOperationLRA Section B2.1.2755NMC will implement a new program at MNGP which isconsistent with GALL AMP XI.E6. Prior to Periodof ExtendedOperationResponse tofollowup to RAI3.6-2, datedFebruary 27, 200656NMC has inspected the incore monitoring dry tubes on anevery-other refueling outage periodicity and will conti nue toperform this inspection during the period of extended operation,as recommended by the guidance provided in GE SIL-409.During the Period ofExtended OperationLRA Section 4.4 and B2.1.1257NMC is an active member of the BWRVIP and will conti nue tofollow applicable inspection guidelines and recommendations,which have been reviewed and approved by the executivecommittee of the BWRVIP, throughout the period of extendedoperation.During the Period ofExtended OperationLRA Section B1.6 and B2.1.1258NMC will follow the guidance provided in BWRVIP-139, SteamDryer Inspection and Flaw Evaluation Guidelines (April 2005),for the MNGP steam dryer inspections.During the Period ofExtended OperationLRA Section 2.1.4.2.2 and B2.1.12 APPENDIX A:  COMMITMENTS FOR LICENSE RENEWAL OF MNGPItem No.CommitmentImplementationScheduleSourceA-1359NMC will add inspection requirements for the P1, P2, and P3core spray piping welds at MNGP, in accordance with guidanceprovided in BWRVIP-18 or subsequent revisions.Prior to the Period ofExtended OperationLRA Section B1.6 and B2.1.1260NMC will adhere to BWRVIP inspection guidelines for core plateholddown bolts by implementation of one or more of thefollowing:1.Develop an alternative to the inspections identified in theBWRVIP which will, at a minimum, satisfy the intent of theBWRVIP in terms of assuring core plate functional integritythroughout the period of extended operation. NMC willprovide the alternative to the inspection program to the NRCstaff for their review and approval at least 1 year beforeentering the period of extended operation.2.Inspect the core plate bolts using either UT, some othervolumetric inspections, EVT-1 from below the core plate, orother approved inspections, in accordance with BWRVIP-25,to assure an adequate number of core plate bolts are intactto prevent lateral displacement of the core plate.3.Install core plate wedges to structurally replace the lateralload resistance provided by the rim holddown bolts andperform no inspections.Prior to the Period ofExtended OperationLRA Section B2.1.12 A-14THIS PAGE IS INTENTIONALLY LEFT BLANK.
B-1APPENDIX BCHRONOLOGYThis appendix contains a chronological listing of the routine licensing correspondence betweenthe staff of the U.S. Nuclear Regulatory Commission (NRC or the staff) and the NuclearManagement Company, LLC (NMC), and other correspondence regarding the NRC staff'sreviews of the Monticello Nuclear Generating Plant (MNGP) (Docket No. 50-263) license renewal application (LRA).March 16, 2005Letter from T. Palmisano, NMC, to the NRC Transmitting Application forRenewed Operating License for the Monticello Nuclear Generating Plant(ADAMS Accession No. ML050880241)March 24, 2005NRC Press Release 053-NRC Announces Availability of LicenseRenewal Application for Monticello (ADAMS Accession No. ML050830481)March 31, 2005Letter from P.T. Kuo, NRC, to T. Palmisano, NMC, Acknowledging theReceipt and Availability of the LRA for MNGP (ADAMS AccessionNo. ML050900052)April 6, 2005Notice of April 20, 2005, Meeting for the NRC to Describe the LicenseRenewal Process (ADAMS Accession No. ML050960308)April 14, 2005NRC Press Release-III-05-016-NRC Staff Schedules Public Meeting forApril 20 to Discuss License Renewal Process for Monticello Nuclear Generating Plant (ADAMS Accession No. ML051040142)April 25, 2005Notice of May 11, 2005, Meeting Between the NRC and NMC to Discussthe LRA for MNGP (ADAMS Accession No. ML051150221)May 5, 2005Determination of Acceptability and Sufficiency for Docketing, ProposedReview Schedule, and Opportunity for a Hearing Regarding the Application for Renewal of the Operating License for MNGP (ADAMS Accession No. ML051260029)May 9,  2005Letter from J. Davis, NRC, to M. Askin regarding maintenance ofreference material at the Monticello Public Library for the MNGP LRA (ADAMS Accession No. 051300167)May 9, 2005Letter from J. Davis, NRC, to A. Wittmann regarding maintenance ofreference material at the Buffalo Public Library for the MNGP LRA (ADAMS Accession No. 051300195)May 12, 2005NRC Press Release 081-NRC Announces Opportunity for Hearingon Application to Renew Operating License for MNGP (ADAMS Accession No. ML051320170)
B-2May 12, 2005 NRC Request for Additional Information for the Review of the MNGP LRA(ADAMS Accession No. ML051330005)May 13, 2005Summary of the Public Information Session Held April 20, 2005, for theNRC to Describe the License Renewal Process (ADAMS AccessionNo. ML051310174)May 18, 2005Summary of Meeting Held May 11, 2005, between the NRC and NMC toDiscuss the MNGP LRA (ADAMS Accession No. ML051400115)May 18, 2005Revision of Schedule for the Review of the MNGP LRA (ADAMSAccession No. ML051400234)May 25, 2005Notice of June 24, 2005, Exit Meeting for the License Renewal Scopingand Screening Methodology Audit for the MNGP LRA (ADAMS Accession No. ML051450575)June 2, 2005NRC Audit and Review Plan for Plant Aging Management Reviews andPrograms for MNGP (ADAMS Accession No. ML051600008)June 10, 2005NMC Response to Request for Additional Information and Submittal ofAdditional Information in Support of the Monticello LRA (ADAMS Accession No. ML051680145)June 17, 2005Summary of Telephone Conference Held on June 9, 2005, between the NRC and NMC Concerning Draft Requests for Additional InformationPertaining to the MNGP LRA (ADAMS Accession No. ML051680443)June 21, 2005 NRC Request for Additional Information for the Review of the MNGP LRA(ADAMS Accession No. ML051720593)July 6, 2005Summary of Meeting Held June 24, 2005, between the NRC and NMC toDiscuss the Results of the Scoping and Screening Methodology Audit for the MNGP LRA (ADAMS Accession No. ML051880402)July 9, 2005Request for a Hearing and Petition for Leave to Intervene by the NorthAmerican Water Office (ADAMS Accession No. ML052280043)July 12, 2005Revision of Schedule for the Review of the MNGP LRA (ADAMSAccession No. ML051950002)July 13, 2005Notice of August 18, 2005, Exit Meeting With NMC on License RenewalAudits of Aging Management Programs and Reviews for MNGP (ADAMS Accession No. ML051940509)July 13, 2005Summary of Telephone Conference Held on July 6, 2005, between the NRC and NMC Concerning Draft Requests for Additional InformationPertaining to the MNGP LRA (ADAMS Accession No. ML051950060)July 18, 2005Audit Trip Report Regarding the NMC Application for License Renewalfor MNGP (ADAMS Accession No. ML051990091)
B-3July 20, 2005 NRC Request for Additional Information for the Review of the MNGP LRA(ADAMS Accession No. ML052020005)July 21, 2005NMC Response to Request for Additional Information Regarding theMonticello LRA (ADAMS Accession No. ML052080040)July 28, 2005Summary of Telephone Conference Held on July 14, 2005, between the NRC and NMC Concerning Draft Requests for Additional InformationPertaining to the MNGP LRA (ADAMS Accession No. ML052100060)July 28, 2005Summary of Public Scoping Meetings to Support Review of the MNGPLRA (ADAMS Accession No. ML052110002)August 3, 2005NRC Staff Answer to Petition to Intervene and Request for Hearing of theNorth American Water Office (ADAMS Accession No. ML052200245)August 3, 2005Notice of Appearance of David R. Lewis on Behalf of NMC (ADAMSAccession No. ML052280129)August 3, 2005NMC Answer to Request for Hearing and Petition to Intervene by theNorth American Water Office (ADAMS Accession No. ML052280136)August 8, 2005Memorandum of the Secretary referring the Petition for Leave toIntervene Submitted by the North American Water Office (ADAMS Accession No. ML052270368)August 9, 2005Reply Comment of the North American Water Office (ADAMS AccessionNo. ML052300291)August 11, 2005Summary of Telephone Conference Held on August 4, 2005, between the NRC and NMC Concerning Information Pertaining to the MNGP LRA(ADAMS Accession No. ML052230323)August 11, 2005NMC Responses to Aging Management Program and AgingManagement Review Audits for the Monticello LRA (ADAMS Accession No. ML052280269)August 12, 2005Establishment of Atomic Safety and Licensing Board (ADAMS AccessionNo. ML052270406)August 16, 2005NMC Response to Request for Additional Information Regarding theMonticello LRA (ADAMS Accession No. ML052340510)August 18, 2005 NRC Request for Additional Information for the Review of the MNGP LRA(ADAMS Accession No. ML052310013)August 18, 2005 NRC Request for Additional Information for the Review of the MNGP LRA(ADAMS Accession No. ML052310044)August 18, 2005 NRC Request for Additional Information for the Review of the MNGP LRA(ADAMS Accession No. ML052310055)
B-4August 19, 2005NRC Staff Motion to Strike Comment of the North American Water Office(ADAMS Accession No. ML052310573)August 29, 2005Reply of North American Water Office to the NRC Staff Motion to StrikeComment of the North American Water Office (ADAMS Accession No. ML052500328)August 31, 2005Summary of Telephone Conference Held on August 15, 2005, betweenthe NRC and NMC Concerning Information Pertaining to the MNGP LRA(ADAMS Accession No. ML052430782)August 31, 2005NMC Additional Information in Response to Aging Management Programand Aging Management Review Audits of the Monticello LRA (ADAMS Accession No. ML052500294)September 6, 2005Summary of Meeting Held August 18, 2005, between the NRC and NMCto Discuss the Results for Aging Management Programs and Reviews for the MNGP LRA (ADAMS Accession No. ML052520251)September 15, 2005 NRC Request for Additional Information for the Review of the MNGP LRA(ADAMS Accession No. ML052620622)September 16, 2005 NRC Request for Additional Information for the Review of the MNGP LRA(ADAMS Accession No. ML052620609)September 16, 2005NMC Response to Three Requests for Additional Information Regardingthe Monticello LRA (ADAMS Accession No. ML052630320)September 26, 2005Docketing of Additional Information Pertaining to the LRA for MNGP(ADAMS Accession No. ML052700535)September 27, 2005Summary of Telephone Conference Held on September 1, 2005,between the NRC and NMC Concerning Information Pertaining to theMNGP LRA (ADAMS Accession No. ML052700456)September 27, 2005Summary of Telephone Conference Held on September 7, 2005,between the NRC and NMC Concerning Information Pertaining to theMNGP LRA (ADAMS Accession No. ML052700227)September 28, 2005 NRC Request for Additional Information for the Review of the MNGP LRA(ADAMS Accession No. ML052730175)October 11, 2005Letter from G. Crocker to Administrative Judge McDade discussingincompleteness of the MNGP LRA (ADAMS Accession No. ML052930174)October 12, 2005Audit and Review Report for Plant Aging Management Reviews andPrograms for Monticello Nuclear Generating Plant (ADAMS Accession No. ML052850461)
B-5October 14, 2005NMC Response to Two Requests for Additional Information Regardingthe MNGP LRA (ADAMS Accession No. ML052910370)October 17, 2005NRC Staff Answer to the Motion of the North American Water Office toFind the License Renewal Application for the MNGP Incomplete (ADAMS Accession No. ML052900401)October 17, 2005NMC Response to North American Water Office's Motion to Find theApplication Incomplete (ADAMS Accession No. ML052970399)October 21, 2005Summary of Telephone Conference Held on October 6, 2005, betweenthe NRC and NMC Concerning Information Pertaining to the MNGP LRA(ADAMS Accession No. ML052970210)October 28, 2005NMC Response to Requests for Additional Information Regarding theMNGP LRA (ADAMS Accession No. ML053070217)October 31, 2005 NRC Request for Additional Information for the Review of the MNGP LRA(ADAMS Accession No. ML053050436)November 1, 2005Memorandum and Order, Ruling on Standing and ContentionAdmissibility (ADAMS Accession No. M L053050414)November 2, 2005Summary of Telephone Conference Call Held on October 11, 2005,between the NRC and NMC Concerning Information Pertaining to theMNGP LRA (ADAMS Accession No. ML053070112)November 7, 2005 NRC Request for Additional Information for the Review of the MNGP LRA(ADAMS Accession No. ML053120003)November 8, 2005Letter from D. Merzke, NRC, to J. Conway, NMC, Regarding PublicAvailability of Audit and Review Report (ADAMS AccessionNo. ML053140265)November 14, 2005 NRC Request for Additional Information for the Review of the MNGP LRA(ADAMS Accession No. ML053190429)November 16, 2005Letter from D. Merzke, NRC, to J. Conway, NMC, Regarding PublicAvailability of Audit Report for Scoping and Screening Methodology(ADAMS Accession No. ML053220358)November 17, 2005NMC Supplement to Responses for Requests for Additional InformationRegarding the MNGP LRA (ADAMS Accession No. ML053250099)November 18, 2005Summary of Telephone Conference Call Held on November 9, 2005,between NRC and NMC Concerning Information Pertaining to the MNGPLRA (ADAMS Accession No. ML053250489)November 22, 2005Summary of Telephone Conference Held on November 15, 2005,between the NRC and NMC Concerning Information Pertaining to theMNGP LRA (ADAMS Accession No. ML053290157)
B-6November 22, 2005NMC Response to Two Requests for Additional Information Regardingthe MNGP LRA (ADAMS Accession No. ML053340269)December 7, 2005NMC Response to Request for Additional Information Regarding theMNGP LRA (ADAMS Accession No. ML053460242)December 16, 2005NMC Supplement to Responses to Requests for Additional InformationRegarding the MNGP LRA (ADAMS Accession No. ML053550250)January 10, 2006Summary of Telephone Conference Call Held on December 21, 2005,between the NRC and NMC Concerning Information Pertaining to theMNGP LRA (ADAMS Accession No. ML060130004)January 30, 2006Summary of Telephone Conference Call Held on January 9, 2006,between the NRC and NMC Concerning Information Pertaining to theMNGP LRA (ADAMS Accession No. ML060310635)January 30, 2006Summary of Telephone Conference Call Held on January 12, 2006,between the NRC and NMC Concerning Information Pertaining to theMNGP LRA (ADAMS Accession No. ML060340200)February 8, 2006Meeting Notice Regarding Public Exit Meeting to Discuss the Results ofthe License Renewal Inspections for the Review of the MNGP LRA (ADAMS Accession No. ML060390125)February 27, 2006NMC Supplement to Responses to Requests for Additional InformationRegarding the MNGP LRA (ADAMS Accession No. ML060610583)February 28, 2006Confirmatory Items Response Regarding the MNGP LRA (ADAMSAccession No. ML060620056)March 15, 2006NMC License Renewal Application Annual Update Letter (ADAMSAccession No. ML060800360)March 30, 2006NRC License Renewal Scoping, Screening, and Aging ManagementInspection Report (ADAMS Accession No. ML060940194)March 31, 2006NMC Supplemental Information and Response to Requests for AdditionalInformation Regarding the MNGP LRA (ADAMS Accession No. ML060940124)April 10, 2006NMC Supplemental Information Regarding the MNGP LRA (ADAMSAccession No. ML061030406)April 26, 2006NRC letter to NMC Transmitting the Safety Evaluation Report Related tothe License Renewal of MNGP (ADAMS Accession No. ML061170035)June 15, 2006NMC Comments Regarding the Safety Evaluation Report for the MNGPLicense Renewal Application (ADAMS Accession No. ML061710264)
B-7June 23, 2006NMC Supplemental Information Regarding the MNGP LRA (ADAMSAccession No. ML061780532)
B-8THIS PAGE IS INTENTIONALLY LEFT BLANK.
C-1APPENDIX CPRINCIPAL CONTRIBUTORSNAMERESPONSIBILITYF. AkstulewiczManagement OversightH. AsharStructural Engineering W. BatemanManagement Oversight B. BogerManagement Oversight E. BrownManagement Oversight T. ChanManagement Oversight K. ChangGALL Audit and Review O. ChopraElectrical Engineering G. CranstonGALL Audit and Review R. DennigManagement Oversight N. DudleyGALL Audit and Review B. ElliotMaterial EngineeringJ. FairMechanical Engineering T. FordReactor Systems G. GallettiQuality Assurance G. GeorgievMechanical Engineering F. GillespieManagement OversightR. GoelMechanical Engineering V. GoelElectrical Engineering J. GrobeManagement Oversight M. HartzmanMechanical Engineering R. HernandezPlant Systems A. HodgdonLegal Counsel N. IqbalFire Protection R. JenkinsManagement Oversight S. JonesManagement Oversight R. KarasManagement Oversight K. KavanaghQuality Assurance J. KnoxElectrical Engineering P. KuoManagement Oversight C. LauronMaterial Engineering S. LeeManagement Oversight C. LiPlant Systems Y. LiMechanical Engineering M. LintzGALL Audit and Review P. LougheedRegion III InspectionL. LundManagement Oversight J. LyonsManagement Oversight J. MaMechanical Engineering K. ManolyManagement Oversight T. MartinManagement Oversight D. MatthewsManagement Oversight M. MayfieldManagement Oversight R. McNallyMechanical Engineering D. MerzkeLead Project Manager C-2M. MitchellManagement OversightJ. RajanMechanical Engineering J. RavalMechanical Engineering B. RogersQuality Assurance J. RowleyProject Management D. ShumPlant Systems D. SolarioManagement Oversight J. StrnishaMechanical Engineering D. ThatcherManagement Oversight S. TingenQuality Assurance M. TschiltzManagement Oversight S. WeerakkodyManagement Oversight P. WenGALL Audit and Review G. WilsonManagement Oversight R. WolfgangFire Protection M. WoodsLegal Counsel M. YoderMaterial Engineering J. ZimmermanManagement OversightCONTRACTORSCONTRACTORTECHNICAL AREALegin Group, Inc.SER SupportAdvanced Technologies and GALL Audit and Report Laboratories International, Inc.
Pacific Northwest NationalPlant Systems Laboratory D-1APPENDIX DREFERENCESThis appendix contains a listing of the references used in the preparation of the SafetyEvaluation Report developed during the review of the license renewal application for Monticello Nuclear Generating Plant (MNGP), Docket Number 50-263.Boiling Water Reactor Vessel and Internals Project (BWRVIP)BWRVIP-03, "BWR Vessel and Internals Project, Reactor Pressure Vessel and InternalsExamination Guidelines."BWRVIP-18, "BWR Core Spray Internals Inspection and Flaw Evaluation Guidelines."BWRVIP-25, "BWR Core Plate Inspection and Flaw Evaluation Guidelines."BWRVIP-26, "BWR Top Guide Inspection and Flaw Evaluation Guidelines."BWRVIP-27, "BWR Vessel and Internals Project, BWR Standby Liquid Control System/CorePlate DP Inspection and Flaw Evaluation Guidelines."BWRVIP-29, "BWR Water Chemistry Guidelines-1993 Revision," EPRI Topical Report,TR-103515.BWRVIP-38, "BWR Shroud Support Inspection and Flaw Evaluation Guidelines."BWRVIP-41, "BWR Jet Pump Assembly Inspection and Flaw Evaluation Guidelines."BWRVIP-47, "BWR Lower Plenum Inspection and Flaw Evaluation Guidelines."BWRVIP-48, "Vessel ID Attachment Weld and Inspection and Flaw Guidelines," EPRI TopicalReport TR-108724.BWRVIP-49, "BWR Instrument Penetration Inspection and Flaw Evaluation Guidelines."BWRVIP-74-A, "BWR Reactor Pressure Vessel Inspection and Flaw Evaluation Guidelines forLicense Renewal."BWRVIP-78, "BWR Integrated Surveillance Program (ISP) Plan."BWRVIP-86, "BWR Vessel and Internals Project:  BWR Integrated Surveillance Program (ISP)Implementation."BWRVIP-130, "BWR Water Chemistry Guidelines-2004 Revision," EPRI Topical Report,TR-1008192.Code of Federal Regulations Title 10, Part 50, "Domestic Licensing of Production and Utilization Facilities," of the Code ofFederal Regulations
.Title 10, Part 50, Appendix B, "Quality Assurance Criteria for Nuclear Power Plants and FuelProcessing Plants,"of the Code of Federal Regulations.Title 10, Part 50, Appendix H, "Reactor Vessel Material Surveillance Program Requirements," of the Code of Federal Regulations.
D-2Title 10, Part 50, Appendix J, "Primary Reactor Containment Leakage Testing for Water-CooledPower Reactors," of the Code of Federal Regulations.Title 10, Part 50, Appendix R, "Fire Protection Program for Nuclear Power Facilities OperatingPrior to January 1, 1979," of the Code of Federal Regulations
.Title 10, Part 51, "Environmental Protectioin Regulations for Domestic Licensing and RelatedRegulatory Functions," of the Code of Federal Regulations.Title 10, Part 54, "Requirements for Renewal of Operating Licenses for Nuclear Power Plants,"of the Code of Federal Regulations.Title 10, Part 100, "Reactor Site Criteria," of the Code of Federal Regulations
.Electric Power Research Institute (EPRI)
EPRI NP-5067, Volumes 1 and 2, "Good Bolting Practices."EPRI NP-5769, "Degradation and Failure of Bolting in Nuclear Power Plants." EPRI Report 1002950, Revision 1, "Aging Effects for Structures and Structural Components(Structural Tools)," May 2003.EPRI Report 1003056, Revision 3, "Non-Class 1 Mechanical Implementation Guideline andMechanical Tools."EPRI Report 1007933, "Aging Assessment Field Guide," December 2003.EPRI Report 1008035, Revision 1, "Expansion Joint Maintenance Guide," May 2003.EPRI Topical Report, TR-1007820, "Closed Cooling Water Chemistry Guideline."EPRI Topical Report, TR-103595, "Report of the Instrument Air Working Group."EPRI TR-104213, "Bolted Joint Maintenance & Application Guide." EPRI Topical Report, TR-108147, "Compressor and Instrument Air System MaintenanceGuide," March 1998.EPRI Topical Report, TR-112657, Revision B-A, "Revised Risk Informed In-Service InspectionEvaluation Procedure."NSAC-202L-R2, "Recommendations for an Effective Flow-Accelerated Corrosion Program,"Electric Power Research Institute.Miscellaneous American Concrete Institute (ACI) 349.3R-96, "Evaluation of Existing Nuclear Safety RelatedConcrete Structures."American Society of Mechanical Engineers (ASME), Boiler and Pressure Vessel Code, SectionXI, Subsection IWB, IWC, and IWD.ASME, Boiler and Pressure Vessel Code, Section XI, Subsection IWE.ASME, Boiler and Pressure Vessel Code, Section XI, Subsection IWF.ASME, Boiler and Pressure Vessel Code, Section XI, Subsection NF.American Society for Testing and Materials (ASTM) D 6217, "Test Method for ParticulateContamination in Middle Distillate Fuels by Laboratory Filtration."
D-3American National Standards Institute (ANSI)/Instrument Society of America (ISA) S7.3,"Quality Standard for Instrument Air." ANSI/ISA Z86.1-1973, "Commodity Specification for Air and Drager Operating Instruction." ANSI N45.2.6, "Qualification of Inspection, Examination, and Testing Personnel for theConstruction Phase of Nuclear Power Plants."ANSI N45.2.9, "Requirements for Collection, Storage, and Maintenance of Quality AssuranceRecords for Nuclear Power Plants," 1974.ASTM D 5163-96, "Standard Guide for Establishing Procedures To Monitor the Performance ofSafety Related Coatings in an Operating Nuclear Power Plant."Audit and Review Plan for Plant Aging Management Reviews and Programs for MonticelloNuclear Generating Plant, June 2, 2005.Audit and Review Report for Plant Aging Management Reviews and Programs for MonticelloNuclear Generating Plant, October 12, 2005.Fire Protection Safety Evaluation Report, August 29, 1979.J.P. Foster, "Analysis of In-reactor Stress Relaxation Using Irradiation Creep Models," ASTMSTP611, Irradiation Effects on the Microstructure and Properties of Metals , 1976.General Electric Document SASR 89-77, "Accumulated Fatigue Usage for the MonticelloNuclear Generating Station Reactor Pressure."General Electric Service Information Letter (SIL)-409, "Incore Dry Tube Cracks" General Electric Topical Report, GE-NE-523-A71-0594, Revision 1, "Alternate BWR FeedwaterNozzle Inspection Requirements." General Electric Topical Report NEDC-32983P, "General Electric (GE) Methodology forReactor Pressure Vessel Fast Neutron Flux Evaluation." Letter from NRC to MNGP, "Monticello Nuclear Generating Plant-Risk Informed In-ServiceInspection Program (TAC NO. MB3819)," July 24, 2002.Letter from NRC to MNGP, "Monticello Nuclear Generating Plant-Fourth 10-Year In-ServiceInspection Interval Request for Relief No. 4 (TAC No. MC2222)," January 6, 2005.Letter from NRC to Nuclear Energy Institute and Union of Concerned Scientists, "StandardizedFormat for License Renewal Applications (MB7344)," April 7, 2003. "Metals Handbook," Ninth Edition, American Society for Metals International.Monticello Nuclear Generating Plant Updated Safety Analysis Report (USAR), Revision 21.NEDO-32205-A, Revision 1, "10 CFR 50 Appendix G Equivalent Margin Analysis for Low UpperShelf Energy in BWR/2-6 Vessels," February 1994.NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50,Appendix J," March 1996.NEI 95-10, "Industry Guideline for Implementing the Requirements of 10 CFR Part 54-TheLicense Renewal Rule," Revision 3, March 2001.NUMARC 93-01, Revision 2, "Industry Guideline for Monitoring the Effectiveness ofMaintenance at Nuclear Power Plants," April 1996.
D-4SAND96-0344, "Aging Management Guideline for Commercial Nuclear Power Plants-ElectricalCable and Terminations," Sandia National Laboratories, September 1996.NRC Generic Communications NRC GL 80-95, "Generic Activity A-10," November 13, 1980.NRC GL 81-11, "BWR Feedwater Nozzle and Control Rod Drive Return Line Nozzle Cracking(NUREG-0619)," February 29, 1981.NRC GL 88-01, "NRC Position on IGSCC in BWR Austenitic Stainless Steel Piping,"January 25, 1988.NRC GL 88-14, "Instrument Air Supply System Problems Affecting Safety Equipment,"August 8, 1988.NRC Generic Letter (GL) 89-08, "Erosion/Corrosion-Induced Pipe Wall Thinning," May 2, 1989.NRC GL 89-13, "Service Water System Problems Affecting Safety-Related Equipment,"July 18, 1989.NRC GL 98-04, "Potential for Degradation of the Emergency Core Cooling System (ECCS) andthe Containment Spray System after a Loss-of-Cooling Accident because of Construction and Protective Coating Deficiencies and Foreign Material in Containment," July 14, 1998.NRC GL 98-05, "Boiling Water Reactor Licensees Use of the BWRVIP-05 Report to RequestRelief from Augmented Inspection." NRC IN 81-38, "Potentially Significant Equipment Failures Resulting from Contamination ofAir-Operated Systems," December 17, 1981.NRC IN 87-28, "Air System Problems at U.S. Light Water Reactors," J une 22, 1987.NRC IN 87-67, "Lessons Learned from Regional Inspections of Licensee Actions in Responseto IE Bulletin 80-11," December 31, 1987.NRC Information Notice (IN) 2001-09, "Main Feedwater System Degradation in Safety-RelatedASME Code Class 2 Piping Inside the Containment of a Pressurized Water Reactor," June 12, 2001.NRC Regulatory Guides NRC RG 1.127, Revision 1, "Inspection of Water-Control Structures Associated with NuclearPower Plants," March 1978.NRC RG 1.147, Revision 13, "In-Service Inspection Code Case Acceptability, ASME Section XI,Division 1," January 2004.NRC RG 1.160, Revision 2, "Monitoring the Effectiveness of Maintenance at Nuclear PowerPlants," March 1997.NRC RG 1.163, "Performance-Based Containment Leak-Test Program," September 1995.NRC RG 1.174, Revision 1, "An Approach for Using Probabilistic Risk Assessment inRisk-Informed Decisions on Plant-Specific Changes to the Licensing Basis," November 2002.NRC RG 1.178, Revision 1, "An Approach for Plant-Specific Risk-Informed Decision-Making forIn-Service Inspection of Piping," September 2003.NRC RG 1.190, "Calculational and Dosimetry Methods for Determining Pressure VesselNeutron Fluence," March 2001.
D-5NRC RG 1.54, "Service Level I, II, and III Protective Coatings Applied to Nuclear Power Plants,"June 1973.NRC RG 1.65, "Materials and Inspections for Reactor Vessel Closure Studs," October 1973.NRC RG 1.99, Revision 2, "Radiation Embrittlement of Reactor Vessel Materials," May 1988.NUREG Series Reports NUREG-0313, "Technical Report on Material Selection and Processing Guidelines for BWRCoolant Pressure Boundary Piping," Revision 2, January 1988.NUREG-0619, "BWR Feedwater Nozzle and Control Rod Drive Return Line Nozzle Cracking: Resolution of Generic Technical Activity A-10," November 1980.NUREG-0661, "Safety Evaluation Report, Mark I Containment Long Term Program, Resolutionof Generic Technical Activity A-7," July 1980.NUREG-1339, "Resolution of Generic Safety Issue 29:  Bolting Degradation or Failure inNuclear Power Plants."NUREG-1344, "Erosion/Corrosion-Induced Pipe Wall Thinning in U.S. Nuclear PowerPlants," 1989.NUREG-1743, "Safety Evaluation Report Related to the License Renewal of Arkansas NuclearOne, Unit 1," April 2001.NUREG-1800, "Standard Review Plan for Review of License Renewal Applications for NuclearPower Plants," April 2001.NUREG-1801, "Generic Aging Lessons Learned (GALL) Report," July 2001.NUREG/CR-5643, "Insights Gained from Aging Research," March 1992.NUREG/CR-5704, "Effects of LWR Coolant Environments on Fatigue Design Curves ofAustenitic Stainless Steels," April 1999.NUREG/CR-6260, "Application of NUREG/CR-5999 Interim Fatigue Curves for SelectedNuclear Power Plant Components." NUREG/CR-6583, "Effects of LWR Coolant Environments on Fatigue Design Curves of Carbonand Low-Alloy Steels," February 1998.}}

Revision as of 10:11, 11 November 2018

Safety Evaluation Report (SER) Related to the License Renewal of Monticello Nuclear Generating Plant
ML062090408
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Site: Monticello Xcel Energy icon.png
Issue date: 07/28/2006
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Office of Nuclear Reactor Regulation
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Nuclear Management Co
Merzke, D., NRR/ADRO/DLR/RLRB, 415-3777
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Safety Evaluation ReportRelated to the License Renewal of the MonticelloNuclear Generating PlantDocket No. 50-263Nuclear Management Company, LLCU.S. Nuclear Regulatory CommissionOffice of Nuclear Reactor RegulationJuly 2006 THIS PAGE IS INTENTIONALLY LEFT BLANK.

iiiABSTRACTThis safety evaluation report (SER) documents the technical review of the Monticello NuclearGenerating Plant (MNGP) license renewal application (LRA) by the staff of the U.S. NuclearRegulatory Commission (NRC or the staff). By letter dated March 16, 2005, NuclearManagement Company, LLC (NMC or the applicant), submitted the LRA for MNGP in accordance with Title 10, Part 54, "Requirements for Renewal of Operating Licenses for Nuclear Power Plants," of the Code of Federal Regulations (10 CFR Part 54). NMC isrequesting renewal of the operating license for MNGP (Facility Operating License NumberDPR-22) for a period of 20 years beyond the current expiration date of midnight September 8, 2010.MNGP is located approximately 30 miles northwest of Minneapolis, Minnesota. The NRC issuedthe construction permit for MNGP on June 19, 1967. The NRC issued the operating license forMNGP on January 9, 1981. MNGP is a single-cycle, forced circulation, General Electric BWR-3,a boiling-water reactor producing steam for direct use in a steam turbine. General Electric Corporation supplied the nuclear steam supply system and Bechtel Corporation originallydesigned and constructed the balance of the plant. MNGP operates at a licensed power outputof 1775 megawatt thermal (MWt), with a gross electrical output of approximately 600 megawatt electric (MWe).The staff reviewed the MNGP LRA in accordance with Commission regulations and NUREG-1800, "Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants," dated July 2001. Section 6 of this SER provides the staff's conclusion of its review of the MNGP LRA.The NRC license renewal project manager is Mr. Daniel Merzke. Mr. Merzke may be reached at(301) 415-3777. Written correspondence should be addressed to the Division of License Renewal, Mail Stop O-11F1, U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001.

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vTABLE OF CONTENTSAbstract.................................................................iiiTable of Contents...........................................................v Abbreviations............................................................xiv 1 Introduction and General Discussion........................................1-11.1 Introduction........................................................1-11.2 License Renewal Background..........................................1-21.2.1 Safety Review.................................................1-3

1.2.2 Environmental

Review...........................................1-41.3 Principal Review Matters..............................................1-5

1.4 Interim

Staff Guidance................................................1-61.5 Summary of Open Items..............................................1-81.6 Summary of Confirmatory Items........................................1-8

1.7 Summary

of Proposed License Conditions................................1-82 Structures and Components Subject to Aging Management Review................2-12.1 Scoping and Screening Methodology....................................2-12.1.1 Introduction...................................................2-12.1.2 Summary of Technical Information in the Application...................2-12.1.2.1 Scoping Methodology.....................................2-22.1.2.2 Screening Methodology...................................2-72.1.3 Staff Evaluation................................................2-82.1.3.1 Scoping Methodology.....................................2-92.1.3.2 Screening Methodology..................................2-202.1.3.3 QA Controls Applied to LRA Development....................2-24 2.1.3.4 Training...............................................2-242.1.4 Conclusion..................................................2-252.2 Plant-Level Scoping Results..........................................2-252.2.1 Introduction..................................................2-252.2.2 Summary of Technical Information in the Application..................2-25

2.2.3 Staff

Evaluation...............................................2-25 2.2.4 Conclusion..................................................2-272.3 Scoping and Screening Results: Mechanical Systems......................2-272.3.1 Reactor Vessel, Internals, and Reactor Coolant System................2-282.3.1.1 Reactor Head Vent System...............................2-292.3.1.2 Reactor Pressure Vessel.................................2-30 2.3.1.3 Reactor Pressure Vessel Internals..........................2-32 2.3.1.4 Reactor Recirculation System.............................2-34 2.3.1.5 Reactor Vessel Instrumentation............................2-372.3.2 Engineered Safety Features.....................................2-382.3.2.1 Automatic Pressure Relief System..........................2-39 2.3.2.2 Combustible Gas Control System..........................2-40 2.3.2.3 Core Spray System.....................................2-40 2.3.2.4 High-Pressure Coolant Injection System.....................2-42 vi2.3.2.5 Primary Containment Mechanical System....................2-432.3.2.6 Reactor Core Isolation Cooling System......................2-45 2.3.2.7 Residual Heat Removal System............................2-462.3.2.8 Secondary Containment System...........................2-482.3.3 Auxiliary Systems.............................................2-492.3.3.1 Alternate Nitrogen System................................2-502.3.3.2 Chemistry Sampling System..............................2-51 2.3.3.3 Circulating Water System.................................2-52 2.3.3.4 Control Rod Drive System................................2-54 2.3.3.5 Demineralized Water System..............................2-55 2.3.3.6 Emergency Diesel Generators System......................2-562.3.3.7 Emergency Filtration Train System.........................2-59 2.3.3.8 Emergency Service Water System..........................2-61 2.3.3.9 Fire System...........................................2-63 2.3.3.10 Fuel Pool Cooling and Cleanup System.....................2-712.3.3.11 Heating and Ventilation System...........................2-742.3.3.12 Instrument and Service Air System........................2-772.3.3.13 Radwaste Solid and Liquid System........................2-792.3.3.14 Reactor Building Closed Cooling Water System..............2-85 2.3.3.15 Reactor Water Cleanup System...........................2-862.3.3.16 Service and Seal Water System..........................2-892.3.3.17 Standby Liquid Control System...........................2-912.3.3.18 Wells and Domestic Water System........................2-922.3.4 Steam and Power Conversion System.............................2-932.3.4.1 Condensate Storage System..............................2-932.3.4.2 Condensate and Feedwater System........................2-962.3.4.3 Main Condenser System.................................2-992.3.4.4 Main Steam System....................................2-103 2.3.4.5 Turbine Generator System...............................2-1052.4 Scoping and Screening Results: Containments, Structures, andComponent Supports..............................................2-1082.4.1 Cranes, Heavy Loads, Rigging..................................2-1092.4.1.1 Summary of Technical Information in the Application..........2-109 2.4.1.2 Staff Evaluation.......................................2-110 2.4.1.3 Conclusion...........................................2-1102.4.2 Diesel Fuel Oil Transfer House..................................2-1102.4.2.1 Summary of Technical Information in the Application..........2-110 2.4.2.2 Staff Evaluation.......................................2-111 2.4.2.3 Conclusion...........................................2-1122.4.3 Emergency Diesel Generator Building............................2-1132.4.3.1 Summary of Technical Information in the Application..........2-113 2.4.3.2 Staff Evaluation.......................................2-114 2.4.3.3 Conclusion...........................................2-1142.4.4 Emergency Filtration Train Building...............................2-1142.4.4.1 Summary of Technical Information in the Application..........2-114 2.4.4.2 Staff Evaluation.......................................2-115 2.4.4.3 Conclusion...........................................2-1162.4.5 Fire Protection Barriers Commodity Group.........................2-1162.4.5.1 Summary of Technical Information in the Application..........2-116 vii2.4.5.2 Staff Evaluation.......................................2-1172.4.5.3 Conclusion...........................................2-1182.4.6 Hangers and Supports Commodity Group.........................2-1182.4.6.1 Summary of Technical Information in the Application..........2-118 2.4.6.2 Staff Evaluation.......................................2-122 2.4.6.3 Conclusion...........................................2-1242.4.7 HPCI Building...............................................2-1242.4.7.1 Summary of Technical Information in the Application..........2-124 2.4.7.2 Staff Evaluation.......................................2-125 2.4.7.3 Conclusion...........................................2-1252.4.8 Intake Structure..............................................2-1252.4.8.1 Summary of Technical Information in the Application..........2-125 2.4.8.2 Staff Evaluation.......................................2-127 2.4.8.3 Conclusion...........................................2-1272.4.9 Miscellaneous SBO Yard Structures..............................2-1272.4.9.1 Summary of Technical Information in the Application..........2-127 2.4.9.2 Staff Evaluation.......................................2-128 2.4.9.3 Conclusion...........................................2-1292.4.10 Offgas Stack...............................................2-1292.4.10.1 Summary of Technical Information in the Application.........2-129 2.4.10.2 Staff Evaluation......................................2-130 2.4.10.3 Conclusion..........................................2-1302.4.11 Offgas Storage and Compressor Building.........................2-1312.4.11.1 Summary of Technical Information in the Application.........2-131 2.4.11.2 Staff Evaluation......................................2-131 2.4.11.3 Conclusion..........................................2-1322.4.12 Plant Control and Cable Spreading Structure......................2-1322.4.12.1 Summary of Technical Information in the Application.........2-132 2.4.12.2 Staff Evaluation......................................2-133 2.4.12.3 Conclusion..........................................2-1332.4.13 Primary Containment.........................................2-1342.4.13.1 Summary of Technical Information in the Application.........2-134 2.4.13.2 Staff Evaluation......................................2-136 2.4.13.3 Conclusion..........................................2-1382.4.14 Radioactive Waste Building...................................2-1382.4.14.1 Summary of Technical Information in the Application.........2-138 2.4.14.2 Staff Evaluation......................................2-139 2.4.14.3 Conclusion..........................................2-1402.4.15 Reactor Building............................................2-1402.4.15.1 Summary of Technical Information in the Application.........2-140 2.4.15.2 Staff Evaluation......................................2-142 2.4.15.3 Conclusion..........................................2-1422.4.16 Structures Affecting Safety....................................2-1432.4.16.1 Summary of Technical Information in the Application.........2-143 2.4.16.2 Staff Evaluation......................................2-144 2.4.16.3 Conclusion..........................................2-1442.4.17 Turbine Building............................................2-1442.4.17.1 Summary of Technical Information in the Application.........2-144 2.4.17.2 Staff Evaluation......................................2-146 viii2.4.17.3 Conclusion..........................................2-1472.4.18 Underground Duct Bank......................................2-1472.4.18.1 Summary of Technical Information in the Application.........2-147 2.4.18.2 Staff Evaluation......................................2-148 2.4.18.3 Conclusion..........................................2-1482.5 Scoping and Screening Results: Electrical and Instrumentation andControls.........................................................2-148

2.5.1 Electrical

and Instrumentation and Controls Systems.................2-1492.5.1.1 480-V Station Auxiliary..................................2-1502.5.1.2 4.16-kV Station Auxiliary................................2-1512.5.1.3 Alternate Shutdown....................................2-152 2.5.1.4 Annunciators.........................................2-1532.5.1.5 Communications......................................2-154 2.5.1.6 DC Battery...........................................2-155 2.5.1.7 Lighting.............................................2-157 2.5.1.8 Neutron Monitoring.....................................2-158 2.5.1.9 Offsite Power.........................................2-159 2.5.1.10 Plant Protection......................................2-159 2.5.1.11 Radiation Monitoring..................................2-160 2.5.1.12 Reactor Level Control.................................2-161 2.5.1.13 Uninterruptible AC....................................2-1622.5.2 Electrical Commodities........................................2-1632.5.2.1 Electrical Penetrations..................................2-1642.5.2.2 Fuse Holders.........................................2-165 2.5.2.3 Non-EQ Cables and Connections.........................2-1662.5.2.4 Offsite Power/SBO Recovery Path........................2-1672.6 Conclusion for Scoping and Screening.................................2-1683 Aging Management Review Results.........................................3-13.0 Applicant's Use of the Generic Aging Lessons Learned Report................3-13.0.1 Format of the License Renewal Application..........................3-23.0.1.1 Overview of Table 1......................................3-2 3.0.1.2 Overview of Table 2......................................3-33.0.2 Staff's Review Process..........................................3-43.0.2.1 Review of AMPs.........................................3-4 3.0.2.2 Review of AMR Results...................................3-5 3.0.2.3 USAR Supplement.......................................3-63.0.2.4 Documentation and Documents Reviewed....................3-63.0.3 Aging Management Programs.....................................3-63.0.3.1 AMPs That Are Consistent with the GALL Report..............3-103.0.3.2 AMPs That Are Consistent with the GALL Report withExceptions or Enhancements.............................3-303.0.3.3 AMPs That Are Not Consistent with or Not Addressedin the GALL Report....................................3-1283.0.4 Quality Assurance Program Attributes Integral to AgingManagement Programs........................................3-1393.0.4.1 Summary of Technical Information in the Application..........3-140 3.0.4.2 Staff Evaluation.......................................3-141 3.0.4.3 Conclusion...........................................3-141 ix3.1 Aging Management of Reactor Coolant System..........................3-1413.1.1 Summary of Technical Information in the Application.................3-141

3.1.2 Staff

Evaluation..............................................3-1423.1.2.1 AMR Results That Are Consistent with the GALL Report........3-1493.1.2.2 AMR Results That Are Consistent with the GALL Report,for Which Further Evaluation is Recommended...............3-1513.1.2.3 AMR Results That Are Not Consistent with or NotAddressed in the GALL Report...........................3-1613.1.3 Conclusion.................................................3-1653.2 Aging Management of Engineered Safety Features.......................3-1653.2.1 Summary of Technical Information in the Application.................3-165

3.2.2 Staff

Evaluation..............................................3-1663.2.2.1 AMR Results That Are Consistent with the GALL Report........3-1703.2.2.2 AMR Results That Are Consistent with the GALL Report,for Which Further Evaluation is Recommended...............3-1723.2.2.3 AMR Results That Are Not Consistent with or NotAddressed in the GALL Report...........................3-1813.2.3 Conclusion.................................................3-1903.3 Aging Management of Auxiliary Systems...............................3-1903.3.1 Summary of Technical Information in the Application.................3-191

3.3.2 Staff

Evaluation..............................................3-1913.3.2.1 AMR Results That Are Consistent with the GALL Report........3-1973.3.2.2 AMR Results That Are Consistent with the GALL Report,for Which Further Evaluation is Recommended...............3-2003.3.2.3 AMR Results That Are Not Consistent with or NotAddressed in the GALL Report...........................3-2113.3.3 Conclusion.................................................3-2403.4 Aging Management of Steam and Power Conversion System...............3-2403.4.1 Summary of Technical Information in the Application.................3-240

3.4.2 Staff

Evaluation..............................................3-2403.4.2.1 AMR Results That Are Consistent with the GALL Report........3-2433.4.2.2 AMR Results That Are Consistent with the GALL Report,for Which Further Evaluation is Recommended...............3-2463.4.2.3 AMR Results That Are Not Consistent with or NotAddressed in the GALL Report...........................3-2503.4.3 Conclusion.................................................3-2583.5 Aging Management of Containments, Structures, and Component Supports...............................................................3-2583.5.1 Summary of Technical Information in the Application.................3-258

3.5.2 Staff

Evaluation..............................................3-2593.5.2.1 AMR Results That Are Consistent with the GALL Report........3-2663.5.2.2 AMR Results That Are Consistent with the GALL Report,for Which Further Evaluation is Recommended...............3-2683.5.2.3 AMR Results That Are Not Consistent with or NotAddressed in the GALL Report...........................3-2813.5.3 Conclusion.................................................3-3053.6 Aging Management of Electrical and Instrumentation and Controls...........3-3053.6.1 Summary of Technical Information in the Application.................3-305

3.6.2 Staff

Evaluation..............................................3-306 x3.6.2.1 AMR Results That Are Consistent with the GALL Report........3-3083.6.2.2 AMR Results That Are Consistent with the GALL Report,for Which Further Evaluation is Recommended...............3-3103.6.2.3 AMR Results That Are Not Consistent with or NotAddressed in the GALL Report...........................3-3113.6.3 Conclusion.................................................3-3193.7 Conclusion for Aging Management Review Results.......................3-3204 Time-Limited Aging Analyses..............................................4-14.1 Identification of Time-Limited Aging Analyses..............................4-14.1.1 Summary of Technical Information in the Application...................4-1

4.1.2 Staff

Evaluation................................................4-2 4.1.3 Conclusion...................................................4-24.2 Neutron Embrittlement of the Reactor Vessel and Internals...................4-24.2.1 RPV Materials USE Reduction Due to Neutron Embrittlement............4-34.2.1.1 Summary of Technical Information in the Application............4-3 4.2.1.2 Staff Evaluation.........................................4-4 4.2.1.3 USAR Supplement.......................................4-94.2.1.4 Conclusion.............................................4-94.2.2 Adjusted Reference Temperature (ART) for RPV Materials Dueto Neutron Embrittlement........................................4-9 4.2.2.1 Summary of Technical Information in the Application............4-9 4.2.2.2 Staff Evaluation.........................................4-9 4.2.2.3 USAR Supplement......................................4-104.2.2.4 Conclusion............................................4-104.2.3 Reflood Thermal Shock Analysis of the RPV........................4-104.2.3.1 Summary of Technical Information in the Application...........4-10 4.2.3.2 Staff Evaluation........................................4-10 4.2.3.3 USAR Supplement......................................4-124.2.3.4 Conclusion............................................4-124.2.4 Reflood Thermal Shock Analysis of the RPV Core Shroud..............4-124.2.4.1 Summary of Technical Information in the Application...........4-12 4.2.4.2 Staff Evaluation........................................4-12 4.2.4.3 USAR Supplement......................................4-134.2.4.4 Conclusion............................................4-134.2.5 RPV Thermal Limit Analysis: Operating Pressure-TemperatureLimits.......................................................4-13 4.2.5.1 Summary of Technical Information in the Application...........4-13 4.2.5.2 Staff Evaluation........................................4-14 4.2.5.3 USAR Supplement......................................4-144.2.5.4 Conclusion............................................4-144.2.6 RPV Circumferential Weld Examination Relief.......................4-154.2.6.1 Summary of Technical Information in the Application...........4-15 4.2.6.2 Staff Evaluation........................................4-15 4.2.6.3 USAR Supplement......................................4-174.2.6.4 Conclusion............................................4-174.2.7 RPV Axial Weld Failure Probability................................4-174.2.7.1 Summary of Technical Information in the Application...........4-17 4.2.7.2 Staff Evaluation........................................4-17 xi4.2.7.3 USAR Supplement......................................4-184.2.7.4 Conclusion............................................4-184.3 Metal Fatigue of the RPV and Internals, and Reactor Coolant Pressure Boundary Piping and Components.....................................4-194.3.1 RPV Fatigue Analyses.........................................4-194.3.1.1 Summary of Technical Information in the Application...........4-19 4.3.1.2 Staff Evaluation........................................4-19 4.3.1.3 USAR Supplement......................................4-204.3.1.4 Conclusion............................................4-204.3.2 Fatigue Analysis of RPV Internals.................................4-214.3.2.1 Summary of Technical Information in the Application...........4-21 4.3.2.2 Staff Evaluation........................................4-21 4.3.2.3 USAR Supplement......................................4-224.3.2.4 Conclusion............................................4-224.3.3 ASME Section III Class 1 Reactor Coolant Pressure Boundary (RCPB) Piping and Fatigue Analysis...............................4-224.3.3.1 Summary of Technical Information in the Application...........4-22 4.3.3.2 Staff Evaluation........................................4-22 4.3.3.3 USAR Supplement......................................4-234.3.3.4 Conclusion............................................4-244.3.4 RCPB Section III Class 2 and 3, Piping and Components..............4-244.3.4.1 Summary of Technical Information in the Application...........4-24 4.3.4.2 Staff Evaluation........................................4-24 4.3.4.3 USAR Supplement......................................4-254.3.4.4 Conclusion............................................4-254.4 Irradiation-Assisted Stress-Corrosion Cracking (IASCC).....................4-254.4.1 Summary of Technical Information in the Application..................4-25

4.4.2 Staff

Evaluation...............................................4-25 4.4.3 USAR Supplement............................................4-274.4.4 Conclusion..................................................4-274.5 Effects of Reactor Coolant Environment.................................4-274.5.1 Summary of Technical Information in the Application..................4-27

4.5.2 Staff

Evaluation...............................................4-28 4.5.3 USAR Supplement............................................4-304.5.4 Conclusion..................................................4-304.6 Fatigue Analyses of the Primary Containment, Attached Piping, andComponents......................................................4-304.6.1 Fatigue Analysis of the Suppression Chamber, Vents, andDowncomers.................................................4-31 4.6.1.1 Summary of Technical Information in the Application...........4-31 4.6.1.2 Staff Evaluation........................................4-31 4.6.1.3 USAR Supplement......................................4-314.6.1.4 Conclusion............................................4-314.6.2 Fatigue Analysis of the SRV Piping Inside the SuppressionChamber and Internal Structures.................................4-324.6.2.1 Summary of Technical Information in the Application...........4-32 4.6.2.2 Staff Evaluation........................................4-32 4.6.2.3 USAR Supplement......................................4-324.6.2.4 Conclusion............................................4-33 xii4.6.3 Fatigue Analysis of Suppression Chamber External Piping and Penetrations4-334.6.3.1 Summary of Technical Information in the Application...........4-33 4.6.3.2 Staff Evaluation........................................4-33 4.6.3.3 USAR Supplement......................................4-344.6.3.4 Conclusion............................................4-344.6.4 Drywell-to-Suppression Chamber Vent Line Bellows FatigueAnalysis.....................................................4-34 4.6.4.1 Summary of Technical Information in the Application...........4-34 4.6.4.2 Staff Evaluation........................................4-34 4.6.4.3 USAR Supplement......................................4-354.6.4.4 Conclusion............................................4-354.6.5 Primary Containment Process Penetration Bellows FatigueAnalysis.....................................................4-35 4.6.5.1 Summary of Technical Information in the Application...........4-35 4.6.5.2 Staff Evaluation........................................4-35 4.6.5.3 USAR Supplement......................................4-364.6.5.4 Conclusion............................................4-364.7 Environmental Qualification of Electrical Equipment (EQ)....................4-364.7.1 Summary of Technical Information in the Application..................4-36

4.7.2 Staff

Evaluation...............................................4-36 4.7.3 USAR Supplement............................................4-394.7.4 Conclusion..................................................4-394.8 Stress Relaxation of Rim Holddown Bolts................................4-394.8.1 Summary of Technical Information in the Application..................4-39

4.8.2 Staff

Evaluation...............................................4-39 4.8.3 USAR Supplement............................................4-424.8.4 Conclusion..................................................4-434.9 Reactor Building Crane Load Cycles....................................4-434.9.1 Summary of Technical Information in the Application..................4-43

4.9.2 Staff

Evaluation...............................................4-43 4.9.3 USAR Supplement............................................4-444.9.4 Conclusion..................................................4-454.10 Fatigue Analyses of HPCI and RCIC Turbine Exhaust Penetrations...........4-454.10.1 Summary of Technical Information in the Application.................4-45 4.10.2 Staff Evaluation..............................................4-45 4.10.3 USAR Supplement...........................................4-464.10.4 Conclusion.................................................4-464.11 Conclusion for Time-Limited Aging Analyses............................4-465 Review by the Advisory Committee on Reactor Safeguards.......................5-16 Conclusion............................................................6-1 xiiiAppendicesAppendix A: Commitments for License Renewal................................A-1Appendix B: Chronology...................................................B-1Appendix C: Principal Contributors...........................................C-1Appendix D: References...................................................D-1TablesTable 3.0.3-1 MNGP's Aging Management Programs.............................3-6Table 3.1-1 Staff Evaluation for Reactor Coolant System Components in the GALL Report................................................................3-143Table 3.2-1 Staff Evaluation for Engineered Safety Features Components in the GALL Report...........................................................3-167Table 3.3-1 Staff Evaluation for Auxiliary Systems Components in the GALL Report...3-192Table 3.4-1 Staff Evaluation for Steam and Power Conversion System Components in the GALL Report......................................................3-241Table 3.5-1 Staff Evaluation for Containments, Structures, and Component Supports in theGALL Report...........................................................3-260Table 3.6-1 Staff Evaluation for Electrical and Instrumentation and Controls Components in the GALL Report...........................................3-307Table 4.2.1-1 Reactor Vessel Upper Shelf Energy Analysis Summary................4-8Table 4.2.6-1 Effects of Irradiation on RPV Circumferential Weld Properties for MNGP..4-16 Table 4.2.7-1 Effects of Irradiation on RPV Axial Weld Properties for MNGP..........4-18 xivABBREVIATIONSACalternating currentACIAmerican Concrete Institute ACRSAdvisory Committee on Reactor Safeguards ADAMSAgencywide Document Access and Management System ADSautomatic depressurization systemAERMaging effect requiring management AFWauxiliary feedwaterAIRinstrument and service air AMAsaging management activities AMGaging management guideline AMPaging management program AMRaging management review AN2alternate nitrogen systemANSIAmerican National Standards Institute APRautomatic pressure relief APRMaverage power range monitor ARaction request ARMarea radiation monitor ARTadjusted reference temperature ASAAmerican Standards Association ASDalternate shutdown ASMEAmerican Society of Mechanical Engineers ASTMAmerican Society for Testing and Materials ATWSanticipated transient without scram AWIadministrative work instructionB&WBabcock and WilcoxBWRboiling-water reactor BWROGBoiling Water Reactor Owners Group BWRVIPBoiling Water Reactor Vessel and Internals ProjectCAPCorrective Action ProgramCASScast austenitic stainless steel CB&IChicago Bridge & Iron CCCWclosed-cycle cooling water CCWclosed cooling water or component cooling water CDRmain condenser CECombustion Engineering

CFRCode of Federal RegulationsCFWcondensate and feedwater CGCcombustible gas control CIconfirmatory item CLBcurrent licensing basis CMAACrane Manufacturers Association of America CRcondition report xvCRDcontrol rod driveCRDAcontrol rod drop acci dentCRDMcontrol rod drive mechanismCRGTcontrol rod guide tube CScontainment spray CSPcore spray CSTcondensate storage tank CUFcumulative usage factor CVCSchemical and volume control systemCWcirculating waterDBAdesign-basis accidentDBDdesign-basis document DBEdesign-basis event DCdirect current DGdiesel generator DGNEDG system DOEDepartment of Energy DOLdiesel oil DWSdemineralized water systemECCSemergency core cooling systemECPelectrochemical potential EDGemergency diesel generator EFBemergency filtration train building EFPYeffective full-power years EFTemergency filtration train EMAequivalent margin analysis EOCIElectric Overhead Crane Institute EOLend of license EPRIElectric Power Research Institute EQenvironmental qualification ESFengineered safety feature ESWemergency service waterFACflow-accelerated corrosionFERCFederal Energy Commission, U.S.

F enenvironmental fatigue factorFHAfire hazards analysis FIRfire system FPfire protection FPCfuel pool cooling and cleanup

FRFederal Registerft-lbfoot-pound FPPfire protection plan FSARfinal safety analysis report FSDfunctional system descriptionFWfeedwater xviGALLgeneric aging lessons learnedGEGeneral Electric GEISGeneric Environmental Impact Statement GLgeneric letter GSIgeneric safety issueHCUhydraulic accumulatorHELBhigh-energy line break HPhorsepower HE/MEhigh energy/moderate energy HEPAhigh efficiency particulate filter HGRhangers and supports HJTCheated junction thermocouple HPBHPCI building HPChigh pressure coolant injection HPCIhigh-pressure coolant injection HTVheating and ventilation HVACheating, ventilation, and air conditioning HWChydrogen water chemistryI&Cinstrumentation and controlsIASCCirradiation assisted stress-corrosion cracking IDinside diameter IEBInspection and Enforcement Bulletin IEEEInstitute of Electrical and Electronics Engineers IFintended function IGAintergranular attack IGSCCintergranular stress-corrosion cracking INinformation notice INPOInstitute of Nuclear Power Operations IPAintegrated plant assessment IRinsulation resistance IRMintermediate range monitor ISAInstrument Society of America ISGinterim staff guidance ISIinservice inspection ISPIntegrated Surveillance Program IWBrequirements for Class 1 components of light-water cooled power plants IWCrequirements for Class 2 components of light-water cooled power plants IWDrequirements for Class 3 components of light-water cooled power plants IWErequirements for Class MC and metallic liners of Class CC components oflight-water cooled power plantsIWFrequirements for Class 1, 2, 3, and MC component supports of light-water cooledpower plantsIWLrequirements for Class CC concrete components of light-water cooled powerplantsksione KIP per square inch, 1000 psiksi-in1/2kilopound per square inch times square root of inches xviikV1000 volts or 1 kilovoltlb/ft 2pound(s) per square footLISLicensing Information Service LLClimited liability com panyLOlubricating oil LLRTlocal leak-rate test LOCAloss-of-coolant accident LOOPloss of offsite power LPlow pressure LPCIlow-pressure coolant injection LPRMlocal power range monitor LRlicense renewal LRAlicense renewal applicationMCCmotor control centerMCRmain control room MEAPmaterial, environment, aging effects, and aging management program MeVmillion electron volts MICmicrobiologically influenced corrosion MNGPMonticello Nuclear Generating Plant MODmotor-operated disconnect MRmaintenance rule MSIVmain steam isolation valve MSTmain steam MTEBNOT DEFINED MUDmakeup demineralizer MVPmechanical vacuum pump MWmegawatts MWemegawatt electric MWhmegawatt hour MWtmegawatt thermaln/cm 2neutrons per square centimeterNDEnondestructive examination NEINuclear Energy Institute NEPANational Environmental Policy Act of 1969 NFPANational Fire Protection Association NMCNuclear Management Company, LLC NMSneutron monitori ng syst emNPSnominal pipe size NRCU.S. Nuclear Regulatory Commission NSRnonsafety-related NSSSnuclear steam suppl y systemNUMARCNuclear Utility Management and Resource CouncilNUREGdesignation of publication prepared by NRC staffOBEoperating-basis earthquake xviiiOCCWopen-cycle cooling water programODSCCoutside-diameter stress-corrosion cracking OEoperating experience OGBoff gas storage and compressor building OGSoff gas stack OIopen itemP&IDpiping and instrumentation diagramPApublic addr ess systemPABplant administration building PASSpost-accident sampli ng syst emPBDprogram-basis document PBXprivate branch exchange PCISprimary containment isolation system PCMprimary containment mechanical PCSprocess computer system PCTprimary containment pHconcentration of hydrogen ions PMpreventive maintenance ppbparts per billion ppmparts per million PPSplant protection system PRMprocess radiation monitor psipounds per square inch psigpounds per square inch gauge P-Tpressure temperature PTpenetrant testing PVCpolyvinyl chloride (plastic)

PWRpressurized-water reactor PWSCCprimary water stress-corrosion crackingQAquality assuranceQCquality control Q-Listquality listRADradwaste solid and liquidRAIrequest for additional information RBCreactor building closed cooling water RBMrod block monitor RCIreactor core isolation cooling RCICreactor core isolation cooling RCPreactor coolant pump RCPBreactor coolant pressure boundary RCSreactor coolant system RECreactor recirculation RGregulatory guide RHRresidual heat removal RI-ISIrisk-informed inservice inspection xixRITreactor internalsRLCreactor level control RPVreactor pressure vessel RSWresidual heat removal service water

RTNDTreference temperature nil ductility transitionRVIreactor vessel instrumentation RVIDReactor Vessel Integrity Database RWBradioactive waste building RWCreactor water cleanupSBOstation blackoutSCstructure and component SCBAself-contained breathing apparatus SCCstress-corrosion cracking SCTsecondary containment SEsafety evaluation SERsafety evaluation report SFPspent fuel pool SIsafety injection SILservice information letter SJAEsteam jet air ejector SLCstandby liquid control SMAWshield metal arc weld SOERsignificant operating event report SPCsteam and power conversion SPDSsafety parameter display system SRsafety-related SRMsource range monitor SRPStandard Review Plan SRP-LRStandard Review Plan for Review of License Renewal Applications for NuclearPower PlantsSRVsafety relief valve SSCsystem, structure, or componentSSWservice & seal water SWservice waterTACtechnical assignment control (internal NRC work management tool)TAPtorus attached piping TASCSthermal stratification, cycling, and striping TGSCCtransgranular stress-corrosion cracking TLAAtime-limited aging analysis TRtopical report TStechnical specification TTthermal transientUACuninterruptible alternating currentµmmicrometer UDBunderground duct bank UPSuninterruptible power supply xxUSARUpdated Safety Analysis ReportUSASUnited States of America Standards USEupper-shelf energy UTultrasonic testing UVultravioletVACvolts-alternating currentVDCvolts-direct current VTvisual examinationWDWwell and domestic waterWOwork orderXLPEcross-linked polyethylene 1-1SECTION 1INTRODUCTION AND GENERAL DISCUSSION1.1 IntroductionThis document is a safety evaluation report (SER) on the application for license renewal (LR)for the Monticello Nuclear Generating Plant (MNGP), as filed by the Nuclear Management Company, LLC (NMC or the applicant). By letter dated March 16, 2005, NMC submitted its application to the U.S. Nuclear Regulatory Commission (NRC or the Commission) for renewalof the MNGP operating license for an additional 20 years. The NRC staff (the staff) preparedthis report, which summarizes the results of its safety review of the renewal application for compliance with the requirements of Title 10, Part 54, "Requirements for Renewal of OperatingLicenses for Nuclear Power Plants," of the Code of Federal Regulations (10 CFR Part 54). TheNRC license renewal project manager for the MNGP license renewal review is Daniel Merzke.Mr. Merzke can be contacted by telephone at 301-415-3777 or by electronic mail at DXM2@nrc.gov. Alternatively, written correspondence may be sent to the following address:Division of License RenewalU.S. Nuclear Regulatory Commission Washington, DC 20555-0001 Attention: Daniel Merzke, Mail Stop 0-11F1In its March 16, 2005, submittal letter, the applicant requested renewal of the operating licenseissued under Section 104b (Operating License No. DPR-22) of the Atomic Energy Act of 1954, as amended, for MNGP, for a period of 20 years beyond the current license expiration date of midnight September 8, 2010. MNGP is located approximately 30 miles northwest of Minneapolis, Minnesota. The NRC issued the construction permit for MNGP on June 19, 1967.The NRC issued the operating license for MNGP on January 9, 1981. MNGP is a single-cycle,forced circulation, General Electric BWR-3, boiling-water reactor producing steam for direct usein a steam turbine. General Electric Corporation supplied the nuclear steam supply system andBechtel Corporation originally designed and constructed the balance of the plant. MNGP operates at a licensed power output of 1775 megawatt thermal (MWt), with a gross electrical output of approximately 600 megawatt electric (MWe). The Updated Safety Analysis Report (USAR) contains details concerning the plant and the site.The license renewal process consists of two concurrent reviews-a technical review of safetyissues and an environmental review. The NRC regulations found in 10 CFR Part 54 and 10CFR Part 51, "Environmental Protection Regulations for Domestic Licensing and Related Regulatory Functions," respectively, set forth the requirements for these reviews. The safety review for the MNGP license renewal is based on the applicant's license renewal application (LRA) and on its responses to the staff's requests for additional information (RAIs). The applicant supplemented and clarified its responses to the LRA and RAIs in audits, meetings, and docketed correspondence. The staff reviewed and considered all information submitted in support of the LRA. The public may view the LRA and all pertinent information and materials, including the USAR mentioned above, at the NRC Public Document Room, located in OneWhite Flint North, 11555 Rockville Pike (first floor), Rockville, MD 20852-2738(301-415-4737/800-397-4209), and at the Monticello Public Library, 200 West 6 th Street, 1-2Monticello, MN 55362. In addition, the public may find the MNGP LRA, as well as materialsrelated 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 MNGP LRA and describesthe 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 staffreviewed the LRA in accordance with NRC regulations and the guidance provided inNUREG-1800, "Standard Review Plan for Review of License Renewal Applications for NuclearPower Plants" (SRP-LR), dated July 2001.Sections 2 through 4 of this SER address the staff's review and evaluation of license renewalissues that it considered during the review of the application. Section 5 is reserved for the reportof the Advisory Committee on Reactor Safeguards (ACRS). Section 6 provides the conclusions of this report.Appendix A to this SER is a table that identifies the applicant's commitments associated withthe renewal of the operating license. Appendix B provides a chronology of the principal correspondence between the NRC and the applicant related to the review of the application.Appendix C is a list of principal contributors to the SER. Appendix D is a bibliography of the references used in support of the review.In accordance with 10 CFR Part 51, the staff prepared a draft plant-specific supplement to theGeneric Environmental Impact Statement (GEIS). This supplement discusses the environmental considerations related to renewing the license for MNGP. The staff issued draft Supplement 26 to NUREG-1437, "Generic Environmental Impact Statement for LicenseRenewal of Nuclear Plants Regarding Monticello Nuclear Generating Plant (NUREG-1437,Supplement 26) Draft Report for Comment," on

.1.2 License Renewal Backgr oundPursuant to Section 103c of the Atomic Energy Act of 1954, as amended, and NRC regulations(10 CFR 50.51(a)), operating licenses for commercial power reactors are issued for 40 years.

Pursuant to 10 CFR 54.31(b), these licenses can be renewed for up to 20 additional years. The original 40-year license term was selected on the basis of economic and antitrust considerations, rather than on technical limitations; however, some individual plant and equipment designs may have been engineered on the basis of an expected 40-year service life.In 1982, the NRC anticipated interest in license renewal and held a workshop on nuclear powerplant aging. This workshop led the NRC to establish a comprehensive program plan for nuclearplant aging research. On the basis of the results of that research, a technical review group concluded that many aging phenomena are readily manageable and do not pose technical issues that would preclude life extension for nuclear power plants. In 1986, the NRC publisheda 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 NRC published the license renewal rule in 10 CFR Part 54 (the Rule) (Volume 56,page 64943, of the Federal Register (56 FR 64943), dated December 13, 1991). The NRCparticipated in an industry-sponsored demonstration program to apply the Rule to a pilot plant 1-3and to gain experience necessary to develop implementation guidance. To establish a scope ofreview for license renewal, the Rule defined age-related degradation unique to license renewal; however, during the demonstration program, the NRC found that many aging mechanismsoccur and are managed during the period of initial license. In addition, the NRC f ound that thescope of the review did not allow sufficient credit for existing programs, particularly the implementation of the Maintenance Rule, which also manages plant-aging phenomena. As aresult, the NRC amended the Rule 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, andmore predictable than the previous Rule. In particular, the NRC amended 10 CFR Part 54 tofocus on managing the adverse effects of aging, rather than on identifying age-related degradation unique to license renewal. The NRC initiated these rule changes to ensure thatimportant systems, structures, and components (SSCs) will continue to perform their intendedfunctions during the period of extended operation. In addition, the revised Rule clarified andsimplified the integrated plant assessment (IPA) process to be consistent with the revised focuson 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 environmental impacts of license renewal and to fulfill the NRC's responsibilities underthe National Environmental Policy Act of 1969 (NEPA).1.2.1 Safety Review License renewal requirements for power reactors are based on two key principles:(1)The regulatory process is adequate to ensure that the licensing bases of all currentlyoperating plants provide and maintain an acceptable level of safety, with the possible exception of the detrimental effects of aging on the functionality of certain SSCs, as well as a few other safety-related (SR) issues, during the period of extended operation.(2)The plant-specific licensing basis must be maintained during the renewal term in thesame manner and to the same extent as during the original licensing term.In implementing these two principles, 10 CFR 54.4, "Scope," defines the scope of licenserenewal as including those SSCs (1) that are SR, (2) whose failure could affect SR functions, and (3) that are relied on to demonstrate compliance with the NRC's regulations for fireprotection (FP), environmental qualification (EQ), pressurized thermal shock (PTS), anticipated transient without scram (ATWS), and station blackout (SBO).Pursuant to 10 CFR 54.21(a), an applicant for a renewed license must review all SSCs that arewithin the scope of the Rule to identify SCs that are subject to an aging management review (AMR). Those SCs that are subject to an AMR perform an intended function without moving parts, or without a change in configuration or properties, and are not subject to replacement based on qualified life or specified time period. As required by 10 CFR 54.21(a), an applicant for a renewed license must demonstrate that the effects of aging will be managed in such a waythat the intended function, or functions, of those SCs will be maintained, consistent with thecurrent licensing basis (CLB), for the period of extended operation; however, active equipment is considered to be adequately monitored and maintained by existing programs. In other words, the detrimental effects of aging that may affect active equipment are more readily detectable 1-4and can be identified and corrected through routine surveillance, performance monitoring, andmaintenance activities. The surveillance and maintenance activities programs for activeequipment, as well as other aspects of maintaining the plant's design and licensing basis, are required throughout the period of extended operation.Pursuant to 10 CFR 54.21(d), each LRA is required to include a supplement to the USAR. Thissupplement must contain a summary description of the applicant's programs and activities for managing the effects of aging and the evaluation of time-limited aging analyses (TLAAs) for the period of extended operation.License renewal also requires the identification and updating of the TLAAs. During the designphase for a plant, certain assumptions are made about the length of time the plant can operate.

These assumptions are incorporated into design calculations for several of the plant's SSCs. In accordance with 10 CFR 54.21(c)(1), the applicant must either show that these calculations willremain valid for the period of extended operation, project the analyses to the end of the periodof extended operation, or demonstrate that the effects of aging on these SSCs can beadequately managed for the period of extended operation.In 2001, the NRC developed and issued Regulatory Guide (RG) 1.188, "Standard Format andContent for Applications to Renew Nuclear Power Plant Operating Licenses." This RG endorses NEI 95-10, Revision 3, "Industry Guideline for Implementing the Requirements of 10 CFR Part 54-The License Renewal Rule," which the Nuclear Energy Institute (NEI) issued in March 2001. NEI 95-10 details an acceptable method of implementing the license renewal rule. TheNRC also used the SRP-LR to review this application.In the LRA, MNGP fully utilizes the process defined in NUREG-1801, "Generic Aging LessonsLearned (GALL) Report," issued in July 2001. The GALL Report provides a summary of staff-approved aging management programs (AMPs) for the aging of many SCs that are subject to an AMR. If an applicant commits to implementing these staff-approved AMPs, the time, effort, and resources used to review an applicant's LRA can be greatly reduced, thereby improving the efficiency and effectiveness of the license renewal review process. The GALL Report summarizes the aging management evaluations, programs, and activities credited for managing aging for most of the SCs used throughout the industry. The report also serves as a reference for both applicants and staff reviewers to quickly identify those AMPs and activities that the staff has determined can provide adequate aging management during the period ofextended operation.1.2.2 Environmental Review In December 1996, the staff revised the environmental protection regulations to facilitate theenvironmental review for license renewal. The staff prepared NUREG-1437, Revision 1,"Generic Environmental Impact Statement for License Renewal of Nuclear Plants," to document its evaluation of the possible environmental impacts associated with renewing licenses of nuclear power plants. For certain types of environmental impacts, the GEIS establishes generic findings that are applicable to all nuclear power plants. These generic findings are codified in Appendix B, "Environmental Effect of Renewing the Operating Licenseof 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), an 1-5applicant for license renewal may incorporate these generic findings in its environmental report.In accordance with 10 CFR 51.53(c)(3)(ii), an environmental report must also include analyses of those environmental impacts that must be evaluated on a plant-specific basis (i.e.,

Category 2 issues).In accordance with NEPA and the requirements of 10 CFR Part 51, the NRC performed aplant-specific review of the environmental impacts of license renewal, including whether new and significant information existed that the GEIS did not consider. As part of its scoping process, the NRC held a public meeting on June 30, 2005, in Monticello, Minnesota, to identifyenvironmental issues specific to the plant. The NRC's draft plant-specific Supplement 26 to theGEIS regarding MNGP documents the results of the environmental review and includes a preliminary recommendation with respect to the license renewal action. The NRC held anotherpublic meeting on March 22, 2006, in Monticello, Minnesota, to discuss the draft plant-specificSupplement 26 to the GEIS regarding MNGP. After considering comments on the draft, the NRC will prepare and publish a final, plant-specific supplement to the GEIS separately from thisreport.1.3 Principal Review MattersTitle 10, Part 54, of the Code of Federal Regulations describes the requirements for renewingoperating licenses for nuclear power plants. The staff performed its technical review of the MNGP LRA in accordance with NRC guidance and the requirements of 10 CFR Part 54.Title 10, Section 54.29, "Standards for Issuance of a Renewed License," of the Code of FederalRegulations sets forth the standards for renewing a license. This SER describes the results ofthe staff's safety review.In 10 CFR 54.19(a), the NRC requires a license renewal applicant to submit generalinformation. The applicant provided this general information in Section 1 of its LRA for MNGP, which it submitted to the NRC by letter dated March 16, 2005. The staff reviewed Section 1 andfound that the applicant had submitted the information required by 10 CFR 54.19(a).In 10 CFR 54.19(b), the NRC requires that each LRA include "conforming changes to thestandard indemnity agreement, 10 CFR 140.92, Appendix B to account for the expiration term of the proposed renewed license." The applicant stated the following in the LRA regarding thisissue:The current indemnity agreement No. B-42 for the Monticello Nuclear GeneratingPlant states that the agreement shall terminate at the time of expiration of thelicense.The indemnity agreement lists DPR-22 as the applicable license number. Shouldthe license number be changed upon issuance of the renewed license, NMC requests that conforming changes be made to the indemnity agreement as appropriate.The staff intends to maintain the original license number upon issuance of the renewed license.Therefore, conforming changes to the indemnity agreement do not need to be made, and the requirements of 10 CFR 54.19(b) have been met.

1-6In 10 CFR 54.21, "Contents of Application-Technical Information," the NRC requires that eachLRA must contain (a) an IPA, (b) a description of any CLB changes that occurred during the staff review of the LRA, (c) an evaluation of TLAAs, and (d) an FSAR (Final Safety Analysis Report) supplement. Sections 3 and 4 and Appendix B to the LRA address the license renewal requirements of 10 CFR 54.21(a), (b), and (c). Appendix A to the LRA contains the USAR supplement required by 10 CFR 54.21(d).In 10 CFR 54.21(b), the NRC requires that each year following submission of the LRA, and atleast 3 months before the scheduled completion of the staff's review, the applicant must submit an amendment to the renewal application that identifies any changes to the CLB of the facilitythat materially affect the contents of the LRA, including the USAR supplement. The applicantsubmitted an update to the LRA by letter dated March 15, 2006, which summarized the changes to the CLB that had occurred at MNGP during the staff's review of the LRA. Thissubmission satisfies the requirements of 10 CFR 54.21(b) and is st ill under staff review.In accordance with 10 CFR 54.22, "Contents of Application-Technical Specifications," anapplicant's LRA must include changes or additions to the technical specifications (TSs) that are necessary to manage the effects of aging during the period of extended operation. In Appendix D to the LRA, the applicant stated that it had not identified any TS changes necessaryto support issuance of the renewed operating license for MNGP. This adequately addresses the requirement specified in 10 CFR 54.22.The staff evaluated the technical information required by 10 CFR 54.21 and 10 CFR 54.22 inaccordance with NRC regulations and the guidance provided by the SRP-LR. Sections 2, 3, and4 of this SER document the staff's evaluation of the technical information contained in the LRA.The final plant-specific supplement to the GEIS will document the staff's evaluation of theenvironmental information required by 10 CFR 54.23, "Contents of Application-EnvironmentalInformation," and will specify the considerations related to renewing the license for MNGP. Thestaff will prepare this supplement separately from this SER.1.4 Interim Staff GuidanceThe license renewal program is a living program. The NRC staff, industry, and other interestedstakeholders gain experience and develop lessons learned with each renewed license. The lessons learned address the NRC's performance goals of safety, openness, and effectiveness.Interim staff guidance (ISG) is documented for use by the NRC staff, industry, and otherinterested stakeholders until it is incorporated into license renewal guidance documents, such as the SRP-LR and the GALL Report.Table 1.4-1 provides the current set of ISGs issued by the staff, as well as the SER sections inwhich the staff addresses them.

1-7Table 1.4-1 Current Interim Staff GuidanceISG Issue(Approved ISG No.)PurposeSER SectionGALL Report presents oneacceptable way to manage agingeffects(ISG-1)This ISG clarifies that the GALLReport contains one acceptableway, but not the only way, tomanage aging for license renewal.N/ASBO Scoping(ISG-2)The license renewal rule10 CFR 54.4(a)(3) includes10 CFR 50.63(a)(1)-SBO.The SBO rule requires that a plantmust withstand and recover froman SBO event. The recovery timefor offsite power is much fasterthan that of EDGs.The offsite power system should beincluded within the scope of licenserenewal.Concrete AMP(ISG-3)Lessons learned from the GALLdemonstration project indicate thatGALL is not clear on whetherconcrete requires an AMP.FP System Piping(ISG-4)This ISG clarifies the staff positionfor wall-thinning of the FP pipingsystem in GALL AMPs XI.M26 andXI.M27.The staff's new position is thatthere is no need to disassemble FPpiping, as disassembly canintroduce oxygen to FP piping,which can accelerate corrosion.Instead, a nonintrusive method,such as volumetric inspection, canbe used.Testing of sprinkler heads shouldbe performed at year 50 ofsprinkler system service life, andevery 10 years thereafter.This ISG eliminates thehalon/carbon dioxide systeminspections for charging pressure,valve lineups, and the automaticmode of operation test from GALL;the staff considers these testverifications to be operationalactivities.

ISG Issue(Approved ISG No.)PurposeSER Section1-8Identification and Treatment ofElectrical Fuse Holders(ISG-5)This ISG includes electrical fuseholders AMR and AMP (i.e., sameas terminal blocks and otherelectrical connections).The position includes only fuseholders that are not inside theenclosure of active components(e.g., inside of switchgears andinverters).Operating experience finds thatmetallic clamps (spring-loadedclips) have a history of age-relatedfailures from aging stressors suchas vibration, thermal cycling,mechanical stress, corrosion, andchemical contamination.The staff finds that visualinspection of fuse clips is notsufficient to detect the aging effectsfrom fatigue, mechanical stress,and vibration.The ISG Process(ISG-8)This ISG clarifies and updates theISG process on improved licenserenewal guidance documents.N/AStandardized Format for LicenseRenewal Applications(ISG-10)This ISG provides a standardizedLRA format for applicants.N/A1.5 Summary of Open ItemsAn open item (OI) is an issue that, in the staff's judgment, has not been resolved in a mannerthat meets all applicable regulatory requirements. The NRC issued the initial SER on April 26,2006, with no OIs. The staff did not identify any subsequent open items in preparing the final SER.1.6 Summary of Confirmatory ItemsA confirmatory item (CI) is an issue that the applicant and the staff have resolved, but for whichthe applicant has not yet formally submitted the resolution. The NRC issued the initial SER onApril 26, 2006, with no CIs. The staff did not identify any subsequent CIs in preparing the finalSER.1.7 Summary of Proposed License ConditionsAs a result of the staff's review of the LRA for MNGP, including subsequent information andclarifications provided by the applicant, the staff identified three proposed license conditions.

1-9The first license condition requires the applicant to include the USAR supplement required by10 CFR 54.21(d) in the next USAR update, as required by 10 CFR 50.71(e), following the issuance of the renewed license.The second license condition requires that the list of commitments identified in Appendix A tothis SER be completed in accordance with the schedule in Appendix A.The third license condition requires that all capsules placed in storage must be maintained forfuture insertion. Any changes to storage requirements must be approved by the NRC, asrequired by 10 CFR Part 50, Appendix H.

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2-1SECTION 2STRUCTURES AND COMPONENTS SUBJECT TO AGINGMANAGEMENT REVIEW2.1 Scoping and Screening Methodology2.1.1 IntroductionTitle 10, Section 54.21, "Contents of Application-Technical Information," of the Code ofFederal Regulations (10 CFR 54.21) requires that each license renewal application (LRA)contain an integrated plant assessment (IPA). Furthermore, the IPA must list and identifystructures and components (SCs) subject to an aging management review (AMR) from all of the systems, structures, and components (SSCs) within the scope of license renewal inaccordance with 10 CFR 54.4, "Scope."In LRA Section 2.1, "Scoping and Screening Methodology," the applicant described the scopingand screening methodology used to identify SSCs at the Monticello Nuclear GeneratingPlant (MNGP) within the scope of license renewal and the SCs subject to an AMR. The staff reviewed the applicant's scoping and screening methodology to determine whether it meets thescoping requirements stated in 10 CFR 54.4(a) and the screening requirements stated in10 CFR 54.21.In developing the scoping and screening methodology for the MNGP LRA, the applicantconsidered the requirements of 10 CFR Part 54, "Requirements for Renewal of OperatingLicenses for Nuclear Power Plants," (the Rule), the Statements of Consideration for the Rule,and the guidance presented by the Nuclear Energy Institute (NEI), in NEI 95-10, Revision 4, "Industry Guideline for Implementing the Requirements of 10 CFR Part 54-The License Renewal Rule." In developing this methodology, the applicant also considered the correspondence between the U.S. Nuclear Regulatory Commission (NRC or the staff) and otherapplicants or NEI.2.1.2 Summary of Technical Information in the Application In LRA Sections 2 and 3, the applicant provided the technical information required by10 CFR 54.21(a). In LRA Section 2.1, the applicant described the process used to identifySSCs that meet the license renewal scoping criteria under 10 CFR 54.4(a), as well as the process used to identify SCs subject to an AMR, pursuant to 10 CFR 54.21(a)(1).Additionally, LRA Sections 2.2, "Plant Level Scoping Results," 2.3, "System Scoping andScreening Results: Mechanical Systems," 2.4, "Scoping and Screening Results: Containments, Structures, and Component Supports," and 2.5, "Scoping and Screening Results: Electrical and Instrumentation and Controls Systems," amplify the process the applicant used to identify SCssubject to an AMR. LRA Section 3, "Aging Management Review Results," contains the following information:

2-2

  • Section 3.5, "Aging Management of Containments, Structures, and ComponentSupports"
  • Section 3.6, "Aging Management of Electrical and Instrumentation and Controls" LRA Section 4, "Time-Limited Aging Analyses," contains the applicant's identification andevaluation of time-limited aging analyses.2.1.2.1 Scoping Methodology In LRA Section 2.1, the applicant described the methodology used to scope SSCs, pursuant tothe 10 CFR 54.4(a) scoping criteria. The following sections present the applicant's scoping methodology, as described in the LRA.2.1.2.1.1 Application of the Scoping Criteria in 10 CFR 54.4(a)The applicant described the general approach to scoping safety-related (SR) andnonsafety-related (NSR) SSCs and SSCs credited with demonstrating compliance with certain regulated events in LRA Section 2.1.2, "Application of Scoping Criteria in 10 CFR 54.4(a)." Thefollowing sections describe the scoping approaches specific to each of the three 10 CFR 54.4(a) scoping criteria.Application of the Scoping Criterion in 10 CFR 54.4(a)(1)In LRA Section 2.1.4.2.1, "Scoping Criterion 1-Safety Related SSCs," the applicant presentedits scoping methodology as it pertains to SR criteria pursuant to 10 CFR 54.4(a)(1). The applicant used MNGP Q-List and Q-List Extension color-coded drawings to code items as SR in the MNGP plant equipment electronic database (CHAMPS), which also served as one of a number of information sources in the current licensing basis (CLB) used to identify SSCs meeting Scoping Criterion 1. For example, information from the Updated Safety Analysis Report (USAR), technical specifications (TSs), and design documents was reviewed to ensure all major system and structure functions had been identified properly. These functions werecompared to Scoping Criterion 1 to identify SSCs within the scope of license renewal which are relied upon to remain functional during and following design-basis events (DBEs).CHAMPS and controlled drawings were used to identify components required to supportsystem-level and structure-level functions within the scope of license renewal. Thosecomponents included within the scope of license renewal generally matched information in CHAMPS. Differences noted were documented and resolved.

2-3Application of the Scoping Criterion in 10 CFR 54.4(a)(2)In LRA Section 2.1.4.2.2, "Non-Safety Related Affecting Safety Related," the applicantpresented the scoping methodology as it related to the NSR criteria pursuant to 10 CFR 54.4(a)(2). The applicant stated that MNGP SSCs meeting Scoping Criterion 2 weregrouped into three categories, (1) CLB topics, (2) NSR SSCs directly connected to Scoping Criterion 1 SSCs (typically piping systems), or (3) NSR SSCs not directly connected to ScopingCriterion 1 SSCs, but whose failure could prevent, as a result of spatial proximity, the satisfactory accomplishment of a Scoping Criterion 1 function. SSCs meeting Scoping Criterion 2 in the first two categories typically were identified during document reviews, including the MNGP USAR, plant drawings, design documents, piping analyses, CHAMPS, and other CLB documents. SSCs in the third category typically were identified by both document reviews and extensive plant walkdowns to identify spatial interactions meeting broader criteria for license renewal.CLB Topics A review of the MNGP CLB identified NSR SSCs with preventive or mitigative functionssupporting safe shutdown, the failure of which could prevent satisfactory accomplishment of a Scoping Criterion 1 function. High-energy line breaks (HELB), internal and external flooding events, internal and external missile hazards, overhead handling systems, and seismicinteractions were evaluated. NSR SSCs were placed within the scope of license renewal as a result of this review if their failure could adversely affect an SR SSC.NSR SSCs Directly Connected to Scoping Criterion 1 SSCs NSR SSCs directly connected to Scoping Criterion 1 SSCs (typically pipi ng systems) andcomponent supports required to prevent NSR SSCs from physical interaction with SR SSCs are within the scope of license renewal. All piping supports in buildings with Scoping Criterion 1 components are within the scope of license renewal. The LRA describes the applicable supports as those that must remain in place so they do not prevent equipment required toperform intended functions from performing them. SCs within the scope of license renewal extend into the NSR portion of the piping and supports up to and including the first equivalent anchor beyond the safety/nonsafety interface, that point beyond which failure of the pipingsystem will not prevent satisfactory performance of Scoping Criterion 1 functions of connectedSSCs. The piping components and supports up to and including the first equivalent anchor are within the scope of license renewal.NSR structures attached or next to Scoping Criterion 1 structures are within the scope oflicense renewal if their failure could prevent a Scoping Criterion 1 SSC from performing its intended function.NSR SSCs Not Directly Connected to Scoping Criterion 1 SSCs NSR SSCs not directly connected, but in spatial proximity, to Criterion 1 SSCs whose failurecould prevent the satisfactory accomplishment of a Criterion 1 function are within the scope of license renewal. The LRA states that both spray (pressurized liquid or steamlines) and leaks (nonpressurized liquid lines) were evaluated for their impact on Scoping Criterion 1 components without regard to whether the Scoping Criterion 1 components were active or passive and 2-4without regard to the duration of the spray or leak. All pressurized liquid systems in the generalarea of Scoping Criterion 1 components are within the scope of license renewal and assumed to leak anywhere around the circumference or along the length of the pipe. All nonpressurized liquid systems directly above Scoping Criterion 1 components are also within the scope oflicense renewal. Leaks were assumed to occur anywhere along the length of the piping system.Air and gas systems are not included within the scope of license renewal becaus e they do notcontain NSR components whose failure could prevent satisfactory accomplishment of Scoping Criterion 1 functions. Site-specific operating experience was reviewed to verify that MNGP air/gas systems have not affected other plant equipment negatively. The applicant's review ofindustry operating experience also revealed no events of this nature. Because none of the air/gas lines are high-energy lines and all supports in buildings with Scoping Criterion 1 components are within the scope of license renewal, air/gas systems are not ScopingCriterion 2 items.NSR conduits, cable trays, junction boxes, or lighting fixtures may contain or be routed nearScoping Criterion 1 cables or other components; therefore, all NSR conduits, trays, junction boxes, and lighting fixtures and their supports located within structures housing SR equipment are within the scope of license renewal. Additionally, conduits, trays, junction boxes, and lighting fixtures and their supports required for regulated events located in structures not housing Scoping Criterion 1 equipment are within the scope of license renewal.Though most heating, ventilation, and air conditioning (HVAC) ducts and their supports areNSR, they are located throughout the plant, typically along ceilings, and thus above manyScoping Criterion 1 SSCs. Like air/gas pipe systems, HVAC ducts are not hazards to other plant equipment. Falling is a concern; therefore, all HVAC duct supports located withinstructures housing Scoping Criterion 1 components are within the scope of license renewal.Application of the Scoping Criterion in 10 CFR 54.4(a)(3)In LRA Section 2.1.4.2.3, "Scoping Criterion 3-Other Regulations Identified in 10 CFRPart 54," the applicant discussed the methodology used to identify SSCs credited with functionsthat demonstrate compliance with regulations for fire protection (FP), environmental qualification (EQ), anticipated transients without scram (ATWS), and station blackout (SBO),pursuant to the 10 CFR 54.4(a)(3) license renewal scoping criteria. The applicant did not evaluate pressurized thermal shock because it is not applicable to boiling-water reactors (BWRs).Fire Protection In LRA Section 2.1.4.2.4, "Fire Protection," the applicant described the scoping of SSCs reliedon to perform functions that demonstrate compliance with 10 CFR 50.48, "Fire Protection";

Appendix R, "Fire Protection Program for Nuclear Power Facilities Operating Prior to January 1,1979," to 10 CFR Part 50, "Domestic Licensing of Production and Utilization Facilities"; andcommitments made in response to Appendix A to NRC Branch Technical Position APCSB 9.5-1, "Guidelines for Fire Protection for Nuclear Power Plants Docketed Prior to July 1, 1976." The applicant stated that a detailed evaluation of the CLB, including CHAMPS, the safe-shutdownanalysis, the fire hazards analysis, plant drawings, the USAR, and the operations manual was 2-5performed for FP, and SSCs supporting either FP design features or safe shutdown followingpostulated fires are within the scope of license renewal.Environmental Qualification In LRA Section 2.1.4.2.5, "Environmental Qualification," the applicant described the scoping ofSSCs relied on to perform functions that demonstrate compliance with 10 CFR 50.49, "Environmental Qualification of Electric Equipment Important to Safety for Nuclear Power Plants," which defines electric equipment important to safety that is required to be environmentally qualified to mitigate certain accidents that would result in harsh environmental plant conditions. The applicant stated that components that meet the requirements of10 CFR 50.49 are identified on the EQ Master List. All equipment identified on the EQ MasterList supporting the MNGP CLB was included within the scope of license renewal as components or commodities, pursuant to 10 CFR 54.4(a)(3).Anticipated Transients without Scram (ATWS)

In LRA Section 2.1.4.2.7, "Anticipated Transients without Scram," the applicant described thescoping of SSCs relied on to perform functions that demonstrate compliance with the ATWS requirements of 10 CFR 50.62, "Requirements for Reduction of Risk from Anticipated Transients Without Scram (ATWS) Events for Light-Water-Cooled Nuclear Power Plants." Theapplicant stated that the MNGP design features related to ATWS are within the scope of licenserenewal because they are relied on to meet 10 CFR 50.62 requirements. The applicant statedthat ATWS mitigation is accomplished by the use of three systems, (1) the alternate rodinjection subsystem, (2) the standby liquid control system, and (3) the recirculation pump tripsystem. Based on a review of the CLB, plant and vendor drawings, the USAR, docketedcorrespondence, modifications, and CHAMPS, the components relied upon to mitigate ATWS events were determined to be within the scope of license renewal.Station Blackout In LRA Section 2.1.4.2.8, "Station Blackout," the applicant described the scoping of SSCs reliedon to perform functions that demonstrate compliance with the requirements of 10 CFR 50.63, "Loss of Alternating Current Power." The applicant stated that, based on the review of plant-specific SBO calculations, the USAR, plant drawings, modifications, and CHAMPS, the components relied upon to mitigate SBO were determined to be within the scope of license renewal.2.1.2.1.2 Documentation Sources Used for Scoping and ScreeningIn LRA Section 2.1.3, "Plant Information Sources," the applicant stated that it had evaluatedinformation from the following sources during the license renewal scoping and screening process:

  • CLB information including TSs and docketed licensing correspondence
  • design-basis documents (DBDs) 2-6
  • Q-List and Q-List Extension
  • controlled drawing file
  • industry codes, standards, and regulations
  • technical correspondence, analyses, and reports
  • calculations
  • plant modifications and alterations
  • nuclear steam supply system supplier; architect-engineer; and vendor reports,specifications, and drawings
  • Maintenance Rule documents
  • CHAMPSThe applicant stated that it reviewed these documents to identify the major SSCs and theirrespective functions. Functions of SSCs that were determined to be within the scope of license renewal were identified as intended functions, pursuant to 10 CFR 54.4(b). CHAMPS and controlled drawings were used to identify components requir ed to support system-level andstructure-level functions within the scope of license renewal. These sources also were used to develop the list of SCs subject to an AMR.2.1.2.1.3 Plant and System-Level Scoping LRA Section 2.1.4 states that the scoping process categorizes the entire plant according tomajor SSCs and commodity groups. The applicant identified and evaluated SSC and commodity group functions against criteria in 10 CFR 54.4(a) to determine whether the function was an intended function. The SSC or commodity was deemed within the scope of license renewal and received further screening if a portion of the SSC or commodity fulfilled a scopingcriterion.2.1.2.1.4 Component-Level Scoping After identifying the intended functions of systems and structures, the applicant identifiedcomponents that support intended functions. The applicant considered components supporting intended functions as within the scope of license renewal and screened them to determine whether an AMR was required.Commodity groups were used when component evaluations were by component type ratherthan by system or structure. Components constructed from similar materials, exposed to similarenvironments, and performing similar intended functions form the commodity groups.

Commodity group components were not associated with specific systems or structures duringthe evaluation, but with their assigned commodity groups. An AMR of each commodity group took place as if it were a separate, individual system. Electrical components, componentsupports, and fire stops and seals were placed in separate commodity groups.CHAMPS does not uniquely identify all components installed in the plant. For example,CHAMPS does not typically include such items as cables, raceways, piping, conduits, fireproofing, general construction items (e.g., nuts, bolts), or consumable materials (e.g., diesel 2-7fuel, resins). Components not uniquely identified in CHAMPS that are within the scope oflicense renewal are identified as commodities or generic assets (e.g., pipe, structural steel) in their respective system or structure in the license renewal database to ensure proper coverageand evaluation.2.1.2.1.5 Structure Scoping LRA Section 2.1.4.1 states that CHAMPS includes a category for structures that comprise all ofthe MNGP buildings and structures. Buildings were categorized as individual or grouped license renewal structures. The applicant electronically searched other information sources, like CLB documentation, using several keywords (e.g., "structure," "new structure," "building modification") to ensure evaluation of all plant structures for license renewal intended functions, regardless of their coverage in CHAMPS.2.1.2.2 Screening Methodology After identifying the SSCs within the scope of license renewal, the applicant implemented aprocess for determining which SSCs would be subject to an AMR, pursuant to 10 CFR 54.21(a)(1). In LRA Section 2.1.5, "Screening Process," the applicant discussed the screening of SSCs within the scope of license renewal.System, Structure, and Commodity Group Component ScreeningLRA Section 2.1.5.2, "General Screening Methodology," states that the screening processidentifies the components from the systems, structures, and commodity groups within the scopeof license renewal that are subject to an AMR. These components perform or support a component-level intended function without moving parts or a change in configuration or properties and are not subject to replacement based on a qualified life or specified time period.

Component-level intended functions support system-level intended functions. The plantsystems, structures, and commodity groups within the scope of license renewal and theirsystem-level intended functions were identified previously in the scoping process. Thescreening process consists of the following distinctive steps:

  • identification of components subject to an AMR (passive and long-lived) for eachsystem, structure, or commodity within the scope of license renewal
  • identification of the component-level intended functions of all components subject toAMRs
  • identification of applicable references for making these determinationsThe applicant identified SCs within the scope of license renewal performing intended functionswithout moving parts or a change in configuration or properties (10 CFR 54.21(a)(1)(I) screening criterion). Active/passive screening determinations were based on the guidance in Appendix B to NEI 95-10. Passive SCs within the scope of license renewal not subject to replacement based on a qualified life or specified time period (10 CFR 54.21(a)(1)(ii) screening criterion) were identified as requiring AMRs. Component supports and fire stops and seals were binned in separate structural commodity groupings.

2-8Electrical/Instrumentation and Control (I&C) Component ScreeningIn LRA Section 2.1.5.4, "Scoping and Screening of Electrical Equipment," the applicantdescribed the methodology for screening electrical and I&C components. Component-level screening was performed for "in-scope" components associated with electrical systems.Components identified as within the scope of license renewal were evaluated pursuant to NEI 95-10, Appendix B guidance to determine whether they were considered "active." Componentswere either screened out as active or included in a commodity group. Long-lived, passive components were divided into four commodity groups, (1) Non-EQ Cables and Connections, (2)

Fuse Holders, (3) Electrical Penetrations, and (4) Offsite Power/SBO Recovery Path components. Aging management was performed on only these four commodity groups.2.1.3 Staff Evaluation The staff evaluated the LRA scoping and screening methodology in accordance with theguidance in Section 2.1, "Scoping and Screening Methodology," of NUREG-1800, "StandardReview Plan for Review of License Renewal Applications for Nuclear Power Plants" (SRP-LR).

The following regulations form the basis for the acceptance criteria for the scoping and screening methodology review:

  • 10 CFR 54.4(a) relating to the identification of plant SSCs within the scope of licenserenewal
  • 10 CFR 54.21(a)(1) and 10 CFR 54.21(a)(2) relating to the applicant's methods foridentifying plant SCs subject to an AMRAs part of the review of the applicant's scoping and screening methodology, the staff reviewedthe activities described in the following sections of the LRA using the guidance in the SRP-LR:
  • Section 2.1 to ensure that the applicant described a process for identifying SSCs withinthe scope of license renewal, in accordance with the requirements of 10 CFR 54.4(a)
  • Sections 2.2, 2.3, 2.4, and 2.5 to ensure that the applicant described a process foridentifying structural, mechanical, and electrical components subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1) and 10 CFR 54.21(a)(2)In addition, the staff conducted a scoping and screening methodology audit at the MNGP facilityin Minnesota during the week of June 20-24, 2005. The audit focused on ensuring that theapplicant had developed and implemented adequate guidance to conduct the scoping and screening of SSCs in accordance with the LRA methodologies and the requirements of the Rule. The staff reviewed implementation procedures and technical reports describing the applicant's scoping and screening methodologies. In addition, the staff conducted detaileddiscussions with the applicant on the implementation and control of the license renewalprogram and reviewed administrative control documentation and selected design documentation used by the applicant during the scoping and screening process. The staff reviewed the applicant's processes for quality assurance (QA) related to the development of the applicant's LRA and training and qualification of the LRA development team. The staff also 2-9reviewed a sample of system scoping and screening results reports for the control roddrive (CRD) system and intake structure (flood control) to ensure that the applicantappropriately implemented the methodology outlined in the administrative controls and that theresults were consistent with the CLB. The staff documented its review in an audit report issued July 18, 2005, identifying several issues requiring additional information from the applicant before completion of the review. Each of those issues is identified and addressed in detail in SER Sections 2.1.

3.1.2 and 2.1.3.1.4.2.1.3.1 Scoping Methodology The applicant's license renewal project personnel and contractors performed the scopingevaluations for the LRA. The staff had detailed discussions with the applicant's license renewalproject personnel and reviewed documentation of the scoping process. The staff assessed whether the scoping methodology described in the LRA and implementation procedures hadbeen implemented appropriately and whether the scoping results were consistent with CLB requirements. The staff also reviewed a sample of system scoping results for the CRD systemand intake structure (flood control).2.1.3.1.1Implementation Procedures and Documentation Sources Used for Scoping andScreeningThe staff reviewed the applicant's scoping and screening implementation procedures to verifythat the process used to identify SCs subject to an AMR was consistent with the LRA andSRP-LR, and that the applicant appropriately implemented the procedural guidance. The staffalso reviewed the scope of CLB documentation sources supporting the LRA and the process used by the applicant to ensure that CLB commitments were considered appropriately in scoping and screening.Scoping and Screening Implementation ProceduresThe staff reviewed the scoping and screening methodology implementation procedures andengineering reports, as documented in the audit report dated July 18, 2005.In reviewing these procedures, the staff focused on the consistency of the detailed proceduralguidance with the LRA and the staff positions documented in the SRP-LR and interim staff guidance documents. The staff found that the scoping and screening methodology instructions were consistent with LRA Section 2.1 and were of sufficient detail to guide the applicant on thescoping and screening implementation process followed during LRA activities.In addition to the implementing procedures, the staff reviewed supplemental design informationincluding DBDs, system drawings, and selected licensing documentation on which the applicantrelied during scoping and screening. The staff found these design documentation sources useful in ensuring that the initial scope of SSCs identified by the applicant was consistent withthe CLB.Sources of Current Licensing Basis InformationThe staff reviewed the scope and depth of the applicant's CLB evaluation to verify that themethodology was sufficiently comprehensive to identify SSCs within the scope of license 2-10renewal and SCs requiring an AMR. As defined in 10 CFR 54.3(a), the CLB is the set of NRCrequirements applicable to a specific plant and a licensee's written commitments for ensuring compliance with and operation within such requirements and the plant-specific design-basis docketed and in effect. The CLB includes NRC regulations, orders, license conditions,exemptions, TSs, design-basis information docketed in the USAR, and licensee commitments remaining in effect that were made in such docketed licensing correspondence as licensee responses to NRC bulletins, generic letters, and enforcement actions, as well as licenseecommitments documented in NRC safety evaluations or licensee event reports.LRA Section 2.1.3 provides a description of the CLB and related documents used during thescoping and screening process that is consistent with the guidance in the SRP-LR andNEI 95-10. Specifically, LRA Section 2.1.3 identified the USAR, TSs, docketed licensing correspondence, the Q-List, controlled plant drawings, industry codes, and plant design records. Additionally, in the scoping and screening implementation procedure, the applicant provided a comprehensive listing of documents that could be used to support scoping and screening evaluations. The applicant noted that system descripti ons and system intendedfunctions were identified based on the review of the applicable sections of the USAR, operations manual, Maintenance Rule scoping document, design- and licensing-basis documents, and license renewal project technical reports.During the audit, the staff reviewed the applicant's technical report, which specifically addressesDBEs. The report addressed in detail various sections of the USAR related to design-basis accidents (DBAs) and bounding transients and evaluated natural phenomena and external events applicable to MNGP. Supplemental information used to verify complete identification of DBEs included selected DBDs covering a number of support and accident mitigation systems,as well as selected topical reports developed to support the license renewal evaluation. Design descriptions for each system described in the USAR were reviewed to identify DBE mitigationfunctions credited in the CLB. The applicant identified these event mitigation functions andconfirmed that the SSCs credited with performing those functions were evaluated adequately inthe scoping and screening process.CHAMPS is the applicant's primary repository for component safety classification information.During the audit, the staff reviewed the applicant's administrative controls for CHAMPS safety classification data and concluded that the applicant had adequate measures to control theintegrity and reliability of CHAMPS safety classification data. Therefore, the staff concl uded thatCHAMPS provides a sufficiently controlled source of component data to support scoping and screening evaluations.The applicant identified topical reports as a source of information supporting identification ofsystems and structures relied upon to demonstrate compliance with events within the scope of10 CFR 54.4(a)(3), as well as documenting evaluation of special topics like scoping and screening of thermal insulation, treatment of consumables, and intended functions of heat exchangers. These reports were developed in accordance with MNGP directives that describe the requirements for preparation of such topical reports. The topical reports contain a listing of CLB references used for their development that was consistent with LRA Section 2.1.3. Thestaff reviewed these reports and concluded that the preparation of the topical reports accordingto applicant requirements reasonably ensured adequate summaries of CLB information for scoping purposes. The staff further verified the adequacy of the technical information in a 2-11sample of the reports by reviewing selected CLB source documents used to develop thetechnical reports.ConclusionAs part of the audit, the staff evaluated the scope and depth of the applicant's CLB evaluationfor assurance that the scoping methodology considered all SSC intended functions. In reviewing the LRA, scoping and screening implementation procedures, and license renewal technical reports, the staff determined that the applicant had developed and reviewed anadequately broad set of documents encompassing its CLB that is consistent with the guidancein the SRP-LR and NEI 95-10. The applicant's document review process adequately identified and documented system description and intended function evaluations performed during thescoping phase of the review. Therefore, the staff concluded that the applicant's methodology forthe identification, review, and documentation of CLB information to support the scoping ofSSCs is adequate.2.1.3.1.2 Application of the Scoping Criteria in 10 CFR 54.4(a)Application of the Scoping Criterion in 10 CFR 54.4(a)(1)In part, 10 CFR 54.4(a)(1) provides that, to identify SSCs within the scope of license renewal,the applicant must include all SR SSCs relied upon to remain functional during and following DBEs to ensure the following functions:

  • the ability to shut down the reactor and maintain it in a safe-shutdown condition
  • the capability to prevent or mitigate the consequences of accidents that could result inpotential offsite exposures comparable to those referred to in 10 CFR 50.34(a)(1),

10 CFR 50.67(b)(2), or 10 CFR 100.11, "Determination of Exclusion Area, LowPopulation Zone, and Population Center Distance"As to identification of DBEs, Section 2.1.3, "Review Procedures," of the SRP-LR states thefollowing:The set of DBEs as defined in the rule is not limited to Chapter 15 (or equivalent)of the Updated Final Safety Analyses Report (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, theCommission's regulations, NRC orders, exemptions, or license conditions withinthe CLB. These sources should also be reviewed to identify SSCs that are relied upon to remain functional during and following DBEs (as defined in 10 CFR 50.49(b)(1)) to ensure the functions described in 10 CFR 54.4(a)(1).The applicant's program for satisfying the scoping requirements of 10 CFR 54.4(a) requiresidentification of all major SR and NSR SSCs and the function or functions that each major SSC is required to perform. The applicant used a number of information sources, the CLB, DBEs, 2-12and quality classifications to identify the major SSCs and their respective functions. USARChapters 12 and 14 address DBEs. The applicant also used its DBDs to identify SR SSCs relied upon to remain functional during and following DBEs. The Q-List of the Operational QA Plan and the Q-List Extension drawings (color-coded piping &instrumentation drawings (P&ID))

specify the QA program boundaries for SSCs. These documents define the SSCs subject to the requirements of Appendix B, "Quality Assurance Criteria for Nuclear Power Plants and Fuel Reprocessing Plants," to 10 CFR Part 50, and were used to code items as SR in CHAMPS.The applicant's review of these documents identified the major SSCs and their respectivefunctions, which were compared to the scoping criteria of 10 CFR 54.4(a) to identify functions within the scope of license renewal. SSC functions that meet 10 CFR 54.4(a) scoping criteria requirements are identified as intended functions in the Advanced License Extension Management System (ALEX) license renewal database. SSC intended functions support one or more of the 10 CFR 54.4(a) scoping criteria.CHAMPS electronically stores component information used to prepare work orders and otheruses. CHAMPS provides seismic and quality classification. The applicant used CHAMPS and controlled drawings to identify components required to support system-level and structure-levelintended functions. Such components were included within the scope of license renewal.The applicant scoped SSCs in accordance with its implementing procedures. For additionalassurance that the applicant adequately implemented its SR scoping methodology, the staffreviewed a sample of the license renewal scoping report results for the CRD system anddiscussed the methodology and results with the applicant's personnel responsible for these evaluations. The staff verified that the applicant had identified and used pertinent engineeringand licensing information to identify the SSCs within the scope of license renewal, in accordance with the 10 CFR 54.4(a)(1) criteria.ConclusionOn the basis of this sample review, discussions with the applicant, and review of the applicant'sscoping process, the staff concluded that the applicant's methodology for identifying systemsand structures meets the 10 CFR 54.4(a)(1) scoping criteria.Application of the Scoping Criterion in 10 CFR 54.4(a)(2)In part, 10 CFR 54.4(a)(2) requires that the applicant consider all NSR SSCs whose failurecould prevent satisfactory accomplishment of any of the functions identified in 10 CFR 54.4(a)(1)(I), 10 CFR 54.4(a)(1)(ii), or 10 CFR 54.4(a)(1)(iii) as within the sc ope oflicense renewal. By letters dated December 3, 2001, and March 15, 2002, the NRC iss ued astaff position to the NEI which provided staff expectations for determining which SSCs meet the 10 CFR 54.4(a)(2) criterion. The December 3, 2001, letter provides specific examples of operating experience which identified pipe failure events (summarized in Information Notice (IN) 2001-09, "Main Feedwater System Degradation in Safety-Related ASME Code Class 2 Piping Inside the Containment of a Pressurized Water Reactor," and the approaches the staff considers acceptable for determining which piping systems should be within the scope oflicense renewal based on the 10 CFR 54.4(a)(2) criterion. The March 15, 2002, letter further describes the staff's expectations for the evaluation of nonpiping SSCs to identify additional NSR SSCs within the scope of license renewal. The position states that applicants should not 2-13consider hypothetical failures, but rather the plant's CLB, engineering judgment and analyses,and relevant operating experience. The paper further describes operating experience as all documented plant-specific and industry-wide experience useful in determining the plausibility ofa failure. Documentation would include NRC generic communications and event reports,plant-specific condition reports, industry reports, such as significant operating event reports (SOERs), and engineering evaluations.In its scoping implementation procedures, the applicant documented its methodology forperforming 10 CFR 54.4(a)(2) scoping of NSR SSCs and described the general methodology for identifying those NSR SSCs whose failure could affect the ability to maintain int endedfunctions of SR SSCs within the scope of license renewal. The procedure provides general guidance consistent with that of Appendix F to NEI 95-10, Revision 4, regarding the use ofmitigative and preventive approaches to identify SSCs within the scope of license renewal to meet the 10 CFR 54.4(a)(2) criterion. The procedure further describes the process for identifying the SSCs within the scope of license renewal and includes guidance for each discipline review (mechanical, structural, and electrical).In addition, the applicant developed a technical report, as documented in the audit report, tofurther define the methodology used for the 10 CFR 54.4(a)(2) evaluation. This technical reportdescribes the current regulation and the interim staff position on scoping of SSCs according to the 10 CFR 54.4(a)(2) criterion; the applicant's evaluation of licensing-basis topics, includingHELB, internal and external missiles, internal and external flooding, and heavy loads; evaluation of NSR SSCs attached directly to SR SSCs; and NSR SSCs within close spatial proximity to SR SSCs. Section 4.0 of the report addresses in detail the results of the 10 CFR 54.4(a)(2) evaluation.With respect to the CLB topics, including HELB, internal and external missiles, internal andexternal flooding, and heavy loads, the applicant's methodology evaluated information for each to identify NSR SSCs of interest. To ensure a complete and extensive evaluation of the existing CLB, the applicant developed a process which included searching CHAMPS to identify relevant references to the TS-bases documents, USAR sections, DBDs, licensing correspondence, plant drawings, plant modification packages, technical reports, and operations manuals for each topic. These documents were reviewed and an evaluation for each topic was performed to identify design features relied on for these events as within the scope of license renewal.The staff reviewed the applicant's methodology in evaluating these CLB topics, discussed theevaluation process with the applicant's staff responsible for performing these reviews, and evaluated a sample of the results of this evaluation to ensure that implementation of writteninstructions and the results are consistent with those evaluations. The staff determined that theapplicant's documented methodology was consistent with the 10 CFR 54.4(a)(2) requirementsand that the applicant's evaluation was consistent with that methodology. The staff reviewed asample of the CLB information used for the applicant's evaluations and confirmed its consistency with that design information.The applicant's evaluation of NSR SSCs attached directly and those within close spatialproximity to SR SSCs considered current industry guidance on the subject as a result of recent staff license renewal evaluations, taking into account that all active as well as passive SR SSCs could be affected adversely by spray or wetting from an NSR pressurized system in the same general location of the plant, regardless of the duration of that exposure. Specifically, the 2-14applicant used a "spaces" approach to identify SR SSCs and NSR SSCs within the same"general area," which is defined as a location sharing a common floor and common walls. This definition was expanded during plant walkdowns in the 10 CFR 54.4(a)(2) evaluation to include adjacent areas (i.e., those separated by a wall or barrier), if there could be communication between the two areas. In those instances, the adjacent area was considered part of the general area.As part of this evaluation, the applicant first listed the SR components and their locations withinthe plant. Review of plant-controlled documents like P&IDs, DBDs, and CHAMPS identified plant areas where NSR and SR SSCs were located. The applicant performed walkdowns of all accessible locations to identify NSR SSCs within these areas and the types of potential interactions that could occur (i.e., leaking, spraying, physical impact). For inaccessible areas, the applicant relied on controlled plant piping layout drawings and operator knowledge of theplant design and operation to identify potential component interactions. The inaccessible areasincluded the drywell/suppression chamber, steam chase, reactor water cleanup (RWCU) and traversing incore probe rooms, condenser room, and steam jet air ejector (SJAE) room. Where the applicant identified potential interactions between the NSR SSCs and SR SSCs within ageneral area, it included those NSR SSCs within the scope of license renewal. The applicant further documented the results on marked-up P&IDs, which highlighted the NSR SCs identified and described the general area, as well as SR SCs that could be affected by the NSR line failure. The staff reviewed a sample of the marked-up P&IDs for the CRD system and reviewedthe applicant's determination of areas of no potential interactions between NSR and SR SSCs.The staff determined that the applicant had evaluated the 10 CFR 54.4(a)(2) scoping criterionconsistently with the applicant's written instructions for such an evaluation and that the resultshad been documented with technical supporting justifications. The staff did not identify any specific concerns regarding the implementation of the 10 CFR 54.4(a)(2) scoping methodologyfor the system sample reviewed.The applicant also discussed its 10 CFR 54.4(a)(2) scoping evaluation process for NSR SSCsdirectly attached to SR SSCs to determine equivalent anchor locations required to establish system boundaries for the evaluation. With respect to the equivalent anchor criteria, theapplicant identified locations in each relevant system where support and attachment are suchthat failure of the piping system beyond the boundary point would not adversely affect the SRfunctions of connected SR components. The applicant relied on its piping stress analysis of record to determine equivalent anchor locations. In most cases, this boundary encompassed at least two levels of supports in each orthogonal direction, and for those few cases where such support was not available, the applicant evaluated the piping stress analysis to determinealternate anchorage locations. The alternate anchorage locations included (1) selected wall penetrations, (2) large pieces of plant equipment, (3) transition points between the piping systems and flexible connections like tubing and ducting, and (4) locations where the pipingsystem moment of inertia ratio exceeds 40:1 between the main and branch lines. In each case,the applicant provided a technical justification for the use of the equivalent anchorage locationbased on CLB information related to the piping stress analysis of record. The staff reviewed the methodology for a selected sample of mechanical systems and confirmed that the applicant'sevaluation was consistent with the guidance and that results had been documented adequatelyand justified technically.In addition to reviewing the implementation procedures associated with the applicant's10 CFR 54.4(a)(2) evaluations, the staff discussed the review process with the applicant's 2-15personnel responsible for performing the review and evaluated a sample of systems andstructures to ensure that the methodology was implemented in accordance with the written instructions and that the results were consistent with those evaluations.The applicant's implementing procedures provided guidance for establishing system boundariesfor NSR piping systems connected directly to SR piping systems. The guidance states, in part,that for NSR SSCs connected to SR SSCs, the NSR SSCs should be included up to the first seismic anchor past the SR-NSR interface, and the boundary drawings should also identify the anchor. A review of piping analyses provided information to extend the piping system to the firstanchor. Where there was no true anchor, the piping analysis was extended far enough to ensure that the NSR portion would have no effect on the SR portion. Typically, the extensionencompassed at least two restraints in each orthogonal direction. Where there were no such restraints in each orthogonal direction, the boundary was extended to an equivalent anchor such as a wall. As an example, the applicant stated that in certain cases of small-bore piping (i.e., 2 inches or less), grouted wall penetrations served as equivalent anchor locations.The staff's review of LRA Section 2.1 identified an area for which it needed additionalinformation to complete its evaluation of the applicant's scoping and screening methodology.

The applicant responded to the staff's RAI as discussed below.In RAI 2.1-2, dated July 20, 2005, the staff requested that the applicant provide the technicalbasis for establishing the grouted wall penetrations as equivalent anchor locations for NSR piping systems connected to SR piping systems and confirm that nongrouted wall penetrationswere not used as equivalent anchor locations for NSR piping systems connected to SR pipingsystems.In its response, by letters dated August 16, 2005, and November 17, 2005, the applicant statedthat 10 grouted wall/floor NSR piping penetrations were considered equivalent anchors. The CLB piping analysis addressed 9 of the 10 grouted penetrations, while 1 of the 10 was not addressed. In its response, the applicant provided an acceptable technical justification forcrediting this one grouted wall/floor piping penetration not addressed as an equivalent anchor.The applicant additionally stated that, in five instances, NSR underground piping was used asan equivalent anchor. In three of the five instances, the CLB piping analysis addressed the use of NSR underground piping as an equivalent anchor. The remaining two instances were not addressed. The applicant provided an acceptable technical justification for crediting the two instances in which underground piping was used as an equivalent anchor. The applicant also stated that it had added NSR underground piping to the scope of license renewal, which was subject to an AMR when credited as an equivalent anchor.Based on its review, the staff found the applicant's response to RAI 2.1-2 acceptable becausethe applicant adequately described its process for establishing the use of grouted wallpenetrations and underground piping as an equivalent anchor termination point. Therefore, the applicant resolved the staff concern described in RAI 2.1-2.ConclusionOn the basis of the additional information supplied by the applicant, which provides technicaljustification for identification of certain equivalent anchor locations, and as a result of the NRC 2-16inspection and audit activities, the staff concluded that the applicant has supplied sufficientinformation to demonstrate that the methodology for identifying systems and structures meetingthe scoping criteria of 10 CFR 54(a)(2) is adequate.Application of the Scoping Criterion in 10 CFR 54.4(a)(3)In part, 10 CFR 54.4(a)(3) requires applicants to consider in safety analyses or plantevaluations all SSCs relied on to perform functions demonstrating compliance with the Commission's regulations for FP (10 CFR 50.48), EQ (10 CFR 50.49), pressurized thermal shock (10 CFR 50.61, "Fracture Toughness Requirements for Protection against Pressurized Thermal Shock Events"), ATWS (10 CFR 50.62), and SBO (10 CFR 50.63) to be within the scope of license renewal. Pressurized thermal shock is not applicable to BWRs and, therefore, the applicant did not evaluate it. SRP-LR Section 2.1.3.1.3, "Regulated Events," states that allSSCs relied upon in the plant's CLB (as defined in 10 CFR 54.3), plant-specific operating experience, industry-wide operating experience (as appropriate), and safety analyses or plant evaluations to perform functions demonstrating compliance with NRC regulations under10 CFR 54.4(a)(3) must be included within the scope of license renewal; however, consideration is not required of hypothetical failures from system interdependencies not part ofthe CLB and not previously experienced.The staff reviewed the applicant's approach to identifying SSCs relied upon to performfunctions related to the four regulated events, as described in 10 CFR 54.4(a)(3). As part of this review, the staff discussed the methodology with the applicant's LRA team, reviewed supporting documentation, and evaluated a sample of the SSCs identified as within scope, pursuant to the10 CFR 54.4(a)(3) criterion.The applicant documented its methodology for scoping SSCs in accordance with10 CFR 54.4(a)(3) in implementation procedures, as described in the audit report. The applicant's initial scoping for regulated events evaluated relevant CLB information to determine whether the structure or system met the scoping criterion of 10 CFR 54.4(a)(3). For the fourregulated events, the applicant developed technical reports describing the relevant rulerequirements, implementation of the requirements, specific information about systems andcomponents credited for the event, the process to identify the scoping boundaries of thesystems credited, a list of CLB information sources for the analysi s, and systems andcomponents within the scope of license renewal for the given regulated event. Systems or structures with one or more components credited for demonstrating compliance with one of the regulated events are within the scope of license renewal, pursuant to the 10 CFR 54.4(a)(3)criterion. In addition, the staff determined that identification of SSCs within the scope of licenserenewal to support 10 CFR 50.63 had been in accordance with the guidance of ISG-02, "Station Blackout Scoping." In summary, the applicant included within the scope of license renewal the SSCs relied upon in safety analyses or plant evaluations to perform intended functions demonstrating compliance with NRC regulations for FP, EQ, ATWS, and SBO, in accordancewith the 10 CFR 54.4(a)(3) criterion.The staff's review of the applicant's scoping methodology included the set of scopingcalculations for each regulated event, a sample of the supporting analyses and documentation, discussion of the methodology and results with the applicant's personnel responsible for these evaluations, and a review of ALEX. The staff verified that the applicant had identified and used 2-17pertinent engineering and licensing information to determine the SSCs within the scope oflicense renewal, in accordance with the 10 CFR 54.4(a)(3) criterion.ConclusionBased on this sampling review, discussions with the applicant, and review of the applicant'sscoping process, the staff determined that the applicant's methodology for identifying systemsand structures meeting the 10 CFR 54.4(a)(3) scoping criterion is adequate.2.1.3.1.3 Plant-Level Scoping of Systems The applicant documented its methodology for scoping systems in accordance with10 CFR 54.4(a) in its implementing procedures. The applicant's appr oach to scoping systemswas consistent with the methodology described in LRA Section 2.1.4. Specifically, theimplementing procedure specified that personnel scoping for license renewal use CLB and DBE documents to describe systems, including lists of all functions that the system is required toaccomplish. Sources of information included the USAR, DBDs, Q-List and Q-List Extension drawings, CHAMPS, the Maintenance Rule documents, P&IDs, and docketed correspondence.

The applicant then compar ed system function lists to the scoping criteria to determine whether the system functions met the 10 CFR 54.4(a) scoping criteria. The applicant documented thescoping results in ALEX, which included a description of t he system, a list of functionsperformed by the system, identification of intended functions, the 10 CFR 54.4(a) scopingcriteria met by the system, references, and a list of components performing intended functions.During the scoping methodology audit, the staff reviewed a sampling of ALEX scoping reports and concluded that they contain an appropriate level of detail to document the scoping process.The applicant established color-coded boundary P&IDs for each mechanical system within thescope of license renewal. A preparer and an independent reviewer comprehensively evaluated the license renewal color-coded P&IDs for completeness and accuracy of the review results.

The staff reviewed several license renewal color-coded boundary P&IDs and verified that ALEX did identify the systems within license renewal boundaries.ConclusionOn the basis of a review of the LRA, ALEX, scoping and screening implementation procedures,license renewal color-coded P&IDs, and a sampling review of system scoping results, the staffconcluded that the applicant's scoping methodology for systems is adequate. In particular, thestaff determined that the applicant's methodology reasonably identified systems within thescope of license renewal and their associated intended functions.2.1.3.1.4 Mechanical Component-Level Scoping After the applicant had identified systems within the scope of license renewal and theirassociated intended functions, it identified the components of each system within the scope oflicense renewal that supported an intended function. As described in LRA Section 2.1.4, theapplicant considered a component to be within the scope of license renewal if needed for performance of a system intended function.

2-18The applicant described the methodology used for component scoping in LRA Section 2.1.4,and its implementing procedures, as documented in the audit report. The applicant evaluated CHAMPS, the USAR, DBDs, DBEs, plant walkdowns, training materials, license renewal color-coded boundary P&IDs, specifications, codes/standards, design changes, plant procedures, and CLB documentation to identify components credited with compliance to 10 CFR 54.4(a). Components meeting the requirements of 10 CFR 54.4(a) were consideredwithin the scope of license renewal and the applicant entered this information into ALEX.The staff reviewed the results of the ALEX scoping reports and discussed the scoping processin detail with the applicant's license renewal project personnel. The staff assessed whether the applicant appropriately applied the LRA scoping methodology and implementation procedures and whether the scoping results were consistent with CLB requirements. The staff determinedthat the applicant's proceduralized methodology was consistent with the description in LRASection 2.1.4 and the guidance in SRP-LR Section 2.1 and was adequately implemented.The staff reviewed the scoping process for the CRD system. The staff verified that the applicanthad developed color-coded system boundary P&IDs that identified license renewal CRD systemboundaries in accordance with the procedural guidance. The staff verified that CRD systemcomponents meeting 10 CFR 54.4(a) requirements were within the scope of license renewal.

The staff found the applicant knowledgeable about the process and conventions for establishing boundaries as defined in the license renewal implementation procedures.ConclusionOn the basis of the applicant's detailed scoping implementation procedures and a samplingreview of CRD system mechanical components scoping results, the staff concluded that theapplicant's methodology for identifying mechanical components within the scope of license renewal meets 10 CFR 54.4(a) requirements.Structural Component ScopingThe applicant described the methodology used for structural scoping in LRA Section 2.1.4, andits implementing procedures, as documented in the audit report. The applicant developed a list of SSCs using CHAMPS information. The applicant's technical reports listed all civil/structural SCs within the scope of license renewal. The applicant evaluated CHAMPS, the USAR, DBDs, training materials, drawings, specifications, codes/standards, design changes, plant procedures, and CLB documentation to identify structures credited with compliance to 10 CFR 54.4(a). In addition, the applicant performed walkdowns of plant buildings. Systems which contained components determined to meet 10 CFR 54.4(a) requirements wereconsidered within the scope of license renewal and the applicant entered this information into ALEX. The scope of license renewal included all SR structures and structural components. SR items within the scope of license renewal include walls, piping and equipment supports, conduit, cable trays, electrical enclosures, and instrument panels relied upon in the CLB. The NSR structures and structural components that perform functions required for compliance with FP, ATWS, and SBO regulations were included within the scope of license renewal. NSR structural items within the scope of license renewal include missile shields that protect SR equipment; overhead handling systems that could affect SR equipment; permanently installed walls, curbs,and doors that provide flood protection for SR equipment; and jet impingement shields and blowout panels that protect SR equipment from the effects of an HELB. The staff reviewed the 2-19LRA, procedures, drawings, and the ALEX database. The staff reviewed the results of thescoping methodology for select structures that included the diesel fuel oil transfer house, offgas stack, and the intake structure (flood control).The audit team reviewed plant procedures which provide instructions for the response of MNGPpersonnel to extreme natural conditions. These procedures address tornados, external flooding, high river water temperature, low river water flow/level, high-wind conditions, heavy snowfall, and high ambient (outside) air temperature. Plant procedures also provide instructions for protecting structures from flooding in the event that Mississippi River flood waters are predicted to exceed specific elevations. For example, steel plates required to be bolted over specific structure openings are stored on site to accomplish this task. Another example of an action to prevent flooding is the removal of the intake structure Amertap hatch covers and installation of the original floor hatches. The staff noted that equipment stored for use, such as steel platesand floor hatches, was not included within the scope of license renewal.The staff's review of LRA Section 2.1.4 identified an area for which it needed additionalinformation to complete its evaluation of the applicant's scoping and screening methodology.

The applicant responded to the staff's RAI as discussed below.In RAI 2.1-1, dated July 20, 2005, the staff requested that the applicant provide the technicalbasis for not including, within the scope of license renewal, equipment stored on site that stationprocedures require to be installed during emergency or abnormal conditions, in accordance with the CLB, or describe the methodology for ensuring that the license renewal scoping addressedall such equipment.In its response, by letter dated August 16, 2005, the applicant stated that it had added steelplates stored outside, which are dedicated for use during postulated external events, and steelhatch covers stored in the warehouse, which are dedicated for external flood use to the scope of license renewal and this equipment was subject to an AMR.Based on its review, the staff found the applicant's response to RAI 2.1-1 acceptable, becausethe applicant revised its scoping and screening methodology to include the appropriate equipment stored on site that the station procedures require to be installed during emergency or abnormal condition in accordance with the CLB. Therefore, the applicant resolved the staffconcern described in RAI 2.1-1.ConclusionThe staff determined that the applicant's methodology is consistent with the description in LRASection 2.1.4 and the guidance in SRP-LR Section 2.1. Based on review of information in the LRA, the applicant's detailed scoping implementation procedures, the additional informationfrom the applicant on scoping and screening methodology for equipment stored on site, and a sampling review of structural scoping results, the staff concluded that the applicant's methodology for identification of structural SSCs within the scope of license renewal meets 10 CFR 54.4(a) requirements.

2-20Electrical and I&C Component ScopingThe applicant described the methodology for electrical and I&C scoping in LRA Section 2.1.5.4,and its implementing procedures, as documented in the audit report. The applicant performed electrical and I&C scoping at a system level. The applicant developed information fromnumerous sources including CHAMPS, the USAR, and the Maintenance Rule program systembasis documents. The applicant entered the system description, the applicable design-basisreference, and system functions into ALEX. The applicant eval uated the system functions inaccordance with the 10 CFR 54.4(a) criteria to determine whether the system was within thescope of license renewal. Following evaluation of t he system functions, the applicant added thereference identifying t he system function which pl aced the system within the scope of licenserenewal to ALEX. The applic ant added systems to the license renewal database which werecreated to include electrical and I&C components not already specifically identified within an existing system (such as cables) in CHAMPS. The System/Structure Scoping and ScreeningOutput Reports document these activities.ConclusionThe staff reviewed the LRA, procedures, drawings, ALEX, and a sample of the results of theapplication of the scoping methodology for select systems. The staff found the applicant'smethodology consistent with the description in LRA Section 2.1.5.4 and with the applicant'simplementing procedures. Based on review of information in the LRA, the applicant's detailed scoping implementation procedures, and a sampling review of electrical and I&C scoping results, the staff concluded that the applicant's methodology for identifying electrical and I&Ccomponents within the scope of license renewal meets 10 CFR 54.4(a) requirements.2.1.3.2 Screening Methodology The applicant described its screening process in LRA Section 2.1.5. In general, the applicant'sscreening consisted of evaluations to determine which SCs within the scope of license renewal were passive and long-lived. Passive and long-lived SCs were then subject to further AMR. The staff reviewed the methodology used by the applicant to determine whether mechanical,structural, and electrical and I&C components within the scope of license renewal would be subject to further AMR. The applicant provided the staff with a detailed discussion of the processes for each discipline and provided administrative documentation that described the screening methodology. The staff also reviewed the screening results report for the CRD system. The staff noted that the applicant's screening process was performed in accordancewith its written requirements and was consistent with the guidance of the SRP-LR and NEI95-10, Revision 4. The staff determined that the screening methodology was consistent with therequirements of the Rule and that the screening methodology identified SCs meeting the10 CFR 54.21(a)(1) screening criterion.The staff evaluated the applicant's screening methodology against the 10 CFR 54.21(a)(1)criterion using the review guidance of SRP-LR, Section 2.1.3.2, "Screening." Pursuant to10 CFR 54.21(a)(1), the applicant's IPA must identify and list SCs subject to an AMR. Further, 10 CFR 54.21(a)(1) requires that SCs subject to an AMR encompass those SCs that (1) perform an intended function, as described in 10 CFR 54.4, without moving parts or changes in configurations or properties and (2) are not subject to replacement based on a qualified life or specified time period. Pursuant to 10 CFR 54.21(a)(2), the applicant must describe and justify 2-21the methods used to meet 10 CFR 54.21(a)(1) requirements. In the LRA, the applicantdescribed screening methodologies unique to the mechanical, structural, and electrical disciplines. The following sections describe the staff's evaluation of the applicant's screening approach for each of these disciplines.Mechanical Component ScreeningThe staff reviewed the methodology used by the applicant to determine whether mechanicalcomponents within the scope of license renewal would be subject to further AMR. The applicant applied a screening process to each mechanical component in ALEX. Implementing procedures require that each component in ALEX be identified as periodically replaced, no intended function, active, or requiring an AMR. CHAMPS was used to determine whether components are periodically replaced. The applicant had previously entered component intended functions into ALEX. The audit team reviewed technical reports which provided specific guidance for determining whether components were active or passive. Technical reports also referred to Appendix B to NEI 95-10 for component types generally considered active or passive. The applicant provided the staff with a detailed discussion of the process and provided ALEX screening report information describing the screening methodology, as well as a sample of the screening result reports for a selected group of SR and NSR systems.During the audit, the staff reviewed the methodology used by the applicant to identify and listthe mechanical components subject to an AMR, as well as the applicant's technical justification for this methodology. The staff also examined the applicant's results from the implementation ofthis methodology by reviewing the CRD system. The review included the license renewalcolor-coded boundary P&IDs and resultant components within the scope of license renewal, the corresponding component-level intended functions, and the resulting list of mechanical components subject to an AMR. The staff reviewed several summary screening reports breaking down the mechanical components within the scope of license renewal into several categories, including component type, AMR requirement, and material, and a comment section.

The staff also discussed the process and results with the cognizant engineers who performed the review. The staff did not identify any discrepancies between the methodology documentedand the implementation results.ConclusionOn the basis of a review of the LRA, the scoping and screening implementation procedures,and a sampling review of system and screening results, the staff determined that the applicant'smechanical component screening methodology is consistent with the guidance of the SRP-LRand is adequate for identifying passive, long-lived components within the scope of license renewal subject to an AMR. Therefore, the staff concluded that the applicant's methodology foridentification of mechanical components subject to an AMR meets 10 CFR 54.21(a)(1) requirements.Structural Component ScreeningAfter determining which structural SSCs were within the scope of license renewal, the applicantimplemented a process for determining which SSCs would be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1). LRA Section 2.1.5 discusses the screening of SSCs within the scope of license renewal. Screening activities identified passive 2-22components, long-lived components, component intended functions, consumables, andcomponent replacement based on performance or condition. The applicant relied on the guidance of NEI 95-10 to develop the plant-specific listing of passive components of interest during the review.ConclusionThe staff reviewed the LRA, procedures, drawings, and the ALEX database. The staff alsoreviewed the results of the scoping and screening methodology for select structures, including the diesel fuel oil transfer house, offgas stack, and intake structure (flood control). The staff found the applicant's methodology consistent with the description in LRA Sections 2.1.4 and2.1.5 and the guidance of SRP-LR Section 2.1. Based on review of information contained in the LRA, the applicant's detailed scoping implementation procedures, and a sampling review ofstructural scoping and screening results, the staff concluded that the applicant's methodologyfor identification of structural SSCs subject to an AMR meets 10 CFR 54.21(a)(1) requirements.Electrical and I&C Component ScreeningThe applicant described the electrical and I&C screening methodology in LRA Section 2.1.5.4,and its implementing procedures, as documented in the audit report. The applicant identified evaluation boundaries for the electrical and I&C systems previously determined to be within thescope of license renewal. The applicant also reviewed components within the evaluation boundary to identify SCs performing intended functions, and compiled such SCs into ALEX.

The applicant reviewed ALEX to identify the passive and long-lived components subject to an AMR in accordance with 10 CFR 54.21. In addition, the applicant identified and reviewed fuse holders, in accordance with the guidance contained in ISG-05, "Electrical Fuse Holders." The applicant documented the results of these activities in four technical reports, "Electrical Penetrations," "Non-EQ Cables and Connections," "Fuse Holders," and "Offsite Power/SBO Recovery Path."ConclusionThe staff reviewed the LRA, procedures, drawings, ALEX, and a sample of the results of thescreening methodology. The staff found the applicant's methodology consistent with thedescription in LRA Section 2.1.5.4 and the applicant's implementing procedures. Based onreview of information in the LRA, the applicant's detailed screening implementation procedures,and a sampling review of electrical and I&C screening results, the staff concluded that the applicant's methodology for identification of electrical and I&C SCs subject to an AMR meets 10 CFR 54.21(a)(1) requirements.InsulationLRA Table 2.1-1 describes the intended function of thermal insulation to "limit heat transfer tomaintain temperature within design limits." During the audit, the staff reviewed technical reports, as documented in the audit report, which described how thermal insulation was scoped and screened at MNGP. No insulation at MNGP is classified as SR, so insulation can be within the scope of license renewal only for environment control or seismic II/I intended functions. The applicant stated that thermal insulation to limit room heat-up was within the scope of licenserenewal in two areas: high pressure coolant injection (HPCI) room piping insulation and residual 2-23heat removal (RHR) room heat exchanger insulation. Therefore, this specific thermal insulationwas subject to an AMR.ConclusionThe staff reviewed the LRA, technical report, and the results of the scoping and screeningmethodology for thermal insulation. The staff found the applicant's methodology consistent withthe description in LRA Table 2.1-1 and the applicant's implementing procedures. Based on review of information in the LRA and the applicant's detailed technical report, the staff determined that the applicant's methodology for identification of insulation subject to an AMRmeets 10 CFR 54.21(a)(1) requirements.ConsumablesDuring the audit, the applicant described the screening review for certain consumablecommodities in LRA Section 2.1.5.3, "Component Classification (Passive, long-lived)."

Section 2.1.5.3 states that evaluation of items to determine whether they are consumablesfollowed the NRC screening guidance of SRP-LR Table 2.1-3, "Specific Staff Guidance onScreening," for determining whether consumable items are subject to an AMR. For consumables periodically replaced, SRP-LR Table 2.1-3 states that the applicant should identifythe standards that are relied on for replacement as part of the methodology description.The table states that consumables like packing, gaskets, component seals, and O-rings may beexcluded from an AMR using a clear basis. Consistent with SRP-LR Table 2.1-3, the applicant divided consumables into four basic categories, (1) packing, gaskets, component seals, and O-rings, (2) structural sealants, (3) oil, grease, and filters (system and component filters), and(4) fire extinguishers, fire hoses, and air packs. The applicant's guidance for performingscreening reviews for commodity groups states that, regardless of how consumables associated with components or structures are screened for an AMR, the bases for the determinations made are presented in the respective AMR reports.The staff selected various AMR reports and verified that each contained a discussion of thetreatment of consumables. The staff reviewed several AMRs during its scoping and screening audit and verified that they contained components subject to short-lived/replaceable determinations.ConclusionThe staff reviewed the LRA, technical report, a sample of the screening methodology results,and AMRs. The staff found the applicant's methodology consistent with the description in LRA Section 2.1.5.3 and the applicant's implementing procedures. Based on review of informationcontained in the LRA, the applicant's detailed screening implementation procedures andtechnical report, a sampling review of consumable screening results, and AMRs, the staff concluded that the applicant's methodology for identification of consumables subject to an AMRmeets 10 CFR 54.21(a)(1) requirements.

2-242.1.3.3 QA Controls Applied to LRA DevelopmentThe staff reviewed the QA controls used by the applicant for reasonable confidence that theLRA scoping and screening methodologies were adequately implemented. Although the applicant did not develop the LRA under a 10 CFR Part 50, Appendix B QA program, the staff determined that the applicant utilized the following QA processes during the LRA development:

  • Written procedures and guidelines governed implementation of the scoping andscreening methodology.
  • The Offsite Review Committee and the Plant Operations Review Committee reviewedand approved the LRA before its submission to the staff.
  • The applicant planned to retain certain license renewal documents as quality records orcontrolled documents.
  • The applicant performed an industry peer review of license renewal activities.
  • The applicant's Nuclear Oversight Department performed a self-assessment in the areaof implementation of license renewal procedures.ConclusionOn the basis of review of pertinent LRA development guidance, discussion with the applicant'slicense renewal personnel, and review of the Nuclear Oversight quality audit report, the staff concluded that such QA activities provide reasonable assurance that LRA development activities were consistent with LRA descriptions.2.1.3.4 Training The staff reviewed the applicant's training process to ensure that guidelines and methodologyfor scoping and screening activities were consistent and appropriate. The applicant had developed 10 license renewal lesson plans to train all technical leads and site personnel in license renewal activities. The applicant developed and used implementing procedures to train contract personnel supporting the license renewal effort. The applicant also required contract personnel to review the applicable regulations, NEI 95-10, the applicable administrative work instruction, and the License Renewal Project Plans. In addition, the applicant created "Documentation of Information Sharing" on specific license renewal topics as they were developed and conducted periodic training sessions for all license renewal personnel.ConclusionOn the basis of discussions with the applicant's license renewal project team responsible for thescoping and screening process and a review of selected documentation in support of the process, the staff concluded that the applicant's personnel understood the requirements andguidance and adequately implemented the scoping and screening methodology documented in the LRA. The staff concluded that license renewal personnel were adequately trained and qualified to perform the applicable license renewal activities.

2-252.1.4 ConclusionThe staff reviewed the information in LRA Section 2.1, the supporting information in the scopingand screening implementation procedures and reports, and the information presented during the scoping and screening methodology audit. The staff verified that the applicant's scopingand screening methodology is consistent with the requirements of the Rule. On the basis of thisreview, the staff concluded that, with the exceptions noted above, the applicant's methodologyfor identifying SSCs within the scope of license renewal and the SCs requiring an AMR is consistent with the requirements of 10 CFR 54.4(a) and 10 CFR 54.21(a)(1).2.2 Plant-Level Scoping Results2.2.1 Introduction In LRA Section 2.1, the applicant described the methodology for identifying the SSCs within thescope of license renewal. In LRA Section 2.2, the applicant used the scoping methodology to determine which SSCs are required to be included within the scope of license renewal. The staff reviewed the plant-level scoping results to determine whether the applicant had properlyidentified all plant-level systems and structures relied upon to remain functional during andfollowing DBEs, as required by 10 CFR 54.4(a)(1), or whose failure could prevent satisfactory accomplishment of any of the SR functions of SSCs within the scope of license renewal, as required by 10 CFR 54.4(a)(2), as well as the systems and structures relied on in safetyanalyses or plant evaluations to perform a function that demonstrates compliance with one of the regulations referenced in 10 CFR 54.4(a)(3).2.2.2 Summary of Technical Information in the Application In LRA Table 2.2-1, the applicant provided a list of the plant-level scoping results, identifyingthose systems, structures, and commodities that are within the scope of license renewal. Basedon the DBEs considered in the plant's CLB, other CLB information relating to NSR systems and structures, and certain regulated events referenced in 10 CFR 54.4(a)(3), the applicant identified those plant-level systems and structures that are within the scope of license renewal,as defined by 10 CFR 54.4.2.2.3 Staff Evaluation In LRA Section 2.1, the applicant described its methodology for identifying the systems andstructures that are within the scope of license renewal and subject to an AMR. The staff reviewed the scoping and screening methodology and provided its evaluation in Section 2.1 of this SER. To verify that the applicant properly implemented its methodology, the staff focusedits review on the implementation results, as shown in LRA Table 2.2-1, to confirm that noplant-level systems and structures were omitted from the scope of license renewal.The staff determined whether the applicant properly identified the systems and structures withinthe scope of license renewal, in accordance with 10 CFR 54.4. The staff reviewed selected systems and structures that the applicant did not identify as falling within the scope of licenserenewal to verify whether the systems and structures have any intended functions that wouldrequire their inclusion within the scope of license renewal. The staff conducted its review of the 2-26applicant's implementation in accordance with the guidance described in SRP-LR Section 2.2,"Plant-Level Scoping Results."In reviewing LRA Section 2.2, the staff identified areas for which it needed additionalinformation to complete its evaluation of the applicant's plant-level scoping results. Therefore, the staff issued RAIs concerning each specific issue to determine whether the applicant properly applied the scoping criteria of 10 CFR 54.4. The following paragraphs describe the staff's RAIs and the applicant's related responses.In RAI 2.2-1, dated June 21, 2005, the staff noted that the control rod velocity limiters describedin USAR Section 6.4 are integral parts of each control rod providing hydraulic damping to reduce the freefall velocity of the rod and reduce consequences if the control rod becomes detached from its drive and drops from the core. The LRA does not mention this component, nor does it appear to refer to USAR Section 6.4; therefore, the staff requested that the applicantclarify whether these components are included within the scope of license renewal or state the basis for their exclusion.In its response, by letter dated July 21, 2005, the applicant stated that control rod velocitylimiters are plant-engineered safety features (ESFs), as described in USAR Chapter 6. Control rod velocity limiters are provided as an integral part of each control rod. They provide hydraulic damping to reduce the freefall velocity of the rod and thereby reduce the consequences if the control rod becomes detached from its drive and drops from the core. Since the control rod velocity limiters are an integral part of each control rod, the velocity limiters are within the scope of license renewal; however, the control rods (including the velocity limiters) are screened out of the AMR process since they are replaced periodically.Based on its review, the staff found the applicant's response to RAI 2.2-1 acceptable. Theapplicant stated that all ESFs are within the scope of license renewal and are in addition to the safety features included in the design of the reactor, reactor primary system, plant and reactorcontrol systems, and other instrumentation or process systems. Most of the ESFs serve nofunction during normal plant operation, but are included for the sole purpose of reducing the consequences of DBAs described in USAR Section 14. The applicant stated that LRA Section 2.3.3.4 includes a discussion of the control rod velocity limiters. Therefore, the applicantresolved the staff concern described in RAI 2.2-1.In RAI 2.2-2, dated June 21, 2002, the staff noted that the safety parameter displaysystem (SPDS) is described in USAR Section 7.13. The SPDS provides a concise display ofcritical plant variables to control room operators to aid them in rapidly and reliably determining the safety status of the plant. The LRA does not mention this system, nor does it appear torefer to USAR Section 7.13 in the text; therefore, the staff requested that the applicant clarifywhether this system is within the scope of license renewal or state the basis for its exclusion.In its response, by letter dated July 21, 2005, the applicant stated that it included the processcomputer system (PCS) in the license renewal system under "Computer." The LRA lists thecomputer system in Table 2.2-1, "Plant Level Scoping Results," page 2-47, which states that the system is not within the scope of license renewal. The PCS provides input to the SPDS andthe SPDS is considered a PCS subsystem.

2-27The applicant further stated that the purpose of the PCS system is to aid the operator in timelydetermination of the plant's operability status during all plant conditions by providing a real-timepresentation of operational data, including input to the SPDS, pertaining to the reactor core andother plant equipment. USAR Section 7.13 states that the SPDS is not essential to safeoperation of the plant, prevention of events that endanger public health and safety, or mitigationof the consequences of an accident. The PCS also records plant operational data, which can be recalled for evaluation of abnormal and unusual events.The applicant stated that the USAR discusses the PCS in relation to such topics as the rodworth minimizer, accident monitoring instrumentation, and the SPDS. The process computer isnot SR and its failure will not cause an SR function to fail (USAR Section 7.8.3). SR isolationdevices between the PCS, neutron monitoring, and the plant protection system (PPS) signalinputs are parts of these other systems for purposes of license renewal.Based on its review, the staff found the applicant's response to RAI 2.2-2 acceptable. Theapplicant stated that the process computer is not on the MNGP Q-list. The process computer isnot required for any of the regulated events referenced in 10 CFR 54.4(a)(3). The 250-volts-direct current (VDC) system battery that powers the process computer is not required tofunction during an SBO event. The FP system does not rely on the computer to process firedetection and alarm signals. The required ATWS monitoring instrumentation does not rely on the PCS; thus, the PCS, including the SPDS, was determined to be outside the scope of licenserenewal. Therefore, the staff's concern described in RAI 2.2-2 is resolved.2.2.4 Conclusion The staff reviewed LRA Section 2.2, the RAI responses described above, and the supportinginformation in the MNGP USAR to determine whether the applicant had failed to identify any systems and structures that should be within the scope of license renewal. The staff's reviewdid not identify any omissions. On the basis of this review, the staff concluded that the applicantproperly identified the systems and structures that are within the scope of license renewal inaccordance with 10 CFR 54.4.2.3 Scoping and Screening Results: Mechanical SystemsThis section documents the staff's review of the applicant's scoping and screening results formechanical systems. Specifically, this section discusses the following mechanical systems:

  • reactor vessel, internals, and reactor cool ant system (RCS)
  • auxiliary systems
  • steam and power conversion systemIn accordance with the requirements of 10 CFR 54.21(a)(1), the applicant must identify and listpassive, long-lived mechanical SSCs that are within the scope of license renewal and subject to an AMR. To verify that the applicant properly implemented its methodology, the staff focused itsreview on the implementation results. This approach allowed the staff to confirm that nomechanical system components that meet the scoping criteria and are subject to an AMR wereomitted.

2-28Staff Evaluation Methodology. The staff performed its evaluation of the information in the LRAin the same manner for all mechanical systems. The objective of the review was to determinewhether the applicant had identified the components and supporting structures for a specificmechanical system, that appeared to meet the scoping criteria specified in the Rule, as withinthe scope of license renewal, in accordance with 10 CFR 54.4. Similarly, the staff evaluated the applicant's screening results to verify that all long-lived, passive components were subject to an AMR, in accordance with 10 CFR 54.21(a)(1).Scoping. To perform its evaluation, the staff reviewed the applicable LRA section andassociated component drawings, focusing its review on components that had not been identified as within the scope of license renewal. The staff reviewed relevant licensing-basis documents, including the USAR, for each mechanical system to determine whether theapplicant had omitted components with intended functions delineated under 10 CFR 54.4(a)from the scope of license renewal. The staff also reviewed the licensing-basis documents to determine whether the LRA specified all intended functions delineated under 10 CFR 54.4(a). Ifomissions were identified, the staff requested additional information to resolve the discrepancies.Screening. Once the staff completed its review of the scoping results, the staff evaluated theapplicant's screening results. For those systems and components with intended functions, thestaff sought to determine (1) if the functions are performed with moving parts or a change in configuration or properties or (2) if the components are subject to replacement based on a qualified life or specified time period, as described in 10 CFR 54.21(a)(1). For t hose systemsand components that did not meet either of these criteria, the staff sought to confirm that thesemechanical systems and components were subject to an AMR, as required by10 CFR 54.21(a)(1). If discrepancies were identified, the staff requested additional information to resolve them.2.3.1 Reactor Vessel, Internals, and Reactor Coolant System In LRA Section 2.3.1, the applicant identified the SCs of the reactor vessel, internals, and RCSthat are subject to an AMR for license renewal.The applicant described the supporting SCs of the reactor vessel, internals, and RCS in thefollowing sections of the LRA:

  • 2.3.1.1reactor head v ent system
  • 2.3.1.2reactor pressure vessel
  • 2.3.1.3reactor pressure vessel internals
  • 2.3.1.4reactor recirculation system
  • 2.3.1.5reactor vessel instrumentationSER Sections 2.3.1.1-2.3.1.5 present the staff's review findings regarding LRASections 2.3.1.1-2.3.1.5, respectively.

2-292.3.1.1 Reactor Head Vent System2.3.1.1.1 Summary of Technical Information in the Application In LRA Section 2.3.1.1, the applicant described the reactor head vent system. The reactor headvent system maintains the reactor pressure boundary. The reactor head v ent system provides ameans to (1) permit venting the RPV during filling for hydrostatic test, (2) permit remote ventingof noncondensable gases which may accumulate in the vessel head space during reactor cooldown after the main steamlines have been flooded, and (3) permit venting of noncondensable disassociated gases which might accumulate in the vessel head space during reactor operation to one of the main steamlines.The reactor head vent system contains SR components that are relied upon to remainfunctional during and following DBEs.The intended function, within the scope of license renewal, is to provide a pressure-retainingboundary.In LRA Table 2.3.1-1, the applicant identified the following reactor head vent system componenttypes that are within the scope of license renewal and subject to an AMR:

  • fasteners/bolting
  • piping and fittings
  • valve bodies2.3.1.1.2 Staff Evaluation The staff reviewed LRA Section 2.3.1.1 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.3.1.1.3 Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the reactor head vent systemcomponents that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the reactor head vent system components that are subject to an AMR, as required by10 CFR 54.21(a)(1).

2-302.3.1.2 Reactor Pressure Vessel2.3.1.2.1 Summary of Technical Information in the Application In LRA Section 2.3.1.2, the applicant described the RPV system. The RPV system consists ofthe RPV top head enclosure, vessel shell, nozzles, nozzle safe ends, penetrations, bottom head, and support skirt and attachment welds. RPV internals are included in the reactor internals system. The RPV serves as a high-integrity barrier against leakage of radioactivematerials to the drywell.The RPV system contains SR components that are relied upon to remain functional during andfollowing DBEs. In addition, the RPV system performs functions that support FP, ATWS, and SBO.The intended functions within the scope of license renewal include the following:

  • provide a pressure-retaining boundary
  • provide structural support to SR components (vessel internals)In LRA Table 2.3.1-2, the applicant identified the following RPV system com ponent types thatare within the scope of license renewal and subject to an AMR:
  • bottom head components-bottom head dollar plate, bottom head torus
  • nozzle safe ends-control rod drive return line cap
  • nozzles-CRD return line
  • nozzles-FW
  • nozzles-main steam
  • nozzles-recirculation outlet, recirculation inlet, core spray, jet pump instrument,instrument and SLC
  • penetration-bottom head drainline
  • penetration-CRD stub t ubes
  • penetration-flux monitor
  • penetration-instrument 2-31
  • RPV external surface
  • support skirt and attachment welds
  • top head enclosure-closure studs and nuts
  • top head enclosure-head spray cap
  • top head enclosure-instrument nozzle (head spare)
  • top head enclosure-instrument nozzle flange (head spare)
  • top head enclosure-top head dollar plate
  • top head enclosure-top head flange
  • top head enclosure-top head torus
  • top head enclosure-vent nozzle
  • vessel shell attachment welds
  • vessel shell-upper intermediate shell, lower intermediate shell, lower shell, beltlinewelds
  • vessel shell-vessel flange, upper shell2.3.1.2.2 Staff Evaluation The staff reviewed LRA Section 2.3.1.2 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.3.1.2.3 Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs thatshould be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the RPV system componentsthat are within the scope of license renewal, as required by 10 CFR 54.4(a), and the RPV system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2-322.3.1.3 Reactor Pressure Vessel Internals2.3.1.3.1 Summary of Technical Information in the Application In LRA Section 2.3.1.3, the applicant described the RPV internals. The RPV internals consist ofall the SCs within the reactor vessel that provide support for the core, control rod systemsupport, instrumentation support, and steam quality enhancement and that direct coolant flow.The RPV internals contain SR components that are relied upon to remain functional during andfollowing DBEs. The failure of NSR SSCs in the RPV internals could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the RPV internals perform functions that support FP, ATWS, and SBO.The intended functions within the scope of license renewal include the following:

  • provide a pressure-retaining boundary
  • provide structural support to SR components (vessel internals)
  • provide adequate flow in a specified distribution spray patternIn LRA Table 2.3.1-3, the applicant identified the following RPV internals component types thatare within the scope of license renewal and subject to an AMR:
  • access hole covers
  • CRGT base
  • core plate
  • core plate bolts
  • core shroud (upper, central, lower)
  • intermediate-range monitor dry tubes, source range monitor dry tubes, incore fluxmonitor guide tubes, low-power range monitor (LPRM) dry tubes
  • jet pump assembly-riser pipe
  • jet pump assemblies-castings (elbow, collar, flare, flange, transition piece)
  • jet pump assemblies-diffuser
  • jet pump assemblies-holddown beams
  • jet pump assemblies-inlet header
  • jet pump assemblies-inlet elbow
  • jet pump assemblies-mixing assembly
  • jet pump assemblies-riser brace arm 2-33
  • jet pump assemblies-thermal sleeves
  • orificed fuel support
  • shroud support structure (shroud support cylinder, shroud support plate, shroud supportlegs)
  • steam dryer
  • top guide2.3.1.3.2 Staff Evaluation The staff reviewed LRA Section 2.3.1.3 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive, long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.3.1.3 identified areas for which it needed additionalinformation to complete its evaluation of the applicant's scoping and screening results. The applicant responded to the staff's RAIs as discussed below.In RAI 2.3.1-1, dated September 15, 2005, the staff noted that LRA Section 3.1.2.2.4.2 statesthe jet pump sensing lines internal to the reactor vessel are not within the scope of license renewal; however, it is unclear whether the portion of the jet pump sensing line external to the reactor vessel that can provide a pressure boundary and structural support is within the scope of license renewal. The staff requested that the applicant indicate whether it had included the external jet pump sensing line piping within the scope of license renewal and identify the LRA table and subcomponent group including the subject component or justify the exclusion.In its response, by letter dated October 14, 2005, the applicant stated the following:Jet Pump Sensing Lines external to the vessel are in scope for license renewal.The sentence on page 3-30 of the LRA was intended to indicate that only internal lines are outside scope. The sensing lines are 1-inch stainless steel pipes in the Reactor Vessel Instrumentation (RVI) system. The aging management for theinternal (Treated Water) environment is shown in LRA Table 3.1.2-5 Reactor Coolant System-Reactor Vessel Instrumentation, on Page 3-82. The applicable aging effects are cracking and loss of material which are managed by American Society of Mechanical Engineers (ASME)Section XI Subsections IWB, IWC, and IWD, the Plant Chemistry Program, and the One-Time Inspection Program. No 2-34aging management is required for the external surfaces of the stainless steelsensing lines exposed to primary containment and plant indoor air.Based on its review, the staff found the applicant's response to RAI 2.3.1-1 acceptable basedon the inclusion of the subject component; therefore, the applicant resolved the staff concerndescribed in RAI 2.3.1-1.In RAI 2.3.1-2, dated September 15, 2005, the staff noted that in LRA Table 2.3.1-3, "ReactorPressure Vessel Internals," core spray (CSP) lines and spargers have been identified as a component type within the scope of license renewal; however, for these components, pressure boundary was identified as the only intended function requiring aging management and not theirfunction of providing adequate flow in a properly distributed spray pattern. The staff requested that the applicant clarify why it had not identified the spray pattern function, in addition topressure boundary function, as an intended function needing maintenance during the extended period of operation.In its response, dated October 14, 2005, the applicant stated the USAR Section 3.6.2.10, "CoreSpray Spargers," states, "The supply line pairs terminate at a common vessel nozzle. Each half has distribution nozzles pointed radially inward and downward at a slight angle to achieve a specified distribution pattern." Therefore, an intended function of 'spray pattern' is assigned to the CSP lines and spargers by revision to LRA Tables 2.3.1-3, "Reactor Pressure Vessel Internals," and 3.1.2-3, "Reactor Coolant System-Reactor Pressure Vessel Internals." There are no changes to the aging effects or the aging management programs (AMPs). The applicant added the component intended function, "spray pattern-to provide adequate flow in a specified distribution spray pattern," by revising LRA Table 2.1-1, "lntended Function Definitions."Based on its review, the staff found the applicant's response to RAI 2.3.1-1 acceptable basedon the inclusion of the spray pattern intended function for the above component; therefore, the applicant resolved the staff concern described in RAI 2.3.1-2.2.3.1.3.3 Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant had adequately identified the RPV internalscomponents that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the RPV internals components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.1.4 Reactor Recirculation System 2.3.1.4.1 Summary of Technical Information in the Application In LRA Section 2.3.1.4, the applicant described the reactor recirculation (REC) system. TheREC system includes the recirculation flow control (RFC) subsystem for license renewalpurposes. The REC system forces water through the reactor core to provide forced convectioncooling of the reactor core. The system consists of two recirculation pump loops outside thevessel and twenty jet pumps inside the vessel. The jet pumps are part of the reactor internals 2-35system. Each REC system loop outside the vessel consists of a motor-driven recirculationpump, two motor-operated gate valves for pump isolation, piping, and required recirculation flowmeasurement devices. Jet pump flow instrumentation outside the reactor vessel is included within the license renewal boundary of the REC system. The REC system (via the recirculationflow control subsystem) also functions as a method of controlling the reactor power level. TheREC system pumps, motors, and loop piping are located in the drywell outside the biologicalshield.The REC system contains SR components that are relied upon to remain functional during andfollowing DBEs. The failure of NSR SSCs in the REC system could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the REC system performs functions that support EQ and ATWS.The intended function, within the scope of license renewal, is to provide a pressure-retainingboundary.In LRA Table 2.3.1-4, the applicant identified the following REC system com ponent types thatare within the scope of license renewal and subject to an AMR:
  • fasteners/bolting
  • filters/strainers
  • heat exchangers
  • piping and fittings
  • pump casings
  • restricting orifices
  • tanks
  • thermowells
  • valve bodies2.3.1.4.2 Staff Evaluation The staff reviewed LRA Section 2.3.1.4 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.3.1.4 identified an area for which it needed additionalinformation to complete its evaluation of the applicant's scoping and screening results. The applicant responded to the staff's RAI as discussed below.

2-36In RAI 2.3.1-3, dated September 15, 2005, the staff noted that, in LRA Table 2.3.1-4, "ReactorRecirculation System," and for a few other systems (for example the CSP and CRD systems),heat exchangers were identified as a component type within the scope of license renewal; however, for these heat exchangers, pressure boundary was identified as the only intended function requiring aging management and not their heat transfer function. Therefore, the staffrequested that the applicant clarify why it did not identify the heat transfer function, in additionto the pressure boundary function, as an intended function needing maintenance during the extended period of operation.In its response, by letter dated October 14, 2005, the applicant stated the following:The heat exchangers in scope for the Reactor Recirculation (REC) system are:

  • The No. 11 and No.12 REC Motor/Generator Set Oil Coolers - Theseheat exchangers are shown on License Renewal (LR) drawing LR-36041 and are in scope for non-safety related components that could adversely affect safety related systems, structures, and components (SSCs) andare only required to maintain a pressure boundary. Therefore, no heat transfer function is required for these components to meet their intended functions.
  • The REC Pump Lower Seal Cooler and REC Pump Upper Seal Cooler -These heat exchangers are shown on drawing LR-36243-1. The heat exchanger tubes serve as a reactor coolant pressure boundary, whereas the shells are in scope for non-safety related components that could adversely affect safety related SSCs and are only required to maintain a pressure boundary. Therefore, no heat transfer function is required for these components to meet their intended functions.The heat exchangers in scope for the Core Spray (CSP) System are:
  • The CSP Pump Motor Oil Coolers - The heat exchangers are shown ondrawing LR-36664. An analysis concluded that the core spray motors are operable if motor cooling water is reduced to zero under worst case room temperatures. Therefore the heat exchanger does not have an intended function of providing heat transfer. The heat exchanger serves only a pressure boundary function.The heat exchangers in scope for the Control Rod Drive (CRD) system are:
  • The CRD Pump Thrust Bearing Cooler and the Lube Oil Cooler for theCRD Pump Speed Increaser Assemblies - These heat exchangers areshown on drawing LR-36244. The heat exchangers are in scope as non-safety related components that could adversely affect safety related SSCs. They are only required to maintain a pressure boundary.

Therefore, no heat transfer function is required for these components to meet their intended safety functions.

2-37Based on its review, the staff found the applicant's response to RAI 2.3.1-3 acceptable. Heattransfer is not an intended function for the REC system heat exchangers; therefore, theapplicant resolved the staff concern described in RAI 2.3.1-3.2.3.1.4.3 Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs thatshould be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the REC system components that arewithin the scope of license renewal, as required by 10 CFR 54.4(a), and the REC systemcomponents that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.1.5 Reactor Vessel Instrumentation 2.3.1.5.1 Summary of Technical Information in the Application In LRA Section 2.3.1.5, the applicant described the RVI system. The RVI system is designed tofulfill a number of requirements pertaining to the vessel itself or the reactor core. Theinstrumentation must (1) provide the operator with sufficient information in the control room toprotect the vessel from undue stresses, (2) provide information which can be used to assure that the reactor core remains covered with water and that the steam separators are not flooded,(3) provide redundant, reliable inputs to the reactor protection system to shut the reactor downwhen fuel damage limits are approached, and (4) provide a method of detecting leakage from the reactor vessel head flange. The RVI system also includes the reference leg backfillsubsystem. This subsystem provides a constant backfill of water from the CRD system's charging water header to the safeguards and FW reference legs to flush any gas-laden water through the condensate chambers and back to the reactor vessel to eliminate level errors resulting from the degassing phenomenon.The RVI system contains SR components that are relied upon to remain functional during andfollowing DBEs. The failure of NSR SSCs in the RVI system could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the RVI system performs functions that support FP, EQ, ATWS, and SBO.The intended functions within the scope of license renewal include the following:

  • provide a pressure-retaining boundary
  • provide flow restrictionIn LRA Table 2.3.1-5, the applicant identified the following RVI system com ponent types thatare within the scope of license renewal and subject to an AMR:
  • fasteners/bolting
  • piping and fittings
  • restricting orifices
  • thermowells 2-38
  • valve bodies2.3.1.5.2 Staff Evaluation The staff reviewed LRA Section 2.3.1.5 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.3.1.5.3 Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the RVI system componentsthat are within the scope of license renewal, as required by 10 CFR 54.4(a), and the RVI system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.2 Engineered Safety Features In LRA Section 2.3.2, the applicant identified the SCs of the ESFs that are subject to an AMRfor license renewal.The applicant described the supporting SCs of the ESFs in the following sections of the LRA:
  • 2.3.2.1automatic pressure relief system
  • 2.3.2.2combustible gas control system
  • 2.3.2.3core spray system
  • 2.3.2.4high pressure coolant injection system
  • 2.3.2.5primary containment mechanical system
  • 2.3.2.6reactor core isolation cooling system
  • 2.3.2.7residual heat removal system
  • 2.3.2.8secondary containm ent systemSER Sections 2.3.2.1-2.3.1.8 present the staff's review findings regarding LRASections 2.3.2.1-2.3.1.8, respectively.

2-392.3.2.1 Automatic Pressure Relief System2.3.2.1.1 Summary of Technical Information in the Application In LRA Section 2.3.2.1, the applicant described the automatic pressure relief (APR) system.The APR system is designed to prevent overpressurization and provide depressurization of thereactor vessel during DBEs. Two safety relief valves (SRVs) on each of the four steamlines are equipped to operate by automatic or manual initiation to blow down the reactor. Steam is passed through the valves, down a tailpipe, and through the torus vent headers to discharge underwater through T-quenchers in the event of SRV activation. The automatic depressurizati on system (ADS) is an APR subsystem that provides backup to the high pressurecoolant injection (HPC) system and is designed to reduce reactor vessel pressure to a rangesuitable for low-pressure emergency core cooling pumps to operate. The low-low set system isan APR subsystem designed to control post-shutdown overpressure with progressive SRVpressure release setpoints. The alternate shutdown (ASD) system panel provides for manualoperation of four APR system SRVs. The APR system is also used to implement the ASDcooling method. To use the ASD cooling method, the reactor is depressurized using the automatic depressurization subsystem of the APR system.The APR system contains SR components that are relied upon to remain functional during andfollowing DBEs. In addition, the APR system performs functions that support FP, EQ, and SBO.The intended function, within the scope of license renewal, is to provide a pressure-retainingboundary.In LRA Table 2.3.2-1, the applicant identified the following APR system com ponent types thatare within the scope of license renewal and subject to an AMR:

  • fasteners/bolting
  • piping and fittings
  • thermowells
  • valve bodies2.3.2.1.2 Staff Evaluation The staff reviewed LRA Section 2.3.2.1 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).

2-402.3.2.1.3 ConclusionThe staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the APR system componentsthat are within the scope of license renewal, as required by 10 CFR 54.4(a), and the APR system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.2.2 Combustible Gas Control System 2.3.2.2.1 Summary of Technical Information in the Application In LRA Section 2.3.2.2, the applicant described the combustible gas control (CGC) system. Inits letter, dated March 15, 2006, the applicant stated that the CGC system was deactivated bycutting and capping process lines connecting to interfacing systems during the 2005 refuelingoutage, in accordance with the NRC's approval of License Amendment 138, which eliminatedthe requirements for hydrogen recombiners and relaxed the requirements for hydrogen and oxygen monitoring. Therefor e, the system has been removed from the scope of licenserenewal.2.3.2.2.2 Conclusion On the basis of the isolation and capping of the CGC system due to License Amendment 138,the staff concluded that the applicant appropriately characterized t he system as outside thescope of license renewal.2.3.2.3 Core Spray System 2.3.2.3.1 Summary of Technical Information in the Application In LRA Section 2.3.2.3, the applicant described the CSP system. The CSP system restores andmaintains the coolant in the RPV in combination with other emergency core cooling systems (ECCS) such that the core is adequately cooled to preclude fuel damage. Twoindependent CSP system loops are provided for use under loss-of-coolant accident (LOCA)conditions associated with large pipe breaks and reactor vessel depressurization. Suction water is normally supplied from the suppression pool, but can also be supplied by the condensate storage tank (CST). The CSP system provides adequate cooling along with low-pressurecoolant injection (LPCI) for intermediate and large line break sizes up to and including the design-basis, double-ended recirculation line break, without assistance from any other ECCS.

In conjunction with the LPCI mode of the RHR system, the HPC system, and the APR, the CSPsystem can act automatically (in response to signals indicative of a LOCA) to reflood the reactorcore and maintain core cooling following a LOCA event. Initiation of the CSP system occurs onsignals indicating (1) reactor low-low water level coincident with low reactor pressure, or (2) sustained reactor low-low water level, or (3) high drywell pressure. The reactor low-low water level signal or the high drywell pressure signal also initiate the emergency diesel generators (EDGs). Cooling water to the CSP system pump motor coolers is supplied by the 2-41emergency service water (ESW) system. The power source for each CSP system is located onseparate emergency buses. The EDGs can supply power for these emergency buses.The CSP system contains SR components that are relied upon to remain functional during andfollowing DBEs. The failure of NSR SSCs in the CSP system could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the CSP system performs functions that support FP, EQ, and SBO.The intended functions within the scope of license renewal include the following:

  • provide flow restriction
  • provide a pressure-retaining boundaryIn LRA Table 2.3.2-3, the applicant identified the following CSP system com ponent types thatare within the scope of license renewal and subject to an AMR:
  • fasteners/bolting
  • gauges (flow, level, and sight)
  • heat exchangers
  • piping and fittings
  • pump casings
  • restricting orifices
  • thermowells
  • valve bodies2.3.2.3.2 Staff Evaluation The staff reviewed LRA Section 2.3.2.3 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.3.2.3.3 Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant had adequately identified the C SP systemcomponents that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the CSP system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2-422.3.2.4 High Pressure Coolant Injection System2.3.2.4.1 Summary of Technical Information in the Application In LRA Section 2.3.2.4, the applicant described the HPC system. The HPC system is part of theECCS. The ECCS provides for continuity of reactor core cooling over the entire range of postulated breaks in the reactor primary system. The HPC system provides adequate corecooling for all break sizes less than those sizes for which the LPCI subsystem or C SP systemcan adequately protect the core, without assistance from other safeguards systems. The HPCsystem performs this function without reliance on offsite power or a water source for theinjection. The HPC system can pump water into the RPV under LOCA conditi ons that do notresult in rapid depressurization of the RPV. The HPC system is a high-head, low-flow systemthat pumps water into the RPV when the reactor primary system is at high pressure. If the HPCsystem fails to deliver the required flow of cooling water to the RPV, the automaticdepressurization feature of the reactor APR system functions to reduce system pressure so thatthe LPCI subsystem can operate to inject water into the RPV. The HPC turbine trips when theturbine steam supply pressure has decreased to the isolation setpoint. All these operations are performed automatically.The HPC system contains SR components that are relied upon to remain functional during andfollowing DBEs. The failure of NSR SSCs in the HPC system could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the HPC system performs functions that support EQ and SBO.The intended functions within the scope of license renewal include the following:

  • provide filtration
  • provide flow restriction
  • provide for heat transfer
  • provide a pressure-retaining boundary
  • limit heat transfer to maintain temperatureIn LRA Table 2.3.2-4, the applicant identified the following HPC system com ponent types thatare within the scope of license renewal and subject to an AMR:
  • fan/blower/housings
  • fasteners/bolting
  • filters/housings
  • gauges (flow, level, and sight)
  • heat exchangers
  • piping and fittings
  • pump casings
  • restricting orifices
  • steam traps
  • tanks
  • thermowells
  • turbines
  • valve bodies 2-432.3.2.4.2 Staff EvaluationThe staff reviewed LRA Section 2.3.2.4 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.3.2.4.3 Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the HPC systemcomponents that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the HPC system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.2.5 Primary Containment Mechanical System 2.3.2.5.1 Summary of Technical Information in the Application In LRA Section 2.3.2.5, the applicant described the primary containment mechanical (PCM)system. The PCM system includes the containment atmosphere control and nitrogen controlcomponents, the hydrogen-oxygen analyzing, the post-accident sampling (PAS), and the hard pipe vent subsystems. The PCM system was created to separate out the mechanicalcomponents of the primary containment (PCT) system for license renewal evaluation purposes.The mechanical components, and the associated electrical and I&C components, were transferred from the PCT system to the PCM system. The resulting PCT system contains only the structural components of the primary containment system. For license renewal evaluations,the PCM system also includes the portions of the mechanical containment penetrationassemblies that are extensions of the mechanical piping. These are the flued heads and guardpipes of the mechanical containment penetration assemblies. The other components of the containment penetration assemblies (e.g., the sleeves) are evaluated in the PCT system. ThePAS subsystem consists of a liquid and gas sample station located outside the secondarycontainment in the turbine building near the control room access door. The system is designedto provide samples under all conditions ranging from normal shutdown and power operation to the design-basis LOCA. The hard pipe vent subsystem provides a vent path from the pressure suppression chamber (wetwell) vapor space to a release point above the reactor building.The PCM system contains SR components that are relied upon to remain functional during andfollowing DBEs. The failure of NSR SSCs in the PCM system could potentially prevent the 2-44satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. Inaddition, the PCM system performs functions that support FP, EQ, and SBO.The intended functions within the scope of license renewal include the following:
  • provide filtration
  • provide a pressure-retaining boundary
  • provide pressure boundary or fission product retentionIn LRA Table 2.3.2-5, the applicant identified the following PCM system com ponent types thatare within the scope of license renewal and subject to an AMR:
  • fasteners/bolting
  • filters/strainers
  • flow element
  • piping and fittings
  • rupture disks
  • thermowells
  • valve bodies2.3.2.5.2 Staff Evaluation The staff reviewed LRA Section 2.3.2.5 and USAR Sections 5.2.1.3, 5.2.2.

3, 5.2.2.7, 5.2.3.10, 5.2.3.11, and 10.3.10.1 using the evaluation methodology described in SER Section 2.3. Thestaff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.3.2.5.3 Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the PCM systemcomponents that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the PCM system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2-452.3.2.6 Reactor Core Isolation Cooling System2.3.2.6.1 Summary of Technical Information in the Application In LRA Section 2.3.2.6, the applicant described the reactor core isolation cooling (RCI) system.The MNGP licensing basis does not include the RCI system as an ESF system The RCIsystem is included within this section, and the related aging management section, forconsistency with the SRP-LR and NUREG-1801, "Generic Aging Lessons Leaned (GALL)Report," issued July 2001. The RCI system uses a steam-driven turbine to drive a pump toinject water into the reactor vessel so that the core is not uncovered in the event of a loss of FW. While the system is not credited in the SBO analysis for mitigating loss of offsitepower (LOOP) events, the system may be used to cope with such events. The RCI pump issupplied demineralized makeup water from the CST and can use the suppression pool as an alternate SR source of water. All components necessary for the initiation and operation of the RCI system are completely independent of any auxiliary alternating current (AC) power, plantservice air, and external cooling water systems, requiring only direct current (DC) control andinstrument power from the plant batteries. The RCI system also provides for primary containment isolation. The pumping capacity of the RCI system is sufficient to maintain thewater level above the core without any other makeup water system in operation.The RCI system contains SR components that are relied upon to remain functional during andfollowing DBEs. The failure of NSR SSCs in the RCI system could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the RCI system performs functions that support EQ.The intended functions within the scope of license renewal include the following:

  • provide filtration
  • provide flow restriction
  • provide for heat transfer
  • provide a pressure-retaining boundaryIn LRA Table 2.3.2-6, the applicant identified the following RCI system com ponent types thatare within the scope of license renewal and subject to an AMR:
  • fasteners/bolting
  • filters/strainers
  • heat exchangers
  • piping and fittings
  • pump casings
  • restricting orifices
  • steam traps
  • tanks
  • thermowells
  • turbines
  • valve bodies 2-462.3.2.6.2 Staff EvaluationThe staff reviewed LRA Section 2.3.2.6 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.3.2.6.3 Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the RCI system componentsthat are within the scope of license renewal, as required by 10 CFR 54.4(a), and the RCI system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.2.7 Residual Heat Removal System 2.3.2.7.1 Summary of Technical Information in the Application In LRA Section 2.3.2.7, the applicant described the RHR system. The RHR system restoresand maintains the reactor coolant inventory in the reactor core so that the reactor core isadequately cooled after depressurization during a LOCA. The RHR system also providescooling for the suppression pool to ensure condensation of the steam resulting from the blowdown from the design-basis LOCA. The RHR system further extends the redundancy of theECCS by providing for primary containment spray/cooling. In addition, the RHR systemprovides for primary containment isolation. The RHR system is designed for essentially threemodes of operation, (1) LPCI, (2) containment spray/cooling, and (3) reactor shutdown cooling.The shutdown cooling s ubsystem is used for routine operations. The LPCI s ubsystem is anintegral part of the RHR system. It operates to restore and maintain the reactor coolantinventory in the reactor core after a LOCA so that the core is sufficiently cooled. The LPCIsubsystem operates in conjunction with the HPC system, the APR system, and the CSP systemto achieve this goal. The RHR system provides a means to remove decay heat and residualheat from the reactor so that refueling and reactor systems servicing can be performed. Inaddition, the RHR system provides the means to supplement the spent fuel pool cooling systemwhen necessary to provide additional cooling capacity.The RHR system contains SR components that are relied upon to remain functional during andfollowing DBEs. The failure of NSR SSCs in the RHR system could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the RHR system performs functions that support FP, EQ, and SBO.

2-47The intended functions within the scope of license renewal include the following:

  • provide filtration
  • provide for heat transfer
  • provide a pressure-retaining boundary
  • limit heat transfer to maintain temperatureIn LRA Table 2.3.2-7, the applicant identified the following RHR system component types thatare within the scope of license renewal and subject to an AMR:
  • fasteners/bolting
  • filters/strainers
  • heat exchangers
  • nozzles
  • piping and fittings
  • pump casings
  • restricting orifices
  • thermowells
  • valve bodies2.3.2.7.2 Staff Evaluation The staff reviewed LRA Section 2.3.2.7 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.3.2.7.3 Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the RHR systemcomponents that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the RHR system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2-482.3.2.8 Secondary Containment System2.3.2.8.1 Summary of Technical Information in the Application In LRA Section 2.3.2.8, the applicant described the secondary containment (SCT) system. TheSCT system completely encloses the reactor and its pressure suppression primarycontainment. The secondary containment enclosure structure provides secondary containment when the primary containment is closed and in service and primary containment when the primary containment is open, as during refueling. The reactor building houses the refueling and reactor servicing equipment, new and spent fuel storage facilities, and other reactor auxiliarysystems or service equipment. The primary purposes for the secondary containment are tominimize ground-level release of airborne radioactive materials to the environs and to provide means for a controlled, elevated release of the building atmosphere, if an accident shouldoccur. The standby gas treatment system (SGTS) is a subsystem of the SCT system and isprovided to maintain, whenever secondary containment isolation conditions exist, a small negative pressure to minimize ground-level escape of airborne radioactivity. Filters are in the system to remove radioactive particulates, and charcoal adsorbers are provided to removeradioactive halogens. All flow from the standby gas treatment system is released through theelevated offgas vent stack and continuously monitored by the stack gas monitori ng system.The SCT system contains SR components that are relied upon to remain functional during andfollowing DBEs. In addition, the SCT system performs functions that support EQ.The intended functions within the scope of license renewal include the following:

  • provide flow restriction
  • provide a pressure-retaining boundaryIn LRA Table 2.3.2-8, the applicant identified the following SCT system com ponent types thatare within the scope of license renewal and subject to an AMR:
  • ductwork
  • fan/blower/housings
  • fasteners/bolting
  • filters/housings
  • flow element
  • piping and fittings
  • restricting orifices
  • thermowells
  • valve bodies
  • ventilation seal2.3.2.8.2 Staff Evaluation The staff reviewed LRA Section 2.3.2.8 and USAR Section 5.3 using the evaluationmethodology described in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.

2-49In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.3.2.8.3 Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the SCT system componentsthat are within the scope of license renewal, as required by 10 CFR 54.4(a), and the SCT system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3 Auxiliary Systems In LRA Section 2.3.3, the applicant identified the SCs of the auxiliary systems that are subjectto an AMR for license renewal.The applicant described the supporting SCs of the auxiliary systems in the following sections ofthe LRA:

  • 2.3.3.2chemistry sampling system
  • 2.3.3.3circulating water system
  • 2.3.3.4control rod drive system
  • 2.3.3.5demineralized water system
  • 2.3.3.6emergency diesel generators system
  • 2.3.3.7emergency filtration train system
  • 2.3.3.9fire system
  • 2.3.3.10fuel pool cooling and cleanup system
  • 2.3.3.11heating and ventilation system
  • 2.3.3.12instrument and service air system
  • 2.3.3.13radwaste solid and liquid system
  • 2.3.3.14reactor building closed cooling water system
  • 2.3.3.15reactor water cleanup system
  • 2.3.3.16service and seal water system
  • 2.3.3.17standby liquid control system
  • 2.3.3.18wells and domestic water systemSER Sections 2.3.3.1-2.3.3.18 present the staff's review findings regarding LRASections 2.3.3.1-2.3.3.18, respectively.

2-502.3.3.1 Alternate Nitrogen System2.3.3.1.1 Summary of Technical Information in the Application In LRA Section 2.3.3.1, the applicant described the alternate nitrogen system (AN2). The AN2system consists of two separate SR trains providing an SR backup pneumatic source fromnitrogen bottle racks located in the turbine building. The AN 2 system interfaces with theinstrument and service air (AIR) system through a check valve, with the nitrogen side held at aslightly lower pressure to allow the AIR system to be used during normal operation. In the eventof an accident, which also disables the AIR system, the AN2 system would automatically supplythe required pneumatic loads. Manifold and system pressures of each train are monitored bypressure switches, which give control room annunciation on low pressure. The nitrogen supply bottles connected to the distribution rack are not long-lived components, and therefore, are notsubject to an AMR.The AN2 system contains SR components that are relied upon to remain functional during andfollowing DBEs. In addition, the AN2 system performs functions that support FP, EQ, and SBO.The intended function, within the scope of license renewal, is to provide a pressure-retainingboundary.In LRA Table 2.3.3-1, the applicant identified the following AN2 system component types thatare within the scope of license renewal and subject to an AMR:

  • fasteners/bolting
  • flexible connections
  • piping and fittings
  • valve bodies2.3.3.1.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.1 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.3.3.1 identified an area for which it needed additionalinformation to complete its evaluation of the applicant's scoping and screening results. The applicant responded to the staff's RAI as discussed below.In RAI 2.3.3.1-1, dated September 16, 2005, the staff noted that the license renewal drawingLR-36049-10 at location B-8 and C-8 shows the nitrogen supply bottles as within the scope of 2-51license renewal; however, LRA Table 2.3.3-1 does not list these nitrogen supply bottles as acomponent type subject to an AMR. These nitrogen supply bottles provide a pressure boundary intended function and are passive and long-lived; therefore, the staff requested that theapplicant clarify whether these nitrogen supply bottles are included with another component type (i.e., tanks) and if not, the applicant should justify why they are not listed in Table 2.3.3-1or update the table to include these components.In its response, by letter dated October 14, 2005, the applicant stated that nitrogen supplybottles are periodically replaced and therefore are not long-lived and are not subject to an AMR, pursuant to the requirements of 10 CFR 54.21(a).Based on its review, the staff found the applicant's response to RAI 2.3.3.1-1 acceptablebecause the nitrogen supply bottles are periodically replaced and thus are not subject to AMR; therefore, the applicant resolved the staff concern described in RAI 2.3.3.1-1.2.3.3.1.3 Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the AN 2 system componentsthat are within the scope of license renewal, as required by 10 CFR 54.4(a), and the AN2 system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3.2 Chemistry Sampling System 2.3.3.2.1 Summary of Technical Information in the Application In LRA Section 2.3.3.2, the applicant described the chemistry sampling (CHM) system. TheCHM system provides for sampling the process fluid of various systems to obtain representative data to evaluate the performance of the plant systems and equipment. The sampling locationsare chosen to ensure that representative samples can be obtained. The sample streams arerouted by the shortest route to a common sample collection area. There is a collective sample station for each building in the plant-radwaste building sample station, located in the radwastebuilding; reactor building sample station, located in the reactor building; and turbine building sample station, located in the turbine building. The stations are provided with closed-loopprocess lines that discharge to the equipment drain tanks and then to the waste collector tankfor reprocessing. Each sample station typically consists of a sample rack with sample shutoff valves; sample coolers; sample chillers; sample modules; instrumentation for conductivity, pH,dissolved oxygen, dissolved hydrogen, and total organic carbon, as well as a local data acquisition system panel. There is a ventilated fume hood for collection of grab samplesadjacent to the sample rack.The failure of NSR SSCs in the CHM system could potentially prevent the satisfactoryaccomplishment of an SR function of SSCs within the scope of license renewal.The intended function, within the scope of license renewal, is to provide a pressure-retainingboundary.

2-52In LRA Table 2.3.3-2, the applicant identified the following CHM system com ponent types thatare within the scope of license renewal and subject to an AMR:

  • chillers
  • fasteners/bolting
  • filters/housings
  • flow element
  • heat exchangers
  • piping and fittings
  • thermowells
  • valve bodies2.3.3.2.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.2 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.3.3.2.3 Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the CHM systemcomponents that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the CHM system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3.3 Circulating Water System 2.3.3.3.1 Summary of Technical Information in the Application In LRA Section 2.3.3.3, the applicant described the circulating water (CWT) system. The CWTsystem removes the heat from the main condenser that is rejected by the turbine or turbinebypass system over the full range of operating loads. The CWT system is a flexible multi-cyclesystem with the capability of once-through circulation of river water, recirculation in a closedcycle with cooling towers, and several variations of these basic modes. Selection of theoperating mode will be determined by the prevailing river flow rate and river temperature toprovide economic plant operation and conformance with restrictions on river water use. The system is equipped with two half-capacity CWT pumps located at the intake structure. The 2-53pumps are designed to circulate cooling water through the main condenser. Two half-capacitycooling tower pumps, located at the discharge structure, are used during cooling tower operation. The pumps are designed to operate in series with the CWT pumps, discharging flow to each of two induced-draft cooling towers.The failure of NSR SSCs in the CWT system could potentially prevent the satisfactoryaccomplishment of an SR function of SSCs within the scope of license renewal.The intended function, within the scope of license renewal, is to provide a pressure-retainingboundary.In LRA Table 2.3.3-3, the applicant identified the following CWT system com ponent types thatare within the scope of license renewal and subject to an AMR:
  • condenser water box
  • expansion joints
  • fasteners/bolting
  • filters/strainers
  • gauges (flow, level, and sight)
  • piping and fittings
  • pump casings
  • tanks
  • thermowells
  • valve bodies2.3.3.3.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.3 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.3.3.3.3 Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the CWT systemcomponents that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the CWT system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2-542.3.3.4 Control Rod Drive System2.3.3.4.1 Summary of Technical Information in the Application In LRA Section 2.3.3.4, the applicant described the CRD system. The CRD system is desi gnedto allow control rod withdrawal or insertion at a limited rate, one control rod at a time, for power-level control and flux shaping during reactor operation. Stored energy available from gas-charged accumulators and/or from reactor pressure provides hydraulic power for rapid simultaneous insertion of all control rods for rapid (scram) reactor shutdown. Each control rod has its own separate drive mechanism, control, and scram devices. The CRD system isdesigned so that sufficient energy is available to force the control rods into the core under conditions associated with abnormal operational transients and accidents. Control rod insertion speed is sufficient to prevent fuel damage as a result of any abnormal operational transient.

The CRD system also supplies water to the RVI reference-leg backfill subsystem. Thissubsystem provides a constant backfill of water from the CRD system's charging water headerto the safeguards and FW reference legs to flush any gas-laden water through the condensate chambers and back to the reactor vessel to eliminate level errors from the degassing phenomenon.The CRD system contains SR components that are relied upon to remain functional during andfollowing DBEs. The failure of NSR SSCs in the CRD system could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the CRD system performs functions that support FP, EQ, ATWS, and SBO.The intended function, within the scope of license renewal, is to provide a pressure-retainingboundary.In LRA Table 2.3.3-4, the applicant identified the following CRD system component types thatare within the scope of license renewal and subject to an AMR:

  • fasteners/bolting
  • filters/strainers
  • flow element
  • gauges (flow, level, and sight)
  • heat exchangers
  • piping and fittings
  • pump casings
  • restricting orifices
  • speed increaser assembly
  • tanks
  • thermowells
  • valve bodies 2-552.3.3.4.2 Staff EvaluationThe staff reviewed LRA Section 2.3.3.4 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.3.3.4.3 Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the CRD systemcomponents that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the CRD system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3.5 Demineralized Water System 2.3.3.5.1 Summary of Technical Information in the Application In LRA Section 2.3.3.5, the applicant described the demineralized water system (DWS). TheDWS provides for storage and distribution of high-quality, nonradioactive demineralized water for use as makeup to the CST system and other systems requiring high-quality demineralizedwater. The DWS is NSR and is not required during or following DBEs. The DWS includes the makeup demineralizer (MUD) subsystem. The MUD subsystem is a double-pass,reverse-osmosis system used to purify and demineralize well water. This demineralized water isused for various plant services which require quality water to (1) minimize damage to components because of chemical and corrosive attack, (2) minimize the fouling of heat transfer surfaces and mechanical parts, and (3) minimize impurities available for activation in neutron flux zones. The MUD subsystem is also NSR and is not required during or following DBEs. TheDWS provides for primary containment isolation.The DWS contains SR components that are relied upon to remain functional during andfollowing DBEs. The failure of NSR SSCs in the DWS could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal.The intended function, within the scope of license renewal, is to provide a pressure-retainingboundary.In LRA Table 2.3.3-5, the applicant identified the following DWS component types that arewithin the scope of license renewal and subject to an AMR:

2-56

  • fasteners/bolting
  • filters/housings
  • flow element
  • heat exchangers
  • piping and fittings
  • pump casings
  • restricting orifices
  • tanks
  • thermowells
  • ultraviolet light housings
  • valve bodies2.3.3.5.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.5 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.3.3.5.3 Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the DWS components thatare within the scope of license renewal, as required by 10 CFR 54.4(a), and the DWS components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3.6 Emergency Diesel Generators System 2.3.3.6.1 Summary of Technical Information in the Application In LRA Section 2.3.3.6, the applicant described the EDG system (DGN). The DGN systemprovides a dependable, onsite power source capable of automatically starting and supplying the loads necessary to safely shut down the plant and maintain it in a safe-shutdown condition upon the loss of offsite power simultaneous with a DBA. The EDGs are normally in the standby mode of operation and remain in this mode unless called upon to start by receipt of appropriate automatic signals or by a manual start. The DGN system contains two identical electromotive,turbocharged, 20-cylinder EDGs, each supplying 4160 volts-alternating current (VAC) to its respective emergency bus. The following subsystems within the DGN system support operation 2-57of the EDGs-(1) an engine fuel oil system, (2) an engine lubricating oil system, (3) a startingair system, (4) a closed-cycle engine cooling water system, and (5) an air intake and exhaustsystem. The engine fuel oil system provides clean, water-free fuel oil to the diesel cylinders.The engine lubricating oil system provides filtered lubricating oil to the diesel engine to ensureadequate lubrication during engine startup and operation. The starting air system consists oftwo independent air-starting systems for each diesel that provide the motive force to initially putthe diesel engine in motion and begin the diesel cycle. The closed-cycle engine cooling watersystem provides cooling to the diesel cylinders and heads and the aftercooler of theturbocharger via two engine-driven centrifugal pumps. The EDG air intake and exhaust systemremoves exhaust gases from the diesel cylinders and supplies fresh air for the combustion process. The DGN system includes the diesel oil (DOL) system as a s ubsystem for licenserenewal purposes. The DOL subsystem provides for the storage and distribution of fuel oil usedin the operation of the plant EDGs, diesel fire pump, and heating boiler.The DGN system contains SR components that are relied upon to remain functional during andfollowing DBEs. The failure of NSR SSCs in the DGN system could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the DGN system performs functions that support FP.The intended functions within the scope of license renewal include the following:
  • provide filtration
  • provide for heat transfer
  • provide a pressure-retaining boundaryIn LRA Table 2.3.3-6, the applicant identified the following DGN system com ponent types thatare within the scope of license renewal and subject to an AMR:
  • fasteners/bolting
  • filters/housings
  • filters/strainers
  • flame arrestors
  • flow element
  • gauges (flow, level, and sight)
  • heat exchangers
  • heaters/coolers
  • piping and fittings
  • pump casings
  • silencer
  • tanks
  • thermowells
  • valve bodies2.3.3.6.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.6 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.

2-58In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.3.3.6 identified an area for which it needed additionalinformation to complete its evaluation of the applicant's scoping and screening results. The applicant responded to the staff's RAI as discussed below.In RAI 2.3.3.6-1, dated September 16, 2005, the staff noted that the DGN system includes aDOL subsystem which stores and supplies diesel fuel oil for the operation of the plant dieselgenerators, diesel fire pump, and heating boiler. The DOL subsystem (except such portions asthe heating boiler oil storage tank and its day tank) is SR and within the scope of license renewal; however, license renewal drawing LR-36051 sheet 1 shows the truck f ill connection atlocation B-5 and the diesel oil receiving tank (T-83) subsystem (including pump, piping, andother components) at location A-7 as outside the scope of license renewal. Therefore, the staffrequested that the applicant clarify whether these components are within the scope of licenserenewal and subject to an AMR, in accordance with the applicable requirements of 10 CFR 54.4(a) and 10 CFR 54.21(a), respectively, or justify their exclusion.In its response, by letter dated October 14, 2005, the applicant stated that the diesel oilreceiving tank (T-83) and truck f ill connection are utilized for receiving, storing, and samplingdiesel fuel oil before transfer of the fuel oil to the diesel oil storage tank (T-44) and that these components are not SR. The applicant explained that failure of the truck f ill connection and thediesel oil receiving tank (T-83) and connecting piping outside the diesel fuel oil transfer house (pump house) would not impact the intended function of any SR SCs. The applicant, therefore, concluded that the NSR f ill connection, diesel oil receiving tank, and connectingpiping outside the pump house performed no license renewal function as defined by 10 CFR 54.4(a) and, therefore, were not within the scope of license renewal.Based on its review, the staff found the applicant's response to RAI 2.3.3.6-1 acceptablebecause the applicant provided a satisfactory explanation as to why the components are outside the scope of license renewal; therefore, the applicant resolved the staff concerndescribed in RAI 2.3.3.6-1.The staff's review of LRA Section 2.3.3.6 identified an area in which information provided in theLRA needed to be verified by the NRC Regional Inspection Team to complete the review of theapplicant's scoping and screening results.Inspection Item 2.3.3.6-1LRA Section 2.3.3.6 states that DGN air-starti ng subsystem components within the scope oflicense renewal are located between the air compressor discharge check valves and the diesel engine air start motors; however, license renewal drawing LR-36051 shows, at locations A-3, B-3, C-3, and D-3, that the license renewal boundaries terminate in the middle of those pipesconnected between the compressor air dryers and discharge check valves (GSA-32-2, 2-59GSA-32-1, GSA-32-4, and GSA-32-3). The actual locations of the license renewal scopeboundaries for these components are not clear. The NRC Regional Inspection Team performedan inspection to ensure that the license renewal scope boundaries for these components satisfy the 10 CFR 54.4(a)(2) criterion.The inspection team determined that the scope boundaries are just upstream of the respectivecheck valves, as indicated. The actual boundaries are where the carbon steel pipe connects to the copper alloy tubing at the nipple to the air dryers. Because of the relative flexibility betweenthe piping and tubing, the boundary is the tubing transition point. The boundary drawing depictsthis transition point between the check valve and the air dryer. The inspectors determined thatthe license renewal boundaries satisfy the 10 CFR 54.4(a)(2) criterion. Therefore, the staff'sconcern described in Inspection Item 2.3.3.6-1 is resolved.2.3.3.6.3 Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant had adequately identified the DGN systemcomponents that are within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant had adequately identified the DGN system components that are subject to anAMR, as required by 10 CFR 54.21(a)(1).2.3.3.7 Emergency Filtration Train System 2.3.3.7.1 Summary of Technical Information in the Application In LRA Section 2.3.3.7, the applicant described the emergency filtration train (EFT) system. TheMNGP licensing basis considers the EFT system as an ESF system. This section includes theEFT system, and the related aging management section, for consistency with the SRP-LR andGALL Report. The heating, ventilation, and air conditioning system that serves the main controlroom (MCR) and the EFT building is designed to provide cool air in the summer and warm air for heating in the winter. Ductwork is used to distribute air. The airflow in the MCR and portions of the EFT building is normally recirculated with return air arranged to pass back to the air conditioning unit, while supplemental outside air is drawn through filtration units. The EFT system will serve the MCR and EFT building during normal or emergency conditions. Anemergency condition is defined as a condition caused by a high radiation level or detection of toxic chemical vapors in the outside air. The air handling units are self-contained package units complete with electric coils for heating and cooling coils for air conditioning. In the normal operating mode, the MCR and EFT building's first and second floors, excluding the battery room, are served by one of the redundant seismic Class 1 air conditioning units. Filtered outside air from an EFT is available on demand. The EFT system operates in the recirculationmode from offsite AC power. If offsite power is not available, the diesel generators willautomatically supply the system.The EFT system contains SR components that are relied upon to remain functional during andfollowing DBEs. In addition, the EFT system performs functions that support FP.

2-60The intended functions within the scope of license renewal include the following:

  • provide structural support to SR components (all other systems)
  • provide for heat transfer
  • provide a pressure-retaining boundaryIn LRA Table 2.3.3-7, the applicant identified the following EFT system com ponent types thatare within the scope of license renewal and subject to an AMR:
  • chillers
  • ductwork
  • fan/blower/housings
  • fasteners/bolting
  • filters/housings
  • heat exchangers
  • piping and fittings
  • valve bodies
  • ventilation seal2.3.3.7.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.7 and USAR Section 6.7 using the evaluationmethodology described in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.3.3.7.3 Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the EFT system componentsthat are within the scope of license renewal, as required by 10 CFR 54.4(a), and the EFT system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2-612.3.3.8 Emergency Service Water System2.3.3.8.1 Summary of Technical Information in the Application In LRA Section 2.3.3.8, the applicant described the ESW system, which includes the followingthree plant subsystems-(1) EDG-ESW subsystem, (2) ESW subsystem, and (3) RHR servicewater subsystem. These subsystems are combined into the ESW system for license renewalpurposes. The EDG-ESW subsystem consists of two separate and independent emergencycooling water loops that provide cooling water to the EDGs. The loops are capable of providing cooling water during a loss of offsite power and during accident conditions. Each loop contains one full capacity pump that supplies strained cooling water to one of the EDGs. The ESW subsystem consists of two separate and independent emergency cooling water loops thatprovide cooling water to the ECCS pump motor coolers, ECCS room coolers, and the EFT.

Each loop is capable of providing cooling water during a loss of offsite power and/or a loss of normal service water. Each loop contains one full capacity pump that supplies strained cooling water to the cooling loads. The RHR service water subsystem (RSW) consists of two separateand independent emergency cooling water loops that provide cooling water to the RHR heatexchangers. Each loop is capable of providing cooling water during a loss of offsite power and during accident conditions. The RHR auxiliary air compressors are included in the RHR servicewater subsystem. The RHR auxiliary air compressors provide an SR backup air supply to the RHR heat exchanger residual heat removal service water (RSW) outlet control valves and theCGC system isolation valves upon occurrence of low pressure in the AIR system. The RHRauxiliary air compressors are normally in standby mode of operation.The ESW system contains SR components that are relied upon to remain functional during andfollowing DBEs. The failure of NSR SSCs in the ESW system could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the ESW system performs functions that support FP and EQ.The intended functions within the scope of license renewal include the following:

  • provide filtration
  • provide flow restriction
  • provide for heat transfer
  • provide a pressure-retaining boundaryIn LRA Table 2.3.3-8, the applicant identified the following ESW component types that arewithin the scope of license renewal and subject to an AMR:
  • fasteners/bolting
  • filters/housings
  • filters/strainers
  • flow element
  • heat exchangers
  • piping and fittings
  • pump casings
  • restricting orifices
  • tanks 2-62
  • thermowells
  • valve bodies2.3.3.8.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.8 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.3.3.8 identified an area in which information provided in theLRA needed to be verified by the NRC Regional Inspection Team to complete the review of theapplicant's scoping and screening results.Inspection Item 2.3.3.8-1License renewal drawing LR-36665 at location C-5 shows a continuation of NSR ESW pipingwithin the scope of license renewal from the valve (ESW-12-4"-JBD-GT) to the desilting line on LR-36665 at location A-5; however, the continuation desilting line at location A-5 is designatedas SW28-4"-JF and not identified as within the scope of license renewal. Consequently, the actual location of the license renewal boundary for this pipe is not clear. The NRC Regi onalInspection Team performed an inspection to ensure that the license renewal scope boundary for this pipe satisfies the 10 CFR 54.4(a)(2) criterion.The inspection team determined that the continuation of NSR ESW piping from the valveESW-12 to the desilting line on LR-36665 at location A-5 should have been shown within the scope of license renewal. The applicant will revise license renewal drawing LR-36665 to showline SW28-4"-JF, the continuation to the desilting line, within the scope of license renewal, up towhere the line enters the column in the intake structure. The inspectors confirmed through walkdowns that the scoping boundary is where this line passes into the column shown at coordinates A-5 on the drawing. The inspectors determined that the license renewal boundarysatisfies the 10 CFR 54.4(a)(2) criterion. Therefore, the staff's concern described in Inspection Item 2.3.3.8-1 is resolved.2.3.3.8.3 Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the ESW systemcomponents that are within the scope of license renewal, as required by 10 CFR 54.4(a), and 2-63that the applicant adequately identified the ESW system components that are subject to anAMR, as required by 10 CFR 54.21(a)(1).2.3.3.9 Fire System 2.3.3.9.1 Summary of Technical Information in the Application In LRA Section 2.3.3.9, the applicant described the fire system. The fire system providesassurance, through defense-in-depth design, that a fire will not prevent the performance ofnecessary safe-shutdown functions or significantly increase the risk of radioactive release to the environment during a postulated fire. The fire system provides fire suppression by fixed waterspray and sprinkler systems, fixed gas (Halon 1301) systems, hose stations, and portableextinguishers located in various areas of the MNGP site. MNGP has a fire detection and alarm system that alarms locally in selected areas of the plant and transmits various alarm,supervisory, and trouble signals to the control room. The fire system ensures compliance withthe regulated event for FP. The Mississippi River supplies the water for the fire system. The firesystem also provides alternate sources of water to other plant systems.The failure of NSR SSCs in the fire system could potentially prevent the satisfactoryaccomplishment of an SR function of SSCs within the scope of license renewal. The fire systemalso performs functions that support FP.The intended functions within the scope of license renewal include the following:
  • provide filtration
  • provide flow restriction
  • provide for heat transfer
  • provide a pressure-retaining boundaryIn LRA Table 2.3.3-9, the applicant identified the following fire system component types that arewithin the scope of license renewal and subject to an AMR:
  • fasteners/bolting
  • filters/strainers
  • fire hydrants
  • flexible connections
  • gauges (flow, level, and sight)
  • heat exchangers
  • nozzles
  • piping and fittings
  • pump casings
  • restricting orifices
  • sprinkler heads
  • tanks
  • valve bodies 2-642.3.3.9.2 Staff EvaluationThe staff reviewed LRA Section 2.3.3.9 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff also reviewed the approved FP SERs, dated August 29, 1979, February 12, 1981, and October 2, 1985. These reports are referenceddirectly in the MNGP FP CLB and summarize the FP program and commitments to 10 CFR 50.48 using the guidance of Appendix A to Branch Technical Position (BTP) Chemical and Mechanical Engineering Branch (CMEB) 9.5-1, "Guidelines for Fire Protection for Nuclear Power Plants." The staff then reviewed those components that the applicant had identified asbeing within the scope of license renewal to verify that the applicant had not omitted anypassive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.3.3.9 identified areas for which it needed additionalinformation to complete its evaluation 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 18, 2005, the staff noted that license renewal drawing LR-36051highlights the diesel fire pump, diesel fire pump day tank, and interconnecting piping as within the scope of license renewal; however, the diesel fire pump day tank fill line is not highlighted.The staff requested that the applicant clarify whether the diesel fire pump day tank fill line iswithin 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), or justify its exclusion.In its response, by letter dated September 16, 2005, the applicant stated the following:The diesel fire pump day tank fill line is not within the scope of license renewaland is not subject to an AMR. The diesel fire pump day tank (T-100) is a 120-gallon capacity tank. The tank conservatively provides about ten hours of operation of the diesel-driven fire pump before makeup is required. This satisfies the requirements of NFPA-20, 'Standard for the Installation of Centrifugal Fire Pumps,' which states that the day tank capacity '...shall be sufficient to operate the engine for at least eight hours.' In accordance with the Operations Manual forthe diesel oil subsystem, the nominal fuel oil consumption of the diesel-driven fire pump is eight (8) gallons per hour. An alternate method of transferring fuel oil from the Diesel Oil Storage Tank (T-44) to the Diesel Fire Pump Day Tank is provided during emergencies and is governed by abnormal procedures in accordance with the MNGP Operations Manual. Under these situations, the Portable Gasoline Engine Powered Fuel Oil Pump (P-229) that is normally stored in Warehouse 2 is utilized. This portable pump is within the scope of licenserenewal and is subject to AMR. P-229 is evaluated in AMR-DGN, Emergency Diesel Generators System, since the diesel oil subsystem including fuel oil to thediesel-driven fire pump, is evaluated within this AMR. Under these emergency 2-65situations, P-229 is connected to the Diesel Oil Storage Tank using portablehoses. T-100 is filled by removing the 8" manhole cover from this tank andinserting the discharge hose from P-229. Consequently, utilizing the PortableGasoline Engine Powered Fuel Oil Pump provides an alternate method of fillingthe Diesel Fire Pump Day Tank and the Diesel Fire Pump Day Tank fill line isexcluded from the scope of license renewal and is not subject to AMR.Based on its review, the staff found the applicant's response to RAI 2.3.3.9-1 acceptablebecause the diesel fire pump day tank can be filled using an alternate method (i.e., the portablegasoline engine powered fuel oil pump) which is within the scope of license renewal and subject to an AMR; therefore, the staff's concern described in RAI 2.3.3.9-1 is resolved.In RAI 2.3.3.9-2, dated August 18, 2005, the staff identified that license renewaldrawing LR-36664 (coordinates C-7) shows the KB/GB boundary and the system boundarybreak (Fire Protection ESW) at opposite ends of valve RHRSW-46, which is the only valve onthe drawing at which they are at opposite ends. The staff requested that the applicant verifywhether this depiction is correct.In its response, by letter dated September 16, 2005, the applicant stated, "This is correct due tothe fact that valve RHRSW-46 is within scope in the Fire Protection (FIR) System. There istypically no correlation between License Renewal system boundary breaks and pipingclassifications."Based on its review, the staff found the applicant's response to RAI 2.3.3.9-2 acceptablebecause it adequately explains the scoping of valve RHRSW-46; therefore, the staff's concerndescribed in RAI 2.3.3.9-2 is resolved.In RAI 2.3.3.9-3, dated August 18, 2005, the staff identified that on license renewaldrawing LR-36664 the piping on the KB side (outlet) of valve RHRSW-46 (coordinates C-7) ishighlighted as within the scope of license renewal, in accordance with 10 CFR 54.4(a)(2). On the continuation license renewal drawing LR-36048, the same piping is shown highlighted aswithin the scope of license renewal pursuant to 10 CFR 54.4(a)(1) and (a)(3). The staff requested that the applicant clarify which paragraph of 10 CFR 54.4 applies to this piping forthe LRA.In its response, by letter dated September 16, 2005, the applicant stated the following:The piping on the 'KB' side of valve RHRSW-46 on LRA drawing LR-36664 ishighlighted in 'green' since it is in the scope of license renewal in accordance with 10 CFR 54.4(a)(2) for non-safety connected to safety (FIR to ESW) and, non-safety affecting safety (NSAS) with respect to potential leakage/spray. It is also in the scope of license renewal in accordance with 10 CFR 54.4(a)(3) for the fire protection regulated event. The continuation of this piping is highlighted on LRA drawing LR-36048 in 'red' and is in the scope of license renewal per 10 CFR 54.4(a)(3) due to the Fire Protection regulated event. The color-coding was performed in this manner to indicate these two separate criteria yet provide differentiation between the two criteria due to this particular piping segment in the FIR System being identified on two separate LR drawings.

2-66Based on its review, the staff found the applicant's response to RAI 2.3.3.9-3 acceptablebecause it adequately explains that the piping on the KB side of valve RHRSW-46 is within thescope of license renewal, pursuant to 10 CFR 54.4(a)(2) and 10 CFR 54.4(a)(3); therefore, the staff's concern described in RAI 2.3.3.9-3 is resolved.In RAI 2.3.3.9-4, dated August 18, 2005, the staff identified that GALL Report Section XI.27,"Fire Water System," describes the requirement for aging management of the FP water systemand recommends that an AMP be established to evaluate the aging effects of corrosion, microbiologically influenced corrosion (MIC), and biofouling of carbon steel and cast iron components in the FP systems exposed to water.LRA Section 2.3.3.9 addresses requirements for the Fire Detection and Protection Program, butdoes not mention trash racks and traveling screens for the fire pump suction water supply.Neither LRA Section 2.3.3.3, "Circulating Water System," nor Section 2.4.8, "Intake Structure,"mention trash racks and traveling screens.The USAR states, in part, the following:River water is turned through an angle of 81 to approach the plant along achannel excavated to elevation 898 feet. It enters the Intake Structure through a trash rack before dividing into two separate streams to the circulating water pump chambers. Each stream passes through two parallel automatically operated traveling screens, the service water pump bay and two parallel motor-operated sluice gates before reaching a circulating water pump. The center dividing wall permits dewatering of either pump bay. A normally closed gate in the wall can be manually opened during normal operation if a traveling screen is out of service for maintenance. Taking suction from the service pump bay are two 14,000 gpm make-up pumps and pumps for the station cooling, screen wash, and fire protection.Trash racks and traveling screens are necessary to remove debris and prevent clogging for theFP water supply system. Trash racks and traveling screens are typically considered passive,long-lived components. Trash racks are located in a freshwater environment. Traveling screensare located in a freshwater/air environment. Although not specifically addressed in the USAR or LRA, trash racks and traveling screens are typically constructed of carbon steel material.Carbon steel in a freshwater environment or a freshwater/air environment is subject to corrosion; therefore, the staff requested that the applicant explain the apparent exclusion of thetrash racks and traveling screens located upstream of the fire pump suctions from the scope oflicense renewal and an AMR.In its response, by letter dated September 16, 2005, the applicant stated the following:The trash racks are installed to remove large debris from entering the IntakeStructure. Since the trash racks are an integral part of the Intake Structure, they were included within the scope of license renewal and are subject to an AMR as part of the Intake Structure, for conservatism. They are identified in Table 3.5.2-8 (Structures and Component Supports-Intake Structure) of the LRA as carbon steel (Component Type) in both an atmosphere/weather and raw water environment and are subject to an AMR due to loss of material. The Structures 2-67Monitoring Program manages the aging effect of loss of material for thiscomponent. The traveling screens are part of the non-safety related Circulating Water System that supports normal plant operation. The traveling screens are provided for trash, fish, and vegetation removal to minimize the fouling and clogging of the Circulating Water System water box tube sheets and piping.

However, for both the trash racks and the traveling water screens, build-up ofdebris is considered event-driven and not age-related. Both the trash ra cks andtraveling screens are non-safety related, non-QA, and non-seismic components.During normal plant operation, the Circulating Water pumps (two pumps inoperation) draw a significant flow of cooling water (292,000 gpm) through the bays of the Intake Structure to support the main condenser cooling requirements. This high flow rate (not including the normal Service Water flow rate that equates to an additional 10,000 gpm with two pumps in operation) creates the potential for debris and sediment to enter the bays. Duringemergency operation, when the Circulating Water pumps are not in operation, the Fire Pumps draw a small flow (1500 gpm/pump) of water through the bays with a corresponding low velocity. The low flow velocity creates an insignificant amount of debris and sediment to accumulate and the traveling water screens are able to pass a sufficient amount of water to support operation of the Fire Pumps. Additionally, the Fire Pumps themselves are equipped with suction strainers. Basket strainers are provided in the main fire pump discharge headers.

Any significant degradation or failure of the traveling screens during normal power operation would be evident and detected by plant operators far in advanceof a complete failure. Even in the case of total failure, floating or heavy debris would not affect the operation of the Fire pumps due to the low velocities at the suction of these pumps. The screens are subject to periodic maintenance and replacement and are continuously monitored through main control room annunciation. Additionally, the river and atmospheric environments for these components are relatively non-aggressive. The traveling screens and trash racks are not required to perform a function during or following a design basis event, and therefore do not meet the scoping criteria of 10 CFR 54.4(a)(1)(I), (ii), or (iii).There is no credible failure mode of the traveling screens and trash racks thatcould prevent satisfactory accomplishment of any of the functions identified in paragraphs 10 CFR 54.4(a)(1)(I), (ii), or (iii). Therefore, the traveling screens andtrash racks do not meet the scoping criteria of 10 CFR 54.4(a)(2). The traveling screens and trash racks are not required to perform a function in support of theregulated events of 10 CFR 54.4(a)(3).

Based on the above, the traveling screens and trash racks are not considered tomeet the scoping criteria of 10 CFR 54.4(a) and do not perform a license renewal intended function per 10 CFR 54.4(b). Consequently, although the trash racks are within the scope of license renewal and are subject to AMR since theyare an integral part of the Intake Structure and were included for conservatism, the traveling screens are not within the scope of license renewal and are not subject to AMR.Based on its review, the staff found the applicant's response to RAI 2.3.3.9-4 acceptablebecause the trash racks are integral parts of the intake structure and were included within the 2-68scope of license renewal and are subject to an AMR for conservatism. The traveling screensare subject to periodic maintenance and replacement and are continuously monitored through main control room annunciation. Even in the case of total failure, floating or heavy debris would not affect the operation of the fire pumps because of the low velocities (compared to the velocities of the flow for the CWT pumps) at the suction of these pumps; therefore, the staff'sconcern described in RAI 2.3.3.9-4 is resolved.In RAI 2.3.3.9-5, dated August 18, 2005, the staff noted that Section 3.1.2(3) of the NRC "FireProtection Safety Evaluation Report," dated August 29, 1979, states that "a sprinkler system willbe installed to provide a means to cool hot gases that enter the cable tray area in the water treatment and ESF motor control center area." This sprinkler system is not shown on thelicense renewal boundary drawings; therefore, the staff requested that the applicant verify thatthis sprinkler system is within the scope of license renewal pursuant to 10 CFR 54.4(a)(3).In its response, by letter dated September 16, 2005, the applicant stated the following:The sprinkler system installed to provide a means to cool the hot gases thatenter the cable tray area in the water treatment and ESF motor control centerareas as addressed in the Fire Protection Safety Evaluation Report dated August 29, 1979, Section 3.1.2(3), is not shown in the Fire System LR boundary drawings (P&lDs). However, the isolation valves to this sprinkler system are shown on License Renewal Boundary Drawing LR-36048, Fire Protection System (coordinates C, 7). Valve FP-142 is located at the Turbine Building 951' elevation and valve FP-145 is located at the Turbine Building 911' elevation.These locked-open valves are noted on the drawing as 'FIREWALL SPRINKLER ABOVE LUBE OIL STORAGE TANKS.' These two valves and the remainder of this sprinkler system (water curtain) are in the scope of license renewal per10 CFR 54.4(a)(3) and are subject to AMR. These components are addressed in Table 3.3.2-9, Auxiliary Systems - Fire System - Summary of Aging ManagementEvaluation, of the MNGP LRA. The aging effects associated with these components are managed by both the Fire Water System and System Condition Monitoring (external environment) AMPs. However, in addition to the installation of this sprinkler system and in compliance with Appendix R of 10 CFR 50,Section IlI.G.2(c), the cable, equipment and associated non-safety circuits of the redundant trains are separated by a fire barrier (wall) having a minimum one-hour rating (two-hour barrier actually installed). This fire barrier (Walls T324 and T331) is addressed in Table 3.5.2-17, Structures and Component Supports -

Turbine Building - Summary of Aging Management Evaluation, of the MNGP LRA. Both the Fire Protection and Structures Monitoring AMPs manage the aging effects associated with this component.Based on its review, the staff found the applicant's response to RAI 2.3.3.9-5 acceptablebecause it adequately explains that the sprinkler system, installed as a means to cool the hotgases that enter the cable tray area in the water treatment and ESF motor control center (MCC)areas, is within the scope of license renewal, pursuant to 10 CFR 54.4(a)(3) and subject to an AMR; therefore, the staff's concern described in RAI 2.3.3.9-5 is resolved.In RAI 2.3.3.9-6, dated August 18, 2005, the staff noted that Section 4.3.1(17) of the NRC's"Fire Protection Safety Evaluation Report," dated August 29, 1979, states that, "The licensee 2-69will provide foam application equipment for use in fighting potential lube oil fires in the turbinebuilding." The license renewal drawings do not show this foam application equipment; therefore, the staff requested that the applicant clarify whether this foam application equipmentis within the scope of license renewal, pursuant to 10 CFR 54.4(a)(3).In its response, dated September 16, 2005, the applicant stated the following:The foam application equipment addressed in the Fire Protection SafetyEvaluation Report dated August 29, 1979, Section 4.3.1(7) concerns the two (2)sets of portable foam applicators for use in fighting potential lube oil fires in the Turbine Building. This portable equipment is not shown in the Fire System LR boundary drawings (P&lDs) since it is portable equipment. This equipment is within the scope of license renewal per 10 CFR 54.4(a)(3) and is stored in the Fire Brigade Room in the Plant Administration Building basement at MNGP. This equipment is not subject to AMR since it is inspected periodically (quarterly) under the Fire Protection Program procedures for fire brigade equipment and replaced on condition.This issue is also addressed in Section 2.1.4.2.4, Fire Protection, of the MNGPLRA that states:Items such as fire extinguishers, fire hoses, portable lighting, and airpacks were subjected to the MNGP's scoping and screening process.This process is consistent with the NRC Staff's guidance on consumablesprovided in NUREG-1800, Table 2.1-3.This issue is further defined in Section 2.1.5.3, Component Classification(Passive, long-lived), of the MNGP LRA that states:C.Fire Extinguishers, Fire Hoses, and Air Packs Components such as fire hoses, fire extinguishers, self-containedbreathing apparatus (SCBA), and SCBA cylinders are consumables that are routinely tested or inspected. The Fire Protection Program complies with the applicable NFPA safety standards, which specify performance and condition monitoring programs for these specific components. They are replaced as necessary. Therefore, while these consumables are in the scope of license renewal, they do not require an AMR.A component (or component commodity group) that was determined tobe active or short-lived is not subject to an AMR, and is screened out by the process.Consequently, this foam application equipment is within the scope of licenserenewal per 10 CFR 54.4(a)(3) but is not subject to an AMR.Based on its review, the staff found the applicant's response to RAI 2.3.3.9-6 acceptablebecause it adequately explains that the foam application equipment is within the scope oflicense renewal, pursuant to 10 CFR 54.4(a)(3), but is not subject to an AMR because it is 2-70inspected periodically (quarterly) under the Fire Protection Program's procedures for firebrigade equipment and replaced as necessary. Therefore, the staff's concern described in RAI 2.3.3.9-6 is resolved.In RAI 2.3.3.9-7, dated August 18, 2005, the staff noted that Section 5.2.6 of the NRC's "FireProtection Safety Evaluation Report," dated August 29, 1979, states that the cable spreadingroom "will be provided with an automatic gas suppression system." The license renewaldrawings do not show this automatic gas suppressi on system; therefore, the staff requestedthat the applicant clarify whether this automatic gas suppressi on system is within the scope oflicense renewal, pursuant to 10 CFR 54.4(a)(3).In its response, dated September 16, 2005, the applicant stated the following:The Cable Spreading Room, addressed in the Fire Protection Safety EvaluationReport dated August 29, 1979, Section 5.2.6.3, is provided with a total floodingautomatic gas suppression system consisting of cylinder storage unitspressurized with Halon 1301. Halon is discharged into the room through wide-angle nozzles. As stated in Section 2.1.4.4 (Evaluation Boundaries -

License Renewal Boundary Drawings) of the MNGP LRA, the in-scope boundaries are depicted in the License Renewal Boundary Drawings. 'The drawings consist of simplified process and instrumentation drawings (for the mechanical systems)' or P&lDs. The Halon gas suppression system does notappear in any of the MNGP P&lDs for the Fire System but rather in individual vendor drawings which are not included as part of the license renewal boundary drawing submittal package. The Cable Spreading Room Halon automatic gas suppression system is in the scope of license renewal. This is confirmed by anddiscussed in Section 2.3.3.9 (Fire System), Table 3.0-1 Mechanical and Civil Service Environments, Table 3.3.2-9, (Auxiliary Systems - Fire System -

Summary of Aging Management Evaluation), Appendix A2.1.17 (Fire Protection) and Appendix B2.1.17 (Fire Protection) of the MNGP LRA. Therefore, the CableSpreading Room automatic gas suppression system is in the scope of licenserenewal per 10 CFR 54.4(a)(3) and is subject to AMR.Based on its review, the staff found the applicant's response to RAI 2.3.3.9-7 acceptablebecause it adequately explains that the automatic gas suppression system is within the scopeof license renewal, pursuant to 10 CFR 54.4(a)(3), and is subject to an AMR; therefore, the staff's concern described in RAI 2.3.3.9-7 is resolved.2.3.3.9.3 Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the fire system componentsthat are within the scope of license renewal, as required by 10 CFR 54.4(a), and the fire systemcomponents that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2-712.3.3.10 Fuel Pool Cooling and Cleanup System2.3.3.10.1 Summary of Technical Information in the Application In LRA Section 2.3.3.10, the applicant described the fuel pool cooling and cleanup (FPC)system. The FPC system is designed to handle the spent fuel cooling load and to maintain poolwater purity and clarity. T he system provides sufficient filtering capacity to filter the entire spentfuel pool water volume every 12 hours1.388889e-4 days <br />0.00333 hours <br />1.984127e-5 weeks <br />4.566e-6 months <br />. The fuel pool temperature is normally maintained at

125 F or less to ensure a reasonable working environment in the pool area, to keep thedemineralizer at an operable temperature, and to maintain visual clarity of the air above the pool; however, operation at temperatures up to 140 F is acceptable to remove decay heat fromthe spent fuel. The fuel pool cooling and cl eanup system consists of circulating pumps, heatexchangers, filter/demineralizers, piping, valves, and instrumentation. The pumps take suction from the skimmer surge tank, located at the top of the spent fuel storage pool water level, whichcontinuously skims the water from the surface and circulates the water to the heat exchangersand filter/demineralizers before discharging the water through the diffusers at the bottom of the spent fuel pool. This arrangement of taking suction from the top and discharging to the bottom of the pool provides a crossflow which tends to sweep the pool and to carry off dirt and small particles. This system may also be used to drain the steam-separator storage pool and thereactor well after refueling.The failure of NSR SSCs in the FPC system could potentially prevent the satisfactoryaccomplishment of an SR function of SSCs within the scope of license renewal.The intended function, within the scope of license renewal, is to provide a pressure-retainingboundary.In LRA Table 2.3.3-10, the applicant identified the following FPC system com ponent types thatare within the scope of license renewal and subject to an AMR:

  • fasteners/bolting
  • heat exchangers
  • piping and fittings
  • pump casings
  • tanks
  • thermowells
  • valve bodies2.3.3.10.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.10 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicant 2-72had identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).In reviewing LRA Section 2.3.3.10, the staff identified areas for which it needed additionalinformation to complete its evaluation of the applicant's scoping and screening results. The applicant responded to the staff's RAIs as discussed below.In RAI 2.3.3.10-1, dated September 16, 2005, the staff noted that LRA Section 2.3.3.10 statesthat components in the FPC system are NSR and that their failure could affect the capability ofSR SSCs to perform their safety function; therefore, they are within the scope of license renewal, in accordance with 10 CFR 54.4(a)(2). License renewal drawing LR-36256, Note 2, also states that the spent fuel pool liner is within the scope of license renewal as part of the reactor building structure. This spent fuel pool liner interfaces with the weirs and their associated connecting surface, FPC system, and fuel pool drains. License renewal drawingLR-36256 at location D-2 shows the adjustable weir and associated connecting surfaces to the south skimmer surge tank, T-48B, to be within the scope of license renewal. License renewal drawing LR-36256 at location D-4 shows similar components, the adjustable weir and connecting surfaces to the north skimmer surge tank, T-48A, as not within the scope of license renewal. Therefore, the staff requested that the applicant clarify whether the adjustable weirand associated connecting surfaces to the north skimmer surge tank, T-48A, at location D-4 are within the scope of license renewal and subject to an AMR, in accordance with the applicable requirements of 10 CFR 54.4(a) and 10 CFR 54.21(a), respectively, or justify their exclusion.In its response, by letter dated October 14, 2005, the applicant stated that only those portionsof skimmer surge tanks T-48A and T-48B not embedded in concrete are within the scope of license renewal. The adjustable weir is an NSR component located inside the concrete wall adjacent to the spent fuel pool. Its failure could not affect the intended function of SR SSCs.

The adjustable weir for the south skimmer surge tank T-48B was shown incorrectly as within the scope of license renewal. In addition, the adjustable weir for the south skimmer surge tankT-48B is not within the scope of license renewal; however, the connecting portion of skimmer tank T-48A at location D-3 is within the scope of license renewal from the skimmer tank up to the concrete wall.Based on its review, the staff found the applicant's response to RAI 2.3.3.10-1 acceptablebecause failure of the components embedded in concrete could not affect the intended function of SR SSCs and therefore are outside the scope of license renewal. In addition, the applicant added the connecting portion of skimmer tank T-48A from the skimmer tank up to the concrete wall to the scope of license renewal; therefore, the staff's concern described in RAI 2.3.3.10-1is resolved.In RAI 2.3.3.10-2, dated September 16, 2005, the staff noted, as shown on license renewaldrawing LR-36256 at location D-4, that diffusers A and B serve as a distribution point for returning cooling water for the FPC system to the fuel storage pool. Their failure could affectthe capability of SR SSCs to perform their safety function; therefore, the staff requested thatthe applicant justify why these diffusers are not within the scope of license renewal.In its response, by letter dated October 14, 2005, the applicant stated that the FPC system iswithin the scope of license renewal only because it contains NSR components which must 2-73maintain sufficient integrity to prevent spray, leakage, or spatial interaction from affectingintended functions of the SR SSCs adversely. The diffusers are located underwater (spent fuel pool) and the failure of these NSR diffusers would not affect SR SSC intended functions. The diffusers are, therefore, not within the scope of license renewal.Based on its review, the staff found the applicant's response to RAI 2.3.3.10-2 acceptablebecause the diffusers are not FPC system components that could affect the capability of SRSSCs to perform their safety function and, therefore, are not within the scope of license renewal; therefore, the staff's concern described in RAI 2.3.3.10-2 is resolved.In RAI 2.3.3.10-3, dated September 16, 2005, the staff determined that license renewal drawingLR-36256 shows an unisolable pipe (FPW17B-3"-MR) between the fuel storage pool and the skimmer surge tank, T-48B, as not within the scope of license renewal. All other piping and components entering the skimmer tank within the same apparent area of the plant are shownas within the scope of license renewal. Failure of this unisolable section of pipe could affect the intended license renewal pressure boundary function for the skimmer tank; therefore, the staffrequested that the applicant justify why this pipe is not included within the scope of licenserenewal.In its response, by letter dated October 14, 2005, the applicant stated that only the connectingportions of both of the skimmer surge tanks, T-48A and T-48B, not embedded in concrete are within the scope of license renewal. Pipe FPW17B-3"-MR is located along side the spent fuel pool and is embedded in concrete. It drains the wave suppression scupper into the portion of the skimmer surge tank embedded in concrete. This NSR component could not impact the intended function of SR SSCs and, therefore, is not within the scope of license renewal.Based on its review, the staff found the applicant's response to RAI 2.3.3.10-3 acceptablebecause pipe FPW17B-3"-MR is embedded in concrete and the failure of this NSR component could not impact the intended function of SR SSCs; therefore, the staff's concern described in RAI 2.3.3.10-3 is resolved.The staff's review of LRA Section 2.3.3.10 identified areas in which information provided in theLRA needed to be verified by the NRC Regional Inspection Team to complete the review of theapplicant's scoping and screening results.Inspection Item 2.3.3.10-1License renewal drawing LR-36256 at locations D-4 and D-2 does not clearly defi ne the systemboundaries between the fuel storage pool and the FPC system and between the fuel storagepool and the fuel pool drains and associated piping. The NRC Regional Inspection Teamperformed an inspection to ensure that the license renewal scope boundaries for the above cited systems satisfy the 10 CFR 54.4(a)(2) criterion.The inspection team found that this item addresses the wave suppression scupper, which isembedded in concrete. Detailed drawings for the reactor building and spent fuel pool provided further definition. The applicant recently revised license renewal drawing LR-36256 as a result of RAI 2.3.3.10-3 to better illustrate the wave suppression scupper drain piping. The inspectorsdetermined that the license renewal boundary satisfies the 10 CFR 54.4(a)(2) criterion.Therefore, the staff's concern described in Inspection Item 2.3.3.10-1 is resolved.

2-74Inspection Item 2.3.3.10-2License renewal drawing LR-36256 at location B-3 shows the license renewal scope boundaryfor the pipe FPW13-4"-HB terminating at a nonspecific location on the piping run (between the pipe FPW13-6"-HB and the valve AO-4"-HB). The actual location of the license renewal scope boundary for this pipe is not clear. The NRC Regional Inspection Team performed an inspectionto ensure that the license renewal scope boundary of this pipe satisfies the 10 CFR 54.4(a)(2) criterion.The inspection team confirmed that the license renewal boundary ends as the line enters the985' pump room. There are no SR components within the 985' pump room. P&IDs do not typically show walls and floors. The inspectors determined that the license renewal boundary satisfies the 10 CFR 54.4(a)(2) criteria. Therefore, the staff's concern described in Inspection Item 2.3.3.10-2 is resolved.2.3.3.10.3 Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the FPC system componentsthat are within the scope of license renewal, as required by 10 CFR 54.4(a), and the FPC system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3.11 Heating and Ventilation System 2.3.3.11.1 Summary of Technical Information in the Application In LRA Section 2.3.3.11, the applicant described the heating and ventilation (HTV) system. TheHTV system consists of the equipment required to affect and control the following space-airprocesses-supply and exhaust, distribution and recirculation (where applicable), differential and static pressure control, filtration, and cooling and heating. It also includes sampling and fume hood exhausting and process tank venting. The applicant scoped the reactor building isolation under the secondary containment system. The portion of the HTV system serving theHPCI building and the RHR/CSP corner rooms is within the scope of license renewal; theequipment is designed to provide cool air during normal operation and DBEs. General plant heating is provided by a network of carbon steel pipes originating at the plant heating boiler andextending throughout most of the plant to supply heated water and/or steam to various unit heaters. Three notable locations not directly served are the drywell, offgas storage building, and portions of the plant serviced by the EFT system.The HTV system contains SR components that are relied upon to remain functional during andfollowing DBEs. The failure of NSR SSCs in the HTV system could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the HTV system performs functions that support FP and EQ.The intended functions within the scope of license renewal include the following:

2-75

  • provide filtration
  • provide for heat transfer
  • provide a pressure-retaining boundaryIn LRA Table 2.3.3-11, the applicant identified the following HTV system com ponent types thatare within the scope of license renewal and subject to an AMR:
  • chillers
  • damper/housings
  • ductwork
  • fan/blower/housings
  • fasteners/bolting
  • filters/strainers
  • gauges (flow, level, and sight)
  • heaters/coolers
  • instrumentation
  • piping and fittings
  • pump casings
  • steam traps
  • tanks
  • valve bodies2.3.3.11.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.11 and USAR Sections 5.3.4 and 10.3.1.3.2 using theevaluation methodology described in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.3.3.11 identified an area for which it needed additionalinformation to complete its evaluation of the applicant's scoping and screening results. The applicant responded to the staff's RAI as discussed below.In RAI 2.3.3.11-1, dated September 15, 2005, the staff requested that the applicant clarifywhether all the associated components of "HVAC units," such as ductwork (equipment frames and housing), filters (housing and supports), ventilation seals, cooling coils, and I&C, are within the scope of license renewal, in accordance with 10 CFR 54.4(a), and subject to an AMR, in accordance with 10 CFR 54.21(a)(1).In its response, by letter dated October 14, 2005, the applicant stated the following:

2-76Certain components indicated on the LR boundary drawings for the HTV Systemare in scope to license renewal in accordance with 10 CFR 54.4(a)(1). Certain air conditioners and many of the unit heaters with their associated steam and/or hot water supply lines are in scope to license renewal in accordance with 10 CFR 54.4(a)(2). In addition, certain air handling units and exhaust fans are in scope to license renewal for the Fire Protection and Environmental Qualification regulated events in accordance with 10 CFR 54.4(a)(3). Other components within the HTV System are excluded from the scope of license renewal since they do not perform any license renewal intended function(s).Component groups such as ductwork, filters, instrumentation, etc, that are listedin Table 2.3.3-11 include those associated with the HVAC units within scope for license renewal in accordance with the scoping criteria listed above.Based on its review, the staff found the applicant's response to RAI 2.3.3.11-1 acceptablebecause all applicable associated components of "HVAC units" consisting of ductwork (equipment frames and housing), filters (housing and supports), and instrumentation are within the scope of license renewal, in accordance with 10 CFR 54.4(a), and subject to an AMR, in accordance with 10 CFR 54.21(a)(1); therefore, the staff's concern described in RAI 2.3.3.11-1is resolved.During the scoping inspection, the inspectors identified a 1-inch branch line from HS12-3"-JB toV-RF-1 (including BH-323, ST-9027, and BH-328) that was outside the scope of license renewal on license renewal drawing LR-36259-1. The applicant stated the line was contained under the steel deck plating of the EDG room foyer, effectively isolated from the SR equipment in the EDG room. However, the steam branch line entry point through the steel plating was not a grouted or robust penetration. A break in the line under the deck plating could cause heatingsteam to enter the EDG room, potentially challenging the room ambient temperature to staywithin the maximum allowable temperature for EDG operability. The applicant placed thisportion of piping, along with the two valves and the steam trap, within the scope of license renewal, pursuant to 10 CFR 54.4(a)(2).The inspectors also noted heating steamline HS5-6"-JB from valve BH-316-1 through BH-722on license renewal drawing LR-36664 as outside the scope of license renewal. The inspectors identified a seismic Class I support, SR-389, about 6 feet from BH-316-1 in the section of pipe outside the scope of license renewal. The applicant stated this portion of pipe was determined to be outside the scope of license renewal because it contained air/gas. However, guidance described in NEI 95-10 requires NSR piping attached to SR piping to be within scope up to and including the first equivalent anchor. Seismic Class I support SR-389 is the first equivalent anchor in this line. Therefore, the applicant placed the section of heating steamline HS5-6"-JBbetween valve BH-316-1 and up to and including support SR-389 within the scope of license renewal, pursuant to 10 CFR 54.4(a)(2).2.3.3.11.3 Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its 2-77review, the staff concluded that the applicant adequately identified the HTV system componentsthat are within the scope of license renewal, as required by 10 CFR 54.4(a), and the HTV system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3.12 Instrument and Service Air System 2.3.3.12.1 Summary of Technical Information in the Application In LRA Section 2.3.3.12, the applicant described the AIR system. The AIR system is designedto provide the plant with a continuous supply of oil-free compressed air. The instrument air portion of the system supplies dried compressed air for most of the pneumatic instruments andcontrols in the plant. The service air portion of the system supplies undried service air to plantcomponents that do not require dry air and to hose stations throughout the plant formiscellaneous use by maintenance and operations personnel. The AIR system includes threenonlubricated air compressors that discharge to air receivers through aftercoolers with moisture separator/traps. The AIR system is normally in continuous operation during normal plantoperation and shutdown. In addition to the AIR system, the plant includes other pneumaticsystems. The other pneumatic systems comprise an outboard main steam isolation valve airsupply which is part of the MST system, an AN2 system which is a separate mechanicalsystem, an instrument nitrogen supply to containment which is part of the primary containmentmechanical system, and the control room breathing air system which is part of the EFT system.The AN2 system interfaces with the AIR system through a check valve, with the nitrogen sideheld at a slightly lower pressure to allow the AIR system to be used during normal operation. Inthe event of an accident, which also disables the AIR system, the AN2 system would automatically pick up the required pneumatic loads.The AIR system contains SR components that are relied upon to remain functional during andfollowing DBEs. The failure of NSR SSCs in the AIR system could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the AIR system performs functions that support EQ.The intended function, within the scope of license renewal, is to provide a pressure-retainingboundary.In LRA Table 2.3.3-12, the applicant identified the following AIR system com ponent types thatare within the scope of license renewal and subject to an AMR:

  • fasteners/bolting
  • gauges (flow, level, and sight)
  • piping and fittings
  • pump casings
  • tanks
  • valve bodies2.3.3.12.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.12 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.

2-78In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.3.3.12 identified an area in which information provided inthe LRA needed to be verified by the NRC Regional Inspection Team to complete the review ofthe applicant's scoping and screening results.Inspection Item 2.3.3.12-1License renewal drawing LR-36049-10 at locations D-6 and B-6 have line continuations (airlines upstream of valves AI-704 and AI-715) outside the scope of license renewal to LR-36049-12 at location B-6. The actual locations of the license renewal scope boundaries of these components are not clear. The NRC Regional Inspection Team performed an inspectionto ensure that the license renewal scope boundaries of these components satisfy the 10 CFR 54.4(a)(2) criterion.License renewal drawing LR-36049-10 shows stainless steel instrument air lines at locationsD-6 and B-6 (air lines upstream of valves AI-704 and AI-715). These lines continue to LR-36049-12 at location B-6 where they join via a "T" to form one line and then continue to the vertical header shown on the drawing. Between the "T" joining these lines and the connection to the main vertical header, the line transitions from stainless steel to copper. This transition is the license renewal scoping boundary. The applicant will revise license renewal drawingLR-36049-12 to show the continuation text to license renewal drawing LR-36049-10 and the piping up to the stainless steel/copper transition point (located between the "T" and the verticalheader) as being within the scope of license renewal. In addition, license renewal drawing LR-36049-10 at locations D-6 and B-6 will be revised to show the continuation to licenserenewal drawing LR-36049-12 as being within the scope of license renewal. The inspectors determined that the license renewal boundary satisfies the 10 CFR 54.4(a)(2) criterion.Therefore, the staff's concern described in Inspection Item 2.3.3.12-1 is resolved.2.3.3.12.3 Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the AIR system componentsthat are within the scope of license renewal, as required by 10 CFR 54.4(a), and that theapplicant adequately identified the AIR system components that are subject to an AMR, asrequired by 10 CFR 54.21(a)(1).

2-792.3.3.13 Radwaste Solid and Liquid System2.3.3.13.1 Summary of Technical Information in the Application In LRA Section 2.3.3.13, the applicant described the radwaste solid and liquid (RAD) system.The RAD system contains the solid radwas te subsystem and the liquid radwaste subsystem.The solid radwaste system is designed to process, package, store, monitor, and provideshielded storage facilities for solid radioactive wastes to allow for radioactive decay and/ortemporary storage before shipment for offsite disposal. The liquid radwaste s ubsystem isdesigned to collect, process, and dispose of all radioactive liquid wastes generated during operation of the plant. The system is designed to accommodate the radioactive input resultingfrom the design-basis maximum fuel leakage condition. Either filtration or filtration followed by mixed deep-bed demineralization is used to remove the radioactive and chemical contaminants from the liquid waste streams. The filters remove insoluble particulate contaminants and the demineralizer is used to remove soluble materials. The filter and demineralizer sludge are backwashed into receiving tanks, dewatered, and packaged as solid waste for disposal off site at NRC-approved sites.The RAD system contains SR components that are relied upon to remain functional during andfollowing DBEs. The failure of NSR SSCs in the RAD system could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the RAD system performs functions that support EQ.The intended functions within the scope of license renewal include the following:

  • provide flow restriction
  • provide a pressure-retaining boundary
  • provide structural support to NSR components (mechanical)In LRA Table 2.3.3-13, the applicant identified the following RAD system com ponent types thatare within the scope of license renewal and subject to an AMR:
  • fasteners/bolting
  • heat exchangers
  • piping and fittings
  • pump casings
  • restricting orifices
  • tanks
  • valve bodies2.3.3.13.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.13 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions 2-80delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.3.3.13 identified areas for which it needed additionalinformation to complete its evaluation of the applicant's scoping and screening results. The applicant responded to the staff's RAIs as discussed below.In RAI 2.3.3.13-1, dated September 16, 2005, the staff noted that the following cases representunisolable piping defined as outside the scope of license renewal; however, the piping is attached or interfaces with components defined as within the scope of license renewal that perform a pressure-boundary function. Failure of these components outside the scope of license renewal could adversely impact the intended pressure-boundary function of components within the scope of license renewal; therefore, the staff requested that the applicant justify theexclusion of the following unisolable components from the scope of license renewal:
  • License renewal drawing LR-36043 at location C-6 shows a 3-inch vent line on the topof machine shop drain tank T-103.
  • License renewal drawing LR-36043 at location C-6 shows a 4-inch vent line on the topof reactor building floor drain sump S-37.
  • License renewal drawing LR-36043 at location C-6 shows line RWN46-4"-MR enteringthe reactor building floor drain sump S-37 from the equipment drain sump S-42 overflow.
  • License renewal drawing LR-36043 at location C-3 shows a 4-inch vent line on the topof drywell floor drain sump S-38.
  • License renewal drawing LR-36044 at location C-2 shows a 4-inch vent line on the topof drywell equipment drain sump S-43.
  • License renewal drawing LR-36044 at location C-2 shows a 4-inch vent line on the topof drywell equipment drain sump S-43.
  • License renewal drawing LR-36044 at location A-3 shows a 4-inch vent line on the top ofturbine building normal waste sump S-45.
  • License renewal drawing LR-36044 at location C-5 shows piping to an obsolete sensingline on the top of reactor building equipment drain tank T-56.
  • License renewal drawing LR-36044 at location A-5 shows a 4-inch vent line and pipingto an obsolete sensing line on the top of the condensate drip tank T-22.
  • License renewal drawing LR-36044 at location A-7 shows 4-inch vent line andRWN48-4"-MR exiting the turbine building equipment drain sump S-44.
  • License renewal drawing LR-36044 at location C-7 shows 4-inch vent line andRWN46-4"-MR exiting the reactor building equipment drain sump S-42.In its response, by letter dated October 14, 2005, the applicant stated that the vent lines for thedrain tanks, floor drain sumps, equipment drain tanks, normal waste sumps, drip tanks, and 2-81equipment drain sumps are NSR, open to the atmosphere, and not relied upon for a pressureboundary. Their failure would not adversely affect the intended function of SR SSCs.

Piping RWN46-4"-MR and RWN48-4"-MR are embedded in concrete and act as overflows between sumps. This piping is NSR and its failure could not impact the intended function of SR SSCs. The sensing lines located on top of the tanks for level indication are filled with air. These sensing lines are NSR and their failure could not impact the intended function of SR SSCs.Based on its review, the staff found the applicant's response to RAI 2.3.3.13-1 acceptablebecause (1) the vent lines are open to the atmosphere and not relied upon for a pressure boundary, (2) piping RWN46-4"-MR and RWN48-4"-MR are embedded in concrete, and (3) the sensing lines located on top of the tanks for level indication are filled with air. The vent lines, piping RWN46-4"-MR and RWN48-4"-MR, and sensing lines are all NSR. Their failure could not impact the intended function of SR SSCs and, thus, are not within the scope of license renewal.

Therefore, the staff's concern described in RAI 2.3.3.13-1 is resolved.In RAI 2.3.3.13-2, dated September 16, 2005, the staff determined that license renewal drawingLR-36044 at location D-7 identified a 10 CFR 54.4(a)(2) boundary for the RAD system as thesection of piping before a normally open isolation valve, CRW-1, which is outside the scope of license renewal, from the CST overflow tank T-67. Failure of the unisolable piping could adversely impact the license renewal pressure-boundary function for the radwaste solid and liquid system; therefore, the staff requested that the applicant justify the location of the licenserenewal scope boundary at valve CRW-1, in accordance with the requirements of 10 CFR 54.4(a).In its response, by letter dated October 14, 2005, the applicant stated that NSR valve CRW-1 islocated outside the reactor building near the CST tanks. The piping connecting to valve CRW-1, which is shown within the scope of license renewal, is located inside the HPCl building, which houses SR components. Failure of this connecting piping could impact the intended function of SR SSCs. Failure of valve CRW-1 located outside the building could not impact the intended function of SR SSCs; therefore, valve CRW-1 and the connecting piping to the CST overflow tank T-67 are not within the scope of license renewal.Based on its review, the staff found the applicant's response to RAI 2.3.3.13-2 acceptablebecause CRW-1 and the connecting piping are located outside the building and could not impact the intended function of SR SSCs, and as such, are not within the scope of license renewal. Therefore, the staff's concern described in RAI 2.3.3.13-2 is resolved.In RAI 2.3.3.13-3, dated September 16, 2005, the staff noted that license renewal drawingsLR-36044 at locations A-7, C-7, C-3, and A-3 and LR-36043 at locations A-6, A-5, C-6, and C-3show the turbine building equipment drain sump (S-44), reactor building equipment drain sump (S-42), drywell equipment drain sump (S-43), turbine building normal waste sump (S-45),

condensate pump area sump (S-53), turbine building floor drain sump (S-40), reactor floor drain sump (S-37), and drywell floor drain sump (S-38) as not within the scope of license renewal.

LRA Section 2.3.3.13 states that all radwaste solid and liquid system components in either theturbine or reactor buildings, and constituting a liquid pressure boundary, are within the scope of license renewal. Failure of the liners for these sumps can negatively impact the intended liquid pressure-boundary functions of the components; therefore, the staff requested that theapplicant clarify whether the sumps and their associated liners are within the scope of license 2-82renewal and subject to an AMR, in accordance with the requirements of 10 CFR 54.4(a) and10 CFR 54.21(a), respectively, or justify their exclusion.In its response, by letter dated October 14, 2005, the applicant stated that the nonlined sumpsare NSR, embedded in concrete, and at the lowest elevations of the turbine and reactor buildings. Their failure could not impact the intended function of SR SSCs and they are not within the scope of license renewal.Based on its review, the staff found the applicant's response to RAI 2.3.3.13-3 acceptablebecause the nonlined sumps embedded in concrete are NSR, located at the lowest elevations of the turbine and reactor buildings, and their failure could not impact the intended function of SR SSCs. As such, they are not within the scope of license renewal; therefore, the staff's concern described in RAI 2.3.3.13-3 is resolved.The staff's review of LRA Section 2.3.3.13 identified areas in which information provided in theLRA needed to be verified by the NRC Regional Inspection Team to complete the review of theapplicant's scoping and screening results.Inspection Item 2.3.3.13-1License renewal drawing LR-36043 shows a 1.5-inch line at location B-1 within the scope oflicense renewal for the RAD system. The drawing specifies the line continues at location E-3,but license renewal drawing LR-36043 has no location E-3. Consequently, the actual location of the license renewal scope boundary for this line is not clear. The NRC Regional InspectionTeam performed an inspection to ensure that the license renewal scope boundary for this line satisfies the 10 CFR 54.4(a)(2) criterion.The applicant determined license renewal drawing LR-36043 requires revision to change thecontinuation of this line from coordinates E-3 to D-4. The NRC Regional Inspection Teamverified the accuracy of the corresponding plant P&ID (-137) as currently drawn. The inspectors determined that the license renewal boundary satisfies the 10 CFR 54.4(a)(2)criterion. Therefore, the staff's concern described in Inspection Item 2.3.3.13-1 is resolved.Inspection Item 2.3.3.13-2License renewal drawing LR-36043 shows piping RWN12-4"-HC at location C-4 as within thescope of license renewal continuing to an undefined location. The actual location of the license renewal scope boundary for this pipe is not clear. The NRC Regional Inspection Teamperformed an inspection to ensure that the license renewal scope boundary for this pipe satisfies the 10 CFR 54.4(a)(2) criterion.The applicant will revise license renewal drawing LR-36043 to show the continuation of thedrainline, RWN12-4"-HC, to license renewal drawing LR-36044, reactor building equipment drain sump, S-42. The applicant will revise license renewal drawing LR-36044 to show thedrains from the reactor building floor drain tank, T-55, as one of the lines discharging into the reactor building equipment drain sump, S-42. The drainline is within the scope of license renewal, pursuant to 10 CFR 54.4(a)(2). The inspectors determined that the license renewal boundary satisfies the 10 CFR 54.4(a)(2) criteria. Therefore, the staff's concern described in Inspection Item 2.3.3.13-2 is resolved.

2-83Inspection Item 2.3.3.13-3License renewal drawing LR-36044 at location B-1 shows the boundary for license renewalterminating at the unisolable junction of piping from the EDG room 11 floor drain to the flow controller just downstream of check valve NW-7. Failure of the unisolable piping can adversely impact the license renewal pressure-boundary function for the RAD system. The NRC Regi onalInspection Team performed an inspection to ensure that the license renewal scope boundary for this component satisfies the 10 CFR 54.4(a)(2) criterion.The inspection team determined that valves NW-7, 8, and 9 are FP-related, with each pipeconnection buried in concrete, although not shown on the drawing. The buried pipe acts as the anchor, therefore the boundary terminates at that point. The inspectors determined that thelicense renewal boundary satisfies the 10 CFR 54.4(a)(2) criterion. Therefore, the staff's concern described in Inspection Item 2.3.3.13-3 is resolved.Inspection Item 2.3.3.13-4License renewal drawing LR-36045 shows several lines entering the drawing from other sheets,RWN20-4"-HC (at location D-8), RWN5-3"-HC (at location D-8), RWN36-3"-HC (at location D-8), FPW13-4"-HP (at location B-8), TW37-4"-HC (at location B-8), SC15-3"-HB (at location D-7), and SC25-3"-HB (at location C-5) as within the scope of license renewal; however, for each of these lines, the boundary terminates at a nonspecific location on license renewal drawing LR-36045. The NRC Regional Inspection Team performed an inspection toensure that the license renewal scope boundaries for the cited components satisfy the10 CFR 54.4(a)(2) criterion.During walkdowns, the inspection team verified that the NSR piping enters the radwastebuilding or the 985' pump room and is, therefore, not within the scope of license renewal. Thereare no SR components in the radwaste building or the 985' pump room, and P&IDs do not typically depict walls. The applicant will revise license renewal drawing LR-36045 to change linenumbers RWN20-4"-HC (at location D-8), RWN5-3"-HC (at location D-8), FPW13-4"-HP (at location B-8), SC15-3"-HB (at location D-7), and SC25-2"-HB (at location C-5) from within the scope of license renewal to outside the scope of license renewal. The continuation drawings already show the transition into the radwaste building or the 985' pump room.The applicant will revise license renewal drawing LR-36044 to extend the wall at location B-1 toencompass line RWN5-3"-HC and to show the transition into the 985' pump room at the wall.

The license renewal boundary ends as the piping enters the 985' pump room.Line number TW37-4"-HC (at location B-8) on license renewal drawing LR-36045 has beenverified by walkdown and shows the transition to be where the line enters the radwaste building wall. The applicant will revise license renewal drawing LR-36045 to change the portion of thisline to outside the scope of license renewal. The applicant will also revise license renewaldrawing LR-36247 (at location C-4) to show the transition of this line through the radwaste building wall. The inspectors determined that the license renewal boundary satisfies the 10 CFR 54.4(a)(2) criteria. Therefore, the staff's concern described in Inspection Item 2.3.3.13-4 is resolved.Inspection Item 2.3.3.13-5 2-84License renewal drawing LR-36046 shows several lines entering the drawing from other sheets,turbine building floor sump drain (at location D-8), drywell and reactor building floor drain sump (at location D-8), machine shop drain (at location B-8), laboratory drain (at location B-8),

laundry drain waste (at location B-4), and machine shop drain (at location B-4), as within the scope of license renewal; however, for each of these lines, the license renewal scope boundary terminates at a nonspecific location on license renewal drawing LR-36046. The NRC Regi onalInspection Team performed an inspection to ensure that the license renewal scope boundaries for the cited components satisfy the 10 CFR 54.4(a)(2) criterion.The inspection team determined that the boundaries end as the lines enter the radwastebuilding wall (locations B-8 & D-8) or 985' pump room wall (location B-4). There are no SR components in the radwaste building or the 985' pump room. P&IDs at MNGP do not typically depict walls. The applicant will revise license renewal drawing LR-36046 (at location D-8) toshow lines RWN19-4"-HC and RWN8-3"-HC outside the scope of license renewal since the scoping boundary ends as the pipes enter the wall, which is already shown on LR-36043 (at location B-1). The inspectors determined that the license renewal boundary satisfies the 10 CFR 54.4(a)(2) criterion. Therefore, the staff's concern described in Inspection Item 2.3.3.13-5 is resolved.Inspection Item 2.3.3.13-6License renewal drawing LR-36241 at location D-7 shows a 1" line, V15-1"-HB, within the scopeof license renewal exiting to license renewal drawing LR-36049-12 at location D-5. Continuation of V15-1"-HB is not shown on license renewal drawing LR-36049-12 at the location specified.

The NRC Regional Inspection Team performed an inspection to ensure that the license renewalscope boundary for this line satisfies the 10 CFR 54.4(a)(2) criterion.The inspection team determined the continuation to license renewal drawing LR-36049-12,shown on license renewal drawing LR-36241, is for the instrument air system and should beshown as outside the scope of license renewal. The applicant will revise license renewaldrawing LR-36241 to change the continuation to license renewal drawing LR-36049-12 from within scope to outside the scope of license renewal.In addition, the applicant will revise license renewal drawing LR-36241 to show that lineV15-1"-HB discharges to the drywell equipment drain sump, S- 43, on license renewal drawing LR-36044. The applicant will also revise license renewal drawing LR-36044 to show the"Reactor Head Vent" as one of the drains discharging into the drywell equipment drain sump, S-43. The inspectors determined that the license renewal boundary satisfies the 10 CFR 54.4(a)(2) criterion. Therefore, the staff's concern described in Inspection Item 2.3.3.13-6 is resolved.Inspection Item 2.3.3.13-7Treated/processed and sampled liquid wastes collected in sumps and drain tanks in variousbuildings may be returned to the CSTs via the appropriate waste sample pump (P-36A or P-36B) and effluent transfer line C19-3"-HS. A portion of this line is shown as within the scope of license renewal on the license renewal drawings LR-36039 at location A-3 and LR-36045 at location B-1; however, the license renewal scope boundaries terminate in the middle of the pipe runs (at the junctions of lines C19-3"-HS and DW17-3"-HS and C19-3"-HS and SC16-10"-HB).

2-85The actual locations of the license renewal scope boundaries for these components are notclear. The NRC Regional Inspection Team performed an inspection to ensure that the licenserenewal scope boundaries for these components satisfy the 10 CFR 54.4(a)(2) criterion.The inspection team determined that this line is within the scope of license renewal, pursuant tothe 10 CFR 54.4(a)(2) criteria, as an equivalent anchor (buried piping). The in-scope boundary begins where the pipe connects to line SC16-10"-HK on LR-36039 (at location B-4) and extends to the radwaste building floor. There are no SR components in the radwaste building.

All P&IDs do not typically depict walls. The inspectors determined that the license renewal boundary satisfies the 10 CFR 54.4(a)(2) criterion. Therefore, the staff's concern described in Inspection Item 2.3.3.13-7 is resolved.2.3.3.13.3 Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the RAD systemcomponents that are within the scope of license renewal, as required by 10 CFR 54.4(a), and that the applicant adequately identified the RAD system components that are subject to anAMR, as required by 10 CFR 54.21(a)(1).2.3.3.14 Reactor Building Closed Cooling Water System 2.3.3.14.1 Summary of Technical Information in the Application In LRA Section 2.3.3.14, the applicant described the reactor building closed coolingwater (RBC) system. The RBC system is a treated water system designed to remove heat fromthe reactor auxiliary systems' equipment. The RBC system consists of a closed cooling waterloop containing two pumps and three heat exchangers in parallel, and the associated piping, valves, and instrumentation. The system temperature is maintained by heat rejection from theRBC system heat exchangers to the service and seal water system. The RBC system ismonitored continuously for radioactivity by a process radiation monitor (PRM). An increase in the radiation level would indicate leakage of contaminated water into the RBC system. Leakagemay also be indicated by a level change in the RBC system surge tank with no associatedreactor power change, equipment change, or makeup water addition. Any potential leakage from the reactor auxiliary systems' equipment is to the RBC system closed loop where it isconfined or isolated.The RBC system contains SR components that are relied upon to remain functional during andfollowing DBEs. The failure of NSR SSCs in the RBC system could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the RBC system performs functions that support EQ.The intended function, within the scope of license renewal, is to provide a pressure-retainingboundary.

2-86In LRA Table 2.3.3-14, the applicant identified the following RBC system com ponent types thatare within the scope of license renewal and subject to an AMR:

  • fasteners/bolting
  • flexible connections
  • flow element
  • gauges (flow, level, and sight)
  • heat exchangers
  • piping and fittings
  • pump casings
  • tanks
  • thermowells
  • valve bodies2.3.3.14.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.14 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.3.3.14.3 Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs thatshould be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the RBC systemcomponents that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the RBC system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3.15 Reactor Water Cleanup System 2.3.3.15.1 Summary of Technical Information in the Application In LRA Section 2.3.3.15, the applicant described the reactor water cleanup (RWC) system. TheRWC system is a filtering and ion e xchange system that maintains water purity in the reactorand recirculation lines during all modes of plant operation. This minimizes changes in the core heat transfer characteristics by reducing the deposition of impurities on fuel surfaces by reducing the amount of waterborne impurities in the reactor primary system. It also reducessources of beta and gamma radiation by removing corrosion products, fission products, and 2-87impurities in the reactor primary system. The RWC system provides for primary containmentisolation and is also isolated on initiation of the SLC system. The RWC system provides forcontinuous purification of a portion of the REC system flow with a minimum of heat loss andwater loss from the cycle.The RWC system contains SR components that are relied upon to remain functional during andfollowing DBEs. The failure of NSR SSCs in the RWC system could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the RWC system performs functions that support EQ and ATWS.The intended function, within the scope of license renewal, is to provide a pressure-retainingboundary.In LRA Table 2.3.3-15, the applicant identified the following RWC system com ponent types thatare within the scope of license renewal and subject to an AMR:
  • fasteners/bolting
  • flow element
  • heat exchangers
  • piping and fittings
  • pump casings
  • restricting orifices
  • thermowells
  • valve bodies2.3.3.15.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.15 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.3.3.13 identified an area for which it needed additionalinformation to complete its evaluation of the applicant's scoping and screening results. The applicant responded to the staff's RAI as discussed below.In RAI 2.3.3.15-1, dated September 16, 2005, the staff noted that license renewal drawingLR-36254 at location C-8 contained two references (line REW3-4" EBD from REC loop B and line REW31-2"-ED from reactor vessel drain) to license renewal drawing LR-36243 at location C-5; however, license renewal drawing LR-36243 only shows one reference (line REW31-2"-ED which is also capped) to license renewal drawing LR-36254. Therefore, the staff requested that 2-88the applicant clarify this discrepancy and confirm which portions of the piping are within thescope of license renewal and subject to an AMR, in accordance with the requirements of 10 CFR 54.4(a) and 10 CFR 54.21(a), respectively, or justify their exclusion.In its response, by letter dated October 14, 2005, the applicant clarified the drawing annotationsshowing the convergence of the two lines REW3-4"-EBD and REW31-2"-ED on license renewal drawing LR-36243 grid location C-6. The extension of line REW3-4"-EBD is shown as a dashed line on license renewal drawing LR-36243, instructing the reviewer to look at license renewal drawing LR-36254 for the details on that pipe. The applicant confirmed that the drawings werecorrect and that both lines are within the scope of license renewal and subject to an AMR, in accordance with the requirements of 10 CFR 54.4(a) and 10 CFR 54.21(a), respectively.Based on its review, the staff found the applicant's response to RAI 2.3.3.15-1 acceptablebecause the applicant confirmed that the lines are within the scope of license renewal;therefore, the staff's concern discussed in RAI 2.3.3.15-1 is resolved.The staff's review of LRA Section 2.3.3.15 identified an area in which information in the LRAneeded to be verified by the NRC Regional Inspection Team to complete the review of theapplicant's scoping and screening results.Inspection Item 2.3.3.15-1License renewal drawing LR-36254 at location B-8 shows two RWN36-3"-HC lines as within thescope of license renewal. One continues to waste collector tank, T-24, shown in license renewal drawing LR-36045, and one continues to waste surge tank, T-23, also shown in license renewal drawing LR-36045; however, the license renewal scope boundaries for these lines terminate in the middle of the pipe runs. The actual locations of the license renewal scope boundaries for these lines are not clear. The NRC Regional Inspection Team performed an inspection toensure that the license renewal scope boundaries for these lines satisfy the 10 CFR 54.4(a)(2)criterion.The inspection team conducted walkdowns, which confirmed that the two RWN36-3"-HC linespass into the 985' pump room and the radwaste building. There are no SR components in the 985' pump room or the radwaste building. The applicant will revise license renewal drawingLR-36045 to change the two RWN36-3"-HC lines (at location D-8) to outside the scope of license renewal. The continuation license renewal drawing LR-36254 will show the transitioninto the 985' pump room. The inspectors determined that the license renewal boundaries satisfy the 10 CFR 54.4(a)(2) criterion. Therefore, the staff's concern described in Inspection Item 2.3.3.15-1 is resolved.2.3.3.15.3 Conclusion The staff reviewed the LRA to determine whether the applicant failed to identify any SSCs thatshould be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the RWC system components that arewithin the scope of license renewal, as required by 10 CFR 54.4(a), and the RWC systemcomponents that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2-892.3.3.16 Service and Seal Water System2.3.3.16.1 Summary of Technical Information in the Application In LRA Section 2.3.3.16, the applicant described the service and seal water (SSW) system. TheSSW system supplies screened and strained cooling water (raw water from the MississippiRiver) to various nonessential plant heat loads and services during all modes of operation. The service water portion of the SSW system consists of three 50-percent capacity service waterpumps, an auto strainer, a bypass basket strainer and associated valves, piping, and instrumentation. Normally two service water pumps are in operation and one service water pump is in auto-standby; however, during cold winter months, only one service water pump is required. The seal water portion of the SSW system provides filtered well water (service waterserves as backup to the well water) to the shaft seals for various pumps, including the service water pumps, RSW pumps, and the CWT pumps. The seal water portion consists of two pumps, two filters, and associated valves, piping, and instrumentation. The service water pumps take suction from the pump suction bay in the intake structure and discharge to the turbine building through the intake structure access tunnel. Service water is used to remove heat from various heat exchangers and coolers located in the reactor building and turbine building. The SSW system also supplies water to the sodium hypochlorite s ubsystem (part ofthe CWT system) and the fire system jockey pump. Service water flow is returned to the river.The SSW system is normally in service during plant operation and shutdown.The failure of NSR SSCs in the SSW system could potentially prevent the satisfactoryaccomplishment of an SR function of SSCs within the scope of license renewal. The SSW system also performs functions that support FP.The intended functions within the scope of license renewal include the following:

  • provide flow restriction
  • provide a pressure-retaining boundaryIn LRA Table 2.3.3-16, the applicant identified the following SSW system com ponent types thatare within the scope of license renewal and subject to an AMR:
  • expansion joints
  • fasteners/bolting
  • filters/strainers
  • gauges (flow, level, and sight)
  • heat exchangers
  • piping and fittings
  • pump casings
  • restricting orifices
  • thermowells
  • valve bodies 2-902.3.3.16.2 Staff EvaluationThe staff reviewed LRA Section 2.3.3.16 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.3.3.16 identified an area in which information in the LRAneeded to be verified by the NRC Regional Inspection Team to complete the review of theapplicant's scoping and screening results.Inspection Item 2.3.3.16-1License renewal drawing LR-36665 at location D-7 shows the line SW21-6"-JF, which continuesto the sodium hypochlorite system shown in license renewal drawing LR-36666, as within thescope of license renewal with the license renewal scope boundary terminating in the middle of the pipe run (downstream of the valve SW-10-6"-54); however, license renewal drawing LR-36666 at location C-6 shows the continuation of the line SW21-6"-JF as within the scope of license renewal and defines the boundary for license renewal at check valve SHC-26.

The actual location of the license renewal scope boundary for this pipe is not clear. The NRC Regional Inspection Team performed an inspection to ensure that the license renewal scope boundary for this pipe satisfies the 10 CFR 54.4(a)(2) criterion.The inspection team confirmed through a walkdown that the line SW21-6"-JF passes through aconcrete ceiling in the intake structure, which acts as the scoping boundary. All P&IDs do not typically depict ceilings. The inspectors determined that the license renewal boundary satisfiesthe 10 CFR 54.4(a)(2) criterion. Therefore, the staff's concern described in Inspection Item 2.3.3.16-1 is resolved.2.3.3.16.3 Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the SSW systemcomponents that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the SSW system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2-912.3.3.17 Standby Liquid Control System2.3.3.17.1 Summary of Technical Information in the Application In LRA Section 2.3.3.17, the applicant described the SLC system. The MNGP licensing basisincludes the SLC system as an ESF system. This section, as well as the related agingmanagement section, includes the SLC system for consistency with the SRP-LR and GALLReport. The SLC system provides a means of inserting negative reactivity into the reactor coreby the injection of neutron-absorbing boron in the form of liquid sodium pentaborate. A key lockswitch that starts the SLC system pumps and opens the squib-operated valves provides controlof injection. The boron solution is capable of shutting down the reactor and providing a sufficient shutdown margin to overcome void and temperature coefficients, as well as the effects of xenon, assuming that none of the withdrawn control rods can be inserted. Service airand demineralized water are provided to the SLC tank for mixing of the boron solution, as well as instrument air to various instrumentation.The SLC system contains SR components that are relied upon to remain functional during andfollowing DBEs. The failure of NSR SSCs in the SLC system could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the SLC system performs functions that support ATWS.The intended function, within the scope of license renewal, is to provide a pressure-retainingboundary.In LRA Table 2.3.3-17, the applicant identified the following SLC system com ponent types thatare within the scope of license renewal and subject to an AMR:

  • fasteners/bolting
  • piping and fittings
  • pump casings
  • tanks
  • thermowells
  • valve bodies2.3.3.17.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.17 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).

2-922.3.3.17.3 ConclusionThe staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the SLC system componentsthat are within the scope of license renewal, as required by 10 CFR 54.4(a), and the SLC system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.3.18 Wells and Domestic Water System 2.3.3.18.1 Summary of Technical Information in the Application In LRA Section 2.3.3.18, the applicant described the wells and domestic water (WDW) system.The WDW system includes the domestic water, sanitary sewer, acid drain, storm drain, andturbine building normal drain subsystems as described below. The domestic water subsystemsupplies well water to the demineralized water system, the service and seal water system, hotand/or cold water to lavatories, the laundry, and showers throughout the plant's protected area.The sanitary sewer subsystem removes wastewater from lavatories, showers, and sinks in theprotected area, site administration building, and warehouse No. 5. It carries the wastewater tothe city of Monticello sew age system. The acid drain subsystem removes water from suchthings as the demineralized water system area drain and heating boiler blowdown, which is unfitfor direct discharge to the river. Drainage from these sources is carried to the discharge retention basin where it is treated and monitored before release to the river. The storm drain subsystem carries water from building roofs and normal surface drainage to the river. Theturbine building normal drain subsystem removes water from areas in the turbine building wherethere is no potential for radioactive contamination and transports it to the river.The failure of NSR SSCs in the WDW system could potentially prevent the satisfactoryaccomplishment of an SR function of SSCs within the scope of license renewal. The WDW system also performs functions that support FP.The intended function, within the scope of license renewal, is to provide a pressure-retainingboundary.In LRA Table 2.3.3-18, the applicant identified the following WDW system component typesthat are within the scope of license renewal and subject to an AMR:

  • fasteners/bolting
  • piping and fittings
  • pump casings
  • valve bodies2.3.3.18.2 Staff Evaluation The staff reviewed LRA Section 2.3.3.18 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.

2-93In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.3.3.18.3 Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the WDW systemcomponents that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the WDW system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.4 Steam and Power Conversion System In LRA Section 2.3.4, the applicant identified the SCs of the steam and power conversionsystem that are subject to an AMR for license renewal.The applicant described the supporting SCs of the steam and power conversi on system in thefollowing sections of the LRA:

  • 2.3.4.1c ondensate storage system
  • 2.3.4.3main condenser system
  • 2.3.4.4main steam system
  • 2.3.4.5turbine generator systemSER Section 2.3.4.1-2.3.4.5 present the staff's review findings regarding LRASections 2.3.4.1-2.3.4.5, respectively.2.3.4.1 Condensate Storage System 2.3.4.1.1 Summary of Technical Information in the Application In LRA Section 2.3.4.1, the applicant described the condensate storage (CST) system. Thecondensate storage system provides a large storage capacity of reactor quality water. Thenormal plant uses for condensate storage water include (1) hotwell makeup and reject, (2) CRD supply, (3) fuel storage pool makeup, (4) demineralizer and radwaste processing, (5) filling therefueling wells, (6) miscellaneous plant flushing and decontamination services, (7) pressurizing

RHR and CSP piping, and (8) normal suction supply for HPC and RCI systems. In addition to the above, the condensate storage system provides storage for reclaimed water from theradwaste system. The suppression pool is the SR source of water for HPCI.

2-94The condensate stor age system contains SR components that are relied upon to remainfunctional during and following DBEs. The failure of NSR SSCs in the condensate storage system could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the condensate storage system performsfunctions that support EQ and SBO.The intended function, within the scope of license renewal, is to provide a pressure-retainingboundary.In LRA Table 2.3.4-1, the applicant identified the following condensate storage systemcomponent types that are within the scope of license renewal and subject to an AMR:

  • fasteners/bolting
  • filters/housings
  • flow element
  • gauges (flow, level, and sight)
  • heat exchangers
  • instrumentation
  • piping and fittings
  • pump casings
  • restricting orifices
  • thermowells
  • valve bodies2.3.4.1.2 Staff Evaluation The staff reviewed LRA Section 2.3.4.1 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.3.4.1 identified an area for which it needed additionalinformation to complete its evaluation of the applicant's scoping and screening results. The applicant responded to the staff's RAI as discussed below.In RAI 2.3.4.1-1, dated September 16, 2005, the staff noted that the HPCI pump normally islined up to the CSTs and the suction is switched to the suppression pool when the level in either CST falls to the TS low level or when a high water level is sensed in the suppression pool. LRA Section 2.3.4.1 states that the portion of the condensate stor age system within the scope oflicense renewal consists of piping and valves which supply the fuel storage pool, HPCI, RCI, RHR, CRD, condensate, FW, CSP, main condenser, and radwaste systems. In addition, the 2-95instrumentation associated with the automatic transfer from the CST to the suppression pool isSR and the components are within the scope of license renewal, in accordance with 10 CFR 54.4(a)(1). LRA Table 2.3.4-1 shows that the intended function of all condensatestorage system component groups is "pressure boundary."License renewal drawing LR-36039 shows the piping within the scope of license renewal,associated with the SR level instrumentation for the north and south CSTs, at locations B-3 andB-6. For each CST, the portion within the scope of license renewal includes the portion of the CST connection piping C22-4"-HJ and C23-4"-HJ between the reactor building and the CST-level instruments. This license renewal drawing does not show the remaining portion of these lines from the reactor building to the CST as within the scope of license renewal. Failure of the piping outside the scope of license renewal would have the same effect as a pressure boundary failure of the portion within the scope of license renewal. Therefore, the staff requested that theapplicant justify why it did not include the portion of lines C22-4"-HJ and C23-4"-HJ between the reactor building and the CST within the scope of license renewal.In its response, by letter dated October 14, 2005, the applicant stated the following:Line segments C22-4"-HJ and C23-4"-HJ, shown on license renewal boundarydrawing LR-36039, include the level switches for the north and south condensate storage tanks (CSTs). The level instrumentation is safety-related because of the automatic transfer feature from the nonsafety-related condensate storage tanksto the safety-related suppression pool.Portions of the line segments connecting to lines C22-4"-HJ and C23-4"-HJlocated between the Reactor Building wall and just prior to valves CST-1-1 and CST-1-2 on LR drawing LR-36039 are buried and are in scope for license renewal. The buried piping is in scope for the reason that it serves as an equivalent anchor for the attached safety related piping. For the purposes of clarification of LR drawing LR-36039, this in scope buried piping is now included in the highlighted segments for C22-4"-HJ/HK and C23-4"-HJ/HK.The remaining line segments which include valves CST-1-1 and CST-1-2 andcontinue to the CSTs between the Reactor Building and the CSTs are above ground and outside the Reactor Building. This piping is considered non-safety related and its failure would only cause the level instrumentation to fail in a safe position by switching suction to the safety-related suppression pool. Therefore, this portion of the CST piping is not in the scope of license renewal.Based on its review, the staff found the applicant's response acceptable because it addressesequivalent seismic restraint and identifies the portions of t he system within the scope of licenserenewal and subject to an AMR, in accordance with the requirements of 10 CFR 54.4(a) and 10 CFR 54.21(a), respectively. The staff reviewed the applicant's use of underground piping as a seismic restraint in SER Section 2.1.3.1.2. Therefore, the staff's concern described inRAI 2.3.4.1-1 is resolved.

2-962.3.4.1.3 ConclusionThe staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the CST system componentsthat are within the scope of license renewal, as required by 10 CFR 54.4(a), and the CST system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.4.2 Condensate and Feedwater System 2.3.4.2.1 Summary of Technical Information in the Application In LRA Section 2.3.4.2, the applicant described the condensate and feedwater (CFW) system.The CFW system supplies condensate from the main condenser to the reactor vessel at anelevated temperature and pressure. The CFW system includes the condensate demineralizer,the reactor FW pump seal, and zinc injection passivation subsystems. Two motor-drivencondensate pumps pump condensate through the SJAE intercondensers and the steam-packing exhauster. After leaving the steam-packing exhauster, condensate passes through the full-flow condensate demineralizer subsystem to ensure a supply of high-purity water to thereactor. Demineralizer effluent is then split into two parallel paths, each with three stages of low-pressure FW heating, to the suction of the reactor FW pumps. The condensate demineralizer subsystem consists of five demineralizer vessels operating in parallel and sizedfor full-condensate flow at reactor-rated conditions. The demineralizer vessels are located inshielded cells. Wastes from an exhausted unit are transferred to the RAD system for disposal.The zinc injection passivation s ubsystem provides a zinc oxide suspension from a continuouslystirred supply tank, which is diluted with demineralized water, and fed to one of two zinc injection pumps. The diluted suspension is continuously injected into the suction of the reactor feed pump just downstream of the reactor feed pump suction valves. Small concentrations of zinc in the reactor water result in a reduction in the amount of cobalt incorporated into the oxide film established on stainless steel piping. This reduction in cobalt-60 incorporation provides substantial reductions in dose rates, particularly in primary containment.The CFW system contains SR components that are relied upon to remain functional during andfollowing DBEs. The failure of NSR SSCs in the CFW system could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the CFW system performs functions that support SBO.The intended functions within the scope of license renewal include the following:

  • provide flow restriction
  • provide a pressure-retaining boundaryIn LRA Table 2.3.4-2, the applicant identified the following CFW system com ponent types thatare within the scope of license renewal and subject to an AMR:
  • expansion joints 2-97
  • fasteners/bolting
  • filters/strainers
  • flow element
  • gauges (flow, level, and sight)
  • heat exchangers
  • piping and fittings
  • pump casings
  • restricting orifices
  • tanks
  • thermowells
  • valve bodies2.3.4.2.2 Staff Evaluation The staff reviewed LRA Section 2.3.4.2 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.3.4.2 identified areas for which it needed additionalinformation to complete its evaluation of the applicant's scoping and screening results. The applicant responded to the staff's RAIs as discussed below.In RAI 2.3.4.2-1, dated September 16, 2005, the staff noted that LRA Table 2.3.4-2 identifies"Pressure Boundary" as the intended function of all the heat exchangers within the scope of license renewal in the CFW system. License renewal drawings LR-36034 and LR-36035 showthat the shells for FW heaters E-11A, E-11B, E-12A, and E-12B are NSR and included within the scope of license renewal, in accordance with the 10 CFR 54.4(a)(2) criterion; however, several turbine and extraction steamlines connected to the heat exchanger shell pressure boundary are not shown within the scope of license renewal. These lines include the following:
  • lines E9-26"-HCD, E10-26"-HCD, E11-26"-HCD, and E12-26"-HCD for L.P.

heaterE-11A on LR-36034 (quadrant B4)

  • lines E1-20"-HCD and E2-20"-HCD for L.I.P. heater E-12A on LR-36034 (quadrant B4)
  • lines E13-26"-HCD, E14-26"-HCD, E15-26"-HCD, and E16-26"-HCD for L.P.

heaterE-11B on LR-36035 (quadrant B-6)

  • lines E2-20"-HCD and E4-20"-HCD for L.I.P. heater E-12B on LR-36035 (quadrant C-6) 2-98Therefore, the staff requested that the applicant justify why it did not include the turbinegenerator system piping connected to the CFW system heaters within the scope of licenserenewal, considering the component's intended function as defined in LRA Table 2.3.4-2 and the scoping criterion specified in 10 CFR 54.4(a)(2).In its response, by letter dated October 14, 2005, the applicant stated the following:The shells for feedwater heaters E-11A, E-11B, E-12A and E-12B are non-safetyrelated and are included within the scope of license renewal in accordance with 10 CFR 54.4(a)(2). These heaters are mounted in the 'neck' of the condenser with only a portion of the heater protruding from the condenser. It is only the ends of the feedwater heater shells which protrude outside of the condenser andhave the capability of impacting the intended function of safety-related SSCs dueto potential leakage or spray that are of concern. The turbine extraction steam lines connected to these heat exchanger shells are located inside the condenser and, therefore, do not pose a potential leak or spray hazard. The failure of thesenon-safety related components could not impact safety-related SSCs per the criteria specified in 10 CFR 54.4(a)(2) and, therefore, are not included in the scope of license renewal.Based on its review, the staff found the applicant's response to RAI 2.3.4.2-1 acceptablebecause the main condenser shell should preclude leakage or spray impacts on SR SSCs from the failure of NSR extraction steamlines inside the main condenser; therefore, the staff's concern described in RAI 2.3.4.2-1 is resolved.In RAI 2.3.4.2-2, dated September 16, 2005, the staff noted that license renewal drawingLR-36036 at locations C-5, C-6, D-5, and D-6 identifies the shells for FW heaters E-11A,E-11B, E-12A, and E-12B as NSR and within the scope of license renewal, in accordance with the 10 CFR 54.4(a)(2) criteria; however, the drawing also shows a connecting steamline to each heater shell as being outside the scope of license renewal with references to license renewal drawings LR-36035 (C-5), LR-36035 (B-5), LR-36034 (B-4), and LR-36034 (C-4),

which could not be found on the indicated license renewal drawings. Therefore, the staff requested that the applicant identify the correct drawings and locations for these references. Inaddition, the staff requested that the applicant justify the determination that the steam pipingconnected to the CFW system heaters is not within the scope of license renewal, consideringthe component's intended function as defined in LRA Table 2.3.4-2 and the scoping criteriaspecified in 10 CFR 54.4(a)(2).In its response, by letter dated October 14, 2005, the applicant stated that, for the FW heaters,license renewal drawings LR-36034 and LR-36035 show the extraction steam details and license renewal drawing LR-36036 shows the condensate and FW details. The applicant stated that the continuation between the drawings is shown only for information and refers to thegeneral area where the extraction steam piping connects to the heaters. Consistent with the extraction steamline noted in RAI 2.3.4.2-1, the applicant stated that the turbine extractionsteamlines identified in RAI 2.3.4.2-2 are inside the condenser and pose no potential leak orspray hazard. The applicant concluded that failure of these NSR extraction steamlines would not impact SR SSCs pursuant to the 10 CFR 54.4(a)(2) criteria and, therefore, are not includedwithin the scope of license renewal.

2-99Based on its review, the staff found the applicant's response to RAI 2.3.4.2-2 acceptable,because the main condenser shell should prevent leakage or spray impacts on SR SSCs from the failure of NSR extraction steamlines inside the main condenser; therefore, the applicant resolved the staff concern described in RAI 2.3.4.2-2.The staff's review of LRA Section 2.3.4.2 identified areas in which information in the LRAneeded to be verified by the NRC Regional Inspection Team to complete the review of theapplicant's scoping and screening results.Inspection Item 2.3.4.2-1LRA Section 2.3.4.2 states that the portion of the CFW system within the scope of licenserenewal consists of pumps, condensate demineralizers, heat exchangers, tanks, and associated piping, valves, and instrumentation from the condensate pump suction to the FWinjection nozzles. LRA Table 2.3.4-2 identifies "Pressure Boundary" as the intended function for all piping and fittings in the CFW system within the scope of license renewal. License renewaldrawing LR-36038-2 shows the CFW system piping associated with the condensatedemineralizer subsystem as NSR and included within the scope of license renewal, inaccordance with the 10 CFR 54.4(a)(2) criterion. Accordingly, license renewal drawing LR-36038-2 at location A-6 identifies a portion of line CH5-3"-HC to the chemical waste tank as within the scope of license renewal. Because the license renewal scope boundary for this line terminates in the middle of the pipe run, the actual location of the license renewal scopeboundary for this pipe is not clear. The NRC Regional Inspection Team performed an inspectionto ensure that the license renewal scope boundary for this pipe satisfies the 10 CFR 54.4(a)(2) criterion.The inspection team conducted a walkdown and confirmed that the license renewal boundaryends as line CH5-3"-HC enters the 985' pump room. There are no SR components in the 985' pump room. All P&IDs do not typically show walls and floors. The inspectors determined that the license renewal boundary satisfies the 10 CFR 54.4(a)(2) criterion. Therefore, the staff'sconcern described in Inspection Item 2.3.4.2-1 is resolved.2.3.4.2.3 Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the CFW systemcomponents that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the CFW system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.4.3 Main Condenser System 2.3.4.3.1 Summary of Technical Information in the Application In LRA Section 2.3.4.3, the applicant described the main condenser (CDR) system. The CDRsystem provides a heat sink for the steam cycle, removes noncondensable gases, and servesas a central collection point for system drains. The system is NSR, but is credited for post-2-100accident plateout and holdup of radioactive iodine in the LOCA and control rod dropaccident analyses conducted pursuant to USAR Sections 14.7.2.4.1 and 14.7.1.6, respectively.Also included in the nonsafety affecting safety function is the automatic closure of mechanical vacuum pump suction valves that isolate the condenser lines to the mechanical vacuum pump on primary containment isolati on system (PCIS) Division 1 logic, which includes detection ofhigh activity in the main steamlines. The CDR system consists principally of the CDR, which condenses steam exhausted from the turbine and turbine bypass system (TGS system). TheCDR is a twin-shell, dual-pressure surface condenser. Each of the two low-pressure turbinesexhausts into a condenser shell. Condenser structural integrity is continuously demonstrated during normal operation when the condenser is required to maintain vacuum. Following a DBA, when the condenser is required to perform its intended function, the main steam isolation valves will be closed and vacuum will be lost. The condenser will not be required to perform apressure-boundary function because atmospheric conditions will exist inside the condenser.The failure of NSR SSCs in the CDR system could potentially prevent the satisfactoryaccomplishment of an SR function of SSCs within the scope of license renewal.The intended functions within the scope of license renewal include the following:

  • provide plateout and holdup of radioactive material
  • provide a pressure-retaining boundaryIn LRA Table 2.3.4-3, the applicant identified the following CDR system component types thatare within the scope of license renewal and subject to an AMR:
  • condenser complex
  • expansion joints
  • fasteners/bolting
  • filters/strainers
  • gauges (flow, level, and sight)
  • heat exchangers
  • LP turbine hood
  • piping and fittings
  • pump casings
  • tanks
  • thermowells
  • valve bodies2.3.4.3.2 Staff Evaluation The staff reviewed LRA Section 2.3.4.3 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had not 2-101omitted any passive and long-lived components that should be subject to an AMR, inaccordance with the requirements of 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.3.4.3 identified areas for which it needed additionalinformation to complete its evaluation of the applicant's scoping and screening results. The applicant responded to the staff's RAIs as discussed below.In RAI 2.3.4.3-1, dated September 16, 2005, the staff noted that on license renewal drawingLR-36035-2 at location B-2, pipe section line number OG6-8"-HC at separator T-72 and downstream piping are not within the scope of license renewal. All other piping and components within the apparent plant area are within the scope of license renewal. Failure of this unisolable section of pipe could affect the license renewal intended pressure-boundary function for the CDR system; therefore, the staff requested that the applicant justify why it did not include thesesections of unisolable piping and components within the scope of license renewal.In its response, by letter dated October 14, 2005, the applicant stated that pipe line numberOG6-8-HC at separator T-72 and the downstream piping have an internal environment of air.

The failure of these NSR components could not impact the intended function of SR SSCs and therefore, are not included within the scope of license renewal. All other piping and componentswithin the plant area are within the scope of license renewal because they contain water and have the ability to impact the intended function of SR SSCs because of the potential for leakageor spray.Based on its review, the staff found the applicant's response to RAI 2.3.4.3-1 acceptable,because pipe line number OG6-8-HC and the downstream piping have an internal environment of air, which does not have the ability to impact the intended function of SR SSCs, and as such,are not within the scope of license renewal; therefore, the staff's concern described in RAI 2.3.4.3-1 is resolved.In RAI 2.3.4.3-2, dated September 16, 2005, the staff noted that license renewal drawingLR-54817-4 at location A-7 is not listed in LRA Section 2.3.4.3 as a license renewal drawing for the CDR system; therefore, the staff requested that the applicant clarify why it did not includeLR-54817-4 in LRA Section 2.3.4.3 as a license renewal drawing for the CDR system.In its response, by letter dated October 14, 2005, the applicant stated that license renewaldrawing LR-54817-4 shows the flow diagram for the recombiner building. There are no CDR components within the scope of license renewal inside the recombiner building. Consequently, license renewal drawing LR-54817-4 is not included in LRA Section 2.3.4.3 as a license renewal drawing for the CDR system.Based on its review, the staff found the applicant's response to RAI 2.3.4.3-2 acceptablebecause license renewal drawing LR-54817-4 shows no CDR components within the scope oflicense renewal; therefore, the staff's concern described in RAI 2.3.4.3-2 is resolved.The staff's review of LRA Section 2.3.4.3 identified areas in which information in the LRAneeded to be verified by the NRC Regional Inspection Team to complete the review of theapplicant's scoping and screening results.

2-102Inspection Item 2.3.4.3-1The CDR system is NSR, but is credited for post-accident plateout and holdup of radioactiveiodine in the LOCA and control rod drop accident analyses, per USAR Sections 14.7.2.4.1 and14.7.1.6, respectively. License renewal drawing LR-36035-2 at locations C-6 and B-6 has piping outside the scope of license renewal with continuations to condenser E-1B connection 29 on license renewal drawing LR-36035 at location D-6. The portion of piping on LR-36035 is within the scope of license renewal. Consequently, the actual locations of the license renewal boundary for these pipes are not clear. The NRC Regional Inspection Team performed aninspection to ensure that the license renewal scope boundary for these pipes satisfies the 10 CFR 54.4(a)(2) criterion.Lines RV34-6"-HB and RV33-6"-HB connect to condenser E-1B at connection 29 on LR-36035.The intended function of the piping is not for post-accident plateout and holdup of radioactive iodine, but for pressure boundary for NSR affecting SR components, as shown in LRA Table 2.3.4-3, "Main Condenser System." Lines RV34-6"-HB and RV33-6"-HB shown on LR-36035-2 are in the SJAE room. There are no SR components in the SJAE room and, therefore, this piping is not required to be within the scope of license renewal.Piping PS9-2"-ED, shown on LR-36035-2, is also in the SJAE room; however, this piping is anHELB line and, therefore, is within the scope of license renewal. The boundary for the HELB line ends at the valves, as stated in USAR Appendix I, Table I.2-1, page 8.The applicant will revise license renewal drawing LR-36035-2 to depict a wall that linesRV34-6"-HB and RV33-6"-HB pass through into the SJAE room. The lines will be shown withinthe scope of license renewal as they continue from license renewal drawing LR-36035 and condenser E-1B connection 29, and outside the scope of license renewal after they pass through the wall into the SJAE room. The inspectors determined that the license renewal boundary satisfies the 10 CFR 54.4(a)(2) criterion. Therefore, the staff's concern described in Inspection Item 2.3.4.3-1 is resolved.Inspection Item 2.3.4.3-2License renewal drawing LR-36035 at location A-8 has a piping continuation, pipe line numberCN-125-4"-EN1C, from the recombiner, license renewal drawing LR-54817-4 at location A-7, that is within the scope of license renewal. The continuation on license renewal drawing LR-54817-4 at location A-7 is outside the scope of license renewal. Consequently, the actuallocation of the license renewal boundary for this pipe is not clear. The NRC Regional InspectionTeam performed an inspection to ensure that the license renewal scope boundary for this pipe satisfies the 10 CFR 54.4(a)(2) criterion.The inspection team confirmed through walkdown that the license renewal boundary ends asthe line, CN-125-4"-EN1C, enters the recombiner building on license renewal drawing LR-54817-4. There are no SR components in the recombiner building; therefore, licenserenewal drawing LR-54817-4 does not depict any components within the scope of license renewal in that building.The applicant will revise license renewal drawing LR-54817-4 (at location A-7) to show thecontinuation of line CN-125-4"-EN1C to license renewal drawing LR-36035 as being within the 2-103scope of license renewal, with the scoping boundary at the wall labeled turbine building. Nocomponents shown to the right of the turbine building wall are within scope, as these are all inthe recombiner building. The inspectors determined that the license renewal boundary satisfies the 10 CFR 54.4(a)(2) criterion. Therefore, the staff's concern described in Inspection Item 2.3.4.3-2 is resolved.2.3.4.3.3 Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the CDR systemcomponents that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the CDR system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.4.4 Main Steam System 2.3.4.4.1 Summary of Technical Information in the Application In LRA Section 2.3.4.4, the applicant described the main steam (MST) system. The MSTsystem transports steam produced in the reactor to the main turbine for the production ofelectricity. This steam is supplied to the high-pressure section of the turbine. Steam leaving the high-pressure turbine is divided, the bulk of it passing through moisture separators before its admission to the low-pressure sections. A portion of the steam is extracted and is condensed as it is cascaded through FW heaters en route to the CDR. Normally, the turbine uses all thesteam being generated by the reactor; however, automatic, pressure-controlled, bypass valves are supplied, which can discharge excess steam directly to the condenser. The MST systemalso supplies steam to the HPCI and RCI turbines. The MST system includes an inline flowrestrictor for each of the four main steamlines. These flow restrictors minimize water losses and protect the fuel barrier before main steam isolation valve closure for steamline ruptures outside of primary containment. Drains are provided to remove condensate from the steamlines. The majority of the components for the MST system are located in the turbine building and reactorbuilding steam chase, with additional piping and valves located in the primary containment. The majority of the system components are made of stainless steel and carbon steel, althoughsome cast austenitic stainless steel and copper alloy material is used.The MST system contains SR components that are relied upon to remain functional during andfollowing DBEs. The failure of NSR SSCs in the MST system could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the MST system performs functions that support FP and EQ.The intended functions within the scope of license renewal include the following:

  • provide filtration
  • provide flow restriction
  • provide a pressure-retaining boundary 2-104In LRA Table 2.3.4-4, the applicant identified the following MST system com ponent types thatare within the scope of license renewal and subject to an AMR:
  • fasteners/bolting
  • filters/strainers
  • flow element
  • piping and fittings
  • restricting orifices
  • thermowells
  • valve bodies2.3.4.4.2 Staff Evaluation The staff reviewed LRA Section 2.3.4.4 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.3.4.4 identified an area for which it needed additionalinformation to complete its evaluation of the applicant's scoping and screening results. The applicant responded to the staff's RAI as discussed below.In RAI 2.3.4.4-1, dated September 16, 2005, the staff noted that license renewal drawingLR-36035-2 at locations D-7 and B-7 indicates that pipe line numbers D109-1"-EF and D108-1"-EF (steam supply lines to Air Ejectors E-2B and E-2A) are not within the scope of license renewal. Table 2.3.4-4 states that piping, fittings, and valves are within the scope oflicense renewal with intended pressure-boundary function. Failure of this section of pipe could affect the license renewal intended pressure-boundary function for the MST system piping;therefore, the staff requested that the applicant justify why it did not include these sections ofunisolable piping and components within the scope of license renewal.In its response, by letter dated October 14, 2005, the applicant stated that lines D109-1"-EFand D 108-1"-EF are inside the SJAE room. These 1-inch pipes are not considered high-energy lines and there are no SR components inside the SJAE room whose intended function could be impacted by this NSR piping; therefore, line numbers D109-1"-EF and D108-1"-EF are not within the scope of license renewal.Based on its review, the staff found the applicant's response to RAI 2.3.4.4-1 acceptablebecause NSR lines D109-1"-EF and D l08-1"-EF are inside the SJAE, are not considered high-energy lines, and as such, are not within the scope of license renewal; therefore, the staff's concern described in RAI 2.3.4.4-1 is resolved.

2-1052.3.4.4.3 ConclusionThe staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the MST systemcomponents that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the MST system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.3.4.5 Turbine Generator System 2.3.4.5.1 Summary of Technical Information in the Application In LRA Section 2.3.4.5, the applicant described the turbine generator system. The turbinegenerator system includes the turbine generator unit and the steam sealing, turbine lube oil,hydrogen cooling, hydrogen seal oil, and stator cooling subsystems. The function of the turbineis to convert the thermodynamic energy of the steam from the nuclear reactor into mechanical energy that drives the generator. The generator in turn converts that energy to an electricaloutput to the power grid. The turbine consists of one single-flow, high-pressure section with two double-flow, low-pressure sections of the non-reheat design on a single shaft. The generator consists of three major parts-the rotor, stator, and exciter. The rotor is turned by the turbine shaft and is the source of the moving magnetic field. The stator consists of windings which form a conductive path for the current induced by the rotating magnetic field of the rotor. The exciter is a separate and smaller generator driven by the turbine to provide power for the main generator rotor magnetic field. The steam sealing subsystem prevents steam leakage past theturbine shaft seals into the turbine building and limits air in-leakage to the turbine casings. The turbine generator shaft is supported by 10 journal bearings. All bearing oil is supplied by the turbine lube oil subsystem, which also provides high-pressure oil to the hydraulic turbine controlmechanisms. The hydrogen gas of the hydrogen cooling subsystem is contained within thegenerator casing. The hydrogen cooling subsystem is designed to reduce the heat generatedfrom windage resistance and provide a good heat transfer medium for generator cooling. The hydrogen seal oil subsystem supplies vacuum treated oil between the rotor shaft and thegenerator end housing hydrogen seals to prevent hydrogen from escaping into the turbine building. The stator cooling subsystem removes heat from the generator stator by circulatinglow-conductivity water through the hollow metal bars forming the stator windings. The subsystem also supplies cooling water to the generator exciter rectifier banks. The statorcooling subsystem consists of a storage tank feeding two parallel pumps, two heat exchangers,a filter, and connecting piping with the generator stator.The failure of NSR SSCs in the turbine generator system could potentially prevent thesatisfactory accomplishment of an SR function of SSCs within the scope of license renewal.The intended function, within the scope of license renewal, is to provide a pressure-retainingboundary.In LRA Table 2.3.4-5, the applicant identified the following turbine generator system componenttypes that are within the scope of license renewal and subject to an AMR:

2-106

  • expansion joints
  • fasteners/bolting
  • filters/housings
  • filters/strainers
  • gauges (flow, level and sight)
  • heat exchangers
  • piping and fittings
  • pump casings
  • restricting orifices
  • steam traps
  • tanks
  • thermowells
  • turbines
  • valve bodies2.3.4.5.2 Staff Evaluation The staff reviewed LRA Section 2.3.4.5 and the USAR using the evaluation methodologydescribed in SER Section 2.3. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.3.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.3.4.5 identified areas for which it needed additionalinformation to complete its evaluation of the applicant's scoping and screening results. The applicant responded to the staff's RAIs as discussed below.In RAI 2.3.4.5-1, dated September 16, 2005, the staff noted that license renewal drawingLR-36034 at location B-4 shows a portion of the sensing line to PT-1217 attached to pipe E2-20"-HCD as within the scope of license renewal; however, the remaining portion of thesensing line and pressure transmitter is shown as outside the scope of license renewal. In addition, license renewal drawing LR-36035 at location D-7 shows pressure transmitters PT-1222 and PT-1223 and portions of the sensing lines to these transmitters as within the scope of license renewal; however, the remaining portions of the sensing line to pipes E3-20"-HCD and E16-26"-HCD are shown as outside the scope of license renewal. LRASection 2.3.4.5 states that the license renewal function for turbine generator piping and gaugesis to maintain a pressure boundary and that NSR structures and/or components of the turbine generator system that could affect SR SSCs must maintain sufficient integrity so that theintended function of the SR SSCs is not adversely affected. Failure of the sensing lines noted above could affect the license renewal intended pressure-boundary function of this turbine generator piping and have a negative impact on the SR SSCs; therefore, the staff requested 2-107that the applicant justify why it did not include portions of the sensing lines and associatedpressure transmitters within the scope of license renewal.In its response, by letter dated October 14, 2005, the applicant stated that the portion of thesensing line to PT-1217 attached to pipe E2-20"-HCD is inside the condenser and should nothave been shown as within the scope of license renewal. PT-1222 and PT-1223 and portions of the sensing lines to these transmitters are within the scope of license renewal because they are on the exterior of the condenser. The sensing lines inside the condenser to pipes E3-20"-HCD and E16-26"-HCD are not within the scope of license renewal. The failure of these NSR linescould not impact the intended function of SR SSCs, and therefore, the applicant did not includethem within the scope of license renewal. During its review, the applicant found that it should have shown the portions of the sensing lines from condenser penetration No. 60 to PT-1216 and PT-1217 on the exterior of the condenser as within the scope of license renewal.Based on its review, the staff found the applicant's response to RAI 2.3.4.5-1 acceptablebecause failure of those NSR portions of sensing lines within the condenser could not impact the intended function of SR SSCs, and consequently, those portions are not within the scope of license renewal; therefore, the staff's concern described in RAI 2.3.4.5-1 is resolved.In RAI 2.3.4.5-2, dated September 16, 2005, the staff noted that LRA Section 2.3.4.5 statesthat the license renewal function for turbine generator piping is to maintain a pressure boundary and that NSR structures and/or components of the turbine generator system that could affectSR SSCs must maintain sufficient integrity so that the intended function of the SR SSCs is not adversely affected.License renewal drawings LR-36034 at location B-4 and LR-36035 at locations B-6, B-7, andC-7 show piping to LIP Heater 12-A&B and LP Heater 11-A & B (E9-26"-HCD, E10-26"-HCD,E11-26"-HCD, E12-26"-HCD, E1-20"-HCD, E2-20"-HCD, E14-26"-HCD, E13-26"-HCD, E15-26"-HCD, E16-26"-HCD, E4-20"-HCD, E3-20"-HCD) as outside the scope of licenserenewal; however, the sensing lines to pressure transmitters attached to these pipes are shown as within the scope of license renewal. Failure of the cited pipes could affect the license renewal intended function of pressure boundary for the turbine generator piping and have a negative impact on the SR SSCs. Therefore, the staff requested that the applicant justify why itdid not include the above cited pipes within the scope of license renewal.In its response, dated October 14, 2005, the applicant stated that portions of the sensing linesto these transmitters are within the scope of license renewal because they are on the exterior of the condenser and could impact the intended function of SR SSCs. The remaining portions of the sensing lines and heater piping to which they are attached are located in the condenser and are not within the scope of license renewal. The failure of this NSR piping could not impact the intended function of SR SSCs. During its review, the applicant found that the portions of the sensing lines from condenser penetration No. 25 to piping E4-20"-

HCD and E3-20"-HCD onlicense renewal drawing LR-36035 (at location C-7) and condenser penetration No. 31 to piping E1-20"-HCD and E2-20"-

HCD should not have been shown within the scope of license renewalbecause they are within the condenser.Based on its review, the staff found the applicant's response to RAI 2.3.4.5-2 acceptable,because those portions of sensing lines within the condenser are not within the scope of license 2-108renewal. The failure of these NSR lines could not impact the intended function of SR SSCs;therefore, the staff's concern described in RAI 2.3.4.5-2 is resolved.2.3.4.5.3 Conclusion The staff reviewed the LRA to determine whether the applicant had failed to identify any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the turbine generator systemcomponents that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the turbine generator system components that are subject to an AMR, as required by10 CFR 54.21(a)(1).2.4Scoping and Screening Results: Containments, Structures, and ComponentSupportsThis section documents the staff's review of the applicant's scoping and screening results forcontainments, structures, and component supports. Specifically, this section discusses the following containments, structures, and component supports:

  • cranes, heavy loads, rigging
  • diesel fuel oil transfer house
  • emergency filtration train building
  • fire protection barriers commodity group
  • hangers and supports commodity group
  • intake structure
  • miscellaneous SBO yard structures
  • offgas stack
  • offgas storage and compressor building
  • plant control and cable spreading structure
  • radioactive waste building
  • reactor building
  • structures affecting safety
  • turbine building
  • underground duct bankIn accordance with the requirements of 10 CFR 54.21(a)(1), the applicant must identify and listpassive, long-lived SCs that are within the scope of license renewal and subject to an AMR. To verify that the applicant properly implemented its methodology, the staff focused its review onthe implementation results. This approach allowed the staff to confirm that there were noomissions of containments, structures, and component supports components that meet thescoping criteria and are subject to an AMR.

2-109Staff Evaluation Methodology. The staff performed its evaluation of the information in the LRAin the same manner for all containments, structures, and component supports. The objective of the review was to determine whether the applicant had identified the components andsupporting structures for a specific containment, structure, or component support, that appeared to meet the scoping criteria specified in the Rule, as within the scope of license renewal, in accordance with 10 CFR 54.4. Similarly, the staff evaluated the applicant'sscreening results to verify that all long-lived, passive components were subject to an AMR in accordance with 10 CFR 54.21(a)(1).Scoping. To perform its evaluation, the staff reviewed the applicable LRA section andassociated component drawings, focusing its review on components that had not been identified as within the scope of license renewal. The staff reviewed relevant licensing-basis documents, including the USAR, for each containment, structure, and component support to determine whether the applicant had omitted components with intended functions delineatedunder 10 CFR 54.4(a) from the scope of license renewal. The staff also reviewed the licensing-basis documents to determine whether the LRA specified all intended functions delineatedunder 10 CFR 54.4(a). If omissions were identified, the staff requested additional information to resolve the discrepancies.Screening. Once the staff completed its review of the scoping results, it evaluated theapplicant's screening results. For those containments, structures, and components supports with intended functions, the staff sought to determine (1) if the functions are performed with moving parts or a change in configuration or properties or (2) if they are subject to replacement based on a qualified life or specified time period, as described in 10 CFR 54.21(a)(1). For those that did not meet either of these criteria, the staff sought to confirm that these containments,structures, and components supports and components were subject to an AMR, as required by 10 CFR 54.21(a)(1). If discrepancies were identified, the staff requested additional information to resolve them.2.4.1 Cranes, Heavy Loads, Rigging 2.4.1.1 Summary of Technical Information in the ApplicationIn LRA Section 2.4.1, the applicant described the cranes, heavy loads, and riggi ng system. Thecranes, heavy loads, and rigging system consists of the reactor building and turbine buildingcranes, numerous hoists, lifting fixtures and devices, and other miscellaneous smaller cranes.

Included in this system are the reactor components' handling equipment, such as the refuelingbridge, various tools, controls, lifting devices, and fixtures. The refueling rod block interlocks arealso included under the reactor manual control system.The failure of NSR SSCs in the cranes, heavy loads, and rigging system could potentiallyprevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal.The intended function, within the scope of license renewal, is to provide structural support toNSR components (civil and structural).

2-110In LRA Table 2.4.1-1, the applicant identified the following cranes, heavy loads, and riggingsystem com ponent types that are within the scope of license renewal and subject to an AMR:

  • carbon steel, low-alloy steel in air/gas (reactor building crane rails, turbine building cranerails, refueling platform rails)
  • carbon steel, low-alloy steel in air/gas (reactor building crane, turbine building crane,refueling platform, reactor vessel head lifting device, dryer and steam separator sling lifting device, and hook box)2.4.1.2 Staff Evaluation The staff reviewed LRA Section 2.4.1 and the USAR using the evaluation methodologydescribed in SER Section 2.4. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.4.In conducting its review, the staff evaluated the structural component functions described in theLRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had not omitted from the scope of license renewal any components with intendedfunctions delineated under 10 CFR 54.4(a). The staff then reviewed those components that theapplicant had identified as being within the scope of license renewal to verify that the applicanthad not omitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.4.1.3 Conclusion The staff reviewed the LRA and related structural components to determine whether theapplicant had failed to identify any SSCs that should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequatelyidentified the cranes, heavy loads, and rigging system components that are within the scope oflicense renewal, as required by 10 CFR 54.4(a), and the cranes, heavy loads, and rigging system components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.4.2 Diesel Fuel Oil Transfer House2.4.2.1 Summary of Technical Information in the Application In LRA Section 2.4.2, the applicant described the diesel fuel oil transfer house. The diesel fueloil transfer house, located north of the diesel generator building and west of the intake structure, is a reinforced concrete building on a mat foundation that provides protective enclosure to the SR diesel oil transfer pump and the diesel oil service pump.The diesel fuel oil transfer house contains SR components that are relied upon to remainfunctional during and following DBEs. The failure of NSR SSCs in the diesel fuel oil transfer 2-111house could potentially prevent the satisfactory accomplishment of an SR function of SSCswithin the scope of license renewal. In addition, the diesel fuel oil transfer house performs functions that support FP.The intended functions within the scope of license renewal include the following:
  • provide flood protection barrier
  • provide missile barrier
  • provide structural support to NSR components (civil and structural)
  • provide structural support to SR components (civil and structural)
  • provide shelter/protection to SR componentsIn LRA Table 2.4.2-1, the applicant identified the following diesel fuel oil transfer housecomponent types that are within the scope of license renewal and subject to an AMR:
  • carbon steel, low-alloy steel in air/gas (structural steel, steel embeds, etc.)
  • carbon steel, low-alloy steel in air/gas (supports for miscellaneous structures (i.e.,members, welds, bolted connections, support anchorage for platforms, stairs, etc.))
  • carbon steel, low-alloy steel in atmosphere/weather (door)
  • concrete in air/gas (foundation, walls, slabs)
  • concrete in air/gas (foundation, walls, slabs, grout)
  • concrete in atmosphere/weather (walls, slab)
  • concrete in below grade (foundation, walls)2.4.2.2 Staff Evaluation The staff reviewed LRA Section 2.4.2 and the USAR using the evaluation methodologydescribed in SER Section 2.4. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.4.In conducting its review, the staff evaluated the structural component functions described in theLRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had not omitted from the scope of license renewal any components with intendedfunctions delineated under 10 CFR 54.4(a). The staff then reviewed those components that theapplicant had identified as being within the scope of license renewal to verify that the applicanthad not omitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.4.2 identified an area for which it needed additionalinformation to complete its evaluation of the applicant's scoping and screening results. The applicant responded to the staff's RAI as discussed below.In RAI 2.4.2-1, dated September 28, 2005, the staff noted that two component groups, (1)concrete in air/gas (foundation, walls, slabs) and (2) concrete in air/gas (foundation, walls, slabs, grout), have identical intended functions in Tables 2.4.2-1, 2.4.3-1, 2.4.4-1, 2.4.7-1,2.4.8-1, 2.4.11-1, 2.4.12-1, 2.4.14-1, 2.4.15-1, 2.4.16-1, and 2.4.17-1. Therefore, the staff 2-112requested that the applicant explain the need for the first component group since it appeared tobe contained in the second component group. The staff also noted that, in addition to those twocomponent groups, concrete in air/gas (walls, slabs) is listed in Tables 2.4.3-1, 2.4.4-1, 2.4.8-1,2.4.12-1, and 2.4.17-1 as a component group with the same intended function for which thestaff requested a similar explanation.In its response, by letter dated October 28, 2005, the applicant stated the following:To explain the difference between component groups, first an explanation of howTable 2.4.x-1 was assembled is needed. Tables in Section 2.4 of the License Renewal Application (LRA) were assembled by copying the component group and intended functions for each 3.5.2-x Table line entry into the 2.4.x-1 Table.This format was consistently used throughout the LRA. Many line entry component group descriptions appear similar but there are subtle differences that are evident upon review of the 3.5.2-x Table aging managementprogram (AMP), aging effects/mechanisms, material, etc.For this specific question, Table 2.4.x-1 component groups, 'concrete in air/gas(foundation, walls, slabs)' and 'concrete in air/gas (foundation, walls, slabs, grout)' have different component group descriptions (one component group includes grout and the other did not). Review of Table 3.5.2-x reveals that thecomponent group without grout is evaluated for the aging effect, 'cracking, loss of bond, loss of material due to corrosion of embedded steel.' The mechanism of corrosion of embedded steel is not applicable to grout but is applicable to reinforced concrete.For part two of this question, the Table 2.4.x-1 component groups, 'concrete inair/gas (walls, slabs),' 'concrete in air/gas (foundation, walls, slabs),' and

'concrete in air/gas (foundation, walls, slabs, grout)' have different component group descriptions. The same rationale discussed above is applicable here as well.Based on its review, the staff found the applicant's response to RAI 2.4.2-1 acceptable. Theapplicant explained that (1) tables in Section 2.4 were copied from the component group andintended function from tables in Section 3.5, (2) one component group includes grout and the other does not, and (3) the mechanism of corrosion of embedded steel is applicable to reinforced concrete but not to grout. Because of these minor differences, tables in Section 2.4 appear repetitious. Therefore, the staff's concern described in RAI 2.4.2-1 is resolved.2.4.2.3 Conclusion The staff reviewed the LRA and related structural components to determine whether any SSCsthat should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequately identified the diesel fuel oil transferhouse components that are within the scope of license renewal, as required by 10 CFR 54.4(a),

and the diesel fuel oil transfer house components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2-1132.4.3 Emergency Diesel Generator Building2.4.3.1 Summary of Technical Information in the ApplicationIn LRA Section 2.4.3, the applicant described the EDG building. The principal function of theEDG building is to provide a safe enclosure and protection for the standby diesel generators and portions of the power distribution systems enclosed therein. The building is primarily asingle-story structure of reinforced concrete construction. A partial second story extends over a portion of the structure. The ground floor consists of a concrete slab which is independent of the building structure and placed on compacted select fill. Exterior walls are of reinforcedconcrete and support the lower roof and second story framing. The roof over the single-story portion of the structure and over the penthouse consists of a thick, reinforced concrete slab supported by structural steel framing. A north-south interior wall of reinforced concrete extends the full height of the structure providing physical separation of the diesel generator systems.The exterior and interior walls extend 6 feet below grade to form a continuous wall footing supported on select fill. The standby diesel generators are located at grade and are supportedon a 3-foot thick reinforced concrete mat which is physically independent of the ground floor slab and building structure.The EDG building contains SR components that are relied upon to remain functional during andfollowing DBEs. The failure of NSR SSCs in the EDG building could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the EDG building performs functions that support FP.The intended functions within the scope of license renewal include the following:

  • provide flood protection barrier
  • provide missile barrier
  • provide structural support to NSR components (civil and structural)
  • provide structural support to SR components (civil and structural)
  • provide shelter/protection to SR componentsIn LRA Table 2.4.3-1, the applicant identified the following EDG building component types thatare within the scope of license renewal and subject to an AMR:
  • carbon steel, low-alloy steel in air/gas (fire-rated doors)
  • carbon steel, low-alloy steel in air/gas (structural steel, steel embeds, etc.)
  • carbon steel, low-alloy steel in air/gas (supports for miscellaneous structures (i.e.,members, welds, bolted connections, support anchorage for platforms, stairs, etc.))
  • carbon steel, low-alloy steel in atmosphere/weather (doors, ventilation assemblies)
  • concrete in air/gas (foundation, walls, slabs)
  • concrete in air/gas (foundation, walls, slabs, grout)
  • concrete in air/gas (walls, slabs)
  • concrete in atmosphere/weather (walls, slab) 2-114
  • concrete in below grade (foundation, walls)
  • masonry walls in air/gas2.4.3.2 Staff Evaluation The staff reviewed LRA Section 2.4.3 and the USAR using the evaluation methodologydescribed in SER Section 2.4. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.4.In conducting its review, the staff evaluated the structural component functions described in theLRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had not omitted from the scope of license renewal any components with intendedfunctions delineated under 10 CFR 54.4(a). The staff then reviewed those components that theapplicant had identified as being within the scope of license renewal to verify that the applicanthad not omitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.4.3.3 Conclusion The staff reviewed the LRA and related structural components to determine whether theapplicant had failed to identify any SSCs that should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequatelyidentified the EDG building components that are within the scope of license renewal, asrequired by 10 CFR 54.4(a), and the EDG building components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.4.4 Emergency Filtration Train Building2.4.4.1 Summary of Technical Information in the Application In LRA Section 2.4.4, the applicant described the EFT building. The function of the EFT buildingis to provide safe enclosure and protection for the main components of the MCR air conditioning system (including the EFT units for the MCR air conditioning system) and for otherSR equipment as necessary. The EFT building is an L-shaped reinforced concrete structure supported by a mat foundation. The west section is supported by two reinforced concrete caissons. The east section is three stories high, and the west section is two stories high.The EFT building contains SR components that are relied upon to remain functional during andfollowing DBEs. The failure of NSR SSCs in the EFT building could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the EFT building performs functions that support FP, ATWS, and SBO.The intended functions within the scope of license renewal include the following:
  • provide flood protection barrier 2-115
  • provide missile barrier
  • provide structural support to NSR components (civil and structural)
  • provide structural support to SR components (civil and structural)
  • provide shelter/protection to SR componentsIn LRA Table 2.4.4-1, the applicant identified the following EFT building component types thatare within the scope of license renewal and subject to an AMR:
  • carbon steel, low-alloy steel in air/gas (fire-rated doors)
  • carbon steel, low-alloy steel in air/gas (structural steel, steel embeds, etc.)
  • carbon steel, low-alloy steel in air/gas (supports for miscellaneous structures (i.e.,members, welds, bolted connections, support anchorage for platforms, stairs, etc.))
  • concrete in air/gas (foundation, walls, slabs)
  • concrete in air/gas (foundation, walls, slabs, grout)
  • concrete in air/gas (walls, slabs)
  • concrete in atmosphere/weather (walls, slab)
  • concrete in below grade (foundation, walls)
  • elastomer sealants (rubber, neoprene, s ilicone, etc.) in air/gas (EFT control volumeseals)2.4.4.2 Staff Evaluation The staff reviewed LRA Section 2.4.4 and the USAR using the evaluation methodologydescribed in SER Section 2.4. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.4.In conducting its review, the staff evaluated the structural component functions described in theLRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had not omitted from the scope of license renewal any components with intendedfunctions delineated under 10 CFR 54.4(a). The staff then reviewed those components that theapplicant had identified as being within the scope of license renewal to verify that the applicanthad not omitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.4.4 identified an area for which it needed additionalinformation to complete its evaluation of the applicant's scoping and screening results. The applicant responded to the staff's RAI as discussed below.In RAI 2.4.4-1, dated September 28, 2005, the staff noted that Table 2.4.4-1 lists two identicalcomponent groups, "concrete in atmosphere/weather (walls, slab)," with identical intended functions; therefore, the staff requested that the applicant explain the need to list the samecomponent group twice.In its response, by letter dated October 28, 2005, the applicant stated the following:

2-116Due to page format/spacing limitations, Table 3.5.2-4 was unable to include allthe component information on the same page, and therefore it became necessary to repeat the component group, intended functions, etc. on the following page. Table 2.4.4-1 could have omitted this duplication but a decisionwas made not to interfere with the process used to assemble the 2.4.x-1 Table.Based on its review, the staff found the applicant's response to RAI 2.4.4-1 acceptable.Although repetitious, the duplicate component groups have no effect on scoping or screening.

Therefore, the staff's concern described in RAI 2.4.4-1 is resolved2.4.4.3 Conclusion The staff reviewed the LRA and related structural components to determine whether theapplicant had failed to identify any SSCs that should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequatelyidentified the EFT building components that are within the scope of license renewal, as requiredby 10 CFR 54.4(a), and the EFT building components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.4.5 Fire Protection Barriers Commodity Group 2.4.5.1 Summary of Technical Information in the ApplicationIn LRA Section 2.4.5, the applicant described the FP barriers commodity group. The FP barrierscommodity group includes fire stop sealants, fireproofing, and metallics such as aluminum andcarbon steel credited in the FP evaluation report. Fire stop sealants, fireproofing, and meta llicscan be used as FP barriers to stop the spread of fire to adjacent fire areas and can also be used to encapsulate structural steel or other metallic and nonmetallic components locatedwithin a fire area to protect them from the effects of a fire. Fire stop sealants, fireproofing, metallics, and combinations thereof provide a fire resistance equivalent to the rating of the primary fire barrier to prevent the spread of fire to adjacent areas. Fire stop sealants, fireproofing, and metallics are used to close openings in ceilings, floors, and walls. Theseopenings may be for penetrating electrical (e.g., cables, cable trays, conduits) or mechanical (e.g., pipes, instrument lines, ventilation ducts) components. Cable tray FP barriers are a type of barrier that prevents the propagation of fire along the length of the cables. Ventilation ductfire barrier housings, located between adjacent fire areas, are an integral part of the FP barrier and therefore are included with the FP barriers. Fire doors, curbs, dikes, concrete, and masonry block walls are evaluated as part of the structure where they are located. Fire and alarm (e.g.,

smoke detectors), and fire suppression (e.g., automatic sprinklers, automatic halon systems)are evaluated in the FIR system. The diesel-driven fire pump is evaluated in both the FIR and the ESW systems.The FP barriers commodity group performs functions that support FP.

The intended function, within the scope of license renewal, is to provide a rated fire barrier.

2-117In LRA Table 2.4.5-1, the applicant identified the following FP barriers commodity groupcomponent types that are within the scope of license renewal and subject to an AMR:

  • carbon steel, low-alloy steel in air/gas (access tunnel FP guard pipe, fire damperhousings)
  • nonmetallic fireproofing in air/gas (cementitious fireproofing for coating structural steeland miscellaneous components)
  • nonmetallic fireproofing in air/gas (fibrous fire wraps, cementitious fireproofing (i.e.,pyrocrete, etc.))
  • nonmetallic fire proofing in air/gas (fibrous fire wraps, cementitious fireproofing (i.e.,pyrocrete, etc.), rigid board (i.e., gypsum board, etc.))
  • nonmetallic fire stop sealants in air/gas (fire stop sealants for EDG building)
  • nonmetallic fire stop sealants in air/gas (fire stop sealants for intake structure)
  • nonmetallic fire stop sealants in air/gas (fire stop sealants for reactor building, EFTbuilding, plant control, and cable spreading structure)
  • nonmetallic fire stop sealants in air/gas (fire stop sealants for turbine building)2.4.5.2 Staff Evaluation The staff reviewed LRA Section 2.4.5 and the USAR using the evaluation methodologydescribed in SER Section 2.4. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.4.In conducting its review, the staff evaluated the structural component functions described in theLRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had not omitted from the scope of license renewal any components with intendedfunctions delineated under 10 CFR 54.4(a). The staff then reviewed those components that theapplicant had identified as being within the scope of license renewal to verify that the applicanthad not omitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.4.5 identified an area for which it needed additionalinformation to complete its evaluation of the applicant's scoping and screening results. The applicant responded to the staff's RAI as discussed below.In RAI 2.4.5-1, dated September 28, 2005, the staff noted that Table 2.4.5-1 lists three identicalcomponent groups, "Non-metallic fire proofing in air/gas (...cementitious fireproofing, ...)," withidentical intended functions; therefore, the staff requested that the applicant explain the need tolist the same component group three times.In its response, by letter dated October 28, 2005, the applicant stated the following:To explain the difference between component groups, first an explanation of howTable 2.4.x-1 was assembled is needed. Tables in Section 2.4 of the LRA were 2-118assembled by copying the component group and intended functions for each3.5.2-x Table line entry into the 2.4.x-1 Table. This format was consistently usedthroughout the LRA. Many line entry component group descriptions appear similar but there are subtle differences that are evident upon review of the 3.5.2-x Table AMP, aging effects/mechanisms, material, etc.Table 2.4.5-1 component groups, 'non-metallic fire proofing in air/gas(cementitious fireproofing for coating structural steel and miscellaneous components),' 'non-metallic fire proofing in air/gas (fibrous fire wraps,cementitious fireproofing (i.e., pyrocrete, etc.)),' and 'non-metallic fire proofing inair/gas (fibrous fire wraps, cementitious fireproofing (i.e., pyrocrete, etc.), rigid board (i.e., gypsum board, etc.))' have different component group descriptions.

Review of Table 3.5.2-5 reveals that component groups were evaluated for agingeffects/mechanisms that were not applicable to all component groups.Based on its review, the staff found the applicant's response to RAI 2.4.5-1 acceptable. Theapplicant explained that (1) the component groups and intended functions in Section 2.4 tableswere copied from tables in Section 3.5 and (2) the aging effects/mechanisms listed in Table 3.5.2-5 were not applicable to all three components groups; therefore, the staff's concerndescribed 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 theapplicant had failed to identify any SSCs that should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequatelyidentified the FP barriers commodity group components that are within the scope of licenserenewal, as required by 10 CFR 54.4(a), and the FP barriers commodity group components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.4.6 Hangers and Supports Commodity Group 2.4.6.1 Summary of Technical Information in the ApplicationIn LRA Section 2.4.6, the applicant described the hangers and supports commodity group. Thehangers and supports commodity group contains component and equipment supports, pipe restraints, junction boxes, control panels, electrical raceways, and electrical conduit associated with plant systems and equipment that are within the scope of license renewal or are locatedwithin structures containing SR components. This commodity group includes the grout under the baseplate and fasteners used with the support or equipment anchorage. Generally,supports provide the connection betw een a system's equipment or component and a plantstructural member (e.g., wall, floor, ceiling, column, beam). They provide support for distributed loads (e.g., piping, tubing, HVAC ducting, conduit, cable trays) and localized loads (e.g.,

individual equipment). Specific types of equipment and components evaluated as part of this commodity group include: (1) pipe supports/restraints-includes all items used to support and/or restrain piping, (2) equipment supports-includes structural steel, fasteners (e.g., bolts, 2-119studs, nuts), and vibration mounts that secure equipment to structures, (3) HVAC ductsupports-includes structural steel and fasteners (e.g., bolts, studs, nuts) that support/attach ventilation duct to structures, (4) raceways-generic component type that is designed specifically for holding electrical wires and cables (e.g., cable trays, exposed and concealed metallic conduit or wireways), and (5) electrical enclosures-generic component type thatcontains electrical components (e.g., conduit, panels, boxes, cabinets, consoles, and bus ducts).The hangers and supports commodity group contains SR components that are relied upon toremain functional during and following DBEs. The failure of NSR SSCs in the hangers and supports commodity group could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the hangers and supports commodity group performs functions that support FP, ATWS, and SBO.The intended functions within the scope of license renewal include the following:

  • provide structural support to NSR components (civil and structural)
  • provide structural support to SR components (civil and structural)In LRA Table 2.4.6-1, the applicant identified the following hangers and supports commoditygroup component types that are within the scope of license renewal and subject to an AMR:
  • aluminum in air/gas (electrical junction boxes)
  • carbon steel, low-alloy steel in air/gas (anchorages of lighting fixtures and junctionboxes inside torus, includes support members, welds, bolted connections)
  • carbon steel, low-alloy steel in air/gas (anchorages of racks, panels, cabinets, andenclosures for electrical equipment and instrumentation; includes lighting fixtures, junction boxes, racks, panels, and cabinets outside torus, includes support members,welds, bolted connections, and support anchorage)
  • carbon steel, low-alloy steel in air/gas (cable trays, conduit, tube track outside torus)
  • carbon steel, low-alloy steel in air/gas (conduit, located inside torus)
  • carbon steel, low-alloy steel in air/gas (lighting fixtures and junction boxes inside torus)
  • carbon steel, low-alloy steel in air/gas (racks, panels, cabinets, lighting fixtures, junctionboxes outside torus)
  • carbon steel, low-alloy steel in air/gas (supports for American Society of MechanicalEngineers (ASME) Class 1 piping and components including RPV stabilizers (i.e.,constant and variable spring hangers, guides, stops, etc.))
  • carbon steel, low-alloy steel in air/gas (supports for ASME Class 1 piping andcomponents including RPV stabilizers, includes support members, welds, boltedconnections, and support anchorage)
  • carbon steel, low-alloy steel in air/gas (supports for ASME Class 2 and 3 piping andcomponents (i.e., constant and variable spring hangers, guides, stops, etc.))

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  • carbon steel, low-alloy steel in air/gas (supports for ASME Class 2 and 3 piping andcomponents, includes support members, welds, bolted connections, and support anchorage)
  • carbon steel, low-alloy steel in air/gas (supports for ASME Class MC components,includes torus seismic restraints, drywell male and female stabilizers, shield stabilizers,torus columns, torus saddles, vent system supports, downcomer bracing, includessupport members, welds, bolted connections and anchorages)
  • carbon steel, low-alloy steel in air/gas (supports for cable trays, conduit, HVAC ducts,tube track, instrument tubing, and non-ASME piping outside torus, includes support members, welds, bolted connections, and support anchorage)
  • carbon steel, low-alloy steel in air/gas (supports for mechanical equipment such as theEDG, HVAC components, pumps, fans, motors, turbines, etc., includes the splash hoods for the ESW pumps and the gas bottle racks, includes support members, welds,bolted connections, and support anchorage)
  • carbon steel, low-alloy steel in air/gas (supports for non-ASME piping, conduit, andcomponents located inside the torus, includes support members, welds, bolted connections)
  • carbon steel, low-alloy steel in atmosphere/weather (conduit for miscellaneous SBOyard structures, etc.)
  • carbon steel, low-alloy steel in atmosphere/weather (supports for conduit formiscellaneous SBO yard structures, etc., includes support members, welds, bolted connections, and support anchorage)
  • carbon steel, low-alloy steel in atmosphere/weather (supports for EFT tornado dampersand other miscellaneous mechanical equipment, includes support members, welds, bolted connections, and anchorage)
  • carbon steel, low-alloy steel in atmosphere/weather (supports for non-ASME piping,includes support members, welds, bolted connections, and support anchorage)
  • carbon steel, low-alloy steel in below grade (conduit for miscellaneous SBO yardstructures, etc.)
  • carbon steel, low-alloy steel in below grade (diesel fuel oil storage tank flood tie-downs)
  • carbon steel, low-alloy steel embedded in concrete (drywell support skirt anchorage,RPV female stabilizers)
  • carbon steel, low-alloy steel embedded in concrete (embedded conduit)
  • carbon steel, low-alloy steel in treated water (supports for ASME Class MC components(i.e., vent system supports, downcomer bracing) includes support members, welds)
  • carbon steel, low-alloy steel in treated water (supports for non-ASME piping andcomponents (i.e., HPC, RCI sparger supports, SRV T-quencher support, ECCS suction strainer supports, etc.) includes support members, welds, bolted connections)
  • concrete in air/gas (anchorage of racks, panels, cabinets, enclosures for electricalequipment and instrumentation, building concrete, grout pads) 2-121
  • concrete in air/gas (supports for ASME Class 1 piping and components, buildingconcrete, and grout pads)
  • concrete in air/gas (supports for ASME Class 2 and 3 piping and components, buildingconcrete, grout pads)
  • concrete in air/gas (supports for ASME Class MC components, building concrete, groutpads)
  • concrete in air/gas (supports for cable trays, conduit, HVAC ducts, tube track,instrument tubing, non-ASME piping and components, building concrete, grout pads)
  • concrete in air/gas (supports for EDG, HVAC system com ponents, and othermiscellaneous mechanical equipment, building concrete, grout pads)
  • concrete in atmosphere/weather (supports for conduit for miscellaneous SBO yardstructures, etc.; building concrete, grout pads)
  • concrete in atmosphere/weather (supports for EFT tornado dampers and othermiscellaneous mechanical equipment, building concrete, grout pads)
  • concrete in atmosphere/weather (supports for non-ASME piping and components,building concrete, grout pads)
  • concrete in below grade (diesel fuel oil storage tank deadmen)
  • elastomer sealants (rubber, neoprene, s ilicone, etc.) in air/gas (vibration isolationelements for ASME Class 1 piping and components)
  • elastomer sealants (rubber, neoprene, s ilicone, etc.) in air/gas (vibration isolationelements for ASME Class 2 and 3 piping and components)
  • elastomer sealants (rubber, neoprene, s ilicone, etc.) in air/gas (vibration isolationelements for ASME Class MC components)
  • elastomer sealants (rubber, neoprene, s ilicone, etc.) in air/gas (vibration isolationelements for EDG, HVAC system components, and other miscellaneous mechanicalequipment)
  • fiberglass in air/gas (electrical junction boxes)
  • lubrite in air/gas (sliding surfaces for ASME Class 1 piping and components)
  • lubrite in air/gas (sliding surfaces for ASME Class 2 and 3 piping and components)
  • lubrite in air/gas (sliding surfaces for torus saddles)
  • plastic in air/gas (electrical junction boxes)
  • stainless steel in air/gas (supports for ASME Class 1 piping and components includingRPV stabilizers, clamps etc.)
  • stainless steel in air/gas (supports for ASME Class 2 and 3 piping and components,clamps, etc.)
  • stainless steel in air/gas (supports for ASME Class MC components (i.e., vent headercolumn support pins))

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  • stainless steel in air/gas (supports for tube track, instrument tubing, non-ASME pipingand components; clamps, etc.)
  • stainless steel in treated water (supports for ASME Class MC components (i.e., ventheader column support pins))2.4.6.2 Staff Evaluation The staff reviewed LRA Section 2.4.6 and the USAR using the evaluation methodologydescribed in SER Section 2.4. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.4.In conducting its review, the staff evaluated the structural component functions described in theLRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had not omitted from the scope of license renewal any components with intendedfunctions delineated under 10 CFR 54.4(a). The staff then reviewed those components that theapplicant had identified as being within the scope of license renewal to verify that the applicanthad not omitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.4.6 identified areas for which it needed additionalinformation to complete its evaluation of the applicant's scoping and screening results. The applicant responded to the staff's RAIs as discussed below.In RAI 2.4.6-1, dated September 28, 2005, the staff noted that after the "System FunctionListing," the applicant referred to Sections 12.2.1.2 and 12.2.1.3 of the USAR for additionalhangers and supports commodity group details. The staff's review of the USAR sections indicates that the SSCs are classified as Class I and Class II with definitions noticeably different from Criteria 1, 2, and 3 in 10 CFR 54.4(a); therefore, the staff requested that the applicantclarify how it reconciled the CLB classification in the system function listing in LRASection 2.4.6.In its response, dated October 28, 2005, the applicant stated that LRA Section 2.1.4.2 and theadditional comment clarify how the CLB classification of SSCs was reconciled. LRA Section 2.1.4.2 states the following:Numerous sources, including the MNGP USAR, docketed correspondence withthe NRC, Maintenance Rule documents, and DBDs provi ded system andstructure-level function information. Documentation of references used in this process was included for eac h system function as appropriate.The process used at the MNGP identified all system-level and structure-levelfunctions. If the functions met any of the criteria specified in 10 CFR Part 54.4(a)(1), (2), or (3), t hen the system or structure was in-scope forLR...The applicant further stated that even though USAR Class I and II designations are significantlydifferent from 10 CFR 54.4 designations, SSCs were still within the scope of license renewal, inaccordance with the criteria in 10 CFR 54.4(a).

2-123Based on its review, the staff found the applicant's response to RAI 2.4.6-1 acceptable. Withthe applicant's clarification, the staff recognized the methods used to reconcile SR SSCs andfound the applicant's method of compliance with the requirements of 10 CFR 50.54 acceptable;therefore, the staff's concern described in RAI 2.4.6-1 is resolved.In RAI 2.4.6-2, dated September 28, 2005, the staff noted that Table 2.4.6-1 line item "carbonsteel, low-alloy steel in air/gas," identifies a number of supports/anchorages as ASME Class MC supports and some are identified as non-ASME support components; therefore, the staff requested that the applicant clarify the classification of component supports inside and outsidethe torus (some may be non-ASME) and specifically, the classification of the support system forthe torus. The staff assumed that the torus support system is classified as Class MC supportsand that all its components are inspected by the requirements of ASME Section XI, Subsection IWF. After reviewing LRA Table 3.5.2-6, it was not obvious how the applicant had treated these supports; therefore, the staff requested that the applicant provide clarifications.In its response, by letter dated October 28, 2005, the applicant stated that the torus supportsinclude torus columns, torus saddles, and torus seismic restraints and pointed out that LRA Table 3.5.2-6, page 3-675, indicates that these supports located on the outside of the torus areclassified as ASME Class MC and will be managed by the ASME Section XI, Subsection IWFProgram. For the remaining torus system support components, the applicant provided anabridged list extracted from Table 3.5.2-6 which provided classifications and locations of these supports.Based on its review, the staff found the applicant's response to RAI 2.4.6-2 acceptable. Theresponse asserted the staff's assumption that all torus supports on the outside of the torus are classified as Class MC supports and are inspected in accordance with the requirements of Section XI, Subsection IWF, of the ASME code. The applicant also clarified that either the Primary Containment In-Service Inspection Program (i.e., ASME Code Section XI, Subsection IWE) or ASME Code Section XI, Subsection NF provides aging management of the remaining supports. The staff considered the applicant's approach logical and acceptable; therefore, the staff's concern described in RAI 2.6.4-2 is resolved.In RAI 2.4.6-3, dated September 28, 2005, the staff noted that Table 2.4.6-1 lists "Carbon steel,low-alloy steel in atmosphere/weather (bolted connections and anchorage)" as a component group and "Carbon steel, low-alloy steel in atmosphere/weather (bolted connections and support anchorage)" as another. The only difference between the two component groups is that one group lists "anchorage" and the other "support anchorage." Therefore, the staff requested that the applicant explain the difference between "anchorage" and "support anchorage" andprovide examples of each.In its response, by letter dated October 28, 2005, the applicant explained that the line entry inLRA Table 2.4.6-1 containing the word "anchorage" also could have included the word "support" before "anchorage" in the description to be consistent with similar entries. The word, "anchorage" alone, however, is sufficient to convey the intent. The applicant further explained that "anchorage" and "support anchorage" refer to components used to secure (i.e., anchor) the support to the concrete surface and include concrete anchors of various types and associated components like nuts and washers.

2-124Based on its review, the staff found the applicant's response to RAI 2.4.6-3 acceptable becausethe applicant adequately explained that the two terms are defined the same and their intendedfunctions are the same. Therefore, the staff's concern described in RAI 2.4.6-3 is resolved.2.4.6.3 Conclusion The staff reviewed the LRA and related structural components to determine whether theapplicant had failed to identify any SSCs that should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequatelyidentified the hangers and supports commodity group components that are within the scope oflicense renewal, as required by 10 CFR 54.4(a), and the hangers and supports commodity group components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.4.7 HPCI Building 2.4.7.1 Summary of Technical Information in the ApplicationIn LRA Section 2.4.7, the applicant described the HPCI building. The principal functions of theHPCI building are to enclose the HPCI turbine and pumps and protect the equipment from weather, tornado, and seismic effects. The building is a Class 1 structure and is part of the secondary containment of the reactor building. The HPCI building is a reinforced concrete structure constructed monolithically with the reactor building. The structure is supported by a reinforced concrete mat which is an extension of the reactor building mat.The HPCI building contains SR components that are relied upon to remain functional duringand following DBEs. The failure of NSR SSCs in the HPCI building could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the HPCI building performs functions that support SBO.The intended functions within the scope of license renewal include the following:

  • provide flood protection barrier
  • provide missile barrier
  • provide structural support to NSR components (civil and structural)
  • provide pressure boundary of essentially leaktight barrier (civil and structural)
  • provide shielding against radiation
  • provide structural support to SR components (civil and structural)
  • provide shelter/protection to SR componentsIn LRA Table 2.4.7-1, the applicant identified the following HPCI building component types thatare within the scope of license renewal and subject to an AMR:
  • carbon steel, low-alloy steel in air/gas (structural steel, steel embeds, etc.)

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  • carbon steel, low-alloy steel in air/gas (supports for miscellaneous structures (i.e.,members, welds, bolted connections, support anchorage for platforms, stairs, etc.))
  • carbon steel, low-alloy steel in atmosphere/weather (roof hatch)
  • concrete in air/gas (foundation, walls, slab)
  • concrete in air/gas (foundation, walls, slab, grout)
  • concrete in atmosphere/weather (slab, roof hatch)
  • concrete in below grade (foundation, walls)
  • elastomer sealants (rubber, neoprene, s ilicone, etc.) in air/gas (roof hatch seals)
  • elastomer sealants (rubber, neoprene, s ilicone, etc.) in atmosphere/weather (roof hatchseals)2.4.7.2 Staff Evaluation The staff reviewed LRA Section 2.4.7 and the USAR using the evaluation methodologydescribed in SER Section 2.4. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.4.In conducting its review, the staff evaluated the structural component functions described in theLRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had not omitted from the scope of license renewal any components with intendedfunctions delineated under 10 CFR 54.4(a). The staff then reviewed those components that theapplicant had identified as being within the scope of license renewal to verify that the applicanthad not omitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.4.7.3 Conclusion The staff reviewed the LRA and related structural components to determine whether theapplicant failed to identify any SSCs that should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequatelyidentified the HPCI building components that are within the scope of license renewal, asrequired by 10 CFR 54.4(a), and the HPCI building components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.4.8 Intake Structure 2.4.8.1 Summary of Technical Information in the ApplicationIn LRA Section 2.4.8, the applicant described the intake structure. The intake structure isbasically a chambered box of reinforced concrete construction. Essentially, the intake structure consists of four 13-foot 8-inch bays with an invert at the intake end which converges to a two-2-126section suction chamber at the discharge end. A CWT pump is mounted over each suctionchamber. The roof of the structure is approximately 4 feet 3 inches above grade and consists of reinforced concrete beam and slab framing. The intake structure contains an operating floor on which the EDG-ESW, ESW, and RHR service water subsystem pumps are mounted. Exteriorand interior walls and slabs are constructed of reinforced concrete and provide support for the operating floor and roof framing. The structure is supported on a mat foundation 3 feet 6 inches in thickness that was placed on a lean concrete fill which overlays a layer of cementedsandstone. The intake structure also includes the access tunnel between the turbine building and the intake structure, as well as the diesel fire pump house which sits on top of the intake structure at the east end. The diesel fire pump house contains the diesel fire pump and the diesel fire pump day tank. The diesel fire pump house is constructed of concrete masonry block walls with an insulated steel deck roof supported by structural steel beams.The intake structure contains SR components that are relied upon to remain functional duringand following DBEs. The failure of NSR SSCs in the intake structure could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal.

In addition, the intake structure performs functions that support FP.The intended functions within the scope of license renewal include the following:

  • provide source of cooling water for plant shutdown
  • provide flood protection barrier
  • provide missile barrier
  • provide structural support to NSR components (civil and structural)
  • provide structural support to SR components (civil and structural)
  • provide shelter/protection to SR componentsIn LRA Table 2.4.8-1, the applicant identified the following intake structure component typesthat are within the scope of license renewal and subject to an AMR:
  • carbon steel, low-alloy steel in air/gas (doors, structural steel, steel embeds, etc.)
  • carbon steel, low-alloy steel in air/gas (supports for miscellaneous structures (i.e.,members, welds, bolted connections, support anchorage for platforms, stairs, etc.))
  • carbon steel, low-alloy steel in atmosphere/weather (structural steel, sheet piles,ventilation assemblies)
  • carbon steel, low-alloy steel in below grade (sheet piles)
  • carbon steel, low-alloy steel in raw water (structural steel, sheet piles)
  • carbon steel, low-alloy steel in raw water (supports for miscellaneous structures (i.e.,members, welds, bolted connections, support anchorage for platforms, stairs, etc.))
  • concrete in air/gas (foundation, walls, slabs)
  • concrete in air/gas (foundation, walls, slabs, grout)
  • concrete in air/gas (walls, slabs)
  • concrete in atmosphere/weather (intake structure and access tunnel roof slabs) 2-127
  • concrete in atmosphere/weather (walls, slabs)
  • concrete in below grade (foundation, walls, lean concrete)
  • concrete in raw water (foundation, walls, slabs)
  • masonry walls in air/gas
  • masonry walls in atmosphere/weather2.4.8.2 Staff Evaluation The staff reviewed LRA Section 2.4.8 and the USAR using the evaluation methodologydescribed in SER Section 2.4. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.4.In conducting its review, the staff evaluated the structural component functions described in theLRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had not omitted from the scope of license renewal any components with intendedfunctions delineated under 10 CFR 54.4(a). The staff then reviewed those components that theapplicant had identified as being within the scope of license renewal to verify that the applicanthad not omitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.4.8.3 Conclusion The staff reviewed the LRA and related structural components to determine whether theapplicant had failed to identify any SSCs that should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequatelyidentified the intake structure components that are within the scope of license renewal, asrequired by 10 CFR 54.4(a), and the intake structure components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.4.9 Miscellaneous SBO Yard Structures 2.4.9.1 Summary of Technical Information in the ApplicationIn LRA Section 2.4.9, the applicant described the miscellaneous SBO yard structures. Themiscellaneous SBO yard structures are those yard structures that provide support for equipment relied upon for recovery from an SBO. These structures are listed below:
  • the foundations and transformer structures for 1R, 2R, 1AR, and 2RS transformers
  • the 345-kV control house
  • the towers/foundation for the 1N2, 1N6, 5N5, 5N7, 8N4, and 8N11 breakers
  • the towers/foundations for the bus bars between the 2RS transformer and the 8N4 and8N11 breakers, this includes the tower/foundation for the 3N4 breaker, 3N5 fused 2-128disconnect, the current limiting protector, and the towers/foundations to the 1ARSmotor-operated disconnect
  • the towers/foundations for the bus bars for the 5N5 and 5N7 breakers, including thewest four rows of columns and the beams that connect them together.
  • the Trenwa trenches connecting the control house to the 115-kV ring bus
  • the Trenwa trenches connecting the control house to the 345-kV ring bus
  • the electrical duct bank from the 1N2 breaker to the 1AR transformer
  • the tower/foundation for the bus 1, 115-kV potential transformer
  • the three 115- kV transmission towers along the west owner-controlled area fencebetween the switchyard and the 1R transformer and the first transmission tower northwest of the plant
  • the block walls surrounding the 1R and 2R transformersThe miscellaneous SBO yard structures perform functions that support SBO.

The intended function, within the scope of license renewal, is to provide structural support toNSR components (civil and structural).In LRA Table 2.4.9-1, the applicant identified the following miscellaneous SBO yard structurescomponent types that are within the scope of license renewal and subject to an AMR:

  • carbon steel, low-alloy steel in air/gas (345-kV house structural steel)
  • carbon steel, low-alloy steel in air/gas (supports for 345-kV house miscellaneous steel(i.e., members, welds, bolted connections, support anchorage))
  • carbon steel, low-alloy steel in atmosphere/weather (anchorages)
  • carbon steel, low-alloy steel in atmosphere/weather (structural steel for 345-kV house,switchyard, and transmission towers, etc.)
  • concrete in air/gas (345-kV house concrete)
  • concrete in atmosphere/weather (345-kV house concrete, foundations)
  • concrete in atmosphere/weather (345-kV house, foundations, trenches, duct bank,grout)
  • concrete in below grade (345-kV house, foundations, trenches, duct bank)
  • masonry walls in atmosphere/weather2.4.9.2 Staff Evaluation The staff reviewed LRA Section 2.4.9 and the USAR using the evaluation methodologydescribed in SER Section 2.4. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.4.

2-129In conducting its review, the staff evaluated the structural component functions described in theLRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had not omitted from the scope of license renewal any components with intendedfunctions delineated under 10 CFR 54.4(a). The staff then reviewed those components that theapplicant had identified as being within the scope of license renewal to verify that the applicanthad not omitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.4.9.3 Conclusion The staff reviewed the LRA and related structural components to determine whether theapplicant had failed to identify any SSCs that should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequatelyidentified the miscellaneous SBO yard structures components that are within the scope oflicense renewal, as required by 10 CFR 54.4(a), and the miscellaneous SBO yard structures components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.4.10 Offgas Stack 2.4.10.1 Summary of Technical Information in the ApplicationIn LRA Section 2.4.10, the applicant described the offgas stack. The function of the offgasstack is to provide for controlled release and dispersal of gaseous radioactive wastes. The stack is a free-standing, tapered, reinforced concrete structure which encloses and supports an independent gas flue. The overall height of the stack above adjacent grade is 328 feet. The internal diameter of the concrete shell is 7 feet at the top and 32 feet at the 946-foot 6-inchelevation, with thickness varying from 7 inches at the top to 10 inches at the 946-foot 6-inchelevation. Below the 946-foot 6-inch elevation to the top of the foundation at the 932-foot 6-inchelevation, the stack shell is a polygon having a maximum inscribed diameter of 34 feet. The wall thickness varies in accordance with radiation shielding requirements. The stack shell is supported on a 4-foot-thick octagonal spread footing with a 1-foot 6-inch pedestal. The independent gas flue is 18 inches in diameter reducing to 14 inches in diameter at the top.The offgas stack contains SR components that are relied upon to remain functional during andfollowing DBEs. The failure of NSR SSCs in the offgas stack could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal.The intended functions within the scope of license renewal include the following:

  • provide flood protection barrier
  • provide path for release of filtered and unfiltered gaseous discharge
  • provide structural support to NSR components (civil and structural)
  • provide shielding against radiation
  • provide structural support to SR components (civil and structural)
  • provide shelter/protection to SR components 2-130In LRA Table 2.4.10-1, the applicant identified the following offgas stack component types thatare within the scope of license renewal and subject to an AMR:
  • carbon steel, low-alloy steel in air/gas (structural steel, steel embeds, etc.)
  • carbon steel, low-alloy steel in air/gas (supports for miscellaneous structures (i.e.,members, welds, bolted connections, support anchorage for platforms, stairs, etc.))
  • carbon steel, low-alloy steel in atmosphere/weather (doors)
  • concrete in air/gas (pedestal, walls, slabs)
  • concrete in air/gas (pedestal, walls, slabs, grout)
  • concrete in atmosphere/weather (pedestal, walls)
  • concrete in below grade (pedestal)
  • masonry walls in air/gas
  • stainless steel in air/gas (cap)
  • stainless steel in atmosphere/weather (cap)2.4.10.2 Staff Evaluation The staff reviewed LRA Section 2.4.10 and the USAR using the evaluation methodologydescribed in SER Section 2.4. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.4.In conducting its review, the staff evaluated the structural component functions described in theLRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had not omitted from the scope of license renewal any components with intendedfunctions delineated under 10 CFR 54.4(a). The staff then reviewed those components that theapplicant had identified as being within the scope of license renewal to verify that the applicanthad not omitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.4.10.3 Conclusion The staff reviewed the LRA and related structural components to determine whether theapplicant had failed to identify any SSCs that should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequatelyidentified the offgas stack components that are within the scope of license renewal, as requiredby 10 CFR 54.4(a), and the offgas stack components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2-1312.4.11 Offgas Storage and Compressor Building2.4.11.1 Summary of Technical Information in the ApplicationIn LRA Section 2.4.11, the applicant described the offgas storage and compressor building. Theoffgas storage building, except for the fan and foyer room portions, was designed for Class 1 seismic conditions and flood conditions, as well as for tornado wind loads and missiles. The only portion of the offgas stor age system which currently has seismic design requirements arethe storage tanks and the attached piping up to the first isolation valve. The building meets allFederal, State, and local codes applicable to industrial process buildings. The building is constructed of reinforced concrete on a suitable foundation and is situated near the base of the offgas stack. The fan and foyer room portions of the offgas storage building provide Class 1-level protection for all external events in which the enclosed equipment is required to perform an SR function. This includes Class 1 dead, live (snow and floor), and wind loads. It does not include seismic or tornado loads or tornado-generated missiles.The offgas storage and compressor building contains SR components that are relied upon toremain functional during and following DBEs. The failure of NSR SSCs in the offgas storage and compressor building could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal.The intended functions within the scope of license renewal include the following:

  • provide structural support to NSR components (civil and structural)
  • provide structural support to SR components (civil and structural)In LRA Table 2.4.11-1, the applicant identified the following offgas storage and compressorbuilding component types that are within the scope of license renewal and subject to an AMR:
  • carbon steel, low-alloy steel in air/gas (structural steel)
  • concrete in air/gas (foundation, walls, slabs)
  • concrete in air/gas (foundation, walls, slabs, grout)
  • concrete in atmosphere/weather (walls, slabs)
  • concrete in below grade (foundation, walls)2.4.11.2 Staff Evaluation The staff reviewed LRA Section 2.4.11 and the USAR using the evaluation methodologydescribed in SER Section 2.4. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.4.In conducting its review, the staff evaluated the structural component functions described in theLRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had not omitted from the scope of license renewal any components with intendedfunctions delineated under 10 CFR 54.4(a). The staff then reviewed those components that theapplicant had identified as being within the scope of license renewal to verify that the applicanthad not omitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).

2-1322.4.11.3 ConclusionThe staff reviewed the LRA and related structural components to determine whether theapplicant had failed to identify any SSCs that should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequatelyidentified the offgas storage and compressor building components that are within the scope oflicense renewal, as required by 10 CFR 54.4(a), and the offgas storage and compressor building components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.4.12 Plant Control and Cable Spreading Structure 2.4.12.1 Summary of Technical Information in the ApplicationIn LRA Section 2.4.12, the applicant described the plant control and cable spreading structure.The primary functions of this structure are to provide, under all operating or postulated accident conditions, safe enclosure for those portions of the standby electrical power systems and I&Csystems vital to overall plant operation and safety which are located therein, as well as anenvironment satisfactory for continuous occupancy by operating personnel. The plant control and cable spreading structure is located at the north end of the original office and control building and includes the MCR, cable spreading room, and battery room. The administration building is located adjacent to the east side of the original office and control building. The original office and control building, as well as the administration building, constitute the plant control and cable spreading structure. The administration building provides a records storage area to meet the requirements of American National Standards Institute (ANSI) N45.2.9,training space, lockers and restroom facilities, an instrument shop, library space, a meetingroom, shift supervisor's office, open office space, and private offices. Modifications to the shift supervisor's office have been made so that the office is part of the MCR for the purpose of meeting the NRC's requirement for the presence of a senior licensed operator in the controlroom at all times. The shift supervisor's office is located immediately adjacent to the MCR, but outside the previously defined control room boundary.The plant control and cable spreading structure contains SR components that are relied upon toremain functional during and following DBEs. The failure of NSR SSCs in the plant control and cable spreading structure could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the plant control and cable spreading structure performs functions that support FP, ATWS, and SBO.The intended functions within the scope of license renewal include the following:

  • provide flood protection barrier
  • provide missile barrier
  • provide structural support to NSR components (civil and structural)
  • provide structural support to SR components (civil and structural)
  • provide shelter/protection to SR components 2-133In LRA Table 2.4.12-1, the applicant identified the following plant control and cable spreadingstructure component types that are within the scope of license renewal and subject to an AMR:
  • carbon steel, low-alloy steel in air/gas (fire-rated doors)
  • carbon steel, low-alloy steel in air/gas (structural steel, steel embeds, etc.)
  • carbon steel, low-alloy steel in air/gas (supports for miscellaneous structures (i.e.,members, welds, bolted connections, support anchorage for platforms, stairs, etc.))
  • concrete in air/gas (foundation, walls, slabs)
  • concrete in air/gas (foundation, walls, slabs, grout)
  • concrete in air/gas (walls, slabs)
  • concrete in atmosphere/weather (walls, slabs)
  • concrete in below grade (foundation, walls)
  • elastomer sealants (rubber, neoprene, s ilicone, etc.) in air/gas (control room seals)
  • masonry walls in air/gas2.4.12.2 Staff Evaluation The staff reviewed LRA Section 2.4.12 and the USAR using the evaluation methodologydescribed in SER Section 2.4. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.4.In conducting its review, the staff evaluated the structural component functions described in theLRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had not omitted from the scope of license renewal any components with intendedfunctions delineated under 10 CFR 54.4(a). The staff then reviewed those components that theapplicant had identified as being within the scope of license renewal to verify that the applicanthad not omitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.4.12.3 Conclusion The staff reviewed the LRA and related structural components to determine whether theapplicant had failed to identify any SSCs that should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant had adequatelyidentified the plant control and cable spreading structure components that are within the scopeof license renewal, as required by 10 CFR 54.4(a), and the plant control and cable spreading structure components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2-1342.4.13 Primary Containment2.4.13.1 Summary of Technical Information in the ApplicationIn LRA Section 2.4.13, the applicant described the primary containment (PCT) system. ThePCT system includes the drywell, the wetwell (torus), the primary containment penetrations, thebioshield wall, the RPV support pedestal, the drywell/torus internal platforms, and the torus external catwalk. The mechanical portion of the primary containment system is included in thePCM system. The PCT system provides a barrier to the release of fission products to the SCTand rapidly reduces the pressure in primary containment after a LOCA. The system consistsof a light-bulb-shaped drywell, a torus-shaped wetwell, and a connecti ng vent system betweenthe drywell and the wetwell. The system encloses the reactor vessel, the reactor coolantrecirculation loops, and various branch connections of the reactor primary system. The drywellis a steel pressure vessel with a spherical lower portion and a cylindrical upper portion. The personnel airlock provides an entrance to the drywell measuring 6 feet by 2.5 feet. The wetwell is a steel pressure vessel in the shape of a torus located below and encircling the drywell.

Penetrations through the drywell and wetwell walls provide for passage of fluid piping and electrical cables. These penetrations are designed to withstand environmental conditions present during a LOCA and to maintain primary containment integrity for extended periods oftime in a post-accident environment. Piping penetrations consist of pipe segments welded into structurally enhanced containment shell plates. Piping penetrations are of two general types-sleeved, those for which the process flow is not in contact with the original penetrationpipe segments, and unsleeved, those for which the process flow is in contact with the originalpenetration pipe segments.The PCT system contains SR components that are relied upon to remain functional during andfollowing DBEs. The failure of NSR SSCs in the PCT system could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the PCT system performs functions that support FP, ATWS, and SBO.The intended functions within the scope of license renewal include the following:

  • provide source of cooling water for plant shutdown
  • provide flood protection barrier
  • provide heat sink during DBAs
  • provide shielding against HELBs
  • provide missile barrier
  • provide structural support to NSR components (civil and structural)
  • provide pressure boundary of essentially leaktight barrier (civil and structural)
  • provide shielding against radiation
  • provide structural support to SR components (civil and structural)
  • provide pipe whip restraintIn LRA Table 2.4.13-1, the applicant identified the following PCT system com ponent types thatare within the scope of license renewal and subject to an AMR:
  • carbon steel, low-alloy steel in air/gas (drywell, torus, drywell head, drywell head bolts,torus ring girder, downcomers, vent lines, vent header, bellows assemblies, vent header deflectors, ECCS suction header)
  • carbon steel, low-alloy steel in air/gas (personnel airlock, equipment hatch, CRD hatch,seismic restraint, inspection ports)
  • carbon steel, low-alloy steel in air/gas (personnel airlock, equipment hatch, CRD hatch,seismic restraint, inspection ports, including locks, hinges, and closure mechanisms)
  • carbon steel, low-alloy steel in air/gas (structural steel (i.e., torus external catwalk,drywell interior platforms, bioshield wall liners, etc.))
  • carbon steel, low-alloy steel in air/gas (structural steel inside torus (i.e., torus internalcatwalk, etc.))
  • carbon steel, low-alloy steel in air/gas (supports for miscellaneous structures, includingplatforms, stairs, and whip restraints, etc. (i.e., members, welds, bolted connections, support anchorage to building structure))
  • carbon steel, low-alloy steel embedded in concrete (drywell support skirt, embeddedshell)
  • carbon steel, low-alloy steel in treated water (structural steel)
  • carbon steel, low-alloy steel in treated water (support members, welds, boltedconnections (i.e., torus internal catwalk support columns))
  • carbon steel, low-alloy steel in treated water (torus, torus ring girder, downcomers,ECCS suction header)
  • concrete in air/gas (bioshield wall, drywell equipment foundation, RPV pedestal)
  • elastomer sealants (rubber, neoprene, s ilicone, etc.) in air/gas (moisture barriers)
  • elastomer sealants (rubber, neoprene, s ilicone, etc.) in air/gas (seals and gaskets)
  • lubrite in air/gas (drywell head, downcomers)
  • lubrite in air/gas (drywell interior platform sliding plates)
  • lubrite in treated water (downcomers)
  • stainless steel in air/gas (RPV to drywell refueling seal)
  • stainless steel in air/gas (vent line bellows)
  • stainless steel in treated water (thermowells) 2-1362.4.13.2 Staff EvaluationThe staff reviewed LRA Section 2.4.13 and the USAR using the evaluation methodologydescribed in SER Section 2.4. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.4.In conducting its review, the staff evaluated the structural component functions described in theLRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had not omitted from the scope of license renewal any components with intendedfunctions delineated under 10 CFR 54.4(a). The staff then reviewed those components that theapplicant had identified as being within the scope of license renewal to verify that the applicanthad not omitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.4.13 identified areas for which it needed additionalinformation to complete its evaluation of the applicant's scoping and screening results. The applicant responded to the staff's RAIs as discussed below.In RAI 2.4.13-1, dated September 28, 2005, the staff requested that the applicant clarifywhether the supports and components included in Code PCT-04 of the system function listingare within the scope of license renewal. The staff requested that the applicant provide asummary listing of these supports and components and a confirmation that their failure under earthquake-induced loads would not affect the functioning of SR SSCs.In its response, by letter dated October 28, 2005, the applicant explained the following:System function Primary Containment (PCT)-04 referred only to non-safetyrelated components that could not affect safety related SSCs. Components associated with this function are not in scope of license renewal. The function for non-safety related components that could affect safety related components is Primary Containment-Non-Safety Affecting Safety (PCT-NSAS), evaluated on page 2-225 of the LRA. Functions associated with component supports are further addressed in Section 2.4.6, 'Hangers and Supports Commodity Group.'

The PCT-04 function was evaluated against the criteria of 10 CFR 54.4(a) and found not to meet any of its requirements. Consequently, the function was provided for information and completeness only, since it did not form a basis for including the primary containment structure within the scope of the Rule. This scoping methodology was consistently used through Section 2 of the LRA.Based on its review, the staff found the applicant's response to RAI 2.4.13-1 acceptable. Theclarification asserts that the components included in the PCT-04 group are not SR and wouldnot affect the integrity of SR SSCs under postulated seismic events; therefore, the staff'sconcern described in RAI 2.4.13-1 is resolved.In RAI 2.4.13-2, dated September 28, 2005, the staff noted that the second and thirdcomponent groups in Table 2.4.13-1 list almost identical components (drywell, torus, drywell head, drywell head bolts, torus ring girder, downcomers, vent lines, vent header, bellows assembly, ECCS suction header) with the same material-environment combination (carbon steel/low-alloy steel in air/gas) and intended functions. A similar redundancy was noted on the 2-137first two component groups on page 2-257 (personnel airlock, equipment hatch, CRD hatch,seismic restraint, and inspection ports). Therefore, the staff requested that the applicant clarifythese redundancies.In its response, by letter dated October 28, 2005, the applicant stated the following:To explain the apparent redundancies between components, first an explanationof how Table 2.4.13-1 was assembled is needed to explain the apparent redundancies between components. Tables in Section 2.4 of the LRA were assembled by copying the component group and intended functions for each 3.5.2-x Table line entry into the 2.4.x-1 Table. This format was consistently usedthroughout the LRA. Many line entry component group descriptions appear similar but there are subtle differences that are evident upon review of the 3.5.2-x Table AMP, aging effects/mechanisms, material, etc.For this specific question, Table 2.4.13-1 component groups, 'carbon steel, lowalloy steel in air/gas (drywell, torus, drywell head, drywell head bolts, torus ring girder, downcomers, vent lines, vent header, bellows assemblies, ECCS suction header)' and 'carbon steel, low alloy steel in air/gas (drywell, torus, drywell head, drywell head bolts, torus ring girder, downcomers, vent lines, vent header, bellows assemblies, vent header deflectors, ECCS suction header)' have different component group descriptions (one component group includes vent header deflectors and the other does not). Review of Table 3.5.2-13 reveals thatthe component group without vent header deflectors is managed by 10 CFR 50, Appendix J while the group with vent header deflectors is managed by the Primary Containment In-Service Inspection Program. This is because the vent header deflectors do not perform a pressure retaining function associated with an Appendix J test.For part two of this question, Table 2.4.13-1 component groups, 'carbon steel,low alloy steel in air/gas (personnel airlock, equipment hatch, [Control Rod Drive]

CRD hatch, seismic restraint inspection ports)' and 'carbon steel, low alloy steelin air/gas (personnel airlock, equipment hatch, CRD hatch, seismic restraintinspection ports, including locks, hinges and closure mechanisms)' have differentcomponent group descriptions. Review of Table 3.5.2-13 reveals that the component group with locks, hinges, and closure mechanisms is managed for adifferent aging effect, 'loss of leak tightness in closed position' in accordance with NUREG-1801 line item II.B4.2-b.Based on its review, the staff found the applicant's response to RAI 2.4.13-2 acceptable. Thepurpose of scoping is to ensure that all SSCs that are within the scope of license renewal pursuant to 10 CFR 54.4 first be identified clearly and then, while performing an AMR, the applicant identifies the relevant material and environment. In this application, the applicant usedthe reverse method; however, the explanation ensures that the applicant has not missed anyimportant SSCs from the scope of license renewal. After reviewing the applicant's approach, the staff understood the reason for the redundancies and found the approach acceptable; therefore, the staff's concern described in RAI 2.4.13-2 is resolved.

2-138In RAI 2.4.13-3, dated September 28, 2005, the staff also noted that Table 2.4.13-1 lists thecomponent group, "lubrite in air/gas," with the drywell head included as a component. In the description of drywell head, the applicant stated, "The head is held in place by bolts and sealed with a double gasket arrangement." Therefore, the staff requested that the applicant clarifywhere the lubrite bearings are used in the drywell head.In its response, by letter dated October 28, 2005, the applicant provided the followinginformation:Lubrite type material is not used for the drywell head or downcomers.Table 2.4.13-1, page 2-260 included this component group, 'lubrite in air/gas (drywell head and downcomers)' because tables in Section 2.4 of the LRA were assembled by copying the component group and intended functions for each Table 3.5.2-13 line entry into Table 2.4.13-1. Table 3.5.2-13 included this entryto demonstrate that NUREG-1801 line item II.B1.1.1-e was evaluated forapplicability. The evaluation provided in Table 3.5.2-13 stated that, 'The drywellhead and downcomer pipes are carbon steel material. Graphite plate material is not used for these components and therefore the aging effect is not applicable'(see LRA note 556). Therefore the description of the drywell head in the LRA, page 2-251 is consistent with note 556 in Table 3.5.2-13.Based on its review, the staff found the applicant's response to RAI 2.4.13-3 acceptable. Thestaff found that the applicant's approach covers all the components subject to AMR; therefore,the staff's concern described in RAI 2.4.13-3 is resolved.2.4.13.3 Conclusion The staff reviewed the LRA and related structural components to determine whether theapplicant had failed to identify any SSCs that should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequatelyidentified the PCT system components that are within the scope of license renewal, as requiredby 10 CFR 54.4(a), and the PCT system components that are subject to an AMR, as requiredby 10 CFR 54.21(a)(1).2.4.14 Radioactive Waste Building 2.4.14.1 Summary of Technical Information in the ApplicationIn LRA Section 2.4.14, the applicant described the radioactive waste building. The radioactivewaste building is located adjacent to the south side of the reactor building. The building is usedfor storage of contaminated materials, such as spent ion exchange resins, filters, anti-C clothing, and contaminated materials. The railroad car airlock and the airlock between thereactor building and the radioactive waste building are part of secondary containment. The radioactive waste building is a reinforced concrete structure supported on a concrete slab. The radioactive waste building was designed such that it would not fail during an earthquake. It is also designed to protect the reactor building from external floods.

2-139The radioactive waste building contains SR components that are relied upon to remainfunctional during and following DBEs. The failure of NSR SSCs in the radioactive waste building could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal.The intended functions within the scope of license renewal include the following:

  • provide flood protection barrier
  • provide shielding against HELBs
  • provide structural support to NSR components (civil and structural)
  • provide pressure boundary of essentially leaktight barrier (civil and structural)
  • provide shielding against radiation
  • provide structural support to SR components (civil and structural)
  • provide shelter/protection to SR componentsIn LRA Table 2.4.14-1, the applicant identified the following radioactive waste buildingcomponent types that are within the scope of license renewal and subject to an AMR:
  • carbon steel, low-alloy steel in air/gas (air lock and railroad doors)
  • carbon steel, low-alloy steel in air/gas (structural steel)
  • carbon steel, low-alloy steel in atmosphere/weather (railroad door)
  • concrete in air/gas (foundation, walls, slabs)
  • concrete in air/gas (foundation, walls, slabs, grout)
  • concrete in atmosphere/weather (walls, slabs)
  • concrete in below grade (foundation, walls)
  • elastomer sealants (rubber, neoprene, s ilicone, etc.) in atmosphere/weather (secondarycontainment seals)
  • glass in air/gas (railroad bay door view port)
  • glass in atmosphere/weather (railroad bay door view port)
  • masonry walls in air/gas
  • roofing in atmosphere/weather (railroad bay built-up roofing)2.4.14.2 Staff Evaluation The staff reviewed LRA Section 2.4.14 and the USAR using the evaluation methodologydescribed in SER Section 2.4. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.4.In conducting its review, the staff evaluated the structural component functions described in theLRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had not omitted from the scope of license renewal any components with intended 2-140functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that theapplicant had identified as being within the scope of license renewal to verify that the applicanthad not omitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.4.14.3 Conclusion The staff reviewed the LRA and related structural components to determine whether theapplicant had failed to identify any SSCs that should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequatelyidentified the radioactive waste building components that are within the scope of licenserenewal, as required by 10 CFR 54.4(a), and the radioactive waste building components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.4.15 Reactor Building 2.4.15.1 Summary of Technical Information in the ApplicationIn LRA Section 2.4.15, the applicant described the reactor building. The principal functions ofthe reactor building are to support and protect enclo sed systems and components and toprovide secondary containment limiting the offsite radiological consequences of accidents. The building provides necessary space for the equipment in a planned arrangement and provides for layout space for the equipment to be removed and replaced if necessary. Reactor internals and fuel can be moved and conveniently stored within the building. The reactor building serves as the secondary containment. The secondary containment, in conjunction with other engineered safeguards and nuclear safety systems, limits the release of radioactive materialsfrom a postulated DBA. The reactor building also provides secondary containment when the primary containment is in service and provides primary containment during reactor refueling and maintenance operations when the primary containment system is open. A majorsubstructure within the reactor building is a reinforced concrete biological shield that surrounds the reactor and drywell portion of the primary containment.The reactor building contains SR components that are relied upon to remain functional duringand following DBEs. The failure of NSR SSCs in the reactor building could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal.

In addition, the reactor building performs functions that support FP, ATWS, and SBO.The intended functions within the scope of license renewal include the following:

  • provide shielding against neutron radiation
  • provide flood protection barrier
  • provide shielding against HELBs
  • provide missile barrier
  • provide structural support to NSR components (civil and structural)
  • provide pressure boundary of essentially leaktight barrier (civil and structural) 2-141
  • provide shielding against radiation
  • provide structural support to SR components (civil and structural)
  • provide shelter/protection to SR components
  • provide pipe whip restraintIn LRA Table 2.4.15-1, the applicant identified the following reactor building component typesthat are within the scope of license renewal and subject to an AMR:
  • aluminum in air/gas (new fuel storage racks)
  • aluminum in atmosphere/weather (siding, ventilation assemblies)
  • aluminum in treated water (spent fuel storage racks)
  • boral in treated water (spent fuel storage racks neutron-absorbing sheets)
  • carbon steel, low-alloy steel in air/gas (drywell to reactor building refueling seal plates)
  • carbon steel, low-alloy steel in air/gas (fire-rated doors)
  • carbon steel, low-alloy steel in air/gas (fire-rated, HELB, and secondary containmentdoors)
  • carbon steel, low-alloy steel in air/gas (structural steel, steel embeds, blowout panels,etc.)
  • carbon steel, low-alloy steel in air/gas (supports for miscellaneous structures (i.e.,members, welds, bolted connections, support anchorage for platforms, stairs, whip restraints, masonry wall supports, etc.))
  • carbon steel, low-alloy steel in atmosphere/weather (structural steel, ventilationassemblies)
  • carbon steel, low-alloy steel in treated water (drywell to reactor building refueling sealplates)
  • concrete in air/gas (foundation, walls, slabs)
  • concrete in air/gas (foundation, walls, slabs, grout)
  • concrete in air/gas (walls, slabs)
  • concrete in atmosphere/weather (walls, slabs)
  • concrete in below grade (foundation, walls)
  • elastomer sealants (rubber, neoprene, s ilicone, etc.) in air/gas (secondary containmentseals, spent fuel pool gate seals, and hatch seals)
  • elastomer sealants (rubber, neoprene, s ilicone, etc.) in atmosphere/weather (secondarycontainment seals)
  • elastomer sealants (rubber, neoprene, s ilicone, etc.) in treated water (spent fuel poolgate seals)
  • glass in air/gas (railroad door view port) 2-142
  • masonry walls in air/gas
  • nonmetallic fireproofing in air/gas (gypsum board walls)
  • roofing in atmosphere/weather
  • stainless steel in air/gas (metal siding screws, upper portion of spent fuel pool,dryer/separator storage pool, reactor well liners, and drywell to reactor building refueling seal bellows)
  • stainless steel in atmosphere/weather (metal siding screws)
  • stainless steel in treated water (dryer/separator storage pool and reactor well liners)
  • stainless steel in treated water (drywell to reactor building refueling seal bellows)
  • stainless steel in treated water (spent fuel pool, dryer/separator storage pool, andreactor well liners)
  • stainless steel in treated water (spent fuel pool liner)
  • stainless steel in treated water (spent fuel storage racks)2.4.15.2 Staff Evaluation The staff reviewed LRA Section 2.4.15 and the USAR using the evaluation methodologydescribed in SER Section 2.4. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.4.In conducting its review, the staff evaluated the structural component functions described in theLRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had not omitted from the scope of license renewal any components with intendedfunctions delineated under 10 CFR 54.4(a). The staff then reviewed those components that theapplicant had identified as being within the scope of license renewal to verify that the applicanthad not omitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.4.15.3 Conclusion The staff reviewed the LRA and related structural components to determine whether theapplicant had failed to identify any SSCs that should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequatelyidentified the reactor building components that are within the scope of license renewal, asrequired by 10 CFR 54.4(a), and the reactor building components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2-1432.4.16 Structures Affecting Safety2.4.16.1 Summary of Technical Information in the ApplicationIn LRA Section 2.4.16, the applicant described the structures affecting safety system. Thestructures affecting safety system pertains to plant structures that perform no safety function or regulated event function (except for the heating boiler building), but could, under certain failurescenarios, adversely affect buildings or equipment having such functions. These structures are listed below:

  • The heating boiler building is located along the east side of the turbine building. Theheating boiler building is a structural steel frame building with insulated metal siding and a steel deck roof. The structural steel columns sit on a reinforced concrete footing. The foundation walls are also of reinforced concrete. The floor consists of a reinforced concrete slab on grade.
  • The non-1E electrical equipment room is located just east of the turbine building. Thestructure contains transformers and switchgear for NSR portions of the 480-VAC power system. In addition, the NSR No. 17 250-VDC battery is located in the non-1E electricalequipment room.
  • The hot machine shop is located along side the turbine building at the east end of thenorth wall. The hot machine shop is a structural steel frame building with insulated metal siding with a steel deck roof. The structural steel columns sit on a reinforced concrete footing. The foundation walls are also of reinforced concrete. The floor consists of a reinforced concrete slab on grade.
  • The turbine building addition is a Class 2 structure and does not contain any Class 1equipment. The structure was designed in accordance with the uniform building code.

The primary function of the turbine building addition is to provide a controlled environment for the condenser retubing effort.

  • The recombiner building is a reinforced concrete structure utilizing heavy shear walls asa lateral force-resisting system resting on a mat foundation. The building consists of twoequipment bays, a shielded tunnel which houses the interconnecting piping, an instrument room, and a pump room. There is also an enclosed walkway and access areas constructed of structural steel with insulated metal siding and insulated builtup roofing.
  • A radwaste storage building is provided for the solid radwaste truck-loading area. Thissheet metal building is provided with shield walls, floor drains, heating, and FP systems.An overhead crane is located in the building. The building is designed to enclose the radwaste shipping truck and to facilitate loading of the truck.The failure of NSR SSCs in the structures affecting safety system could potentially prevent thesatisfactory accomplishment of an SR function of SSCs within the scope of license renewal.

The structures affecting safety system also performs functions that support FP.The intended functions within the scope of license renewal include the following:

  • provide structural support to NSR components (civil and structural)In LRA Table 2.4.16-1, the applicant identified the following structures affecting safety systemcomponent types that are within the scope of license renewal and subject to an AMR:
  • carbon steel, low-alloy steel in air/gas (fire-rated doors)
  • carbon steel, low-alloy steel in air/gas (structural steel)
  • concrete in air/gas (foundations, walls, slabs)
  • concrete in air/gas (foundations, walls, slabs, grout)
  • concrete in atmosphere/weather (foundations, walls, slabs)
  • concrete in below grade (foundations, walls)2.4.16.2 Staff Evaluation The staff reviewed LRA Section 2.4.16 and the USAR using the evaluation methodologydescribed in SER Section 2.4. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.4.In conducting its review, the staff evaluated the structural component functions described in theLRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had not omitted from the scope of license renewal any components with intendedfunctions delineated under 10 CFR 54.4(a). The staff then reviewed those components that theapplicant had identified as being within the scope of license renewal to verify that the applicanthad not omitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.4.16.3 Conclusion The staff reviewed the LRA and related structural components to determine whether theapplicant had failed to identify any SSCs that should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequatelyidentified the structures affecting safety system components that are within the scope of licenserenewal, as required by 10 CFR 54.4(a), and the structures affecting safety system componentsthat are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.4.17 Turbine Building 2.4.17.1 Summary of Technical Information in the ApplicationIn LRA Section 2.4.17, the applicant described the turbine building (TGB). The TGB is aClass 2 structure; however, the portions that support and protect electrical controls and instrumentation for Class 1 equipment were designed in accordance with the criteria for the design of portions of Class 2 structures enclosing and/or supporting Class 1 equipment. The primary function of the TGB is to provide the necessary environment required for safe operation and maintenance of the turbine generator and other components of the power conversionsystem. The TGB is a combination of reinforced concrete and structural steel construction. The 2-145foundation is a reinforced concrete mat of variable thickness supported on undisturbed soil. Thefoundation supports the reinforced concrete turbine generator pedestal, as well as the building superstructure. The reinforced concrete portion of the superstructure extends from the top of the mat foundation to the turbine deck. Structural steel beam and girded framing support the reinforced concrete floor slabs. Interior reinforced concrete walls extending from the top of the mat up to the operating floor are oriented to protect personnel against radiation emanating fromthe turbine and auxiliary systems. A structural steel-framed superstructure is based at theturbine deck on reinforced concrete columns located within the exterior walls. The superstructure encloses the operating floor and also provides support and closure for a traveling bridge crane. A 5-ply tar and felt insulated roof is supported by a metal roof deck which also acts as a diaphragm to transmit lateral forces to vertically braced end walls or shear frames.The TGB contains SR components that are relied upon to remain functional during andfollowing DBEs. The failure of NSR SSCs in the TGB could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the TGB performs functions that support FP, ATWS, and SBO.The intended functions within the scope of license renewal include the following:
  • provide flood protection barrier
  • provide shielding against HELBs
  • provide missile barrier
  • provide structural support to NSR components (civil and structural)
  • provide shielding against radiation
  • provide structural support to SR components (civil and structural)
  • provide shelter/protection to SR components
  • provide pipe whip restraintIn LRA Table 2.4.17-1, the applicant identified the following TGB component types that arewithin the scope of license renewal and subject to an AMR:
  • carbon steel, low-alloy steel in air/gas (fire-rated doors)
  • carbon steel, low-alloy steel in air/gas (structural steel, steel embeds, doors, etc.)
  • carbon steel, low-alloy steel in air/gas (supports for miscellaneous structures (i.e.,members, welds, bolted connections, support anchorage for platforms, stairs, whip restraints, masonry wall supports, etc.))
  • carbon steel, low-alloy steel in atmosphere/weather (doors)
  • concrete in air/gas (foundation, walls, slabs)
  • concrete in air/gas (foundation, walls, slabs, grout)
  • concrete in air/gas (walls, slabs)
  • concrete in atmosphere/weather (walls near recombiner building)
  • concrete in atmosphere/weather (walls, slabs) 2-146
  • concrete in below grade (foundation, walls)
  • masonry walls in air/gas
  • nonmetallic fireproofing in air/gas (cementitious fireproofing, pyrocrete walls)
  • nonmetallic fireproofing in air/gas (gypsum board walls)2.4.17.2 Staff Evaluation The staff reviewed LRA Section 2.4.17 and the USAR using the evaluation methodologydescribed in SER Section 2.4. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.4.In conducting its review, the staff evaluated the structural component functions described in theLRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had not omitted from the scope of license renewal any components with intendedfunctions delineated under 10 CFR 54.4(a). The staff then reviewed those components that theapplicant had identified as being within the scope of license renewal to verify that the applicanthad not omitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.4.17 identified an area for which it needed additionalinformation to complete its evaluation of the applicant's scoping and screening results. The applicant responded to the staff's RAI as discussed below.In RAI 2.4.17-1, dated September 28, 2005, the staff noted that Table 2.4.17-1 lists "Carbonsteel, low-alloy steel in air/gas (fire rated doors)" as a component group with the intended function being fire barrier, and "Carbon steel, low-alloy steel in air/gas (...doors,...)" as another component group with one of the intended functions also being fire barrier. Therefore, the staff requested that the applicant explain the difference between the doors listed in the twocomponent groups.In its response, by letter dated October 28, 2005, the applicant provided the following response:Table 2.4.17-1 component group, 'carbon steel, low alloy steel in air/gas (firerated doors)' refers to doors that provide a fire barrier intended function and are managed for aging by the Fire Protection Program. Table 2.4.17-1 component group, 'carbon steel, low alloy steel in air/gas (structural steel, steel embeds, doors, etc.)' refers to those doors that were assigned a fire barrier function as discussed above, but also perform at least one other intended function such as high energy line break (HELB) barrier and/or flood barrier. Consequently doors with a fire barrier intended function that also perform additional functions are managed by the Structures Monitoring Program in addition to the Fire Protection Program in accordance with NUREG-1801.Based on its review, the staff found the applicant's response to RAI 2.4.17-1 acceptable,because the applicant adequately explained that the doors have different intended functions.Therefore, the staff's concern described in RAI 2.4.17-1 is resolved.

2-1472.4.17.3 ConclusionThe staff reviewed the LRA and related structural components to determine whether theapplicant had failed to identify any SSCs that should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequatelyidentified the TGB components that are within the scope of license renewal, as required by10 CFR 54.4(a), and the TGB components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.4.18 Underground Duct Bank 2.4.18.1 Summary of Technical Information in the ApplicationIn LRA Section 2.4.18, the applicant described the underground duct bank. The undergroundduct bank runs between the third floor of the EFT building and the reactor building. The primary function of the duct bank is to carry Division 2 safe-shutdown cables outside of areas where fire damage could occur. The duct bank includes risers at each end with an underground section in between. The underground portion of the duct bank is 700 feet in length and is rectangular in cross section. It is constructed of reinforced concrete and contains sixteen 4-inch diameter raceways. Access to the duct bank is provided by four reinforced concrete manholes. Seismic joints occur at the manhole to duct bank interface and the riser to duct bank interface.The underground duct bank contains SR components that are relied upon to remain functionalduring and following DBEs. In addition, the underground duct bank performs functions that support FP and SBO.The intended functions within the scope of license renewal include the following:

  • provide flood protection barrier
  • provide structural support to NSR components (civil and structural)
  • provide structural support to SR components (civil and structural)
  • provide shelter/protection to SR componentsIn LRA Table 2.4.18-1, the applicant identified the following underground duct bank componenttypes that are within the scope of license renewal and subject to an AMR:
  • carbon steel, low-alloy steel in air/gas (structural steel, steel embeds, etc.)
  • carbon steel, low-alloy steel in air/gas (supports for miscellaneous structures (i.e.,members, welds, bolted connections, support anchorage for platforms, stairs, etc.))
  • carbon steel, low-alloy steel in atmosphere/weather (manhole covers/supports)
  • carbon steel, low-alloy steel in below grade (manhole covers/supports)
  • concrete in air/gas (foundation, walls, slabs)
  • concrete in atmosphere/weather (walls, slabs) 2-148
  • concrete in below grade (foundation, walls, slabs, grout)2.4.18.2 Staff Evaluation The staff reviewed LRA Section 2.4.18 and the USAR using the evaluation methodologydescribed in SER Section 2.4. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.4.In conducting its review, the staff evaluated the structural component functions described in theLRA and USAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had not omitted from the scope of license renewal any components with intendedfunctions delineated under 10 CFR 54.4(a). The staff then reviewed those components that theapplicant had identified as being within the scope of license renewal to verify that the applicanthad not omitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.4.18.3 Conclusion The staff reviewed the LRA and related structural components to determine whether theapplicant had failed to identify any SSCs that should be within the scope of license renewal. No omissions were identified. In addition, the staff performed a review to determine whether the applicant had failed to identify any components that should be subject to an AMR. No omissions were identified. On the basis of its review, the staff concluded that the applicant adequatelyidentified the underground duct bank components that are within the scope of license renewal,as required by 10 CFR 54.4(a), and the underground duct bank components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.5 Scoping and Screening Results: Electrical and Instrumentation and ControlsThis section documents the staff's review of the applicant's scoping and screening results forelectrical and I&C systems. Specifically, this section discusses the following:
  • electrical and I&C systems
  • electrical commoditiesIn accordance with the requirements of 10 CFR 54.21(a)(1), the applicant must identify and listpassive, long-lived SCs that are within the scope of license renewal and subject to an AMR. To verify that the applicant properly implemented its methodology, the staff focused its review onthe implementation results. This approach allowed the staff to confirm that there were noomissions of electrical and I&C system components that meet the scoping criteria and aresubject to an AMR.Staff Evaluation Methodology. The staff performed its evaluation of the information in the LRAin the same manner for all electrical and I&C systems. The objective of the review was todetermine whether the applicant had identified the components and supporting structures for aspecific electrical and I&C system, that appeared to meet the scoping criteria specified in theRule, as within the scope of license renewal, in accordance with 10 CFR 54.4. Similarly, the 2-149staff evaluated the applicant's screening results to verify that all long-lived, passive componentswere subject to an AMR, in accordance with 10 CFR 54.21(a)(1).Scoping. To perform its evaluation, the staff reviewed the applicable LRA section andassociated component drawings, focusing its review on components that had not been identified as within the scope of license renewal. The staff reviewed relevant licensing-basis documents, including the USAR, for each electrical and I&C system component to determinewhether the applicant had omitted components with intended functions delineated under10 CFR 54.4(a) from the scope of license renewal. The staff also reviewed the licensing-basis documents to determine whether the LRA specified all intended functions delineated under10 CFR 54.4(a). If omissions were identified, the staff requested additional information to resolve the discrepancies.Screening. Once the staff completed its review of the scoping results, the staff evaluated theapplicant's screening results. For those systems and components with intended functions, thestaff sought to determine (1) if the functions are performed with moving parts or a change in configuration or properties or (2) if they are subject to replacement based on a qualified life or specified time period, as described in 10 CFR 54.21(a)(1). For those electrical and I&C systemsand components that did not meet either of these criteria, the staff sought to confirm that theywere subject to an AMR, as required by 10 CFR 54.21(a)(1). If discrepancies were identified, the staff requested additional information to resolve them.2.5.1 Electrical and Instrumentation and Controls Systems In LRA Section 2.5.1, the applicant identified the SCs of the electrical and I&C systems that aresubject to an AMR for license renewal.The applicant described the supporting SCs of the electrical and I&C systems in the followingsections of the LRA:
  • 2.5.1.1480-V station auxiliary system
  • 2.5.1.24.16-kV station auxiliary
  • 2.5.1.3alternate shutdown
  • 2.5.1.4annunciators
  • 2.5.1.5communications
  • 2.5.1.6DC battery
  • 2.5.1.7lighting
  • 2.5.1.8neutron monitoring
  • 2.5.1.9offsite power
  • 2.5.1.10plant protection
  • 2.5.1.11radiation monitoring
  • 2.5.1.12reactor level control (RLC)
  • 2.5.1.13uninterruptible ACSER Sections 2.5.1.1-2.5.1.13 present the staff's review findings regarding LRASections 2.5.1.1-2.5.1.13, respectively.

2-1502.5.1.1 480-V Station Auxiliary2.5.1.1.1 Summary of Technical Information in the Application In LRA Section 2.5.1.1, the applicant described the 480-V station auxiliary system. The 480-Vstation auxiliary system consists of transformers, breakers, load centers, and MCCs. Power istypically supplied to motors less than 250 horsepower (HP) and lighting transformers. The system receives power from the 4.16-kV station auxiliary system through load centertransformers. It distributes power through load center buses and MCCs.The 480-V station auxiliary system contains SR components that are relied upon to remainfunctional during and following DBEs. The failure of NSR SSCs in the 480-V station auxiliarysystem could potentially prevent the satisfactory accomplishment of an SR function of SSCs within the scope of license renewal. In addition, the 480-V station auxiliary system performsfunctions that support FP, ATWS, and SBO.The applicant identified the 480-V station auxiliary system SCs that are within the sc ope oflicense renewal. LRA Section 2.5.2 evaluates electrical commodities for this system that aresubject to AMR. LRA Section 2.4.6 evaluates supports for electrical components.2.5.1.1.2 Staff Evaluation The staff reviewed LRA Section 2.5.1.1 and the USAR using the evaluation methodologydescribed in SER Section 2.5. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.5.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.5.1.1 identified an area for which it needed additionalinformation to complete its evaluation of the applicant's results. The applicant responded to the staff's RAI as discussed below.In RAI 2.5.1-1, the staff noted that LRA Section 2.5.1.1, under the system function listing 480-V station auxiliary, states that MCCs 132, 133A, and 142A are credited with supporting anATWS event; however, license renewal drawing LR-36298, does not include MCC 132 as within the scope of license renewal; therefore, the staff requested that the applicant resolve thediscrepancy.In its response, by letter dated September 16, 2005, the applicant provided the followingresponse:MCC 132 Breaker B3230 supplies power to the tank heater for Standby LiquidControl (SLC) Tank T-200. The SLC System mitigates an ATWS event. The 2-151drawing is in error. Drawing LR-36298 will be revised to show MCC 132 as beingwithin the scope of License Renewal.Based on its review, the staff found the applicant's response to RAI 2.5.1-1 acceptable becausethe applicant will revise its boundary drawing to indicate MCC 132 as being within the scope oflicense renewal. Therefore, the staff's concern described in RAI 2.5.1-1 is resolved.During the scoping inspection, the inspectors identified discrepancies between the scoping andscreening report and license renewal drawing LR-36298. Specifically, the license renewal classification of breakers fed from several 480-V load centers was not consistent with the license renewal scoping and screening document. The applicant also identified several other load center cubicles which were not previously shown as being within the scope of license renewal, but which should have been included. The applicant determined that the additionalcomponents brought into scope of license renewal were all active components, and therefore, screened out and did not require aging management. On the basis of its review, the staff concluded that the breakers are active components, and therefore not subject to an AMR.2.5.1.1.3 Conclusion On the basis of its review, the staff concluded that the applicant adequately identified the 480-Vstation auxiliary system components that are within the scope of license renewal, as required by10 CFR 54.4(a), and the 480-V station auxiliary system components that are subject to anAMR, as required by 10 CFR 54.21(a)(1).2.5.1.2 4.16-kV Station Auxiliary 2.5.1.2.1 Summary of Technical Information in the Application In LRA Section 2.5.1.2, the applicant described the 4.16-kV station auxiliary system. All stationpower is supplied from the 4.16-kV station auxiliary system (4 kV) through distribution buses tovarious motors and stepdown transformers. The 4.16-kV system is a three-phase, groundedneutral distribution system. The system uses eight 4.16-kV bus sections, each housed in metalclad assemblies. Six buses, 11, 12, 13, 14, 15, and 16, are located in the turbine building.Buses 17 and 18 are located at the discharge structure to serve the cooling tower pumps. The plant's 4.16-kV buses may be supplied from either of two sources. The normal source is the 2R transformer supplied from the 345-kV substation. The alternate source is the 1R transformer supplied from the 115-kV substation. Protective relaying, if activated, deenergizes the 2Rtransformer and initiates an open circuit transfer to the 1R transformer. Air circuit breakers (ACBs) connect sources and loads to the buses. Two 125-V station batteries supply control power to control the opening and closing of the plant breakers in the 4.16-kV system.The 4.16-kV station auxiliary system contains SR components that are relied upon to remainfunctional during and following DBEs. In addition, the 4.16-kV station auxiliary system performsfunctions that support FP, ATWS, and SBO.The applicant identified the 4.16-kV station auxiliary system component types that are within thescope of license renewal. Section 2.5.2 evaluates electrical commodities for this system thatare subject to AMR. Section 2.4.6 evaluates supports for electrical components.

2-1522.5.1.2.2 Staff EvaluationThe staff reviewed LRA Section 2.5.1.2 and the USAR using the evaluation methodologydescribed in SER Section 2.5. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.5.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.5.1.2.3 Conclusion On the basis of its review, the staff concluded that the applicant adequately identified the 4.16-kV station auxiliary system components that are within the scope of license renewal, asrequired by 10 CFR 54.4(a), and the 4.16-kV station auxiliary system components that aresubject to an AMR, as required by 10 CFR 54.21(a)(1).2.5.1.3 Alternate Shutdown 2.5.1.3.1 Summary of Technical Information in the Application In LRA Section 2.5.1.3, the applicant described the ASD system, which is designed to providealternative shutdown capability, as required by 10 CFR 50.48 and Appendix R to 10 CFRPart 50. This system assures safe shutdown in the event of a fire in the control room, cable spreading room, or both. The ASD system performs the above by providing for a remotecentralized location at which existing plant systems can be manually controlled. T he syst emuses existing Division II systems and equipment. The ASD control panel is located on the thirdfloor of the emergency filtration building. This area is adjacent to the turbine building and the control room.The ASD system contains SR components that are relied upon to remain functional during andfollowing DBEs. In addition, the ASD system performs functions that support FP and SBO.The applicant identified the ASD system com ponent types that are within the scope of licenserenewal. Section 2.5.2 evaluates electrical commodities for this system that are subject to anAMR. Section 2.4.6 evaluates supports for electrical components.2.5.1.3.2 Staff Evaluation The staff reviewed LRA Section 2.5.1.3 and the USAR using the evaluation methodologydescribed in SER Section 2.5. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.5.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant had 2-153not omitted from the scope of license renewal any components with intended functionsdelineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.5.1.3.3 Conclusion On the basis of its review, the staff concluded that the applicant adequately identified the ASDsystem components that are within the scope of license renewal, as required by10 CFR 54.4(a), and the ASD system components that are subject to an AMR, as required by10 CFR 54.21(a)(1).2.5.1.4 Annunciators 2.5.1.4.1 Summary of Technical Information in the Application In LRA Section 2.5.1.4, the applicant described the plant annunciators. The plant annunciatorsconsist of MCC panels and local panels for selected systems and associated plantinstrumentation. They alert operators to off-normal conditions for monitored variables.The failure of NSR SCs in the plant annunciators could potentially prevent the satisfactoryaccomplishment of an SR function of SSCs within the scope of license renewal. The plant annunciators also perform functions that support FP and SBO.The applicant identified the plant annunciators component types that are within the scope oflicense renewal. Section 2.5.2 evaluates electrical commodities for this system that are subjectto an AMR. Section 2.4.6 evaluates supports for electrical components.2.5.1.4.2 Staff Evaluation The staff reviewed LRA Section 2.5.1.4 and the USAR using the evaluation methodologydescribed in SER Section 2.5. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.5.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.5.1.4.3 Conclusion On the basis of its review, the staff concluded that the applicant adequately identified the plantannunciators components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the plant annunciators components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2-1542.5.1.5 Communications2.5.1.5.1 Summary of Technical Information in the Application In LRA Section 2.5.1.5, the applicant described the communications system. Thecommunications system consists of the following five subsystems-(1) telephone system, (2)site public address (PA) system, (3) sound-powered system, (4) intercom system, and (5) plantradio system. The plant telephone system is the most widely used method of communication atMNGP and is centered around an AT&T programmable solid-state private branch exchange (PBX) switch. There is also a set of telephones located in the control room, technical support center, and training center which are used solely to perform NRC notification. This system iscalled the FTS 2000 and uses dedicated circuits leased from commercial carriers to make direct connections to various branches/offices of the NRC. The design of this system providesindependence from the normal tel ephone system and guarantees availability of commercialcircuits in the event of heavy telephone use by the local community. The site PA system isdesigned to provide general plant paging capability and also provides a single-party linechannel between paging stations. The sound powered system is a series of hard-wiredtelephone jacks located at various places throughout the plant that can be used formaintenance and calibration activities. The intercom system is a multichannel system withpush-button channel selection at the master stations located in the control room and cablespreading room. The plant radio system is a Motorola repeater-based system with six separatechannels.The communications system performs functions that support FP.The applicant identified the communications system component types that are within the scopeof license renewal. Section 2.5.2 evaluates electrical commodities for this system that aresubject to an AMR. Section 2.4.6 evaluates supports for electrical components.2.5.1.5.2 Staff Evaluation The staff reviewed LRA Section 2.5.1.5 and the USAR using the evaluation methodologydescribed in SER Section 2.5. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.5.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.5.1.5.3 Conclusion On the basis of its review, the staff concluded that the applicant adequately identified thecommunications system components that are within the scope of license renewal, as requiredby 10 CFR 54.4(a), and the communications system components that are subject to an AMR,as required by 10 CFR 54.21(a)(1).

2-1552.5.1.6 DC Battery2.5.1.6.1 Summary of Technical Information in the Application In LRA Section 2.5.1.6, the applicant described the DC battery. Two independent divisions of24-VDC batteries are provided. They include two battery systems which feed separate DCbuses and two battery chargers per division fed from different AC feeders and distribution panels. These 24-VDC batteries provide power for the nuclear instrumentation, PRMs, and

H 2/O 2 analyzer isolation valve position indication. Two independent divisions of 125-VDCbatteries are provided. They include two battery systems which feed separate DC buses anddistribution panels. The 250-VDC system consists of essential and nonessential subsystems.The essential system consists of two independent divisions of 250-VDC batteries with centertaps for 125 VDC. The 250-VDC system supplies highly reliable power to large loads, such asmotor-driven pumps, valves, and uninterruptible power supplies (UPSs). The nonessential system consists of one division of 250-VDC batteries. It includes one battery system which ischarged by rectifiers in the UPS and distribution panels.The DC battery contains SR components that are relied upon to remain functional during andfollowing DBEs. In addition, the DC battery performs functions that support FP, ATWS, and SBO. This system contains equipment that is required to be qualified in accordance with10 CFR 50.49.The applicant identified the DC battery component types that are within the scope of licenserenewal. Section 2.5.2 evaluates electrical commodities for this system that are subject to anAMR. Section 2.4.6 evaluates supports for electrical components.2.5.1.6.2 Staff Evaluation The staff reviewed LRA Section 2.5.1.6 and the USAR using the evaluation methodologydescribed in SER Section 2.5. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.5.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).The staff's review of LRA Section 2.5.1.6 identified an area for which it needed additionalinformation to complete its evaluation of the applicant's results. The applicant responded to the staff's RAI as discussed below.In RAI 2.5.1-2, the staff noted that LRA Section 2.5.1.6, under the description of DC battery,states that the 24-VDC batteries provide power for the nuclear instrumentation, PRMs, and H 2/0 2 analyzer isolation valve position indication, this section further states, under the systemfunction listing, that the 24-VDC system continuously provides DC electrical power to the SRand NSR loads. However, the 24-VDC system is not considered SR bec ause the system is not 2-156required to provide the SR function of these loads; therefore, the staff requested that theapplicant indicate specific safety loads powered by the 24-VDC system and explain how theseloads would perform the SR function if the 24-VDC NSR power supply were to fail.In its response, by letter dated September 16, 2005, the applicant responded:The 24 VDC system provides power to the Source Range Monitors (SRMs) andthe Intermediate Range Monitors (IRMs) in the Neutron Monitoring System (NMS). With the mode switch in SHUTDOWN and RUN, SRMs andIRMs are not required to be operable. Per the Technical Specifications, the SRMs and IRMs are only required to be operable when the mode switch is in REFUEL and STARTUP. The 24 VDC system provides power to the SRMs andIRMs, but is not required for them to provide their Safety Related function.

Failure of 24 VDC power will initiate the safety functions (rod block and scram).The Division I 24 VDC system provides power for the output trip relaying (not theradiation monitors) for the Off-Gas Pretreatments monitors. In the event of a 24VDC failure for this relaying, offgas trip timers will conservatively trip the operating recombiner train after a 30-minute delay. Operability of the monitorsthemselves is not affected.The Division I 24 VDC system also provides power for the Flux-Tilt monitor. Thismonitor is classified as non-safety related and is not required for normal operation.The Division II 24 VDC system provides power for the Discharge Canal, ServiceWater, Radwaste Effluent, and Reactor Building Closed Cooling Water process liquid radiation monitors. These monitors are all classified as non-safety related.

In the event of loss of Division II 24 VDC, compensatory measures would be implemented for these radiation monitors in accordance with the applicable MNGP site procedures.Finally, each divisions of 24 VDC supplies power for the corresponding divisionof containment atmosphere monitori ng system isolation valve position indication.Control power for the valves is provided by other sources. The valve position indication function does not meet the criteria of 10 CFR 54.4(a)(I), (ii), or (iii) forbeing within the scope of license renewal.Based on its review, the staff found the applicant's response to RAI 2.5.1-2 acceptable becausethe applicant adequately described the safety loads power ed by the system and how thoseloads perform if the power supply were to fail. Therefore, the staff's concern described in RAI 2.5.1-2 is resolved.2.5.1.6.3 Conclusion On the basis of its review, the staff concluded that the applicant adequately identified the DCbattery components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the DC battery components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2-1572.5.1.7 Lighting2.5.1.7.1 Summary of Technical Information in the Application In LRA Section 2.5.1.7, the applicant described the lighting system. The lighting systemprovides light in all areas for safe, efficient operation of the plant. Normal lighting is supplied by normal AC power. Several locations in the plant are supplied by normal lighting which is supplied from an essential lighting source. Essential lighting is supplied by a normal AC source, or by the diesel generators, or by the 1AR transformer during a loss of the normal AC source.

The emergency lighting system is independent of the AC system. 8-hour, battery-poweredemergency lighting units are also located throughout the plant. These units have individual batteries that are continuously charged from normal AC power sources. In the event normal AC power is lost, these units will illuminate. Appendix R to 10 CFR Part 50 requires 8-hour lightingunits to be located in the MCR, at the ASD panel, along the pathway in between, in the 11diesel generator room, and in the warehouse/cold shop equipment bay.The lighting system contains SR components that are relied upon to remain functional duringand following DBEs. In addition, the lighting system performs functions that support FP and SBO.The applicant identified the lighting system component types that are within the scope of licenserenewal. Section 2.5.2 evaluates electrical commodities for this system that are subject to anAMR. Section 2.4.6 evaluates supports for electrical components.2.5.1.7.2 Staff Evaluation The staff reviewed LRA Section 2.5.1.7 and the USAR using the evaluation methodologydescribed in SER Section 2.5. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.5.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.5.1.7.3 Conclusion On the basis of its review, the staff concluded that the applicant adequately identified thelighting system components that are within the scope of license renewal, as required by10 CFR 54.4(a), and the lighting system components that are subject to an AMR, as requiredby 10 CFR 54.21(a)(1).

2-1582.5.1.8 Neutron Monitoring2.5.1.8.1 Summary of Technical Information in the Application In LRA Section 2.5.1.8, the applicant described neutron monitoring systems. The local powerrange monitor (LPRM) s ubsystem is designed to continuously monitor the neutron flux level inthe reactor while in the power range. The LPRM subsystem signals must be available to permitdemonstration of compliance with the critical power ratio limits. The individual LPRM output signals serve as input signals to the average power range monitors (APRMs) and rod block monitor (RBM). The APRM subsystem is designed to provide a continuous, accurate indicationof the average core power. The RBM is an operational aid designed to prevent violation of the fuel integrity safety criteria during withdrawal of a single control blade. The RBM also provides a local relative power signal for operator evaluation during control blade movement. The startup range monitors consist of 12 neutron flux monitoring channels. They include four SRMs and eight IRMs. The source range monitoring system is used to provide neutron flux informationfrom subcritical to an intermediate flux level. The intermediate range monitoring system is usedto provide neutron flux information from the upper limit of the source range monitors to the lower limit of the power range monitors.The neutron monitoring systems contain SR components that are relied upon to remainfunctional during and following DBEs.The applicant identified the neutron monitoring component types that are within the scope oflicense renewal. Section 2.5.2 evaluates the electrical commodities for this system that aresubject to an AMR. Section 2.4.6 evaluates the supports for electrical components.2.5.1.8.2 Staff Evaluation The staff reviewed LRA Section 2.5.1.8 and the USAR using the evaluation methodologydescribed in SER Section 2.5. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.5.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.5.1.8.3 Conclusion On the basis of its review, the staff concluded that the applicant adequately identified theneutron monitoring components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the neutron monitoring components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2-1592.5.1.9 Offsite Power2.5.1.9.1 Summary of Technical Information in the Application In LRA Section 2.5.1.9, the applicant described the offsite power system. The 115-kVsubstation contains buses, breakers, transformers, and associated equipment necessary to connect the MNGP 345-kV system to the Xcel Energy 115-kV transmission system. The 115-kVsubstation supplies power to the 1R and 1AR transformers. The 230-kV substation contains buses, breakers, transformers, and associated equipment. It connects the Xcel 345-kV transmission system to the Great River Energy 230-kV transmission system. The 230-kVsubstation system includes the No. 6 transformer. The 345-kV substation contains t he buses,breakers, and associated equipment necessary to connect the Xcel 345-kV transmission system to the 2RS and 1ARS transformers.The offsite power system performs functions that support SBO.The applicant identified the offsite power system com ponent types that are within the scope oflicense renewal. Section 2.5.2 evaluates electrical commodities for this system that are subjectto an AMR. Section 2.4.6 evaluates supports for electrical components.2.5.1.9.2 Staff Evaluation The staff reviewed LRA Section 2.5.1.9 and the USAR using the evaluation methodologydescribed in SER Section 2.5. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.5.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.5.1.9.3 Conclusion On the basis of its review, the staff concluded that the applicant adequately identified the offsitepower components that are within the scope of license renewal, as required by 10 CFR 54.4(a),

and the offsite power components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.5.1.10 Plant Protection 2.5.1.10.1 Summary of Technical Information in the Application In LRA Section 2.5.1.10, the applicant described the PPS. The PPS consists of the reactorprotection system, the ATWS system, and the primary containment isolati on system (PCIS).The reactor protection system includes the motor-generator power supplies' associated controland indicating equipment, sensors, relays, bypass circuitry, and switches that cause rapid 2-160insertion of control rods (scram) to shutdown the reactor. The ATWS system consists of twoseparately powered trip systems, each made up of two subchannels. Each subchannel receivesan input from an independent sensor monitoring each of the ATWS trip parameters. A trip occurring in both subchannels will cause an ATWS trip which opens both recirculating motorgenerator set generator field breakers and causes control rod insertion by venting the scram air header. The PCIS provides protection against the onset and consequences of accidents involving the gross release of radioactive materials from the primary containment. This protection is the automatic isolation of appropriate pipelines which penetrate the primarycontainment whenever certain monitored variables exceed their preselected operational limit.The PPS contains SR components that are relied upon to remain functional during andfollowing DBEs. In addition, the PPS performs functions that support FP, ATWS, and SBO. This system contains components required to be qualified in accordance with 10 CFR 50.49.The applicant identified the PPS component types that are within the scope of license renewal.Section 2.5.2 evaluates electrical commodities for this system that are subject to an AMR.

Section 2.4.6 evaluates supports for electrical components.2.5.1.10.2 Staff Evaluation The staff reviewed LRA Section 2.5.1.10 and the USAR using the evaluation methodologydescribed in SER Section 2.5. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.5.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.5.1.10.3 Conclusion On the basis of its review, the staff concluded that the applicant adequately identified the PPScomponents that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the PPS components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.5.1.11 Radiation Monitoring 2.5.1.11.1 Summary of Technical Information in the Application In LRA Section 2.5.1.11, the applicant described the area radiation monitors (ARMs). There arenumerous ARMs located throughout the plant, recombiner building, and offgas storage building.

Each consists of a detector coupled to an indicator located either on control room panels C-11 or C-252D. The indicators for the containment high-range monitors are located on panels C-257 and C-258 in the control room. The PAS system indicators are on PAS system panel C-261.Two multipoint recorders, NR-18-55 and RR-7573, located on panel C-02 and panel C-252D, respectively, record the readings of all channels, except the high-range channel (RI-7774) from 2-161the offgas storage building, the drywell monitors, and the PAS system monitor. All of the ARMsuse Geiger-Mueller detectors, except for the containment high-range monitors which are ion chambers. These units are X-ray and gamma sensing devices. The PRM system consists ofseveral subsystems that provide continuous monitoring of the radiation levels of liquid andgaseous processes throughout the plant which can release activity directly to the environment.

These subsystems assist in controlling the release of radioactive byproducts within the legallyprescribed limits as set forth in the TSs. They also help provide for personnel safety by warning of abnormal radiation release levels and, in some cases, automatically terminating these releases.The ARMs contain SR components that are relied upon to remain functional during andfollowing DBEs. In addition, the ARMs contain components which are part of the Environmental Qualification Program.The applicant identified the ARMs component types that are within the scope of licenserenewal. Section 2.5.2 evaluates electrical commodities for this system that are subject to anAMR. Section 2.4.6 evaluates supports for electrical components.2.5.1.11.2 Staff Evaluation The staff reviewed LRA Section 2.5.1.11 and the USAR using the evaluation methodologydescribed in SER Section 2.5. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.5.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.5.1.11.3 Conclusion On the basis of its review, the staff concluded that the applicant adequately identified the ARMcomponents that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the ARM components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.5.1.12 Reactor Level Control 2.5.1.12.1 Summary of Technical Information in the Application In LRA Section 2.5.1.12, the applicant described the RLC system. The FW system consists oftwo constant-speed, motor-driven FW pumps with throttling flow control that have a combinedcapacity of the total required flow to the reactor. The RLC system automatically controls theflow of FW into the reactor vessel to maintain the water level in the vessel within a predetermined range during all modes of plant operations. The RLC system employs waterlevel, steam flow, and FW flow as a three-element control. Single-element control, which employs water level only, is also available.

2-162The RLC system performs functions that support FP and SBO.The applicant identified the RLC component types that are within the scope of license renewal.Section 2.5.2 evaluates electrical commodities for this system that are subject to an AMR. Section 2.4.6 evaluates supports for electrical components.2.5.1.12.2 Staff Evaluation The staff reviewed LRA Section 2.5.1.12 and the USAR using the evaluation methodologydescribed in SER Section 2.5. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.5.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.5.1.12.3 Conclusion On the basis of its review, the staff concluded that the applicant adequately identified the RLCsystem components that are within the scope of license renewal, as required by10 CFR 54.4(a), and the RLC system components that are subject to an AMR, as required by10 CFR 54.21(a)(1).2.5.1.13 Uninterruptible AC 2.5.1.13.1 Summary of Technical Information in the Application In LRA Section 2.5.1.13, the applicant described the uninterruptible AC (UAC) system. TheUAC system is composed of two Class 1E inverters that provide a Division 1 and a Division 2120-VAC UPS. The Division 1 inverter (Y-71) is supplied by Division 1 250-VDC distribution panel D-31, with an alternate AC source to the static switch from essential MCC-134 through a stepdown transformer. The Division 2 inverter (Y-81) is supplied by Division 2 250-VDC distribution panel D-100 with an alternate AC source to the static switch from essential MCC-144 through a step-down transformer. The 480-Volt AC system is composed of one UPSY-91 which provides a reliable source of 480-Volt AC power. This system is not a Class 1Esystem. The normal source for Y-91 is from LC-108 through circuit breaker 52-804. Thealternate source is through circuit breaker 52-704 on LC-107. The backup DC source is 250-VDC battery No. 17 via circuit breaker No. 1 on panel D-71. Y-91 rectifier section provides the charging for No. 17 battery, as well as being the normal supply for Y-91 inverter section. The instrument and control AC power provides AC power to plant AC instrument loads.The UAC system contains SR components that are relied upon to remain functional during andfollowing DBEs. In addition, the UAC system performs functions that support FP, ATWS, and SBO.

2-163The applicant identified the UAC system com ponent types that are within the scope of licenserenewal. Section 2.5.2 evaluates electrical commodities for this system that are subject to anAMR. Section 2.4.6 evaluates supports for electrical components.2.5.1.13.2 Staff Evaluation The staff reviewed LRA Section 2.5.1.13 and the USAR using the evaluation methodologydescribed in SER Section 2.5. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.5.In conducting its review, the staff evaluated the system functions described in the LRA andUSAR, in accordance with the requirements of 10 CFR 54.4(a), to verify that the applicant hadnot omitted from the scope of license renewal any components with intended functions delineated under 10 CFR 54.4(a). The staff then reviewed those components that the applicanthad identified as being within the scope of license renewal to verify that the applicant had notomitted any passive and long-lived components that should be subject to an AMR, in accordance with the requirements of 10 CFR 54.21(a)(1).2.5.1.13.3 Conclusion On the basis of its review, the staff concluded that the applicant adequately identified the UACsystem components that are within the scope of license renewal, as required by10 CFR 54.4(a), and the UAC system components that are subject to an AMR, as required by10 CFR 54.21(a)(1).2.5.2 Electrical Commodities In LRA Section 2.5.2, the applicant presented the results of the screening process for electricalcomponents evaluated as commodities subject to an AMR for license renewal. The applicant explained in LRA Section 2.1.5.4 that the scoping and screening process for electricalequipment was unique in several aspects. All electrical systems were evaluated to determinewhether the system intended functions met 10 CFR 54.4(a)(1) through (a)(3) requirements.SSCs supporting intended functions were considered within the scope of license renewal. The applicant performed component-level screening for electrical and mechanical systems withinthe scope of license renewal. Most component-level screening was performed and documented in the license renewal database on a commodity basis. Components were either screened out as active or included in a commodity group.The applicant described electrical commodity groups and their intended function in the followingsections of the LRA:

  • 2.5.2.2fuse holders
  • 2.5.2.3non-EQ cables and connections
  • 2.5.2.4offsite power/SBO recovery pathSections 2.5.2.1-2.5.2.4 present the staff's review findings regarding LRASections 2.5.2.1-2.5.2.4, respectively.

2-1642.5.2.1 Electrical Penetrations2.5.2.1.1 Summary of Technical Information in the Application In LRA Section 2.5.2.1, the applicant described the electrical penetrations. The electricalpenetrations assemblies consist of one or more electrical conductors and materials, which provide a pressure boundary between the inboard and outboard sides of the penetration. Thepenetration must be capable of maintaining the license renewal intended function of "electrical continuity" through the boundary. The cable and material associated with maintaining the license renewal intended function is the focus of this review. Section 2.4.13 of the LRA contains portions and materials of the penetration assembly associated with the license renewal intended function "pressure boundary" (or essentially leaktight containment barrier). For an electrical penetration to be within the scope of license renewal, it must support an intended function of one of the systems or components identified as within the scope of license renewal.MNGP uses penetrations manufactured by GE and D.G. O'Brien. There are 24 electrical penetrations at MNGP. Nineteen of these are in use and five are spares. There are six penetrations designated as requiring EQ and are addressed in SER Section 4.7. Of the remaining 13 penetrations, only 4 are within the scope of license renewal. The other nine penetrations do not contain cables which provide a license renewal SR intended function or are credited for any of the regulated events.The intended function of electrical penetrations is to provide electrical connections to specifiedsections of an electrical circuitIn LRA Table 2.5.2-1, the applicant identified the following commodity groups that are within thescope of license renewal and subject to an AMR:

  • non-EQ insulated cables and connections
  • non-EQ electrical and I&C penetration assemblies except cable and connections(electrical components only-potting compound, vapor barrier, and support)
  • non-EQ electrical cables used in instrumentation circuits not subject to 10 CFR 50.49EQ requirements that are sensitive to reduction in conductor insulation resistance2.5.2.1.2 Staff Evaluation The staff reviewed LRA Section 2.5.2.1 and the USAR using the evaluation methodologydescribed in SER Section 2.5. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.5.2.5.2.1.3 Conclusion On the basis of its review, the staff concluded that the applicant adequately identified theelectrical penetrations components that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the commodity groups for electrical penetrations components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).

2-1652.5.2.2 Fuse Holders2.5.2.2.1 Summary of Technical Information in the Application In LRA Section 2.5.2.2, the applicant described the fuse holders. For a fuse holder (block, clips,and connection points) to be within scope, it must support an intended function of one of the systems or components identified as within the scope of license renewal. In addition, the reviewof fuse holders applies only to those that are not part of a larger assembly, but support SR and NSR functions in which the failure of a fuse precludes a safety function from being accomplished. Fuse holders inside an enclosure of an active component, such as the switchgear, load center, MCC, distribution panel, power supply, power inverter, charger, converter, inverter, or circuit board, are parts of the larger assembly. Since the applicant regularly inspects and maintains piece parts and subcomponents in such an enclosure as part of the plant's normal maintenance and surveillance activities, they are not subject to an AMR.Since there is no all-inclusive fuse database at MNGP, the applicant used various databases,analysis/calculations, and plant walkdowns to identify those fuse holders meeting the abovecriteria. Based on the above reviews of databases, analysis/calculations, and in-plant walkdowns, the applicant determined that the majority of the fuse holders at MNGP are locatedinside an active device enclosure. For those fuse holders not located inside an active device enclosure, the applicant performed further evaluation to determine whether the fuse holdersupported an intended function of systems or components identified as within the scope oflicense renewal. Those fuse holders not supporting an intended function were scoped out and no further evaluations were performed. Those fuse holders that do support an intended function were scoped in and are subject to AMR.The intended function of fuse holders is to provide electrical connections to specified sectionsof an electrical circuit.In LRA Table 2.5.2-2, the applicant identified the fuse holders as a commodity group that iswithin the scope of license renewal and subject to an AMR.2.5.2.2.2 Staff Evaluation The staff reviewed LRA Section 2.5.2.2 and the USAR using the evaluation methodologydescribed in SER Section 2.5. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.5.2.5.2.2.3 Conclusion On the basis of its review, the staff concluded that the applicant adequately identified the fuseholders that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the fuse holders as a commodity group that is subject to an AMR, as required by 10 CFR 54.21(a)(1).

2-1662.5.2.3 Non-EQ Cables and Connections2.5.2.3.1 Summary of Technical Information in the Application In LRA Section 2.5.2.3, the applicant described the non-EQ cables and connections. Thecomponents evaluated are non-EQ power, I&C insulated cables and connections (connections include connectors, splices, and terminal blocks), and uninsulated (bare) ground conductors.SER Section 4.7 evaluates components that are part of the Environmental QualificationProgram. In accordance with the Department of Energy's cable aging management guideline presented in SAND96-0344, "Aging Management Guideline for Commercial Nuclear Power Plants-Electrical Cable and Terminations," issued September 1996, an insulated cable is an assembly of a single electrical conductor (wire) with an insulation covering or a combination of conductors insulated from one another with overall coverings. Connections (or terminations) are used to connect the cable conductors to other cables or electrical devices. The applicant evaluated several types of connections. Plug-in connectors are one or more electrical contacts that plug or screw into a mating receptacle. Splice insulation systems (heat shrink and tape) areinsulation material generally applied over compression (i.e., bolted) or fusion connections and are used to seal and insulate cable or splice terminations or junctions from the surrounding environment. Terminal blocks are an insulating base with fixed points for landing of wiring orconnection of terminal (ring) lugs. Terminal blocks are installed in enclosures such as controlboards, MCCs, motors, terminal boxes, or power panel boards for protection from both physical and environmental damage. Uninsulated ground conductors are electrical conductors (e.g.,

bare copper cable, bare copper bar) that are used to make electrical equipment ground connections.Uninsulated ground cables are neither classified as SR nor relied upon for SR equipment toperform their intended function, as identified in 10 CFR 54.4(a); therefore, the applicant hasdetermined that uninsulated ground cables are outside the scope of license renewal.The intended function of non-EQ cable and connections is to provide electrical connections tospecified sections of an electrical circuit.In LRA Table 2.5.2-3, the applicant identified the non-EQ cables and connections as commoditygroups that are within the scope of license renewal and subject to an AMR as follows:

  • electrical cables and connections not subject to 10 CFR 50.49 EQ requirements
  • electrical cables used in instrumentation circuits not subject to 10 CFR 50.49 EQrequirements that are sensitive to reduction in conductor insulation resistance
  • inaccessible medium voltage (2 kV to 34.5 kV) cable and connections (e.g., installed inconduit or direct buried) not subject to 10 CFR 50.49 EQ requirements2.5.2.3.2 Staff Evaluation The staff reviewed LRA Section 2.5.2.3 and the USAR using the evaluation methodologydescribed in SER Section 2.5. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.5.

2-1672.5.2.3.3 ConclusionOn the basis of its review, the staff concluded that the applicant adequately identified thenon-EQ cables and connections that are within the scope of license renewal, as required by 10 CFR 54.4(a), and the non-EQ cables and connections as commodity groups that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.5.2.4 Offsite Power/SBO Recovery Path 2.5.2.4.1 Summary of Technical Information in the Application In LRA Section 2.5.2.4, the applicant described the offsite power/SBO recovery path. Thepassive, long-lived, in-scope components comprising the offsite power/SBO recovery path subject to an AMR include phase bus, switchyard bus, high-voltage insulators, transmission conductors, non-EQ cables and connections, and non-EQ buried cable. The hardware used to secure or attach switchyard bus and transmission conductors to high-voltage insulators is also included. Phase bus is a bus that is enclosed (either within its own enclosure or inside a vault) and is not part of an active component, such as switchgear, load center, or MCC. There are four types of phase bus-isolated-phase bus, nonsegregated phase bus, phase bus enclosed in a vault, and segregated phase bus. MNGP has two of the types of phase buses mentioned above. A switchyard bus is an uninsulated, unenclosed, rigid electrical conductor used in switchyards to connect two or more elements of an electrical power circuit, such as active disconnect (gang) switches and passive transmission conductors. Included with the switchyard bus is the hardware used to secure the bus to a high-voltage insulator or transmission conductor. Switchyard bus connections to an active component (e.g., disconnect (gang) switch, transformer) are inspected and maintained along with the active components (e.g., disconnect (gang) switch, transformer) and are not included here. In accordance with the Institute of Electrical and Electronics Engineers, an insulator is an insulating material in a form designed to support a conductor physically and separate the conductor electrically from another conductor or object. Transmission conductors are uninsulated, stranded electrical cables used to electrically connect two or more elements of an electrical power circuit. The offsite power system/recovery path boundary includes the 345-kV, 115-kV, and 13.8-kV system componentsfrom the plant 4.16-kV buses out to the first switchyard breaker, which disconnects the plant from the 345-kV or 115-kV ring bus or the 13.8-kV system fed from the No. 10 transformer.In LRA Table 2.5.2-4, the applicant identified the following commodity groups for offsitepower/SBO recovery path that are within the scope of license renewal and subject to an AMR:

  • nonsegregated phase bus
  • high-voltage insulators
  • high-voltage transmission conductors
  • electrical cables and connections not subject to 10 CFR 50.49 EQ requirements
  • inaccessible medium voltage (2 kV to 34.5 kV) cable (e.g., installed in conduit or directburied) not subject to 10 CFR 50.49 EQ requirements 2-168The intended functions of the above commodity groups include the following:
  • insulate and support an electrical conductor
  • provide electrical connections to specified sections of an electrical circuit2.5.2.4.2 Staff Evaluation The staff reviewed LRA Section 2.5.2.4 and the USAR using the evaluation methodologydescribed in SER Section 2.5. The staff conducted its review in accordance with the guidance described in SRP-LR Section 2.5.The staff's review of LRA Section 2.5.2.4 identified an area for which it needed additionalinformation to complete its evaluation of the applicant's results. The applicant responded to the staff's RAI as discussed below.In RAI 2.5.2-1, dated August 18, 2005, the staff noted that LRA Section 2.5.2.4, under thedescription of Offsite Power/SBO Recovery Path, states that the path boundary includes the 345-kV, 115-kV, and 13.8-kV system components from the plant 4.16-kV buses out to the firstswitchyard breaker, which disconnects the plant from the 345-kV or 115-kV ring bus or the 13.8-kV system fed from the No. 10 transformer in the switchyard. The staff requested that theapplicant confirm that the path boundary also includes the associated control circuits subject toan AMR.In its response, by letter dated September 16, 2005, the applicant confirmed that the controlcircuits for the offsite power/SBO recovery path components within the scope of license renewalare included within the AMR scope.Based on its review, the staff found the applicant's response to RAI 2.5.2-1 acceptable becausethe applicant verified that the associated control circuits are subject to an AMR. Therefore, thestaff's concern described in RAI 2.5.2-1 is resolved.2.5.2.4.3 Conclusion On the basis of its review, the staff concluded that the applicant adequately identified the offsitepower/SBO recovery path components that are within the scope of license renewal, as requiredby 10 CFR 54.4(a), and adequately identified the commodity group for the offsite power/SBOrecovery path components that are subject to an AMR, as required by 10 CFR 54.21(a)(1).2.6 Conclusion for Scoping and ScreeningThe staff reviewed the information in LRA Section 2, "Scoping and Screening Methodology forIdentifying Structures and Components Subject to Aging Management Review, and Implementation Results." The staff determined that the applicant's scoping and screeningmethodology was consistent with the requirements of 10 CFR 54.21(a)(1) and the SRP-LR onthe treatment of SR and NSR SSCs within the scope of license renewal and that the SCsidentified as requiring an AMR are consistent with the requirements of 10 CFR 54.4 and10 CFR 54.21(a)(1).

2-169On the basis of its review, the staff concluded that the applicant adequately identified thosesystems and components that are within the scope of license renewal, as required by10 CFR 54.4(a), and those systems and components that are subject to an AMR, as requiredby 10 CFR 54.21(a)(1).

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3-1SECTION 3AGING MANAGEMENT REVIEW RESULTSThis section of the safety evaluation report (SER) contains the staff's evaluation of theapplicant's aging management programs (AMPs) and aging management reviews (AMRs). In Appendix B to its license renewal application (LRA), the applicant described the 35 AMPs that itrelies on to manage or monitor the aging of long-lived, passive structures and components (SCs).In LRA Section 3, the applicant provided the results of the AMRs for those SCs that it identifiedin LRA Section 2 as being within the scope of license renewal and subject to an AMR.3.0 Applicant's Use of the Generic Aging Lessons Learned ReportIn preparing its LRA, Nuclear Management Company, LLC (NMC or the applicant), creditedNUREG-1801, "Generic Aging Lessons Learned (GALL) Report," issued July 2001. The GALLReport contains the staff's generic evaluation of the existing plant programs, and it documentsthe technical basis for determining when existing programs are adequate without modification, and when existing programs should be augmented for the extended period of operation. The evaluation results documented in the GALL Report indicate that many of the existing programsare adequate to manage the aging effects for particular SCs for license renewal without change. The GALL Report also contains recommendations on specific areas for which existing programs should be augmented for license renewal. An applicant may reference the GALL Report in its LRA to demonstrate that the programs at its facility correspond to those reviewedand approved in the report.The GALL Report provides a summary of staff-approved AMPs to manage or monitor the agingof SCs that are subject to an AMR. If an applicant commits to implementing these staff-approved AMPs, the time, effort, and resources used to review an applicant's LRA willlikely be reduced, thereby improving the efficiency and effectiveness of the license renewal review process. The GALL Report also serves as a reference for applicants and staff reviewers to quickly identify those AMPs and activities that the staff has determined will adequatelymanage or monitor aging during the period of extended operation.The GALL Report identifies (1) systems, structures, and components (SSCs), (2) SC materials,(3) the environments to which the SCs are exposed, (4) the aging effects associated with thegiven materials and environments, (5) the AMPs that are credited with managing or monitoring the aging effects, and (6) recommendations for further applicant evaluations of aging management for certain component types.The staff performed its review in accordance with the requirements of Title 10, Part 54,"Requirements for Renewal of Operating Licenses for Nuclear Power Plants," of the Code ofFederal Regulations (10 CFR Part 54), the guidance provided in NUREG-1800, "StandardReview Plan for Review of License Renewal Applications for Nuclear Power Plants" (SRP-LR),

issued July 2001, and the guidance provided in the GALL Report.

3-2In addition to its review of the LRA, the staff conducted an onsite audit of selected AMRs andassociated AMPs, as described in the "Audit and Review Plan for Plant Aging Management Reviews and Programs for Monticello Nuclear Generating Plant," dated June 2, 2005. The staff designed its onsite audits and reviews to maximize the efficiency of its review of the LRA. This helps reduce the need for formal correspondence between the staff and the applicant, thereby improving the review's efficiency. In addition, the applicant could respond to questions and the staff could readily evaluate the applicant's responses.3.0.1 Format of the License Renewal Application The applicant submitted an application that followed the standard LRA format, which wasagreed to by the U.S. Nuclear Regulatory Commission (NRC) staff and the Nuclear EnergyInstitute (NEI) (see letter dated April 7, 2003, ADAMS Accession No. ML030990052). This revised LRA format incorporates lessons learned from the staff's reviews of the previous five LRAs. These previous applications used a format developed from information gained during an NRC staff and NEI demonstration project that was conducted to evaluate the use of the GALLReport in the staff's review process.The organization of LRA Section 3 parallels Chapter 3 of the SRP-LR. Two types of tablespresent the AMR results information in LRA Section 3:(1)Table 1-Table 3.x.1, where "3" indicates the LRA section number, "x" indicates thesubsection number from the GALL Report, and "1" indicates that this is the first table type in LRA Section 3.(2)Table 2-Table 3.x.2-y, where "3" indicates the LRA section number, "x" indicates thesubsection number from the GALL Report, "2" indicates that this is the second table type in LRA Section 3, and "y" indi cates the system table number.The content of previous applications for other plants' renewals and the Monticello NuclearGenerating Plant (MNGP) application is essentially the same. The revised format used for the MNGP application was intended to modify the tables in Section 3 to provide additional information that will assist the staff in its review. In Table 1, the applicant summarized theportions of the application that it considered to be consistent with the GALL Report. In Table 2,the applicant identified the linkage between the scoping and screening results in Section 2 ofthe LRA and the AMRs in Section 3.3.0.1.1 Overview of Table 1 Table 3.x.1 (Table 1) provides a summary comparison of how the facility aligns with thecorresponding tables in the GALL Report, Volume 1. The table is essentially the same as Tables 1 through 6 provided in the GALL Report, Volume 1, except that the "Type" column has been replaced by an "Item Number" column and the "Item Number in GALL" column has been replaced by a "Discussion" column. The "Item Number" column provides the reviewer with a means to cross-reference from Table 2 to Table 1. The applicant used the "Discussion" column to provide clarifying and amplifying information. This column might contain the following types of information:

3-3

  • further evaluation recommended (information or reference to the location of thatinformation)
  • the name of a plant-specific program being used
  • exceptions to the GALL Report assumptions
  • a discussion of how the line is consistent with the corresponding line item in the GALLReport when this may not be intuitively obvious
  • a discussion of how the item is different from the corresponding line item in the GALLReport (e.g., when an exception is taken to an AMP that is listed in the GALL Report)The format of Table 1 allows the staff to align a specific Table 1 row with the correspondingGALL Report, Volume 1, table row so that the consistency can be easily verified.3.0.1.2 Overview of Table 2 Table 3.x.2-y (Table 2) provides the detailed results of the AMRs for those componentsidentified in LRA Section 2 as subject to an AMR. The LRA contains a Table 2 for each of the systems or components within a system grouping (e.g., reactor coolant system (RCS),engineered safety features (ESFs), and auxiliary systems). For example, the ESF groupcontains tables specific to the core spray (CSP) system, high-pressure coolant injection (HPC) system, and residual heat removal (RHR) system,. Table 2 consists of the following ninecolumns: (941)Component Type-The first column identifies the component types from LRASection 2 that are subject to an AMR. The table lists the component types in alphabetical order. (942)Intended Function-The second column contains the license renewal intendedfunctions for the listed component types. LRA Table 2.1-1 contains definitions of intended functions. (943)Material-The third column lists the particular materials of construction for thecomponent type. (944)Environment-The fourth column lists the environment to which the componenttypes are exposed. The column indicates the internal and external service environments; LRA Table 3.0-1 lists these environments. (945)Aging Effect Requiring Management (AERM)-The fifth column lists aging effectsrequiring management. As part of the AMR process, the applicant determined any AERMs for each combination of material and environment. (946)AMPs-The sixth column lists the AMPs that the applicant used to manage theidentified aging effects. (947)NUREG-1801 Volume 2 Line Item-The seventh column lists the GALL Reportitem(s) that the applicant identified as being similar to the AMR results in the LRA.The applicant compared each combination of component type, material, environment, AERM, and AMP in LRA Table 2 to the items in the GALL Report. If the GALL Report contained no corresponding items, the applicant left the column 3-4blank. In this way, the applicant identified the AMR results in the LRA tables thatcorrespond to the items in the GALL Report tables. (948)Table 1 Item-The eighth column lists the corresponding summary item numberfrom Table 1. If the applicant identified AMR results in Table 2 that are consistentwith the GALL Report, then Table 2 should list the associated Table 3.x.1 line summary item number. If the GALL Report contains no corresponding item, then the applicant left the eighth column blank. In this way, the information from the two tables can be correlated. (949)Notes-The ninth column lists the corresponding notes that the applicant used toidentify how the information in Table 2 aligns with that in the GALL Report. An NEI working group developed the notes identified by letters, which will be used in futureLRAs. Any plant-specific notes are identified by a number and provide additional information concerning the consistency of the line item with the GALL Report.3.0.2 Staff's Review Process The staff conducted the following three types of evaluations of the AMRs and associated AMPs: (1)For items that the applicant stated were consistent with the GALL Report, the staffconducted either an audit or a technical review to determine consistency with the GALL Report. (2)For items that the applicant stated were consistent with the GALL Report withexceptions and/or enhancements, the staff conducted either an audit or a technicalreview of the item to determine consistency with the GALL Report. In addition, the staff conducted either an audit or a technical review of the applicant's technical justification for the exceptions and the adequacy of the enhancements. (3)For other items, the staff conducted a technical review per 10 CFR 54.21(a)(3).The staff performed audits and technical reviews of the applicant's AMPs and AMRs. Theseaudits and technical reviews determine whether the effects of aging on SCs can be adequately managed so that their intended functions can be maintained consistent with the plant's currentlicensing basis (CLB) for the period of extended operation, as required by 10 CFR Part 54.3.0.2.1 Review of AMPs For those AMPs for which the applicant claimed consistency with the GALL Report AMPs, thestaff conducted either an audit or a technical review to verify that the applicant's AMPs were consistent with the AMPs in the GALL Report. For each AMP that had one or more deviations, the staff evaluated each deviation to determine (1) whether the deviation is acceptable and (2)whether the AMP, as modified, will adequately manage the aging effect(s) for which it iscredited. For AMPs that the GALL Report, the staff performed a full review to determine theadequacy of the AMPs. 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 toan AMR for license renewal.

3-5 (2)Preventive Actions-Preventive actions should prevent or mitigate aging degradation. (3)Parameters Monitored or Inspected-Parameters monitored or inspected should belinked to the degradation of the particular SC intended function(s). (4)Detection of Aging Effects-Detection of aging effects should occur before there is aloss of SC intended function(s). This element 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 the timely detection of aging effects. (5)Monitoring and Trending-Monitoring and trending should provide predictability of theextent of degradation, as well as timely corrective or mitigative actions. (6)Acceptance Criteria-Acceptance criteria, against which the need for corrective actionwill be evaluated, should ensure that the SC intended function(s) are maintained underall CLB design conditions during the period of extended operation. (7)Corrective Actions-Corrective actions, including root cause determination andprevention of recurrence, should be timely. (8)Confirmation Process-The confirmation process should ensure that preventive actionsare adequate and that appropriate corrective actions have been completed and are effective. (9)Administrative Controls-Administrative controls should provide a formal review andapproval process. (10)Operating Experience-Operating experience of the AMP, including past correctiveactions resulting in program enhancements or additional programs, should provide objective evidence to support the conclusion that the effects of aging will be m anagedadequately so that the SC intended function(s) will be maintained during the period ofextended operation.The "Audit and Review Report for Plant Aging Management Reviews and Programs MonticelloNuclear Generating Plant," dated October 12, 2005 (hereafter referred to as the MNGP audit and review report), details the staff's audit evaluation of program elements (1) through (6), as summarized in SER Section 3.0.3.The staff reviewed the applicant's Corrective Action Program (CAP) and documented itsevaluations in SER Section 3.0.4. The staff's evaluation of the CAP included assessment of theCorrective Actions, Confirmation Process, and Administrative Controls program elements.The staff reviewed the information concerning the Operating Experience program element anddocumented its evaluation in the MNGP audit and review report. The staff also included a summary of the program in SER Section 3.0.3.The staff reviewed the Updated Safety Analysis Report (USAR) supplement for each AMP todetermine if it adequately describes the program or activity, as required by 10 CFR 54.21(d).

3-63.0.2.2 Review of AMR ResultsLRA Table 2 contains information concerning whether the applicant's AMRs align with theAMRs identified in the GALL Report. For a given AMR in Table 2, the staff reviewed the intended function, material, environment, AERM, and AMP combination for a particular component type within a system. The applicant identified the AMRs that correlate between acombination in Table 2 and a combination in the GALL Report using a referenced item number in the seventh column, "NUREG-1801 Volume 2 Line Item." The staff also conducted onsiteaudits to verify the correlation. A blank seventh column indicates that the applicant could not locate an appropriate corresponding combination in the GALL Report. The staff conducted a technical review of these combinations that were not consistent with the GALL Report. The nextcolumn, "Table 1 Item," provides a reference number that indicates the corresponding row in Table 1.3.0.2.3 USAR Supplement Consistent with the SRP-LR, for the AMRs and associated AMPs that it reviewed, the staff alsoreviewed the USAR supplement that summarizes the applicant's programs and activities for managing the effects of aging for the period of extended operation, as required by 10 CFR 54.21(d).3.0.2.4 Documentation and Documents Reviewed In performing its review, the staff relied heavily on the LRA, the LRA supplements, the SRP-LR,and the GALL Report.In addition, during the onsite audit, the staff examined the applicant's justification, asdocumented in the staff's MNGP audit and review report, to verify that the applicant's activities and programs will adequately manage the effects of aging on SCs. The staff also conducteddetailed discussions and interviews with the applicant's license renewal project personnel and others with technical expertise relevant to aging management.3.0.3 Aging Management Programs Table 3.0.3-1 presents the AMPs credited by the applicant and described in LRA Appendix B.The table also indicates the GALL Report program that the applicant claimed its AMP wasconsistent with (if applicable) and the SSCs for managing or monitoring aging. Finally, the tableprovides the section of the SER that documents the staff's evaluation of the program.Table 3.0.3-1 MNGP's Aging Management ProgramsMNGP AMP(LRA Section)

GALLComparison GALLAMP(s)LRA Systems or StructuresThat Credit the AMPStaff'sSER SectionExisting AMPs10 CFR 50, Appendix JProgram(B2.1.1)Consistent withexceptionsXI.S4containments, structures,and component supports 3.0.3.2.1 MNGP AMP(LRA Section)

GALLComparison GALLAMP(s)LRA Systems or StructuresThat Credit the AMPStaff'sSER Section3-7ASME Section XIIn-Service Inspection,Subsections IWB,IWC, and IWDProgram(B2.1.2)Consistent withexceptionXI.M1reactor coolant system,engineered safety features 3.0.3.2.2ASME Section XI,Subsection IWFProgram(B2.1.3)Consistent withenhancementXI.S3containments, structures,and component supports 3.0.3.2.3Bolting IntegrityProgram(B2.1.4)Consistent withenhancementsXI.M18reactor coolant system,engineered safety features,auxiliary systems, steam andpower conversion system,containment, structures, andcomponent supports3.0.3.2.4Buried Piping & TanksInspection Program(B2.1.5)Consistent withenhancementsXI.M34engineered safety features;auxiliary systems;containments, structures,and component supports 3.0.3.2.5BWR Control RodDrive Return LineNozzle Program(B2.1.7)Consistent withexceptionsXI.M6reactor coolant system 3.0.3.2.6BWR FeedwaterNozzle Program(B2.1.8)Consistent withenhancementsXI.M5reactor coolant system 3.0.3.2.7BWR PenetrationsProgram(B2.1.9)Consistent withexceptionsXI.M8reactor coolant system 3.0.3.2.8BWR Stress CorrosionCracking Program(B2.1.10)Consistent withexceptionXI.M7reactor coolant system,engineered safety features,auxiliary systems 3.0.3.2.9BWR Vessel IDAttachment WeldsProgram(B2.1.11)Consistent withexceptionXI.M4reactor coolant system 3.0.3.2.10BWR Vessel InternalsProgram(B2.1.12)Consistent withexception andenhancementXI.M9reactor coolant system 3.0.3.2.11Closed-Cycle CoolingWater System Program(B2.1.13)Consistent withexceptions andenhancementXI.M21reactor coolant system,engineered safety features,auxiliary systems 3.0.3.2.12Compressed AirMonitoring Program(B2.1.14)Consistent withexceptions andenhancementsXI.M24auxiliary systems 3.0.3.2.13 MNGP AMP(LRA Section)

GALLComparison GALLAMP(s)LRA Systems or StructuresThat Credit the AMPStaff'sSER Section3-8Fire ProtectionProgram(B2.1.17)Consistent withexception andenhancementXI.M26auxiliary systems;containments, structures,and component supports 3.0.3.2.15Fire Water SystemProgram(B2.1.18)Consistent withenhancementXI.M27auxiliary systems 3.0.3.2.16Flow-AcceleratedCorrosion Program(B2.1.19)ConsistentXI.M17reactor coolant system,engineered safety features,auxiliary systems, steam andpower conversion system 3.0.3.1.2Fuel Oil ChemistryProgram(B2.1.20)Consistent withexceptions andenhancementsXI.M30auxiliary systems 3.0.3.2.17Inspection of OverheadHeavy Load and LightLoad (Related toRefueling) HandlingSystems Program(B2.1.22)Consistent withexception andenhancementsXI.M23containments, structures,and component supports 3.0.3.2.18Open-Cycle CoolingWater System Program(B2.1.24)ConsistentXI.M20engineered safety features,auxiliary systems, steam andpower conversion system 3.0.3.1.5Plant ChemistryProgram(B2.1.25)Consistent withexceptionsXI.M2reactor coolant system,engineered safety features,auxiliary systems, steam andpower conversion system 3.0.3.2.19Primary ContainmentIn-Service InspectionProgram(B2.1.26)ConsistentXI.S1containments, structures,and component supports 3.0.3.1.6Protective CoatingMonitoring &Maintenance Program(B2.1.27)Consistent withenhancementXI.S8containments, structures,and component supports3.0.3.2.20Reactor Head ClosureStuds Program(B2.1.28)Consistent withexceptionsXI.M3reactor coolant system 3.0.3.1.7Reactor VesselSurveillance Program(B2.1.29)Consistent withenhancementXI.M31reactor coolant system 3.0.3.2.21Structures MonitoringProgram(B2.1.31)Consistent withenhancementsXI.S6containments, structures,and component supports 3.0.3.2.23 MNGP AMP(LRA Section)

GALLComparison GALLAMP(s)LRA Systems or StructuresThat Credit the AMPStaff'sSER Section3-9System ConditionMonitoring Program(B2.1.32)Plant-specificNAreactor coolant system;engineered safety features;auxiliary systems; steam andpower conversion system;containments, structures,and component supports 3.0.3.3.2Thermal Aging &Neutron IrradiationEmbrittlement of CastAustenitic StainlessSteel (CASS) Program(B2.1.33)ConsistentXI.M13reactor coolant system 3.0.3.1.8Electrical EquipmentSubject to10 CFR 50.49EnvironmentalQualification (EQ)Requirements Program(B3.1)ConsistentX.E1electrical and instrumentationand controls3.0.3.1.9Metal Fatigue of theReactor CoolantPressure BoundaryProgram(B3.2)Consistent withenhancementX.M1reactor coolant system,engineered safety features3.0.3.2.24 New AMPsBus Duct InspectionProgram(B2.1.6)Plant specificNAelectrical and instrumentationand controls 3.0.3.3.1Electrical Cables &Connections NotSubject to10 CFR 50.49EnvironmentalQualificationRequirements Program(B2.1.15)ConsistentXI.E1electrical and instrumentationand controls 3.0.3.1.1Electrical Cables NotSubject to10 CFR 50.49EnvironmentalQualificationRequirements Used inInstrumentationCircuits Program(B2.1.16)Consistent withexceptionsXI.E2electrical and instrumentationand controls 3.0.3.2.14 MNGP AMP(LRA Section)

GALLComparison GALLAMP(s)LRA Systems or StructuresThat Credit the AMPStaff'sSER Section3-10Inaccessible MediumVoltage (2kV to34.5kV) Cables NotSubject to10 CFR 50.49 EQRequirements Program(B2.1.21)ConsistentXI.E3electrical and instrumentationand controls 3.0.3.1.3One-Time InspectionProgram(B2.1.23)ConsistentXI.M32reactor coolant system,engineered safety features,auxiliary systems, steam andpower conversion system 3.0.3.1.4Selective Leaching ofMaterials Program(B2.1.30)Consistent withexceptionXI.M33engineered safety features,auxiliary systems, steam andpower conversion system 3.0.3.2.223.0.3.1 AMPs That Are Consistent with the GALL ReportIn LRA Appendix B, the applicant identified the following AMPs as consistent with the GALLReport:

  • Electrical Cables & Connections Not Subject to 10 CFR 50.49 EnvironmentalQualification (EQ) Requirements Program (B2.1.15)
  • Flow-Accelerated Corrosion (FAC) Program (B2.1.19)
  • Inaccessible Medium Voltage (2kV to 34.5kV) Cables Not Subject to 10 CFR 50.49 EQRequirements Program (B2.1.21)
  • One-Time Inspection Program (B2.1.23)
  • Open-Cycle Cooling Water (OCCW) System Program (B2.1.24)
  • Reactor Head Closure Studs Program (B2.1.28)
  • Thermal Aging & Neutron Irradiation Embrittlement of Cast Austenitic StainlessSteel (CASS) Program (B2.1.33)
  • Electrical Equipment Subject to 10 CFR 50.49 EQ Requirements Program (B3.1)3.0.3.1.1Electrical Cables & Connections Not Subject to 10 CFR 50.49 EnvironmentalQualification Requirements ProgramSummary of Technical Information in the Application. In LRA Section B2.1.15, the applicantdescribed the Electrical Cables & Connections Not Subject to 10 CFR 50.49 EQ Requirements Program, stating that this new program is consistent with GALL AMP XI.E1, "Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements." An adverse localized environment is a condition in a limited plant area that is significantly more severe than the specified service environment for the component. An adverse variation in environment is significant if it could appreciably increase the rate of aging of a component or 3-11have an immediate adverse effect on operability. In most areas of the plant, the actual ambientenvironments (e.g., temperature, radiation, or moisture) are less severe than the plant designenvironment. However, in a limited number of localized areas, the actual environments may be more severe than the plant design environment for those areas. Cable and connection insulation materials may degrade more rapidly than expected in these adverse localized environments. Since they are not subject to the EQ requirements of 10 CFR 50.49,"Environmental Qualification of Electric Equipment Important to Safety for Nuclear Power Plants," the electrical cables and connections covered by this AMP are either not exposed to harsh accident conditions or not required to remain functional during or following an accident to which they are exposed. The scope of this program includes accessible non-EQ electrical cables and connections, including control and instrumentation circuits, within the scope of license renewal.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report documents the details of the staff's evaluation of this AMP. The staff determined that this AMP is consistent with theAMP described in the GALL Report, including the associated operating experience attribute.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.E1.The staff reviewed those portions of AMP B2.1.15, "Electrical Cables & Connections NotSubject to 10 CFR 50.49 Environmental Qualification Requirements Program," which the applicant claims are consistent with GALL AMP XI.E1, "Electrical Cables & Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program," and found themconsistent with the GALL Report AMP. Because it is consistent with the GALL Report, the AMPensures that the effects of aging will be adequately managed. The staff found the applicant'sLRA AMP acceptable because it conforms to the recommended GALL Report AMP.Operating Experience. In LRA Section B2.1.15, the applicant explained that the ElectricalCables & Connections Not Subject to 10 CFR 50.49 EQ Requirements Program is a new site-specific program and therefore does not have any operating experience. However, as noted in the GALL Report, industry operating experience shows that adverse local environments caused by heat or radiation for electrical cables and connections have been shown to exist and produce degradation of insulating material degradation that can be detected visually.During the audit and review, the staff asked the applicant how it captures operating experience.The applicant stated that the site's CAP identifies, tracks, and trends site operating experiencerelated to all site components. It documents any site component identified as degraded, failed, or potentially unable to fulfill its intended functions in the site CAP database. The plantengineering staff then evaluates these components for the extent of the condition and takesappropriate followup actions. The plant engineering staff also trends related CAPs to identify generic issues and addresses trended site issues in program health reports presented to site management on a scheduled basis. The CAP also addresses issues related to 10 CFR 54.21, "Contents of Application-Technical Information," and external operating events reported by theNRC, Institute of Nuclear Power Operations (INPO), Licensing Information Service (LIS), and NMC Fleet. The staff reviewed the applicant's response and found it acceptable.

3-12The staff recognized that the CAP, which captures internal and external operating experienceissues, will ensure that the licensee reviews and incorporates operating experience in thefuture.On the basis of its review of the above industry and plant-specific operating experience anddiscussions with the applicant's technical personnel, the staff concluded that the applicant'sElectrical Cables & Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program will adequately manage the aging effects identified in the LRA for whichthis AMP is credited.USAR Supplement. In LRA Section A2.1.15, the applicant provided the USAR supplement forthe Electrical Cables & Connections Not Subject to 10 CFR 50.49 EQ Requirements Program.Subsequently, by letter dated June 10, 2005, the applicant revised its USAR supplement toinclude the following commitment, documented as commitment 26 in Table A.5:Prior to the period of extended operation, the MNGP Electrical Cables &Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Program will be implemented as a new program consistent withthe recommendations of NUREG-1801 Chapter XI Program XI.E1. The program will manage the aging of conductor insulation material on cables, connectors,and other electrical insulation materials that are installed in an adverse localized environment caused by heat, radiation, or moisture.The staff reviewed this section and determined that the information in the USAR supplement asaugmented by the commitment adequately describes the program as required by 10 CFR 54.21(d).Conclusion. On the basis of its review and audit of the applicant's Electrical Cables &Connections Not Subject to 10 CFR 50.49 EQ Requirements Program, the staff determined that those program elements for which the applicant claimed consistency with the GALL Report areconsistent with the GALL Report. The staff concluded that the applicant demonstrated that theeffects of aging will be adequately managed so that intended functions will be maintainedconsistent with the CLB for the period of extended operation, as required by10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.1.2 Flow-Accelerated Corrosion Program Summary of Technical Information in the Application. In LRA Section B2.1.19, the applicantdescribed the Flow-Accelerated Corrosion (FAC) Program, stating that this existing program is consistent with GALL AMP XI.M17, "Flow-Accelerated Corrosion." The program implements the Electric Power Research Institute (EPRI) guidelines in NSAC-202L-R2, "Recommendations for an Effective Flow-Accelerated Corrosion Program." This program also requires the use of CHECWORKS as a predictive tool. The program includes (1) an analysis to determine locations susceptible to flow-accelerated corrosion (FAC), (2) performance of limited baseline inspections, (3) followup inspections to confirm the predictions, and (4) repairing or replacing 3-13components, as necessary. The MNGP FAC Program includes the response made to GenericLetter (GL) 89-08, "Erosion/Corrosion Induced Pipe Wall Thinning, dated May 2, 1989."Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's evaluation of this AMP. The staff determined that this AMP is consistent with the AMPdescribed in the GALL Report, including the associated operating experience attribute.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.M17.During the audit and review, the staff asked the applicant to clarify the minimum allowable wallthickness defined in the MNGP FAC program. The applicant stated that if degradation isdetected such that the measured wall thickness is less than 87.5 percent of nominal wallthickness for safety-related (SR) piping or 60 percent of nominal wall thickness for nonsafety-related (NSR) piping, it will perform an engineering evaluation to determine whetherthe degraded component is acceptable for continued use. If the component requires repair orreplacement during the inspection outage, the applicant will initiate a conditionreport (CR)/action request (AR) in accordance with the site-specific CAP. If a replacement is planned for the next refueling outage, the applicant will initiate a work request in accordancewith the site-specific process for work requests/work orders (WOs). In addition to the engineering evaluation, the applicant will examine adjacent areas to bound the thinning andassure that the actual minimum wall thickness is measured.The applicant further evaluated the adequacy of using 60 percent of pipe nominal wall thicknessas a trigger point for an engineering evaluation of NSR piping. The applicant determined thatthe 60-percent criterion has technical merit in statistical analysis, but lacks rigorous justificationbecause the applicant has not performed any plant-specific analysis to ensure its validity for all cases at MNGP. By letter dated August 11, 2005, the applicant provided responses to questions raised during the AMP and AMR audits. In this letter, the applicant committed to revise its FAC Inspection Program to use the industry-accepted 87.5 percent of nominal pipe wall thickness for NSR piping as a trigger point for an engineering evaluation. The applicant identified this as commitment 53 in Table A.5 of the USAR supplement provided in its letter dated March 15, 2006. On the basis of its review, the staff found the applicant's responseacceptable because it adequately addressed the minimum wall thickness evaluation.The staff reviewed those portions of the MNGP AMP B2.1.19, "Flow-Accelerated CorrosionProgram," that the applicant claimed are consistent with GALL AMP XI.M17, "Flow-AcceleratedCorrosion," and found them consistent with the GALL Report AMP. Because it is consistent withthe GALL Report, the AMP ensures that the effects of aging will be adequately managed. Thestaff found the applicant's AMP acceptable because it conforms to the recommended GALL Report AMP.Operating Experience. In LRA Section B2.1.19, the applicant explained that the FAC wallthinning problems in single-phase systems have occurred throughout the industry infeedwater (FW) and c ondensate systems, and in two-phase piping in extraction steamlines andmoisture separator reheater and FW heater drains. Application of the program at MNGP hasresulted in the identification and replacement of susceptible piping sections with materials more 3-14resistant to FAC (e.g., extraction steam system piping and piping downstream of the moistureseparators). The NRC originally outlined the FAC program in NUREG-1344,"Erosion/Corrosion-Induced Pipe Wall Thinning in U.S. Nuclear Power Plants," issued 1989, and implemented it through GL 89-08. The MNGP program has evolved through industry experience and is now implemented using the guidelines of NSAC-202L-R2 and CHECWORKS as a predictive tool. Monitoring locations and inspection methods have improved over time based on industry and plant experience and through the development of new techniques.On the basis of its review of the above operating experience and discussions with theapplicant's technical personnel, the staff concluded that the applicant's FAC Program willadequately manage the aging effects at the applicant's plant.USAR Supplement. In LRA Section A2.1.19, the applicant provided the USAR supplement forthe FAC Program. The staff reviewed this section and determined that the information in the USAR supplement provides an adequate summary description of the program, as required by 10 CFR 54.21(d).Conclusion. On the basis of its review and audit of the applicant's FAC Program, the staffdetermined that those program elements for which the applicant claimed consistency with theGALL Report are consistent with the GALL Report. The staff concluded that the applicantdemonstrated that the effects of aging will be adequately managed so that intended functionswill be maintained consistent with the CLB for the period of extended operation, as required by10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it provides an adequate summary description of the program, as required by 10 CFR 54.21(d).3.0.3.1.3Inaccessible Medium Voltage (2kV to 34.5kV) Cables Not Subject to 10 CFR 50.49EQ Requirements ProgramSummary of Technical Information in the Application. In LRA Section B2.1.21, the applicantdescribed the Inaccessible Medium Voltage (2kV to 34.5kV) Cables Not Subject to 10 CFR 50.49 EQ Requirements Program, stating that this new program is consistent withGALL AMP XI.E3, "Inaccessible Medium-Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements." The intended function of insulated cables andconnections is to provide electrical connections to specified sections of an electrical circuit to deliver voltage, current, or signals. Most electrical cables at MNGP are located in dry environments. However, some cables may be exposed to condensation and wetting in inaccessible locations, such as conduits, cable trenches, cable troughs, duct banks, underground vaults, or direct buried installations. When an energized medium-voltage cable is exposed to wet conditions for which it was not designed, water treeing or a decrease in the dielectric strength of the conductor insulation can occur. This can potentially lead to electrical failure. In this AMP, the applicant takes periodic actions to prevent the exposure of cables to significant moisture, such as inspecting for water collection in cable manholes and conduit, and draining water, as needed. In-scope, medium-voltage cables exposed to significant moisture and significant voltage are tested to provide an indication of the condition of the conductor insulation. The specific type of test performed will be determined before the initial test, and it willbe a proven test for detecting deterioration of the insulation system as a result of wetting, suchas power factor, partial discharge, polarization index, or other testing that is state-of-the-art at the time the test is performed.

3-15Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's evaluation of this AMP. The staff determined that this AMP is consistent with the AMPdescribed in the GALL Report, including the associated operating experience attribute.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.E3.During the audit and review, the staff asked that the applicant explain the process for assuringthat cables in conduit are not subject to significant moisture and, thus, are not subject to testing. The applicant indicated that it is impossible to assure that cables in undergroundconduit are not exposed to significant moisture. The applicant further noted that the majority ofits underground cables are buried without the use of conduit and are thus subject to significant moisture and required to be tested. Cables located in underground conduit are also subject to significant moisture from condensation and required to be tested. In addition, under the Parameters Monitored or Inspected program element, included as part of MNGP AMP B2.1.21, "Inaccessible Medium Voltage (2kV to 34.5kV) Cables Not Subject to 10 CFR 50.49 EQ Requirements," the MNGP program will test medium-voltage cables (2 kilovolt (kV) to 34.5 kV)within the scope of license renewal exposed to moisture (direct buried or in underground conduit) and energized more than 25 percent of the time. The staff reviewed this response and found it acceptable.In the course of its review, the staff noted the applicant's statement that, in the PreventiveActions program element, it takes periodic actions, like inspecting for water collection in cable manholes and conduit and draining water as needed, to prevent prolonged exposure of medium-voltage cables to significant moisture. In the LRA, the applicant stated the following:Medium voltage cables, for which such actions are taken, are not required to betested since operating experience indicates that prolonged exposure to significant moisture and being energized for significant periods of time are required to induce this aging effect.In Request for Additional Information (RAI) B2.1.21-1, dated November 7, 2005, the staff notedits position that inaccessible medium-voltage cables be tested and inspected. Therefore, thestaff requested that the applicant remove the line from the LRA indicating that medium-voltagecables are not required to be tested. In addition, the staff requested that the applicant state theinspection frequency and its basis.In its response, by letter dated December 7, 2005, the applicant stated that it will revise thePreventive Action program element in LRA Section B2.1.21 to delete the following text:Medium-voltage cables, for which such actions are taken, are not required to betested since operating experience indicates that prolonged exposure to significant moisture and being energized for significant periods of time are required to induce this effect.

3-16In its letter dated March 15, 2006, the applicant amended the Detection of Aging Effectsprogram element by adding the following statement:In addition, the underground electrical vaults (manholes, handholes, etc)containing cable at MNGP are designed and installed without a concrete bottom.

The electrical vaults are set on natural soil which is porous river sand.

Historically, water accumulation in electrical vaults has not been an issue due to the natural draining of the porous soil. The inspection frequency for water collection will be based on actual plant experience. For those electrical vaults within the scope of license renewal, the initial inspection frequency for water accumulation will be at least once every two years. The first inspection for license renewal is to be completed before the period of extended operation.Based on its review, the staff found the applicant's response to RAI B2.1.21-1 acceptable. Thestaff found that the applicant's response addresses the staff's concern regarding testing and inspection of water in manholes for inaccessible medium-voltage cables. Therefore, the staff's concern described in RAI B2.1.21-1 is resolved.The staff reviewed those portions of MNGP AMP B2.1.21 that the applicant claimed areconsistent with GALL AMP XI.E3 and found them consistent with the GALL Report AMP.Because it is consistent with the GALL Report, the AMP ensures that the effects of aging will beadequately managed. The staff found the applicant's LRA AMP acceptable because it conforms to the recommended GALL Report AMP.Operating Experience. In LRA Section B2.1.21, the applicant explained that the InaccessibleMedium Voltage (2kV to 34.5kV) Cables Not Subject to 10 CFR 50.49 EQ Requirements Program is a new program with no operating experience. However, as noted in the GALL Report, industry operating experience shows 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 vary directly with operating voltage. Treeing is much less prevalent in 4-kV cables than those operated at 13-kV or 33-kV. Minimizing exposure to moisture also lessens the potential for the development of water treeing.During the audit and review, the staff asked the applicant how it captures operating experience.The applicant indicated that the site's CAP identifies, tr acks, and trends site operatingexperience related to all site components. The applicant documents any site component identified as degraded, failed, or potentially unable to fulfill its intended functions in the site CAPdatabase. The plant engineering staff then evaluates these components for the extent of the condition and takes appropriate followup actions. The plant engineering staff also trends related CAPs to identify generic issues and addresses trended site issues in program health reports presented to site management on a scheduled basis. The CAP also addresses issues related to 10 CFR 54.21 and external operating events from the NRC, INPO, LIS, and NMC Fleet. Thestaff reviewed the applicant's response and found it acceptable.The staff recognized that the CAP, which captures internal and external operating experienceissues, will ensure that operating experience is reviewed and incorporated in the future.On the basis of its review of the above industry and plant-specific operating experience anddiscussions with the applicant's technical personnel, the staff concluded that the applicant's 3-17Inaccessible Medium Voltage (2kV to 34.5kV) Cables Not Subject to 10 CFR 50.49 EQRequirements Program will adequately manage the aging effects identified in the LRA for whichthis AMP is credited.USAR Supplement. In LRA Section A2.1.21, the applicant provided the USAR supplement forthe Inaccessible Medium Voltage (2kV to 34.5kV) Cables Not Subject to 10 CFR 50.49 EQ Requirements Program.Subsequently, by letter dated June 10, 2005, the applicant revised its USAR supplement toinclude the following commitment, documented as commitment 36 in Table A.5:Prior to the period of extended operation, the MNGP InaccessibleMedium-Voltage (2kV to 34.5kV) Cables Not Subject to 10 CFR 50.49 EQ Requirements Program will be implemented as a new program consistent withthe recommendations of NUREG-1801 Chapter XI, Program XI.E3.The staff reviewed this section and determined that the information in the USAR supplement asaugmented by the commitment adequately describes the program, as required by 10 CFR 54.21(d).Conclusion. On the basis of its review and audit of the applicant's Inaccessible Medium Voltage(2kV to 34.5kV) Cables Not Subject to 10 CFR 50.49 EQ Requirements Program, the staff determined that those program elements for which the applicant claimed consistency with theGALL Report are consistent with the GALL Report. The staff concluded that the applicantdemonstrated that the effects of aging will be adequately managed so that intended functionswill be maintained consistent with the CLB for the period of extended operation, as required by10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.1.4 One-Time Inspection Program Summary of Technical Information in the Application. In LRA Section B2.1.23, the applicantdescribed the One-Time Inspection Program, stating that this new program is consistent withGALL AMP XI.M32, "One-Time Inspection." The MNGP One-Time Inspection Program addresses concerns with and confirmation for the potential long incubation period for certain aging effects on SCs. In some cases, (1) an aging effect is not expected to occur but data are not sufficient to completely rule it out, or (2) an aging effect is expected to progress very slowly.

The activities of the One-Time Inspection Program include (1) determination of the sample size based on an assessment of materials of fabrication, environment, plausible aging effects, and operating experience, (2) identification of the inspection locations in the system or componentbased on the aging effect, (3) determination of the examination technique, including acceptancecriteria that will be effective in managing the aging effect for which the component is examined,and (4) evaluation of the need for followup examinations to monitor the progression of any identified aging degradation. The program will manage the aging effects caused by corrosion,cracking, erosion, fouling, fretting, or thermal exposure. The program will also verify the absence of reduction of neutron absorption capacity of boral in the spent fuel pool.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's 3-18evaluation of this AMP. The staff determined that this AMP is consistent with the AMPdescribed in the GALL Report, including the associated operating experience attribute.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.M32.The staff reviewed those portions of the MNGP AMP B2.1.23, "One-Time Inspection Program,"that the applicant claimed are consistent with GALL AMP XI.M32 and found them consistentwith the GALL Report AMP. Because it is consistent with the GALL Report, the AMP ensures that the effects of aging will be adequately managed. The staff found the applicant's AMPacceptable because it conforms to the recommended GALL Report AMP.Operating Experience. In LRA Section B2.1.23, the applicant explained that the One-TimeInspection Program is a new program with no operating experience.During the audit and review, the staff asked the applicant how it captures operating experience.The applicant indicated that the MNGP CAP identifies, tr acks, and trends site operatingexperience related to all site components. The applicant documents any site component identified as degraded, as failed, or as potentially unable to fulfill its intended functions in thesite CAP database. The plant engineering staff then evaluates these components for the extentof the condition and takes appropriate followup actions. The plant engineering staff also trends related CAPs to identify generic issues and addresses trended site issues in program health reports presented to site management on a scheduled basis. The CAP also addresses issues related to 10 CFR 54.21 and external operating events from the NRC, INPO, LIS, and NMCFleet. The staff reviewed the applicant's response and found it acceptable.The staff recognized that the CAP, which captures the internal and external operatingexperience issues, will ensure evaluation and incorporation of operating experience forobjective evidence of the adequate management of aging effects.USAR Supplement. In LRA Section A2.1.23, the applicant provided the USAR supplement forthe One-Time Inspection Program.Subsequently, by letter dated June 10, 2005, the applicant revised its USAR supplement toinclude the following commitment, documented as commitment 38 in Table A.5:Prior to the period of extended operation, the MNGP One-Time InspectionProgram will be implemented as a new program consistent with the recommendations of NUREG-1801 Chapter Xl Program XI.M32, "One-TimeInspection." This program will include measures to verify the effectiveness of thefollowing aging management programs: Plant Chemistry Program and Fuel Oil Chemistry Program. This program will also confirm the absence of age relateddegradation in selected components (e.g., flow restrictors, venturis) within License Renewal scope.The staff reviewed this section and determined that the information in the USAR supplement asaugmented by the commitment adequately describes the program, as required by 10 CFR 54.21(d).

3-19Conclusion. On the basis of its review and audit of the applicant's One-Time InspectionProgram, the staff determined that those program elements for which the applicant claimedconsistency with the GALL Report are consistent with the GALL Report. The staff concluded that the applicant demonstrated that the effects of aging will be adequately managed so thatintended functions will be maintained consistent with the CLB for the period of extendedoperation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.1.5 Open-Cycle Cooling Water System Program Summary of Technical Information in the Application. In LRA Section B2.1.24, the applicantdescribed the Open-Cycle Cooling Water (OCCW) System Program, stating that this existing program is consistent with GALL AMP XI.M20, "Open-Cycle Cooling Water System." The MNGP OCCW System Program relies on the implementation of the recommendations of NRC GL 89-13, "Service Water System Problems Affecting Safety-Related Equipment," dated July 18, 1989, to ensure that the effects of aging on the raw water service water systems will bemanaged for the period of extended operation. This program manages the aging effects of metallic components in water systems (e.g., piping and heat exchangers) exposed to raw,untreated (e.g., service) water. Corrosion, erosion, and biofouling in SSCs serviced by the OCCW system cause these aging effects. The program includes (1) surveillance and control ofbiofouling, (2) tests to verify heat transfer, and (3) routine inspection and maintenance. The MNGP OCCW System Program complies with the MNGP response to NRC GL 89-13. Theapplicant has incorporated the commitments it made to comply with GL 89-13 into plant procedures and programs.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's evaluation of this AMP. The staff determined that this AMP is consistent with the AMPdescribed in the GALL Report, including the associated operating experience attribute.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.M20.The staff reviewed those portions of the MNGP AMP B2.1.24, "Open-Cycle Cooling WaterSystem Program," that the applicant claimed are consistent with GALL AMP XI.M20, "Open-Cycle Cooling Water System," and found them consistent with the GALL Report AMP. Because it is consistent with the GALL Report, the AMP ensures that the effects of aging will beadequately managed. The staff found the applicant's AMP acceptable because it conforms to the recommended GALL Report AMP.Operating Experience. In LRA Section B2.1.24, the applicant explained that the OCCW SystemProgram has been effective in managing loss of material and heat transfer degradation aging effects for systems within the scope of the program. Various self-assessments and NuclearOversight Department reviews have demonstrated program effectiveness and have shown that MNGP has implemented the requirements of GL 89-13. The applicant has documented andevaluated corrosion and material condition issues in the site CAP.

3-20The staff reviewed the operating experience provided in the LRA and interviewed theapplicant's technical personnel to confirm that the plant-specific operating experience revealedno degradation not bounded by industry experience.On the basis of its review of the above industry and plant-specific operating experience, thestaff concluded that applicant's OCCW System Program will adequately manage the agingeffects identified in the LRA for which this AMP is credited.USAR Supplement. In LRA Section A2.1.24, the applicant provided the USAR supplement forthe OCCW System Program. The staff reviewed this section and determined that the information in the USAR supplement adequately describes the program, as required by 10 CFR 54.21(d).Conclusion. On the basis of its review and audit of the applicant's OCCW System Program, thestaff determined that those program elements for which the applicant claimed consistency withthe GALL Report are consistent with the GALL Report. The staff concluded that the applicantdemonstrated that the effects of aging will be adequately managed so that intended functionswill be maintained consistent with the CLB for the period of extended operation, as required by10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.1.6 Primary Containment In-Service Inspection Program Summary of Technical Information in the Application. In LRA Section B2.1.26, the applicantdescribed the Primary Containment In-Service Inspection Program, stating that this existing program is consistent with GALL AMP XI.S1, "ASME Section XI, Subsection IWE." The MNGP Primary Containment In-Service Inspection Program requires visual examinations of the accessible surfaces (base metal and welds) of the drywell, torus, vent lines, internal vent system, penetration assemblies, and associated integral attachments. The program alsorequires examination of pressure-retaining bolting and the drywell interior slab moisture barrier.

The program conforms to the applicable requirements of 10 CFR 50.55a, "Codes and Standards," and the 1992 Edition with 1992 Addenda of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code (ASME Code), Subsection IWE. The applicant performs a detailed visual examination (VT)-3 and VT-1 examination once during each 10-year inservice inspection (ISI) interval. This examination occurs either at the end of the interval or is spread across the three periods that comprise the interval. The applicant performs general visual examinations that assess the overall structural condition once during each period. Surface and/or volumetric examination augments visual examination as required to define the extent of observed conditions or to identify deterioration at inaccessible locations.

Limited scope examinations are performed as required to evaluate disassembled bolting and the condition of the normally submerged torus surface when the suppression pool is drained.

The applicant periodically updates the program as required by 10 CFR 50.55a.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's evaluation of this AMP. The staff determined that this AMP is consistent with the AMPdescribed in the GALL Report, including the associated operating experience attribute.

3-21The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.S1.The applicant stated in MNGP AMP B2.1.26, "Primary Containment In-Service InspectionProgram," that exceptions to ASME Code requirements granted by approved code cases or relief requests are not considered exceptions to the GALL Report criteria. In addition, the discussions of some program elements cite a number of relief requests. In all cases, the applicant reiterated that these are not considered exceptions since the NRC reviewed the MNGP IWE program and the program is in accordance with 10 CFR 50.55a with

NRC-approved relief requests.The staff noted that 10 CFR 54.21 requires the LRA to contain information for each SC withinthe scope of license renewal demonstrating that the applicant will adequately manage agingeffects so that intended functions will be maintained consistent with the CLB for the period ofextended operation. The staff questioned the applicant's position that exceptions to ASMECode requirements granted by code cases or relief requests are not considered exceptions to the GALL Report.In its letter dated August 31, 2005, the applicant stated the following:The statement under the 'NUREG-1801 Consistency' regarding 'Exceptions toASME Code requirements that have been granted by approved Code Cases or relief requests are not considered to be exceptions to NUREG-1801 criteria'should be removed. The statement is not required. ASME Section XI, Subsection IWE alternatives expire prior to the period of extended operation.The statement under the 'Scope of Program' regarding 'These are notconsidered exceptions since the MNGP program has been reviewed by the NRC and is in accordance with 10 CFR 50.55a with NRC approved relief requests'should be removed. The statement is not required. ASME Section XI, Subsection IWE alternatives expire prior to the period of extended operation.The statement under the 'Parameters Monitored or Inspected' regarding 'Theseare not considered exceptions since the MNGP program has been reviewed by the NRC and is in accordance with 10 CFR 50.55a with NRC approved reliefrequests' should be removed. The statement is not required. ASME Section XI, Subsection IWE alternatives expire prior to the period of extended operation.The statement under the 'Detection of Aging Effects' regarding 'This is notconsidered an exception since the MNGP program has been reviewed by the

NRC and is in accordance with 10 CFR 50.55a with NRC approved reliefrequests' should be removed. The statement is not required. ASME Section XI, Subsection IWE alternatives expire prior to the period of extended operation.The statement under the 'Monitor and Trending' regarding 'This is notconsidered an exception since the MNGP program has been reviewed by the

NRC and is in accordance with 10 CFR 50.55a with NRC approved relief 3-22requests' should be removed. The statement is not required. ASME Section XI,Subsection IWE alternatives expire prior to the period of extended operation.The statement under the 'Corrective Actions' regarding 'This is not consideredan exception since the MNGP program has been reviewed by the NRC and is inaccordance with 10 CFR 50.55a with NRC approved relief requests' should beremoved. The statement is not required. ASME Section XI, Subsection IWE alternatives expire prior to the period of extended operation.The statement under the 'Confirmation Process' regarding 'This is notconsidered an exception since the MNGP program has been reviewed by the

NRC and is in accordance with 10 CFR 50.55a with NRC approved reliefrequests' should be removed. The statement is not required. ASME Section XI, Subsection IWE alternatives expire prior to the period of extended operation.The staff found the applicant's position acceptable, because the applicant removed referencesstating that relief requests were not considered exceptions to the GALL Report and the reliefrequests will not be credited for aging management.The staff reviewed those portions of the MNGP AMP B2.1.26 that the applicant claimed areconsistent with GALL AMP XI.S1 and found them consistent with the GALL Report AMP.Because it is consistent with the GALL Report, the AMP ensures that the effects of aging will beadequately managed. The staff found the applicant's AMP acceptable because it conforms to the recommended GALL Report AMP.Operating Experience. In LRA Section B2.1.26, the applicant explained that the PrimaryContainment In-Service Inspection Program, when implemented in conjunction with the 10 CFR 50, Appendix J Program and special examinations conducted to address specific industry issues, has demonstrated that aging of the primary containment, the internal vent system, and steel components within the torus is managed in an effective manner. Specialexaminations have verified the absence of significant corrosion in the drywell sand pocket region and on the normally submerged surfaces of the torus. The applicant also stated that leakage testing has been effective in early detection of passive isolation barrier deterioration (active barriers are outside the scope of the AMP). Examinations under the ISI program have shown that there is no significant corrosion on, or other deterioration of, accessible containmentshell, vent system, and penetration assembly surfaces.On the basis of its review of the above operating experience and discussions with theapplicant's technical personnel, the staff concluded that the Primary Containment In-ServiceInspection Program will adequately manage the aging effects identified in the LRA for which theAMP is credited.USAR Supplement. In LRA Section A2.1.26, the applicant provided the USAR supplement forthe Primary Containment In-Service Inspection Program. The staff reviewed this section and determined that the information in the USAR supplement adequately describes the program, asrequired by 10 CFR 54.21(d).Conclusion. On the basis of its review and audit of the applicant's Primary ContainmentIn-Service Inspection Program, the staff determined that those program elements for which the 3-23applicant claimed consistency with the GALL Report are consistent with the GALL Report. Thestaff concluded that the applicant demonstrated that the effects of aging will be adequatelymanaged so that intended functions will be maintained consistent with the CLB for the period ofextended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.1.7 Reactor Head Closure Studs ProgramSummary of Technical Information in the Application. In LRA Section B2.1.28, the applicantdescribed the Reactor Head Closure Studs Program, stating that this existing program is consistent with GALL AMP XI.M3, "Reactor Head Closure Studs." The MNGP Reactor Head Closure Studs Program is part of the MNGP ASME Section XI In-Service Inspection Program.

The Reactor Head Closure Studs Program is in accordance with the ASME Code,Section XI, 1995 Edition through the 1996 Addenda, and provides for condition monitoring of the reactor head closure stud bolting. Replacement reactor head studs available for use at MNGP include preventive measures described in Regulatory Guide (RG) 1.65, "Material and Inspection for Reactor Vessel Closure Studs," issued October 1973. The applicant updates the program periodically as required by 10 CFR 50.55a.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's evaluation of this AMP. The staff determined that this AMP is consistent with the AMPdescribed in the GALL Report, including the associated operating experience attribute.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.M3.During the audit and review, the staff noted that the applicant stated the following in LRASection B2.1.28:Exceptions to ASME requirements that have been granted by approved CodeCases or relief requests are not considered to be exceptions to NUREG-1801criteria.The staff asked that the applicant clarify this statement. The applicant responded that it usedCode Case -307-2, "Revised Ultrasonic Examination Volume for Class 1 Bolting, Table IWB-2500-1, Examination Category B-G-1, When the Examinations Are Conducted Fromthe End of the Bolt or Stud or From the Center-Drilled Hole," dated September 24, 1999, thatapplied to the reactor head closure studs. The applicant also used the ASME Code,Section XI, 2001 Edition, in lieu of the 1995 edition with addenda through 1996, for repair and replacement activities; the staff discusses this second exception below. Code users employ code cases when they cannot or do not want to perform a particular code requirement. This is an allowed exception to the application of the code by the user and thus is an exception to GALL Reportrecommendations. The staff determined that the code case used affected the GALL Reportrecommendation and that its use constituted an exception. In its letter dated August 11, 2005, 3-24supplemented by its letter dated August 31, 2005, the applicant stated that it will change itsapplication to identify the use of the code case as an exception to this AMP. The following provides the staff evaluation of these exceptions.Exception 1: The GALL Report identifies the following recommendation for the ParametersMonitored or Inspected program element associated with the exception:The ASME Section XI ISI program detects and sizes cracks, detects loss ofmaterial, and detects coolant leakage by following the examination and inspection requirements specified in Table IWB-2500-1.In its letter dated August 11, 2005, the applicant stated that when conducting ultrasonic testing(UT) examinations from the end of the stud to satisfy ASME Code,Section XI, examination requirements, the examination volume may be limited to a cylinder of 1/4-inch thickness measured from the minor diameter and the length of the threaded portion of the stud.The staff confirmed that Table 1 of RG 1.147, Revision 13, "In-Service Inspection Code CaseAcceptability, ASME Section XI, Division 1," issued January 2004, lists Code Case -307-2.Based on this listing, the NRC staff has reviewed this code case and accepted it for generalindustry use.The staff then reviewed both the applicable ASME Code,Section XI ISI requirements for thereactor head closure studs and the alternative requirements of Code Case -307-2. ASME Code,Section XI, requires a visual examination of the surfaces of the reactor head closure nuts, washers, and bushings; a volumetric examination of the vessel flange threads and reactor head closure stud when examined in place; and a surface and volumetric examination of the reactor head closure stud when removed. In lieu of the volumetric examination required by ASME Code,Section XI, of essentially the entire volume of the reactor head closure stud, Code Case -307-2 allows examination of a cylindrical region of 1/4-inch thickness measured from the minor diameter of the reactor head closure stud and the length of the threaded portion of the stud. The staff noted that the use of this code case reduces the required examination volume tothe higher stress area of the bolting. The roots of the threads are stress risers and, hence, likelysites for crack initiation. Cracks at the roots of threads will be perpendicular to straight beam UTexamination from the end of the stud and will create a corner trap for angle beam UTexamination from the center hole. The staff reviewed the difference between the tworequirements and noted that the use of the code case alters the portion of the stud examinedbut continues to identify relevant aging effects (i.e., cracking and general corrosion) as the high-stress portion of the stud continues to be examined. Thus, the staff determined that theapplicant's use of the code case has no impact on the aging effect being managed.On the basis of a review of the above exception and of operating experience for AMP B2.1.28,"Reactor Head Closure Studs Program," the staff found this exception acceptable.Exception 2: The GALL Report identified the following recommendation for the CorrectiveActions program element associated with the exception:Repair and replacement are in conformance with the requirements of IWB-4000and IWB-7000, respectively, and the material and inspection guidance of RG

1.65.

3-25In its letter dated August 11, 2005, the applicant stated that the staff has already genericallyreviewed and approved the use of the ASME Code,Section XI, 2001 edition, as an alternative to the 1995 edition with 1996 addenda, for repair and replacement for aging management of systems and components within the scope of license renewal. Therefore, this alternative will notaffect the aging management of components crediting ISI performed in accordance with ASME Code,Section XI. The applicant provided the following justification, published in Volume 69 of

the Federal Register, pages 58804 and 58816 on October 1, 2004, accompanying the NRC'samendments to its regulations that incorporated, by reference, certain updated editions andaddenda of the ASME Code for use by NRC licensees:Accordingly, an applicant may use Subsections IWB, IWC, IWD, IWE, IWF, andIWL of Section XI of the ASME BPV Code (2001 Edition and the 2002 and 2003 Addenda) as acceptable alternatives to the requirements of the 1995 Edition up to and including the 1996 Addenda of the ASME Code,Section XI referenced in the GALL AMPs without the need to submit these alternatives for NRC review inits plant-specific license renewal application.Because the NRC staff has already reviewed and approved this alternative, related to repairand replacement, generically for aging management of systems and components within thescope of license renewal, the staff concluded that it does not need to be classified as an exception and that the affected program element is consistent with the GALL Report.Exception 3: The GALL Report identified the following recommendations for the Scope ofProgram element associated with the exception:The program includes preventive measures of NRC Regulatory Guide 1.65 tomitigate cracking. The program is applicable to closure studs and nuts constructed from materials with a maximum tensile strength limited to less than 1172 MPa (170 ksi) (Nuclear Regulatory Commission [NRC] Regulatory Guide[RG] 1.65).The inspectors noted that RG 1.65 recommends that reactor head closure stud materialmeasured ultimate tensile strength not exceed 170 kilo-pounds per square inch (ksi) to minimize the likelihood of stress-corrosion cracking (SCC). Hardness tests conducted on the installed reactor head studs showed that most studs have greater than 170 ksi tensile stress.

The applicant committed to document this exception to NUREG-1801 in the LRA. In its letterdated March 15, 2006, the applicant stated the following:The Reactor Head Closure Studs Program does not incorporate the ultimatetensile strength requirement of NRC Regulatory Guide 1.65 for the existingreactor head closure studs. NMC considers this an acceptable exception to NUREG-1801, since these studs are considered susceptible to cracking atMNGP and NMC continues to manage them through the preventative measures recommended by Regulatory Guide 1.65 regardless of the tensile strength.The inspectors found this exception to the GALL Report acceptable because the applicantconsiders these studs to be susceptible to cracking, continues to manage the studs using the other preventive measures of RG 1.65, continues to conduct UT and surface examinations on a 10- year interval, and, to date, has identified no apparent discontinuities.

3-26The staff reviewed those portions of AMP B2.1.28 that the applicant claimed are consistent withGALL AMP XI.M3 and found them consistent. The staff found the applicant's AMP acceptable because it conforms to the recommended GALL Report AMP with the exceptions described.Operating Experience. In LRA Section B2.1.28, the applicant explained that the Reactor HeadClosure Studs Program has been effective in managing the aging effects of reactor pressure vessel (RPV) closure studs. The applicant has considered plant operating experience in the evaluation of stud performance. The MNGP inspection and testing methodologies have detected no cracking, nondestructive examination (NDE) indications, or aging effects for the RPV studs. Intergranular SCC (IGSCC) was seen in two RPV head studs at another plant. In response to this incident, MNGP performed field hardness testing and UT examination of the reactor head studs removed from the reactor cavity during the 1991 outage, evaluated the testresults, and evaluated the original certified material test reports. It found no evidence of RPV head stud cracking.The staff reviewed the operating experience provided in the LRA and interviewed theapplicant's technical personnel to confirm that plant-specific operating experience revealed no degradation not bounded by industry experience.On the basis of its review of the above industry and plant-specific operating experience anddiscussions with the applicant's technical personnel, the staff concluded that the applicant'sReactor Head Closure Stud Program will adequately manage the aging effects identified in theLRA for which this AMP is credited.USAR Supplement. In LRA Section A2.1.28, the applicant provided the USAR supplement forthe Reactor Head Closure Studs Program. The staff reviewed this section and determined that the information in the USAR supplement adequately describes the program, as required by 10 CFR 54.21(d).Conclusion. On the basis of its review and audit of the applicant's Reactor Head Closure StudsProgram, the staff determined that those program elements for which the applicant claimedconsistency with the GALL Report are consistent with the GALL Report. The staff concluded that the applicant demonstrated that the effects of aging will be adequately managed so thatintended functions will be maintained consistent with the CLB for the period of extendedoperation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.1.8Thermal Aging & Neutron Irradiation Embrittlement of Cast Austenitic StainlessSteel (CASS) ProgramSummary of Technical Information in the Application. In LRA Section B2.1.33, the applicantdescribed the Thermal Aging & Neutron Irradiation Embrittlement of CASS Program, stating that this existing program is consistent with GALL AMP XI.M13, "Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel (CASS)." The MNGP Thermal Aging and Neutron Irradiation Embrittlement of CASS Program monitors the aging effects of loss of fracture toughness on the intended function of the component by performing examinations onCASS reactor vessel internal components as part of the MNGP ASME Section XI In-Service Inspection Program. The Thermal Aging and Neutron Irradiation Embrittlement of CASS 3-27Program is in accordance with ASME Code,Section XI, Subsection IWB, Category B--1 andB--2 requirements, and provides for condition monitoring of the CASS components. The applicant performs additional enhanced visual inspections that incorporate the requirements of the Boiling Water Reactor Vessel and Internals Project (BWRVIP) to detect the effects of loss of fracture toughness due to thermal aging and neutron irradiation embrittlement of CASS reactor vessel internals. The applicant updates the program periodically as required by 10 CFR 50.55a.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's evaluation of this AMP. The staff determined that this AMP is consistent with the AMPdescribed in the GALL Report, including the associated operating experience attribute.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.M13.During the audit and review, the staff questioned the applicant regarding the screening criteriafor determining the susceptibility of CASS components to thermal aging. The applicant statedthat it does not address this screening process; instead, the program includes all CASS reactor vessel internal components. These components consist of jet pump assembly castings, the orifice fuel support casting, and the guide tube base casting. The staff found this approach conservative and therefore acceptable.During the audit and review, the staff asked the applicant whether its current approved ISI reliefrequests or code cases affect any of its AMP program elements. In its letter dated August 31, 2005, the applicant identified the following exception to the GALL Report program element.Exception: The GALL Report identifies the following recommendations for the CorrectiveActions program element associated with the exception taken:Repair is in conformance with IWA-4000 and IWB-4000, and replacement is inaccordance with IWA-7000 and IWB-7000.In its letter dated August 11, 2005, the applicant stated that an approved alternative allows theuse of the ASME Code,Section XI, 2001 edition in lieu of the 1995 edition with the 1996 addenda for repair/replacement activities. Section 3.0.3.1.7 of the SER provides the staff'sevaluation of this exception.Because the NRC has already reviewed and approved this alternative, relating to repair andreplacement, generically for aging management of systems and components within the scopeof license renewal, the staff concluded that it does not need to be classified as an exception and that, with regard to this item, the affected program element is consistent with the GALL Report.The staff reviewed those portions of AMP B2.1.33, "Thermal Aging & Neutron IrradiationEmbrittlement of Cast Austenitic Stainless Steel (CASS) Program," that the applicant claimed are consistent with GALL AMP XI.M13 and found them consistent. The staff found the 3-28applicant's AMP acceptable because it conforms to the recommended GALL Report AMP withthe exception described.Operating Experience. In LRA Section B2.1.33, the applicant explained that the Thermal Aging& Neutron Irradiation Embrittlement of CASS Program has been effective in managing aging effects due to thermal aging and neutron irradiation embrittlement. The applicant periodically examines materials within the scope of the program and evaluates them for corrective action as needed. In addition to ASME inspection requirements, the applicant follows vendor guidance (e.g., BWRVIP-03, "BWR Vessel and Internals Project, Reactor Pressure Vessel and Internals Examination Guidelines," and BWRVIP-41, "BWR Jet Pump Assembly Inspection and Flaw Evaluation Guidelines").In addition, the staff reviewed the operating experience provided in the LRA and interviewed theapplicant's technical personnel to confirm that plant-specific operating experience revealed no degradation not bounded by industry experience.On the basis of its review of the above operating experience and discussions with theapplicant's technical personnel, the staff concluded that the applicant's Thermal Aging &Neutron Irradiation Embrittlement of CASS Program will adequately manage the aging effectsidentified in the LRA for which this AMP is credited.USAR Supplement. In LRA Section A2.1.33, the applicant provided the USAR supplement forthe Thermal Aging & Neutron Irradiation Embrittlement of CASS Program. The staff reviewed this section and determined that the information in the USAR supplement adequately describesthe program, as required by 10 CFR 54.21(d).Conclusion. On the basis of its review and audit of the applicant's Thermal Aging & NeutronIrradiation Embrittlement of CASS Program, the staff determined that those program elementsfor which the applicant claimed consistency with the GALL Report are consistent with the GALLReport. The staff concluded that the applicant demonstrated that the effects of aging will beadequately managed so that intended functions will be maintained consistent with the CLB forthe period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.1.9Electrical Equipment Subject to 10 CFR 50.49 EQ Requirements ProgramSummary of Technical Information in the Application. In LRA Section B3.1, the applicantdescribed the Electrical Equipment Subject to 10 CFR 50.49 EQ Requirements Program, stating that this existing program that is consistent with GALL AMP X.E1, "EnvironmentalQualification (EQ) of Electric Components." The purpose of the MNGP EQ program is to ensure that SR electrical equipment is capable of performing its function in a harsh environment (effects of a loss-of-coolant accident (LOCA), high-energy line break (HELB), or post-LOCA radiation) and is qualified in accordance with the Equipment Qualification Final Rule, 10 CFR 50.49, dated February 22, 1983. This program describes EQ program attributes, andhow those attributes ensure that the EQ program remains effective throughout the licenserenewal period (60 years).

3-29Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's evaluation of this AMP. The staff determined that this AMP is consistent with the AMPdescribed in the GALL Report, including the associated operating experience attribute.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's MNGP audit and review report, which assesses the consistency of the AMP elements with GALL AMP X.E1.The staff reviewed those portions of AMP B3.1, "Electrical Equipment Subject to 10 CFR 50.49EQ Requirements Program," that the applicant claimed are consistent with GALL AMP X.E1and found them consistent. Because it is consistent with the GALL Report, the AMP ensures that the effects of aging will be adequately managed. The staff found the applicant's AMPacceptable because it conforms to the recommended GALL Report AMP.Operating Experience. In LRA Section B3.1, the applicant explained that the MNGP EQprogram includes monitoring and assessment of industry information in order to assess its impact on EQ components at MNGP. The EQ Coordinator is responsible for reviewing the disposition of such information, as well as subsequent assignment of actions to be taken, and confirming that completion of the actions has satisfactorily addressed potential MNGP EQ aging issues. The following examples provide objective evidence that the MNGP EQ program is responsive to externally identified operating experience items as well as proactive in self-identification activities:

  • An NRC safety system design inspection, conducted in March 2003, resulted in twogreen findings and four corrective actions.
  • A nuclear oversight quality assurance (QA) assessment in June 2003 resulted in nofindings.
  • The 2001 internal self-assessment resulted in a determination of effectiveimplementation, but noted specific areas needing improvement and additionalrecommendations for continued improvement.
  • The applicant periodically performs program health reviews to measure the acceptabilityof the program and identify improvements as applicable in accordance with MNGP and NMC Fleet procedures.
  • The applicant conducts operating experience reviews of EQ issues identified at othersites and processes these items through the CAP.On the basis of its review of the above operating experience and discussions with theapplicant's technical personnel, the staff concluded that the Electrical Equipment Subject to10 CFR 50.49 EQ Requirements Program will adequately manage the aging effects observedat the applicant's plant.USAR Supplement. In LRA Section A4.1, the applicant provided the USAR supplement for theElectrical Equipment Subject to 10 CFR 50.49 EQ Requirements Program. The staff reviewed this section and determined that the information in the USAR supplement adequately describesthe program, as required by 10 CFR 54.21(d).

3-30Conclusion. On the basis of its review and audit of the applicant's Electrical Equipment Subjectto 10 CFR 50.49 EQ Requirements Program, the staff determined that those program elementsfor which the applicant claimed consistency with the GALL Report are consistent with the GALLReport. The staff concluded that the applicant demonstrated that the effects of aging will beadequately managed so that intended functions will be maintained consistent with the CLB forthe period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.2 AMPs That Are Consistent with the GALL Report with Exceptions or EnhancementsIn LRA Appendix B, the applicant identified the following AMPs that are, or will be, consistentwith the GALL Report, with exceptions or enhancements:

  • ASME Section XI In-Service Inspection, Subsections IWB, IWC, and IWDProgram (B2.1.2)
  • Bolting Integrity Program (B2.1.4)
  • Buried Piping & Tanks Inspection Program (B2.1.5)
  • BWR FW Nozzle Program (B2.1.8)
  • BWR Vessel Inside Diameter (ID) Attachment Welds Program (B2.1.11)
  • BWR Vessel Internals Program (B2.1.12)
  • Closed-Cycle Cooling Water (CCCW) System Program (B2.1.13)
  • Compressed Air Monitoring Program (B2.1.14)
  • Electrical Cables Not Subject to 10 CFR 50.49 EQ Requirements Used inInstrumentation Circuits Program (B2.1.16)
  • Fire Water System Program (B2.1.18)
  • Fuel Oil Chemistry Program (B2.1.20)
  • Inspection of Overhead Heavy Load and Light Load (Related to Refueling) HandlingSystems Program (B2.1.22)
  • Plant Chemistry Program (B2.1.25)
  • Protective Coating Monitoring & Maintenance Program (B2.1.27)
  • Reactor Vessel Surveillance Program (B2.1.29) 3-31
  • Selective Leaching of Materials Program (B2.1.30)
  • Structures Monitoring Program (B2.1.31)
  • Metal Fatigue of the Reactor Coolant Pressure Boundary Program (B3.2)For AMPs that the applicant claimed are consistent with the GALL Report, with exceptions orenhancements, the staff performed an audit to confirm that those attributes or features of theprogram for which the applicant claimed consistency with the GALL Report are indeed consistent. The staff also reviewed the exceptions and enhancements to the GALL Report to determine whether they are acceptable and adequate. The following sections document theresults of the staff's audit and reviews.3.0.3.2.1 10 CFR 50, Appendix J Program Summary of Technical Information in the Application. In LRA Section B2.1.1, the applicantdescribed the 10 CFR 50, Appendix J Program, stating that this existing program is consistent,with exceptions, with GALL AMP XI.S4, "10 CFR Part 50, Appendix J." The MNGP 10 CFR 50, Appendix J Program specifies pneumatic pressure tests and visual examinations to verify the structural and leak-tight integrity of the primary containment. An overall (Type A) pressure test assesses the capacity of the containment to retain design-basis accident (DBA) pressure. This test also measures total leakage through the containment pressure-retaining boundary. Local (Type B & C) tests measure leakage through individual penetration isolation barriers. These barriers are maintained as required to keep overall and local leakage under technical specification (TS) and plant administrative limits. The applicant performs tests at intervals determined by the risk and performance factors applicable to each tested item in accordance with governing regulations and standards. Visual examinations are performed before each Type A test. The applicant also performs these examinations at least once during each containment ISI period in which no Type A test is conducted. The examinations are performed to detect corrosion and other types of deterioration on the accessible surfaces of the containment.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's audit evaluation of this AMP. The staff reviewed the exceptions and the associated justifications todetermine whether the AMP, with the exceptions, remains adequate to manage the agingeffects for which it is credited.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.S4.In the LRA, the applicant stated the following exceptions to the program elements listed forAMP XI.S4 in the GALL Report.Exception 1: The GALL Report identifies the following recommendation for the Scope ofProgram element associated with the exception taken:The scope of the containment LRT program includes all pressure-retainingcomponents. Two types of tests are implemented. Type A tests are performed to measure the overall primary containment integrated leakage rate which is 3-32obtained by summing leakage through all potential leakage paths includingcontainment welds, valves, fittings, and components that penetrate containment.Type B tests are performed to measure local leakage rates across each pressure-containing or leakage-limiting boundary for containment penetrations.

Type A and B tests described in 10 CFR Part 50, Appendix J, are acceptable methods for performing these LRTs. Leakage testing for containment isolation valves (normally performed under Type C tests), if not included under this program, is included under LRT programs for systems containing the isolationvalves.In the LRA, the applicant stated that main steam isolation valves (MSIVs) are tested at25 pounds per square inch gauge (psig) instead of at an accident pressure of 42 psig. The applicant indicated that Section III.C.2 of Appendix J, "Primary Reactor Containment LeakageTesting for Water-Cooled Power Reactors," to 10 CFR Part 50, "Domestic Licensing of Production and Utilization Facilities," requires, in part, that Type C testing be performed at thepeak calculated accident pressure, which for MNGP is 42 psig. The outboard MSIVs are tested by pressurizing the volume between the inboard and outboard valves. The inboard MSIVs at MNGP are angled (Y-pattern globe) in the main steamlines for better closure characteristics. A test pressure at the peak calculated accident pressure (42 psig) acting under the inboard valve disc could lift the disc off its seat and cause excessive leakage into the vessel. The NRC hasapproved Type C testing of these valves at a reduced pressure of 25 psig as part of a request for relief (letter from Darrell G. Eisenhut, NRC, to D.M. Musolf, NMC, dated June 3, 1984). Thestaff determined that the inboard valves are the same design as the valves evaluated by the NRC and that a test pressure alternative in the leakage test will have no impact on agingmanagement. Therefore, the staff concluded that this exception is acceptable.Exception 2: The GALL Report identifies the following recommendation for the Monitoring andTrending program element associated with the exception taken:Because the LRT program is repeated throughout the operating license period,the entire pressure boundary is monitored over time. The frequency of these tests depends on which option (A or B) is selected. With Option A, testing is performed on a regular fixed time interval as defined in 10 CFR Part 50, Appendix J. In the case of Option B, the interval for testing may be increased on the basis of acceptable performance in meeting leakage limits in prior tests.

Additional details for implementing Option B are provided in NRC RegulatoryGuide 1.163 and NEI 94-01, Rev. 0.In the LRA, the applicant stated that the Type A test interval is extended, on a one-time basis,to 15 years, exceeding the 10-year interval limit in NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50, Appendix J," issued March 1996.

The applicant stated that MNGP is currently under Option B, "Performance-Based Requirement," of Appendix J to perform the Type A containment integrated leakage rate test. In accordance with Option B provisions and acceptable Type A test performance history, the Type A testing will occur at a frequency of 10 years. The most recent Type A test was in March 1993;thus, the applicant will have to perform the subsequent test no later than March 2003. Followinggeneral industry practice, the applicant submitted a request for a one-time test interval extension to 15 years based on a plant-specific, risk-based evaluation. The staff approved this request in a letter from L.M. Padovan, NRC, to D.L. Wilson, NMC, dated March 31, 2003; 3-33therefore, MNGP will have to perform one Type A test no later than March 2008, before theperiod of extended operation. The frequency of future Type A tests will be determi ned on thebasis of the next Type A test results and the limit set forth in Appendix J, Option B.The staff found that, in addition to the integrated leakage test, Type A test requirements includevisual examination of the containment exterior and interior to detect conditions that mightadversely affect structural integrity or leak tightness. The applicant performs an examination before each Type A test and between tests at nominal intervals of 40 months. Because MNGP followed its CLB in having a Type A test interval extended once to 15 years ending before the period of extended operation and the additional visual examination requirements are in place, the staff found this exception acceptable.The staff reviewed those portions of the AMP B2.1.1, "10 CFR 50, Appendix J Program," thatthe applicant claimed are consistent with GALL AMP XI.S4 and found them consistent. Thestaff found the applicant's AMP acceptable because it conforms to the recommended GALL Report AMP with the exceptions as described above.Operating Experience. In LRA Section B2.1.1, the applicant explained that the 10 CFR 50,Appendix J Program tests conducted under the program have been effective principally in detecting developing leakage through containment isolation valves, which, as active components, are outside the scope of the AMP. Testing has also detected developing leakagein both an electrical penetration conductor seal and a hot piping penetration expansion bellows.

The applicant corrected both of these conditions while the leakage was still small. MNGP iscommitted to the risk- and performance-based program defined by Option B of Appendix J".

This approach uses plant- and industrywide operating experience as the bases for defining the performance and risk factors, which, in turn, are used to determine testing intervals. Using this approach enhances the effectiveness of the program as an aging management tool by concentrating testing and maintenance resources on components that have higher risk and/or ahistory of high leakage.The staff reviewed the operating experience provided in the LRA and interviewed theapplicant's technical personnel to confirm that plant-specific operating experience revealed no degradation not bounded by industry experience.On the basis of its review of the above operating experience and discussions with theapplicant's technical personnel, the staff concluded that the applicant's 10 CFR 50, Appendix JProgram will adequately manage the aging effects identified in the LRA for which this AMP iscredited.USAR Supplement. In LRA Section A2.1.1, the applicant provided the USAR supplement forthe 10 CFR 50, Appendix J Program. The staff reviewed this section and determined that the information in the USAR supplement adequately describes the program, as required by 10 CFR 54.21(d).Conclusion. On the basis of its review and audit of the applicant's 10 CFR 50, Appendix JProgram, the staff determined that those program elements for which the applicant claimedconsistency with the GALL Report are consistent with the GALL Report. In addition, the staffreviewed the exceptions and the associated justifications and determined that the AMP, with theexceptions, is adequate to manage the aging effects for which it is credited. The staff 3-34concluded that the applicant demonstrated that the effects of aging will be adequately managedso that intended functions will be maintained consistent with the CLB for the period of extendedoperation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.2.2 ASME Section XI In-Service Inspection, Subsections IWB, IWC, and IWD Program Summary of Technical Information in the Application. In LRA Section B2.1.2, the applicantdescribed the ASME Section XI In-Service Inspection, Subsections IWB, IWC, and IWD Program, stating that this existing program is consistent, with exception, with GALL AMP XI.M1, "ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWD." The MNGP ASME Section XI In-Service Inspection, Subsections IWB, IWC, and IWD Program is part of the MNGP ASME Section XI In-Service Inspection Program. This program is in accordance with the ASME Code,Section XI, 1995 edition through the 1996 addenda and is subject to the limitations and modifications of 10 CFR 50.55a. The program provides for condition monitoring of Class 1, 2, and 3 pressure-retaining components and their integral attachments. The applicant inspects Class 1 and 2 piping in accordance with the risk informed ISI (RI-ISI) program as described in the EPRI Topical Report (TR)-112657, Revision B-A, "Revised Risk Informed In-Service Inspection Evaluation Procedure." The NRC has approved the use of RI-ISIin a safety evaluation (SE) documented in an NRC letter dated July 24, 2002, "MonticelloNuclear Generating Plant-Risk Informed In-Service Inspection Program (TAC No. MB3819)."

The applicant updates the program periodically as required by 10 CFR 50.55a. The Plant Chemistry Program augments this program where applicable.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's audit evaluation of this AMP. The staff reviewed the exceptions and the associated justifications todetermine whether the AMP, with the exceptions, remains adequate to manage the agingeffects for which it is credited.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.M1.In the LRA, the applicant stated the following exceptions to the program elements listed forAMP XI.M1 in the GALL Report.Exceptions 1 and 2: The GALL Report recommends the following for the Scope of Programelement associated with the exception taken:The ASME Section XI program provides the requirements for ISI, repair, andreplacement. The components within the scope of the program are specified in Subsections IWB-1100, IWC-1100, and IWD-1100 for Class 1, 2, and 3 components, respectively, and include all pressure-retaining components and their integral attachments in light-water cooled power plants. The componentsdescribed in Subsection IWB-1220, IWC-1220 and IWD-1220 are exempt from the examination requirements of Subsections IWB-2500, IWC-2500, and IWD-2500.

3-35In the LRA, the applicant stated that, pursuant to 10 CFR 50.55a(b)(2)(xi), it uses therequirements of IWB-1220 in the 1989 edition of the ASME Code,Section XI, for Class 1 piping instead of the 1995 edition of the ASME Code,Section XI, with the 1996 addenda and that, pursuant to 10 CFR 50.55a(b)(2)(xxi)(B), reused CRD bolting must meet examinationrequirements for Table IWB-2500-1, Category B-G-2, Item B7.80, of the 1995 edition of theASME Code,Section XI.The staff determined that both of the items that the applicant identified as exceptions are, infact, requirements codified in 10 CFR 50.55a and that the Scope of Program program element in the GALL Report mentions no specific ASME Code,Section XI, edition or addenda. The staff asked the applicant why it considered these items exceptions to the GALL Report. The applicant stated that it "conservatively" identified these items as exceptions solely because theyare requirements not contained in the ASME Code,Section XI, 1995 edition through 1996 addenda identified in the GALL Report program description for this AMP. The applicant stated that these codified requirements result in inspections that otherwise will not be required by the1995 edition through 1996 addenda of the ASME Code,Section XI. Because the items identified by the applicant are requirements codified in 10 CFR 50.55a and necessitate more stringent examinations than the ASME Code,Section XI, 1995 edition through 1996 addenda would otherwise call for, the staff found these exceptions acceptable.During the audit and review, the staff asked the applicant whether its approved ISI reliefrequests or code cases affect any of the AMP elements. The applicant stated that code cases and relief requests for the MNGP ASME Section XI In-Service Inspection, Subsections IWB, IWC, IWD, and IWF Program are valid for approximately 21 months into the period of extended operation and that the current inspection interval ends on May 31, 2012. In addition, theapplicant provided results of its reevaluation of code cases and relief requests as documented in its letter dated August 31, 2005. That reevaluation identified six additional exceptions(Exceptions 3 through 8) to the GALL Report program elements. The following paragraphs describe and evaluate these additional exceptions to the GALL Report.Exception 3: The GALL Report identifies the following recommendation for the Detection ofAging Effects program element associated with the exception taken:Category B-G-1 specifies volumetric examination of studs in place, from the top of thenut to the bottom of the flange hole; surface and volumetric examination of studs when removed; volumetric examination of flange threads; and visual VT-1 examination of the surfaces of nuts, washers, and bushings.In its letter dated August 11, 2005, the applicant stated that its ASME Section XI In-ServiceInspection, Subsections IWB, IWC, and IWD Program includes implementation of Code Case N-307-2, which revises the UT examination volume for Class 1 bolting.Table 1 of RG 1.147 lists Code Case N-307-2. The applicant categorized implementation ofthis code case as an exception to the GALL Report because the description of the Detection of Aging Effects program element in GALL Report AMP XI.M1 references ASME Code,Section XI, Table IWB-2500-1, Examination Category B-G-1. The applicant stated that the onlyClass 1 bolts at MNGP with center holes are the reactor head closure studs and the reactor recirculation (REC) pump bolts. The applicant also stated that provisions of this code case were added to Table IWB-2500-1, Figure IWB-2500-12, and Appendix VIII, Supplement 8, 1.1(c), to 3-36the 2000 addenda of the ASME Code,Section XI. The applicant stated that this code casechanges the portion of the bolt evaluated but will still detect the presence of the relevant agingeffect. Because this code case only changes the portion of the component examined and continues to examine all applicable components in a way that will detect relevant aging effects,the staff concluded that this exception to the GALL Report is acceptable.Exception 4: The GALL Report identifies the following recommendation for the Monitoring andTrending program element associated with the exception taken:For Class 1, 2, or 3 components, the inspection schedule of IWB-2400,IWC-2400, or IWD-2400, respectively, and the extent and frequency of IWB-2500-1, IWC-2500-1, or IWD-2500-1, respectively, provides for timely detection of degradation.In its letter dated August 11, 2005, the applicant stated that its ASME Section XI In-ServiceInspection, Subsections IWB, IWC, and IWD Program includes implementation of Code Case N-526, Revision 13, "In-Service Inspection Code Case Acceptability, ASME Section XI,Division 1," issued January 2004, which provides alternative requirements for successive inspections mandated by IWB-2420 and IWC-2420 when areas of the vessel are found, by volumetric examinations, to contain subsurface flaws.Table 1 of RG 1.147 lists Code Case N-526. The applicant categorized implementation of thiscode case as an exception to the GALL Report because the successive inspections required by IWB-2420 and IWC-2420 may be waived when a flaw is found acceptable for continued service in accordance with IWB-3600. In its letter dated August 11, 2005, the applicant stated thatvessel aging effects are still managed and that any flaws for which successive inspections arewaived are required to be acceptable for continued service in accordance with IWB-3600. The applicant also stated that the ASME Code,Section XI, requires that the sequence ofcomponent examinations established during the first inspection interval be repeated during each successive inspection interval to the extent practical. Because any flaws are determined to be acceptable in accordance with IWB-3600 and component examinations are required to be repeated during successive inspection intervals (so that any flaw area will be reexami ned atleast once in each inspection interval), the staff concluded that this exception to the GALL Report is acceptable.Exception 5: The GALL Report identifies the following recommendation for the Detection ofAging Effects program element associated with the exception taken:Class 1 Components, Table IWB-2500-1Examination Category B-D, for full penetration welds of nozzles in reactorvessels, pressurizers, steam generators (primary side), and heat exchangers (primary side): This category specifies volumetric examination of all nozzle-to-vessel welds and the nozzle inside radius.In its letter dated August 11, 2005, the applicant stated that its ASME Section XI In-ServiceInspection, Subsections IWB, IWC, and IWD Program will deviate from the requirements of 3-37ASME Code,Section XI, Table IWB-2500-1 and Figure IWB-2500-7(b) with regard to theexamination volume for Category B-D components (full penetration welded nozzles in vessels).The applicant identified that, based on its implementation of ASME Code,Section XI, CodeCase N-613-1, "Ultrasonic Examination of Penetration Nozzles in Vessels, Examination Category B-D, Item Nos. B3.10 and B3.90, Reactor Nozzle to Vessel Welds, Figs. IWB-2500-7(a), (b), and (c),Section XI, Division 1," issued June 2001, examination of Category B-D components will deviate from the requirements of the 1995 edition through 1996 addenda ofASME Code,Section XI, Table IWB-2500-1, Item No B3.90 and from the requirements of ASME Code,Section XI, Figure IWB-2500-7(b). Specifically, Figure IWB-2500-7(b) requires that a minimum volume of material equal to a distance of one-half the reactor vessel shell thickness (i.e., a distance of approximately 2-1/2 inches for MNGP) be included in the examination volume on each side of the weld; however, the applicant's ASME Section XI In-Service Inspection, Subsections IWB, IWC, and IWD Program at MNGP, instead, includes a reduced examination volume of one-half inch of base metal on each side of the widest portion of the weld. The applicant provided the following technical justification for the reduction in examination volume:The required examination volume for the reactor vessel pressure retainingnozzle-to-vessel welds extends far beyond the weld into the base metal, and is unnecessarily large. The proposed alternative re-defined the examination volume boundary to 1/2 inch of base metal on each side of the widest portion of the weld, removing from examination the base metal that was extensively examined during prior inspections, and that is not in the high residual stress region associated with the weld.The creation of flaws during plant service in the volume excluded from theproposed reduced examination is unlikely because of the low stress in the base metal away from the weld. The stresses caused by welding are concentrated at or near the weld. Cracks, should they initiate, occur in the high-stressed areas ofthe weld. These high-stress areas are contained in the volume that is defined by Code Case N-613-1 and are thus subject to examination. During previous examinations, no indications exceeding the allowable limits of the preservice or Inservice criteria were found in the reactor vessel nozzle to shell examination volumes including the base metal areas proposed for exclusion from examination in this request.The staff reviewed the applicant's description and technical justification for this exceptionsummarized in the preceding paragraph. The staff also reviewed the applicant's request for relief, "Request for Authorization to Utilize Code Case N-613-1," dated February 27, 2004,which provides a similar technical justification and includes tables of previous examination results. Because the examination volume will still include the heat-affected regions of basemetal around the welds where new cracks are most likely to occur and previous examinations ofthe base metal beyond the heat-affected regions have detected no unacceptable conditions, thestaff concluded that this exception is acceptable.Exception 6: The GALL Report identifies the following recommendation for the CorrectiveActions program element associated with the exception taken:

3-38For Class 1, 2, and 3, respectively, repair is in conformance with IWB-4000,IWC-4000, and IWD-4000, and replacement according to IWB-7000, IWC-7000, and IWD-7000. Approved BWRVIP-44 and BWRVIP-45 documents, respectively, provide guidelines for weld repair of nickel alloys and for weldabilityof irradiated structural components.In its letter dated August 11, 2005, the applicant stated that an approved alternative allows theuse of the 2001 edition of the ASME Code,Section XI, in lieu of the 1995 edition with the 1996 addenda for repair/replacement activities. Section 3.0.3.1.7 of this SER provides the staff's evaluation of this exception.On the basis that the NRC staff has already reviewed and approved this alternative related torepair and replacement generically for aging management of systems and components withinthe scope of license renewal, the staff concluded that it is not an exception and that the affectedprogram element is consistent with the GALL Report.Exception 7: The GALL Report identifies the following recommendation for the Detection ofAging Effects program element associated with the exception taken:Components are examined and tested as specified in Tables IWB-2500-1,IWC-2500-1, and IWD-2500-1, respectively, for Class 1, 2, and 3 components.

The tables specify the extent and schedule of the inspection and examinationmethods for the components of the pressure-retaining boundaries. Alternative approved methods that meet the requirements of IWA-2240 are also specified inthese tables.In its letter dated August 11, 2005, the applicant stated that its ASME Section XI In-ServiceInspection, Subsections IWB, IWC, and IWD Program includes an RI-ISI methodology that provides an alternative to the ASME Code,Section XI, ISI requirements as to (1) the number of locations inspected, (2) the locations inspected, and (3) the method of inspection. Thisalternative applies to welds in ASME Code,Section XI, Categories B-F (Class 1 pressure retaining dissimilar metal welds in vessel nozzles), B-J (Class 1 pressure retaining welds in piping), C-F-1 (Class 2 pressure retaining welds in austenitic stainless steel or high-alloy piping), and C-F-2 (Class 2 pressure retaining welds in carbon or low-alloy steel piping).The applicant submitted a description of its RI-ISI program in its letter dated December 18,2001, "Alternative to the ASME Boiler and Pressure Vessel Code Section XI Requirements for Class 1 and 2 Piping Welds-Risk Informed In-Service Inspection Program." In a letter, "Monticello Nuclear Generating Plant-Risk-Informed In-Service Inspection Program (TAC No.

MB3818)," dated July 24, 2002, the NRC documents authorization for the applicant's RI-ISIprogram during the current (fourth) 10-year ISI interval.In its letter dated August 11, 2005, supplemented by its August 31, 2005, letter, the applicantjustified continuation of its RI-ISI program into the period of extended operation:...The RI-ISI program maintains the fundamental requirements of ASMESection XI, such as the examination technique, examination frequency, and acceptance criteria. Although the RI-ISI program reduces the number of required examination locations, it maintains an acceptable level of quality and safety 3-39pursuant to 10 CFR 50.55a(a)3, by focusing inspections on the most safetysignificant welds with nondestructive examination techniques that are more focused towards finding the type of expected degradation as well as the types of flaws and degradation found during traditional inspections.A systematic approach was used to identify component susceptibility to commondegradation mechanisms and to categorize these degradation mechanisms into the appropriate degradation categories with respect to their potential to result in a postulated leak or rupture in the pressure boundary. An evaluation to determine the susceptibility of components to a particular degradationmechanism that may be a precursor to a leak or rupture in the pressure boundary, and an independent assessment of the consequences of a failure at that location were performed. Industry and plant-specific piping operating experience was used to identify piping degradation mechanisms and failure modes, and consequence evaluations performed used probabilistic riskassessment to establish safety ranking of piping segments for selecting new inspection locations. The degradation mechanisms identified in the RI-ISI Program include thermal fatigue including thermal stratification, cycling, and striping (TASCS) and thermal transients (TT); intergranular stress corrosion cracking (IGSCC); and flow-accelerated corrosion (FAC). The consequences of pressure boundary failures were evaluated and ranked on their impact on core damage and early release. Therefore, redistributing the welds to be inspected with consideration of the safety significance of the segments provides assurance that segments whose failure have a significant impact on plant risk receive an acceptable and improved level of inspection.The RI-ISI examinations result in improved detection of service-relateddegradations over those currently required by ASME Section XI. Therefore, the aging effect of cracking continues to be adequately managed for the piping welds.The staff reviewed the applicant's technical justification for this exception. In addition, the staffreviewed the applicant's detailed RI-ISI program description in its letter requesting relief, dated December 18, 2001, and NRC authorization to implement the RI-ISI program in a letter datedJuly 24, 2002. Based on its review of these documents, the staff determined the following:

  • The letter from MNGP dated December 18, 2001, lists 15 systems that its RI-ISIprogram encompasses.
  • For 10 of the 15 systems that the RI-ISI methodology characterizes in the high- ormedium-risk regions, the MNGP RI-ISI program will change the location and categoryand, typically, will reduce the number of inspected welds from the ASME Code,Section XI, numbers, locations, and categories. However, the applicant will conti nue toinspect a representative number of welds in each of these systems per ASME Code,Section XI, requirements.
  • For 5 of t he 15 systems (component cooling water, control rod drive (CRD) hydraulic,fuel pool emergency cooling, primary containment and atmospheric control, and torus hard vent systems) where the RI-ISI methodology characterizes all pipe welds in the 3-40low-risk region, the MNGP RI-ISI program will eliminate inspection of welds previouslyinspected in accordance with ASME Code,Section XI, requirements.
  • The NRC staff review of the applicant's RI-ISI program, documented in a letter datedJuly 24, 2002, concluded that the MNGP RI-ISI program will provide an acceptable levelof quality and safety pursuant to 10 CFR 50.55a with regard to the number of inspections, locations of inspections, and methods of inspections.Supported by its previous approval of the applicant's RI-ISI program, the staff concluded thatthe ASME Section XI In-Service Inspection, Subsections IWB, IWC, and IWD Program, as modified by the RI-ISI program approved by the NRC in a letter dated July 24, 2002, isacceptable for managing applicable component aging effects through the end of the applicant's current ISI inspection interval on May 31, 2012, approximately 21 months into the extendedoperating period. The staff based this conclusion on the fact that (1) the Class 1 and 2 weldsaffected by implementation of RI-ISI representative welds most susceptible to various age-related degradation mechanisms are still examined to ASME Code,Section XI,requirements, (2) any continuation of the RI-ISI program into the period of extended operationbeyond May 31, 2012, will require review and authorization pursuant to 10 CFR 50.55a, and (3)any subsequent authorization to continue the RI-ISI program into the next ISI inspection interval will include consideration of any adverse industry or plant-specific operating experience thatmight preclude the use or require modification of the RI-ISI program for affected component aging management through the period of extended operation. On the basis of theseconsiderations, the staff concluded that the applicant's implementation of RI-ISI is anacceptable exception to the Detection of Aging Effects program element as described in the GALL Report for AMP XI.M1.Exception 8: The GALL Report recommends the following for the Detection of Aging Effectselement associated with the exception taken:Examination category B-H for integral attachments for vessels: This categoryspecifies volumetric or surface examination of essentially 100% of the length of the attachment weld at each attachment subject to examination.In its letter dated August 11, 2005, the applicant stated that based on a relief request approvedpursuant to 10 CFR 50.55a, its ASME Section XI In-Service Inspection, Subsections IWB, IWC, and IWD Program excludes volumetric or surface examination of the reactor vessel stabilizerbracket welds to the exterior of the RPV. The 1995 edition of the ASME Code,Section XI, classifies the reactor vessel stabilizer bracket welds as Category B-H components (integralattachments for vessels) in the IWB-2500 examination category tabulation and, based on achange in ASME Code,Section XI, category nomenclature, the 1995 addenda classify them as Category B-K components (welded attachments for vessels, piping, pumps, and valves) in the IWB-2500 examination category tabulation.In its letter dated August 11, 2005, the applicant justified not performing a volumetric or surfaceexamination of the reactor vessel stabilizer bracket welds as specified by ASME C ode,Section XI, and described in the GALL Report:Four RPV (reactor pressure vessel) stabilizer brackets are attached to the Class1 RPV with full penetration fillet welds at 0, 90, 180, and 270 RPV azimuth 3-41at an elevation of 994'-2". The RPV stabilizers are connected with flexiblecouplings to the brackets on the RPV and also to the biological shield wall. The RPV stabilizers, brackets, and their attachment welds are designed to withstandand resist local loads (jet reaction forces) and seismic loads while allowing axial and radial movement due to normal thermal growth. The RPV stabilizer bracketsdo not provide structural support during normal operation. The MNGP RPV has never experienced jet reaction forces or seismic events, therefore the stabilizers, brackets, and attachment welds have not experienced the loads for which they are designed.The area around the stabilizers is extremely congested. The vessel stabilizerbrackets are surrounded by mirror insulation that is secured by cable hangers and buckles, ventilation ductwork with support bracing, and electrical installations such as thermocouples. All of this equipment must be relocated and restored to provide access to the stabilizers for examination of the welds. Additionally, dueto the location of the stabilizer brackets and the lack of a working platform at thestabilizer location, a complex scaffold installation is required to provide access tothe examination location.As an alternative to the requirements of Table IWB-2500-1, Category B-K, Item B10.10, inSection XI of the ASME Code, the applicant proposed a surface examination on the stabilizerbrackets if local (jet reaction forces) or seismic design loads are experienced. In addition, the applicant stated that a one-time VT-3 inspection of the accessible areas of all four welded attachments during the 2005 refueling outage noted no reportable conditions.The applicant also stated that relief from this inspection will have no effect on agingmanagement of the components within the scope of license renewal crediting these programs.

The welds are part of the external surface of the reactor vessel. LRA Table 3.1.2-2 discusses aging management for the vessel external surface". The staff reviewed the applicant's justification for this exception. In addition, the staff reviewed the NRC's letter, "MonticelloNuclear Generating Plant-Fourth 10-Year In-Service Inspection Interval Request for Relief No.

4 (TAC No. MC2222)," dated January 6, 2005, in which the staff approved the applicant's request for relief from the requirements of the ASME Code,Section XI, with regard to the requirements of Table IWB-2500-1, Category B-K, Item B10.10 for inspection of the reactorvessel stabilizer bracket welds.On the basis of the information reviewed and additional discussions with the applicant, the NRCissued RAI B2.1.2-1 on August 18, 2005, to obtain an additional technical basis for this exception. The staff asked the applicant to describe details of the weld used for the stabilizer bracket attachment, describe applicable examination requirements and any available results from the time of vessel manufacture, describe inspections since initial startup of the plant, identify and describe stressors that the welds experience during normal operation, statewhether the welds have experienced any stressors different from the normal operating stressors, and summarize any related industry experience with similar welds known to the applicant.In its response, dated September 16, 2005, the applicant provided additional information onweld type and examinations. The four 3-1/2-inch-thick stabilizer brackets are wel ded to theoutside of the RPV with a double-bevel groove weld (3/16-inch root opening, 1/8-inch root face, 3-42 and 30 groove angle) and a concave reinforcing fillet. At the time of vessel manufacture, a UTexamination was conducted of the vessel shell surface before the stabilizer brackets werewelded at the weld location to a depth at least equal to the thickness of the bracket and over the entire area of the subsequent connection, plus a band all around this area half as wide as the thickness of the bracket. After the stabilizer brackets were welded to the vessel, a magneticparticle examination was conducted of the welds. The only examination of the stabilizer bracketwelds since manufacture occurred in March 2005 and consisted of a VT-3 examination of the stabilizer brackets using a flashlight and mirror looking for cracks or linear indications, wear,corrosion, and contaminants. This examination did not identify any reportable indications on anyof the four stabilizer brackets.The applicant's response also provided the following bases to conclude that degradation of thestabilizer bracket welds is unlikely: *Degradation of the stabilizer bracket welds is unlikely because the cumulative fatigueusage factor for the stabilizer brackets is extremely low, so cracking due to fatigue is notexpected to occur. *The brackets and welds are made of carbon steel, and SCC is not applicable for thismaterial; furthermore, during reactor operation, the drywell is maintained in an inert atmosphere with the RPV at high temperatures, so loss of material due to general corrosion is not expected to occur. *MNGP does not use boric acid or a borated solution as a moderator in the reactorcoolant system. Therefore, loss of material due to boric acid corrosion of externalsurfaces does not occur. *Flexible couplings connect the RPV stabilizers to the brackets on the RPV and to thebiological shield wall. The RPV stabilizers, brackets, and their attachment welds aredesigned to withstand and resist local loads (jet reactor forces) and seismic loads while allowing axial and radial movement due to normal thermal growth. During normal operation, there is no loading on the stabilizer brackets; the stabilizers, brackets, andattachment welds have never experienced the loads for which they were designed. *Because of design differences, the Duane Arnold plant was able to conduct surfaceexaminations on portions of its stabilizer bracket attachment welds in April 2005 andfound no reportable indications. In addition, the MNGP staff does not know of any failures or defects of these or similar welds at any other boiling-water reactors (BWRs).Based on the applicant's additional information that an appropriate original inspection of thestabilizer brackets and welds was performed, that there are no stressors to cause degradationof the brackets or welds during normal operation, that no operational events have subjected thebrackets or welds to abnormal stressors, that a recent VT-3 examination of the brackets found no indications of weld or bracket degradation, and that industry operating experience does not suggest occurrence of any age-related degradation of the stabilizer brackets or welds, the staffconcluded that this exception to the Detection of Aging Effects program element is acceptable.The staff reviewed those portions of AMP B2.1.1, "ASME Section XI In-Service Inspection,Subsections IWB, IWC, and IWD Program," that the applicant claimed are consistent withGALL AMP XI.M1 and found them consistent. The staff found the applicant's AMP acceptable 3-43because it conforms to the recommended GALL Report AMP with the exceptions as describedabove.Operating Experience. In LRA Section B2.1.2, the applicant stated that a review of operatingexperience for the ASME Section XI In-Service Inspection, Subsections IWB, IWC, and IWD Program identified no adverse trends or issues with program performance. The program identified and corrected problems before they caused any significant impact to safe operation or loss of intended functions. The applicant took corrective actions to prevent recurrence. The MNGP ASME Section XI In-Service Inspection, Subsections IWB, IWC, and IWD Program monitors the condition of the pressure-retaining components within the license renewal boundary. MNGP procedures contain guidance for indications of degradation requiring evaluation, repair, or replacement. The applicant performs periodic self-assessments and reviews of industry and plant experience to identify any areas needing improvement. Some examples include the following: *The applicant modified its ASME Section XI In-Service Inspection, Subsections IWB,IWC, and IWD Program at the end of the third interval to incorporate an improved strategy for NDE as described in EPRI TR-112657 and in compliance with the requirements of RG 1.174, Revision 1, "An Approach for Using Probabilistic RiskAssessment in Risk-Informed Decisions on Plant-Specific Changes to the Licensing Basis," issued November 2002, and RG 1.178, Revision 1, "An Approach for Plant-Specific Risk-Informed Decision-Making for In-Service Inspection of Piping,"

issued September 2003. *Inspections in 1998 and 2001 of steam dryer jacking screws revealed a crack-likeindication in the screw tack weld at 325 degrees. Following the inspection in 1998, an evaluation indicated that the crack was acceptable. Reinspections of the jacking screwsin 2001 showed no crack growth in the 325 degree screw and no indications of cracking in the other screws. *The applicant detected cracking in 34 tack welds on jet pump beam adjusting screws in1994 during the in-vessel visual inspection at the end of cycle 16. Cracking wasascribed to high cycle fatigue. Applicant staff restored tack welds so that each adjustingscrew had a minimum of one uncracked tack weld. Tack welds are and will conti nue tobe visually inspected.The staff reviewed the operating experience provided in the LRA and interviewed theapplicant's technical personnel to confirm that plant-specific operating experience revealed no degradation not bounded by industry experience.On the basis of its evaluation of the applicant's program against the program elementsdescribed in the GALL Report AMP, its review of the above industry and plant-specific operating experience, and its discussions with the applicant's technical personnel, the staff concluded that the applicant's ASME Section XI In-Service Inspection, Subsections IWB, IWC, and IWD Program will adequately manage the aging effects identified in the LRA for which this AMP iscredited.USAR Supplement. In LRA Section A2.1.2, the applicant provided the USAR supplement forthe ASME Section XI In-Service Inspection, Subsections IWB, IWC, and IWD Program. The 3-44staff reviewed this section and determined that the information in the USAR supplementadequately describes the program, as required by 10 CFR 54.21(d).Conclusion. On the basis of its review and audit of the applicant's ASME Section XI In-ServiceInspection, Subsections IWB, IWC, and IWD Program, the staff determined that those programelements for which the applicant claimed consistency with the GALL Report are consistent withthe GALL Report. In addition, the staff reviewed the exceptions and the associated justificationsand determined that the AMP, with the exceptions, is adequate to manage the aging effects forwhich it is credited. The staff concluded that the applicant demonstrated that the effects ofaging will be adequately managed so that intended functions will be maintained consistent withthe CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff alsoreviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.2.3 ASME Section XI, Subsection IWF Program Summary of Technical Information in the Application. In LRA Section B2.1.3, the applicantdescribed the ASME Section XI, Subsection IWF Program, stating that this existing program is consistent, with enhancement, with GALL AMP XI.S3, "ASME Section XI, Subsection IWF." The MNGP ASME Section XI, Subsection IWF Program is part of the MNGP ASME Section XI In-Service Inspection Program. The applicant performs the ASME Section XI, Subsection IWF Program in accordance with the ASME Code,Section XI, 1995 edition through the 1996 addenda and 10 CFR 50.55a. The program provides for condition monitoring of Class 1, 2, 3, and MC component supports. The applicant selects component supports for inspection in accordance with the ASME Code classification and increases the quantity of component supports selected for examination as a result of discovered support deficiencies. Visual inspection is the primary method for identifying deficiencies. The applicant periodically updates the program as required by 10 CFR 50.55a.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's audit evaluation of this AMP. The staff reviewed the enhancement and the associated justifications todetermine whether the AMP, with the enhancement, remains adequate to manage the agingeffects for which it is credited.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.S3.In the LRA, the applicant stated that, after enhancement of its current program, it will contain noexceptions to program elements of GALL AMP XI.S3; however, during the audit and review, the staff asked the applicant whether its approved ISI relief requests or code cases affect any of its AMP elements. In its letter dated August 11, 2005, supplemented by its letter dated August 31, 2005, the applicant identified for Code Case N-491-2, "Rules for Examination of Class 1, 2, 3,and MC Component Supports of Light-Water Cooled Power Plants,Section XI, Division 1,"

issued March 2000, the following exception to the GALL Report program element.Exception: The GALL Report recommends the following for the Corrective Actions programelement associated with the exception taken:

3-45In accordance with IWF-3122, supports containing unacceptable conditions areevaluated or tested, or corrected before returning to service. Corrective actions are delineated in IWF-3122.2. IWF-3122.3 provides an alternative for evaluationor testing to substantiate structural integrity and/or functionality.In its letter dated August 11, 2005, the applicant stated that it may perform corrective measureson a component support to return it to design condition after acceptance by evaluation or test without requiring additional examinations.The applicant explained that most of the provisions of the original code case were added to the1990 addenda to the ASME Code,Section XI, but that Code Case N-491-2 provisions were added to IWF-3112.3 and IWF-3122.3 in the 1997 addenda. Because some of the provisions were added by ASME Code,Section XI, addenda later than what the GALL Report references, the applicant has identified these provisions as an exception to the GALL Report description ofthe ASME Section XI, Subsection IWF Program.The applicant stated in its letter dated August 11, 2005, that this exception to the CorrectiveAction Program element of GALL Report AMP XI.S3 will have no impact on aging managementfor the component supports. The staff reviewed the applicant's description of this exception together with requirements specified in the ASME Code,Section XI, 1995 Edition through 1996 Addenda. Because the applicant's AMP provides inspections required by ASME Code,Section XI, Subsection IWF (involving requirements for Class 1, 2, 3, and MC component supports of light-water-cooled power plants) and requires reasonable and appropriate corrective actions before a defective component returns to service, the staff agreed that this exception willhave no detrimental impact on the adequacy of affected component aging management. For this reason, together with review of the ASME Section XI, Subsection IWF Program operating experience, the staff found this exception acceptable.In the LRA, the applicant stated that it will implement the following enhancement to make thisAMP consistent with the recommendation in the GALL Report.Enhancement: The GALL Report recommends the following for the Scope of Program programelement associated with the enhancement made:Starting with the 1990 Addenda to the 1989 Edition, the scope of SubsectionIWF was revised. The required percentages of each type of nonexempt support subject to examination were incorporated into Table IWF-2500-1. The revised percentages are 25% of Class 1 nonexempt piping supports, 15% of Class 2 nonexempt piping supports, 10% of Class 3 nonexempt piping supports, and 100% of supports other than piping supports (Class 1, 2, 3, and MC). For pipe supports, the total sample consists of supports from each system (such as mainsteam, feedwater, residual heat removal), where the individual sample sizes are proportional to the total number of nonexempt supports of each type and function within each system. For multiple components other than piping withi n a systemof similar design, function, and service, the supports of only one of the multiple components are required to be examined. To the extent practical, the same supports selected for examination during the first inspection interval are examined during each successive inspection interval.

3-46In the LRA, the applicant stated that it will enhance its ASME Section XI, Subsection IWFProgram to inspect Class MC components supports consistent with the GALL Report, Chapter III, Section B1.3, "Supports for ASME Class MC Components."During the audit and review, the staff asked the applicant for more details about its current IWFprogram and to identify the inspections that the enhancement will add. In response, theapplicant provided the following information: *The current MNGP IWF program does not include VT-3 examination of MC supports. *The current MNGP IWE program includes general visual examinations of MCcomponents and their supports in accordance with ASME Code,Section XI, Table IWE-2500-1.The applicant stated that examinations conducted under the current IWE program include thefollowing MC supports: *torus/ring header seismic restraints *drywell male and female stabilizers *shield stabilizers

  • torus columns
  • torus saddles
  • vent system supports *downcomer bracingThe applicant further stated that for the period of extended operation, the ASME Section XI,Subsection IWF Program will perform VT-3 examinations of the MC supports listed above inaccordance with ASME Code,Section XI, Table IWF-2500-1 in compliance with the ASME Code,Section XI, 1995 edition and 1996 addenda ISI requirements. In addition, for the period of extended operation, the ASME Section XI, Subsection IWE Program will conti nue thegeneral visual examination of the MC components and their supports listed above in accordance with ASME Code,Section XI, Table IWE-2500-1.The staff reviewed the applicant's response together with the applicant's program-basisdocument (PBD) for the IWF program. The staff concluded that by adding a requirement for VT-3 inspection of MC component supports, the applicant's current program will be consistentwith GALL AMP XI.S3. On this basis, the staff found the applicant's response acceptable.The staff asked whether the applicant's program, when enhanced as described in the LRA, willprovide for inspection of all Class MC supports rolled up into applicable line items of the GALL Report, Chapter II, Section B1.3, which specifies ASME Code,Section XI, Subsection IWF as the AMP. In response, the applicant stated the following:When the ASME Section XI, Subsection IWF Program is enhanced, all MNGPMC supports will be rolled up into the applicable NUREG-1801 line items to theextent required by ASME Section XI, Table IWF-2500-1.The staff reviewed the applicant's response together with the applicant's proposed programenhancement as described in the LRA and evaluated in the applicant's PBDs. Based on this 3-47review, the staff concluded that the applicant's program includes appropriate components asrequired by ASME Code,Section XI, Table IWF-2500-1. On this basis, the staff found the applicant's response acceptable.Based on the applicant's responses to the staff's questions and review of associateddocuments provided by the applicant, the staff concluded that the existing program, enhancedas described in the LRA, will be fully consistent with the AMP elements described in GALLAMP XI.S3.The applicant stated, in the LRA, that the enhancement is required to satisfy the GALL ReportAMP recommendations and is scheduled for implementation before the period of extended operation. On the basis of its evaluations of the applicant's program against the programelements described in the GALL Report AMP, together with its review of AMP B2.1.3, "ASME Section XI, Subsection IWF," program operating experience, the staff found this enhancement acceptable, as such changes to the applicant's program provide assurance that the program will adequately manage the effects of aging.The staff reviewed those portions of AMP B2.1.3 that the applicant claimed are consistent withGALL AMP XI.S3 and found them consistent. The staff found the applicant's AMP acceptable because it conforms to the recommended GALL Report AMP with the exception and enhancement as described above.Operating Experience. In LRA Section B2.1.3, the applicant stated that the MNGP ASMESection XI, Subsection IWF Program addresses industry operating experience and prescribes the need for additional augmented requirements for Class 1, 2, 3, and MC component supportsas applicable. In addition, MNGP has been performing a general visual examination on accessible Class MC component supports in accordance with the ASME Section XI, Subsection IWE Program and has not identified any aging effects of concern.The staff reviewed the operating experience provided in the LRA and interviewed theapplicant's technical personnel to confirm that plant-specific operating experience revealed no degradation not bounded by industry experience.On the basis of its evaluation of the applicant's program against the program elementsdescribed in the GALL Report AMP, its review of the above industry and plant-specific operating experience, and discussions with the applicant's technical personnel, the staff concluded that the applicant's ASME Section XI, Subsection IWF program will adequately manage the agingeffects identified in the LRA for which this AMP is credited.USAR Supplement. In LRA Section A2.1.3, the applicant provided the USAR supplement forthe ASME Section XI, Subsection IWF Program.Subsequently, by letter dated June 10, 2005, the applicant revised its USAR supplement toinclude the following commitment, documented as commitment 9 in Table A.5:Prior to the period of extended operation, the MNGP ASME Section XI,Subsection IWF Program will be enhanced to provide inspections of Class MCcomponents supports consistent with NUREG-1801, Chapter III Section B1.3.

3-48The staff reviewed this section and determined that the information in the USAR supplement asaugmented by the commitment adequately describes the program, as required by 10 CFR 54.21(d).Conclusion. On the basis of its review and audit of the applicant's ASME Section XI, SubsectionIWF Program, the staff determined that those program elements for which the applicantclaimed consistency with the GALL Report are consistent with the GALL Report. In addition, thestaff reviewed the enhancement and confirmed that its implementation before the period ofextended operation will result in the existing AMP being consistent with the GALL Report AMPto which it was credited. The staff concluded that the applicant demonstrated that the effects ofaging will be adequately managed so that intended functions will be maintained consistent withthe CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff alsoreviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.2.4 Bolting Integrity Program Summary of Technical Information in the Application. In LRA Section B2.1.4, the applicantdescribed its Bolting Integrity Program, stating that this existing AMP is consistent, with enhancements, with GALL AMP XI.M18, "Bolting Integrity."The applicant stated that the Bolting Integrity Program manages the aging affects associatedwith bolting within the scope of license renewal through periodic inspection, material selection, thread lubricant control, assembly and torque requirements, and repair and replacement requirements. These activities are based on the applicable requirements of the ASME Code,Section XI, and plant operating experience and include consideration of the guidance contained in NUREG-1339, "Resolution of Generic Safety Issue 29: Bolting Degradation or Failure inNuclear Power Plants," EPRI NP-5769, "Degradation and Failure of Bolting in Nuclear Power Plants," EPRI TR-104213, "Bolted Joint Maintenance & Application Guide," and EPRI NP-5067,Volumes 1 and 2, "Good Bolting Practices."The Bolting Integrity Program credits 11 AMPs for the inspection of installed bolts,namely(1) 10 CFR 50, Appendix J, (2) ASME Section XI In-Service Inspection, Subsections IWB, IWC and IWD, (3) Primary Containment In-Service Inspection, (4) Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems, (5) ASME Section XI, Subsection IWF, (6) Buried Piping and Tanks Inspection, (7) Bus Duct Inspection, (8) BWR Vessel Internals, (9) Reactor Head Closure Studs Monitoring, (10) System Condition Monitoring, and (11) Structures Monitoring Programs.The applicant stated that enhancements are required to satisfy the GALL Report AMPrecommendations. It will add the enhancements to the Parameters Monitored or Inspected andAcceptance Criteria elements of the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program, Structures Monitoring Program, and System Condition Monitoring Program. These enhancements will add guidance for visual boltinginspections found in EPRI TR-104213 and EPRI NP- 5067, Volumes 1 and 2.The LRA also states that inspection of bolting for ASME Code,Section XI, Class 1, 2, 3, andMC components is in accordance with the ASME Code,Section XI requirements. Because the scope of license renewal includes components besides those related to ASME Code, 3-49Section XI, the applicant relies upon other programs for additional inspections that includechecking the material condition of bolting for signs of corrosion, wear, and other problems, and associated pressure-retaining joints for signs of leakage. Upon detection of degraded conditions, the applicant performs followup inspections, repairs, replacements, or application of additional testing methods as required by the site CAP and applicable ASME Code,Section XI acceptance criteria.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's audit evaluation of this AMP. The staff reviewed the enhancements and the associated justificationsto determine whether the AMP, with the enhancements, remains adequate to manage the agingeffects for which it is credited.The staff reviewed the Bolting Integrity Program against the AMP elements in the GALL Report,SRP-LR Section A.1.2.3, and SRP-LR Table A.1-1 and focused on the program's managementof aging effects through the incorporation of the 10 program elements. The applicant indicated that the site-controlled Quality Assurance Program includes the Corrective Actions, Confirmation Process, and Administrative Controls elements. SER Section 3.0.4 discusses the staff's evaluation of the Quality Assurance Program.LRA Section B2.1.4 states that the Bolting Integrity Program is consistent with GALLAMP XI.M18 with enhancements added to the Parameters Monitored or Inspected and Acceptance Criteria elements of the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program, Structures Monitoring Program, and System Condition Monitoring Program. These enhancements will add guidance for visual boltinginspections found in EPRI TR-104213, and EPRI NP-5067, Volumes 1 and 2". The staff reviewed the Parameters Monitored or Inspected and Acceptance Criteria elements and concluded that the applicant has acceptable criteria for visual bolting inspections and acceptance criteria for the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program, Structures Monitoring Program, and System Condition Monitoring Program. The staff has reviewed and approved similar enhancements to bolting programs based on EPRI NP-5067 and EPRI TR-104213, as documented in NUREG-1743,"Safety Evaluation Report Related to the License Renewal of Arkansas Nuclear One, Unit 1,"issued April 2001. For these reasons, the staff found that the guidelines for enhancements tothe Bolting Integrity Program reflect industry practice and meet the recommendations of GALL AMP XI.M18.The staff's review of LRA Section B2.1.4 identified an area for which it needed additionalinformation to complete its evaluation of the applicant's program elements. The applicant responded to the staff's RAI as discussed below.In RAI B2.1.4-1, dated July 20, 2005, the staff noted that Table Items 3.3.1-18, 3.3.1-24, and3.4.1-08 in the LRA provide a general discussion of the Bolting Integrity Program as applied to the ESF, auxiliary, and steam and power conversion (SPC) systems. Therefore, the staffrequested that the applicant state whether the Bolting Integrity Program manages all closurebolting in the ESF, auxiliary, and SPC systems for loss of preload, even though the AMR tablescontain no specific line items for this aging effect.In its response, by letter dated August 16, 2005, the applicant stated the following:

3-50As discussed in Section B2.1.4 of the License Renewal Application, the BoltingIntegrity Program manages aging effects for bolting within the scope of license renewal. This includes closure bolting that is required to support a pressure boundary intended function for components of the systems listed in SectionB2.1.4, Scope of Program. Detection of aging effects includes visual inspection of pressure retaining joints for signs of leakage, which may be the result of loss of preload. With the exception of the Emergency Filtration (EFT) System, this includes all closure bolting of the Engineered Safety Features (ESF), Auxiliary,and Steam and Power Conversion (SPC) systems in the LRA. As noted in LRATable 3.3.2-7, bolting of the EFT System is not susceptible to aging effects due to is location in a controlled environment and is, therefore, not included in the Bolting Integrity Program.In a telephone conversation on November 4, 2005, the staff requested that the applicant explainwhy closure bolting of the EFT system is not susceptible to aging effects and not included in theBolting Integrity Program.In its response, by letter dated November 17, 2005, the applicant stated that bolting in the EFTsystem is not susceptible to aging effects (i.e., corrosion) because of its location in a controlled air environment; however, the Bolting Integrity Program is credited with managing the loss of preload aging effect for the EFT system. The applicant supplemented its response toRAI B2.1.4-1 as follows:Closure bolting of the EFT system is managed by the Bolting Integrity Programfor loss of preload. Section B.2.1.4, Scope of Program, of the LRA for the BoltingIntegrity Program is revised to include the EFT system.Based on its review, the staff found the applicant's response to RAI B2.1.4-1 acceptable. Theapplicant stated that the Bolting Integrity Program manages all closure bolting in the ESF,auxiliary, and SPC systems for loss of preload; therefore, the staff's concern described in RAIB2.1.4-1 is resolved.During the audit and review, the staff asked the applicant whether its current approved ISI reliefrequests or code cases affect any of its AMP program elements. In its letter dated August 31, 2005, the applicant identified the following exception to the GALL Report for the Bolting IntegrityProgram:Element: 7: Corrective ActionsException: An approved alternative allows the use of the 2001 Edition of ASME Section XI in lieu of the 1995 Edition with the 1996 Addenda for repair/replacement activities.SER Section 3.0.3.1.7 documents the staff's evaluation of this exception.Because the NRC has already reviewed and approved this alternative, as it relates to repair andreplacement, generically for aging management of systems and components within the scopeof license renewal, the staff concluded that the applicant need not classify it as an exceptionand that, with regard to this item, the affected program element is consistent with the GALL Report.

3-51Operating Experience. The applicant stated that both the industry and the NRC have revealed anumber of instances of bolting concerns, from material control and certification to bolting practices, use of lubrication, and the impact of aging mechanisms. The MNGP Bolting Integrity Program incorporates both plant and industry experience on bolting issues. For example, MNGP previously evaluated and addressed NRC information notices (INs), bulletins, circulars,and GLs listed in Section 3 of NUREG-1339. Some of these resulted in confirmatory analysesor inspections and others in modifications or the addition of special items to consider in the procurement and design processes. MNGP replaced all reactor vessel shroud head bolts with a new vendor recommended design, for example, when it identified cracking issues with the prior design.A review of plant operating experience identified issues with missing or loose bolts, inadequatethread engagement, and improper bolt applications. In all cases, MNGP corrected the identified concern; no significant safety event resulted; and the applicant implemented additional actions,such as procedural enhancements, as needed to minimize the potential for recurrence.In RAI B2.1.4-2, dated July 20, 2005, the staff noted that, after the applicant had submitted theLRA, failed bolts on tee-quencher supports were found at the Hatch Nuclear Plant Unit 2 (Hatch 2). Subsequent analysis revealed that high-strength bolts are susceptible to hydrogen-induced cracking and may fail after 20 to 25 years of service. Therefore, the staff requested that the applicant explain why the tee-quencher bolts at MNGP will not fail as a resultof hydrogen-induced cracking.In its response, by letter dated August 16, 2005, the applicant stated that the tee-quenchersupport design at MNGP differs from the design at Hatch 2. In addition, all bolts are 1-inch-diameter, 3.75-inch-long hex bolts procured to the requirements of American Society for Testing Materials (ASTM) A-325 Type 1 or A-193 Grade B7 material specification. These are not high-strength bolts, having ultimate strength of approximately 125 ksi or less, and are well below the ultimate strength of SA540 Grade B21 Class 1 bolts at Hatch 2. Further, analysis of the Hatch 2 event determined that the most likely cause of SCC of the high-strength bolts wasthe significant contribution of hydrogen embrittlement. One possible source of the hydrogenembrittlement was the use of a zinc primer inside the torus. MNGP does not use a zinc primer; instead, it uses a modified phenolic-based primer in the torus. Finally, MNGP performs underwater inspections of these bolts periodically, and the May 1993 inspection identified no problems or loose connections.Based on its review, the staff found the applicant's response to RAI B2.1.4-2 acceptable. Thestaff concurred with the applicant's conclusions that the Hatch 2 event does not apply to MNGPbecause the tee-quencher design differs from the design at Hatch 2. The bolts at MNGP arelower strength bolts not susceptible to SCC, and the application of phenolic-based instead of zinc-based primer inside the torus has minimized any source of hydrogen. In addition, the applicant performs periodic inspection of tee-quencher bolts in accordance with the requirements of its Primary Containment In-Service Inspection Program, providing added assurance that bolting materials inside the torus will be adequately managed during the periodof extended operation. Therefore, the staff's concern described in RAI B2.1.4-2 is resolved.On the basis of its review of the above industry and plant-specific operating experience, thestaff concluded that the Bolting Integrity Program will adequately manage the aging effects 3-52identified in the LRA for which this AMP is credited. The staff concluded that this programattribute is acceptable.USAR Supplement. In LRA Section A2.1.4, the applicant provided the USAR supplement forthe Bolting Integrity Program.Subsequently, by letter dated June 10, 2005, the applicant revised its USAR supplement toinclude the following commitment, documented as commitment 10 in Table A.5:Prior to the period of extended operation, the guidance for performing visualbolting inspections contained in EPRI TR-104213, Bolted Joint Maintenance &

Application Guide, and the Good Bolting Practices Handbook (EPRI NP-5067 Volumes 1 and 2) will be included in the Bus Duct Inspection Program,Inspection of Overhead Heavy Load and Light Load (Related to Refueling)

Handling Systems Program, Structures Monitoring Program and the System Condition Monitoring Program.The staff reviewed this section and determined that the information in the USAR supplement asaugmented by the commitment adequately describes the program, as required by 10 CFR 54.21(d).Conclusion. On the basis of its review and audit of the applicant's Bolting Integrity Program, thestaff determined that those program elements for which the applicant claimed consistency withthe GALL Report are consistent with the GALL Report. In addition, the staff reviewed the enhancements and confirmed that their implementation before the period of extended operationwill result in the existing AMP being consistent with the GALL Report AMP to which it wascredited. The staff concluded that the applicant demonstrated that the effects of aging will beadequately managed so that intended functions will be maintained consistent with the CLB forthe period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.2.5 Buried Piping & Tanks Inspection Program Summary of Technical Information in the Application. In LRA Section B2.1.5, the applicantdescribed the Buried Piping & Tanks Inspection Program, stating that this existing program is consistent, with enhancements, with GALL AMP XI.M34, "Buried Piping and Tanks Inspection."

The Buried Piping & Tanks Inspection Program consists of preventive and condition monitoring measures to manage the aging effects for buried piping, conduit, and tanks within the scope of license renewal. Buried components within the scope of license renewal include carbon steel piping, bolting, conduit, and tanks (loss of material due to general, crevice, galvanic, pitting, and microbiologically influenced corrosion (MIC)) and cast iron piping (loss of material due to general, crevice, galvanic, and pitting corrosion, MIC, and selective leaching). Preventive measures consist of protective coatings and/or wraps on buried components. Condition monitoring consists of periodic inspections of buried components. In addition, buried components are not routinely uncovered during maintenance activities. Therefore, other systemmonitoring and functional testing activities are relied upon to provide effective degradation aging management of buried piping and tanks. Some of these activities are neither preventive nor mitigative in nature, but they do provide indication of a leak. However, the potential problem 3-53(i.e., small leak) is detected at an early stage, such that repairs can be made before the loss ofcomponent intended function.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's audit evaluation of this AMP. The staff reviewed the enhancements and the associated justificationsto determine whether the AMP, with the enhancements, remains adequate to manage the agingeffects for which it is credited.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses consistency of the AMP elements with GALL AMP XI.M34.In the LRA, the applicant stated that the following enhancements will make this AMP consistentwith the recommendation in the GALL Report.Enhancement 1: The GALL Report recommends the following for the Scope of Programprogram element associated with the enhancement made:The program relies on preventive measures such as coating and wrapping andperiodic inspection for loss of material caused by corrosion of the external surface of buried carbon steel piping and tanks. Loss of material in these components, which may be exposed to aggressive soil environment, is caused by general, pitting, and crevice corrosion, and microbiologically influenced corrosion (MIC). Periodic inspections are performed when the components are excavated for maintenance or for any other reason.The applicant stated in the LRA that it will update the scope of the Buried Piping & TanksInspection Program to implement procedures to include inspections of buried components when uncovered. In interviews with the applicant's technical personnel about the enhanced program, the applicant stated that the enhanced program will take inspection opportunities when buriedcomponents are uncovered at times other than scheduled buried piping inspections. In addition, it will update the excavating procedure to perform inspection(s), when buried components areuncovered. The staff reviewed the applicant's response and plant procedures and found this enhancement acceptable as such changes to the applicant's program provide assurance that the effects of aging will be adequately managed.During the aging management inspection, the inspectors noted that, although the PBDsindicate that the Buried Piping & Tanks Inspection Program would manage buried conduit, the existing inspections and related procedures were limited to buried piping and the diesel fuel oil storage tank. Since buried conduit is galvanized and not wrapped or coated, aging of conduit could be different from that of underground piping and tanks. In its letter dated March 15, 2006,the applicant amended the scope of the program to include conduit. The staff found this acceptable because it ensures that potential aging effects of buried conduit are managed.Enhancement 2: The GALL Report recommends the following for the Parameters Monitored orInspected program element associated with the enhancement made:

3-54The program monitors parameters such as coating and wrapping integrity thatare directly related to corrosion damage of the external surface of buried carbon steel piping and tanks. Coatings and wrappings are inspected by visual techniques. Any evidence of damaged wrapping or coating defects, such as coating perforation, holidays, or other damage, is an indicator of possible corrosion damage to the external surface of piping and tanks.In the LRA, the applicant stated that it will add the Diesel Fuel Oil Storage Tank T-44 internalinspections to the list of scheduled inspections in the Buried Piping & Tanks Inspection Program.The staff noted that the applicant's buried diesel fuel oil storage tank inspection is an internalinspection. In RAI B2.1.5-1, dated October 31, 2005, the staff requested that the applicantclarify whether the diesel fuel oil storage tank internal inspection is in addition to or in lieu of the external inspection recommended in the GALL Report.In its response, by letter dated November 22, 2005, the applicant stated that the Buried Piping& Tanks Inspection Program and the 10-year diesel fuel oil storage tank internal inspection willsupplement the external inspection as recommended in the GALL Report and will incl ude bothvisual and UT inspections. External inspections of the diesel fuel oil storage tank will take placeas opportunities arise. Should the applicant excavate the tank during maintenance activities, itwill perform an external inspection consistent with the GALL Report for inspecting the externalsurfaces of buried piping and tanks.In the Detection of Aging Effects program element, the applicant stated, "An enhancement tothe underground piping inspections is to include a provision that if evaluations of pipe wall thickness show a susceptibility to corrosion, further evaluation as to the extent of susceptibility will be performed." The applicant restated in its RAI response that inspections of the externalsurfaces of other buried carbon steel components will also indicate the external surfacecondition of the diesel fuel oil storage tank.The applicant stated that the diesel fuel oil storage tank internal inspection supplements theexternal inspections recommended in the GALL Report and, therefore, is an acceptable AMP for the detection of aging effects consistent with the GALL Report. The staff reviewed the applicant's response and found this enhancement acceptable as it provides assurance that the effects of aging will be adequately managed.Enhancement 3: The GALL Report recommends the following for the Detection of AgingEffects program element associated with the enhancement made:Periodic inspection of susceptible locations to confirm that coating and wrappingare intact is an effective method to ensure that corrosion of external surfaces has not occurred and the intended function is maintained. The inspections are performed in areas with the highest likelihood of corrosion problems, and in areas with a history of corrosion problems. Because the inspection frequency is plant-specific and also depends on the plant operating experience, the applicant's proposed inspection frequency is to be further evaluated for the extended period of operation.

3-55In the LRA, the applicant stated that it will revise the Buried Piping & Tanks Inspection Programto include a provision that if evaluations of pipe wall thickness show susceptibility to corrosion,further evaluation as to the extent of susceptibility will be performed. It will revise the Buried Piping & Tanks Inspection Program to specify a 10-year buried pipe inspection frequency and a 10-year Diesel Fuel Oil Storage Tank T-44 internal inspection frequency.During the audit and review, the staff asked the applicant about the types of inspections it willperform for this program before the period of extended operation. In response, the applicantstated that a visual and UT inspection of the buried Diesel Fuel Oil Storage Tank T-44 was performed in 2003 and showed no significant loss of material due to corrosion on the tank interior. Additionally, the applicant stated that a visual and UT inspection of the buried pipe nearthe offgas stack was performed in 1999 and no degradation due to aging effects was detected.

The applicant also stated that it regularly in spects the underground piping for the off gas systemgoing to the plant stack. The Offsite Safety Review Committee established this requirement to preclude leakage of offgas from the underground piping for any reason, including aging effects.The staff reviewed the applicant's response and plant procedures and found the enhancementacceptable by providing assurance that AMP B2.1.5, "Buried Piping & Tanks Inspection Program," is consistent with the AMP elements described in GALL AMP XI.M34.Enhancement 4: The GALL Report recommends the following for the Monitoring and Trendingprogram element associated with the enhancement made:Results of previous inspections are used to identify susceptible locations.In the LRA, the applicant stated that the underground piping inspections will include review ofprevious buried piping issues to determine possibly susceptible locations.During the audit and review, the applicant provided technical information regarding thestatement that MNGP has mild soil conditions. In response to the staff's questions, the applicant provided technical data for pH, chloride, and sulfate concentrations, which verified this conclusion. The enhancement of the Monitoring and Trending program element will incl ude areview of previous buried piping issues to determine possibly susceptible locations. The staff reviewed the applicant's response and found AMP B2.1.5 consistent with the AMP elements described in GALL AMP XI.M34.The staff reviewed those portions of AMP B2.1.5 that the applicant claimed are consistent withGALL AMP XI.M34 and found them consistent. The staff found the applicant's AMP acceptable because it conforms to the recommended GALL Report AMP with the enhancements as described above.Operating Experience. In LRA Section B2.1.5, the applicant stated that the Buried Piping &Tanks Inspection Program relies on preventive measures, periodic inspections, and functional testing to manage the aging effects of buried components. MNGP operating experience has shown no buried component failures for systems within the scope of license renewal(emergency service water (ESW), diesel generator, hangars and supports, secondary containment system, fire system (FIR)). The only failures of buried components were on thewell water piping system and the instrument air system to the cooling towers. These are not SRsystems and they are outside the scope of license renewal. The failures are not located near 3-56any buried components within the scope of license renewal. The well water piping failure waspostulated to be caused by MIC and not a failure of the protective coating. The cause of the failure of the instrument air line is yet to be determined. Periodic visual and UT inspections of buried pipe have shown no significant loss of material due to pipe corrosion. Periodic UT inspections of the diesel fuel oil storage tank interior have also shown no significant loss of material due to corrosion. Periodic functional testing of the ESW and fire header systems hasshown no functional failures. Periodic vapor point monitoring and ground water monitoring near the diesel fuel oil storage tank have shown no functional failures of the storage tank or the diesel fuel oil lines.The staff reviewed the operating experience provided in the LRA and interviewed theapplicant's technical personnel to confirm that plant-specific operating experience revealed no degradation not bounded by industry experience.On the basis of its review, operating experience documentation, and discussions with theapplicant's technical personnel, the staff concluded that the applicant's Buried Piping & TanksInspection Program will adequately manage the aging effects identified in the LRA for whichthis AMP is credited.USAR Supplement. In LRA Section A2.1.5, the applicant provided the USAR supplement forthe Buried Piping & Tanks Inspection Program. The staff reviewed this section and determined that the information in the USAR supplement adequately describes the program, as required by10 CFR 54.21(d).In its letter dated June 10, 2005, the applicant supplemented LRA Section A2.1.5 by listing thefollowing commitments, documented as commitments 11-16 in Table A.5, to be performed before the period of extended operation: (1)The Buried Piping and Tanks Inspection Program will update theimplementing procedures to include inspections of buried components when they are uncovered. (2)The Diesel Fuel Oil Storage Tank, T-44, internal inspection will be addedto the list of scheduled inspections in the Buried Piping and Tanks Inspection Program. (3)The Buried Piping and Tanks Inspection Program will be revised toinclude a provision that if evaluations of pipe wall thickness show a susceptibility to corrosion, further evaluation as to the extent of susceptibility will be performed. (4)The Buried Piping and Tanks Inspection Program will be revised tospecify a 10-year buried pipe inspection frequency. (5)The Buried Piping and Tanks Inspection Program will be revised tospecify a 10-year inspection frequency for Diesel Fuel Oil Storage Tank T-44. (6)The Buried Piping and Tanks Inspection Program will be revised toinclude a review of previous buried piping issues to determine possible susceptible locations.

3-57Conclusion. On the basis of its review and audit of the applicant's Buried Piping & TanksInspection Program, the staff determined that those program elements for which the applicantclaimed consistency with the GALL Report are consistent with the GALL Report. In addition, thestaff reviewed the enhancements and confirmed that their implementation before the period ofextended operation will result in the existing AMP being consistent with the GALL Report AMPto which it was credited. The staff concluded that the applicant demonstrated that the effects ofaging will be adequately managed so that intended functions will be maintained consistent withthe CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff alsoreviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.2.6 BWR Control Rod Drive Return Line Nozzle Program Summary of Technical Information in the Application. In LRA Section B2.1.7, the applicantdescribed the BWR CRD Return Line Nozzle Program, stating that this existing program isconsistent, with exceptions, with GALL AMP XI.M6, "BWR Control Rod Drive Return Line Nozzle." The MNGP BWR CRD Return Line Nozzle Program is part of the MNGP ASME Section XI In-Service Inspection Program. The BWR CRD Return Line Nozzle Program is in accordance with the ASME Code,Section XI, 1995 edition through the 1996 addenda, and provides for condition monitoring of the BWR CRD return line (CRDRL) nozzle. In 1977, theCRDRL nozzle safe end was removed and the CRDRL nozzle was capped. In 1986, theCRDRL nozzle was modified again by removing the portion of the existing weld butter layersusceptible to IGSCC, by re-cladding the weld prep area with corrosion-resistant cladding, and by installing a new nozzle cap of non-IGSCC susceptible stainless steel. As a result of capping the CRDRL nozzle, the NUREG-0619, "BWR Feedwater Nozzle and Control Rod Drive ReturnLine Nozzle Cracking: Resolution of Generic Technical Activity A-10," issued November 1980, augmented examinations are no longer required. Not performing the NUREG-0619 augmentedexaminations is considered an exception to GALL Report AMP XI.M6. The applicant updates the program periodically as required by 10 CFR 50.55a.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's audit evaluation of this AMP. The staff reviewed the exceptions and the associated justifications todetermine whether the AMP, with the exceptions, remains adequate to manage the agingeffects for which it is credited.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.M6.In the LRA, the applicant stated the following exceptions to the program elements listed forAMP XI.M6 in the GALL Report.Exception 1: The GALL Report recommends the following for the Parameters Monitored orInspected, Detection of Aging Effects, and Monitoring and Trending program elements associated with the exception taken:

3-58The aging management program (AMP) monitors the effects of cracking on theintended function of the component by detecting and sizing cracks by ISI inaccordance with Table IWB 2500-1 and NUREG-0619.The extent and schedule of inspection, as delineated in NUREG 0619, assuresdetection of cr acks before the loss of intended function of the component.Inspection recommendations include liquid penetrant testing (PT) of the CRDRLnozzle blend radius and bore regions and the reactor vessel wall area beneath the nozzle, return-flow-capacity demonstration, CRD-system-performance testingand ultrasonic inspection of welded connections in the rerouted line. The inspection is to include base metal to a distance of one-pipe-wall thickness or 0.5 in., whichever is greater, on both sides of the weld.The inspection schedule of NUREG-0619 provides timely detection of cracks.In the LRA, the applicant stated that it does not perform the NUREG-0619 augmentedinspections; it removed the CRDRL nozzle safe end and capped the nozzle in 1977. Theapplicant also stated that it modified the nozzle again in 1986 to remove that portion of theexisting weld butter layer susceptible to IGSCC by re-cladding the weld prep area with corrosion-resistant cladding and by installing a new nozzle cap of 316 L nuclear-grade stainlesssteel. Because of these modifications, the applicant stated in its LRA that the requiredaugmented inspections on the CRDRL nozzle specified in NUREG-0619 through NRC GL80-95, "Generic Activity A-10," dated November 13, 1980, are no longer necessary. Although the applicant did not perform those augmented inspections specified in NUREG-0619, it didfollow the guidance in NUREG-0619, Section 8.2, for other inspections and maintenanceactivities related to the CRD system. The following summarizes the activities related to NUREG-0619, Section 8.2: *Section 8.2(3)-The final PT inspection of the CRDRL nozzle showed no indications. Asystem flow and performance test had satisfactory results. *Section 8.2(3a)-The welded connection joining the rerouted CRDRL to the reactorwater cleanup (RWCU) system is inspected every refueling outage with UT and includesbase metal to a distance of one pipe-wall thickness or 0.5 inches, whichever is greater, on both sides of the weld. *Section 8.2(3b)-The remainder of the CRDRL does not meet the definition of Class 1,2, or 3 pipe and, therefore, NUREG-0313, Revision 2, "Technical Report on MaterialSelection and Processing Guidelines for BWR Coolant Pressure Boundary Piping,"

issued January 1988, does not require augmented inspections. *Section 8.2(3c)-Since carbon steel piping was retained in the exhaust header,procedures were developed for (1) periodically performing a random sampling of hydraulic accumulator unit filters to determine if cleaning and flushing is required, and (2) periodically performing a flush of the CRD exhaust header.The applicant further stated that its commitment in response to GL 80-95 to implement therequirements for the CRDRL nozzle specified in NUREG-0619, Section 8, has been completed.The activities described above relating to NUREG-0619, Sections 8.2(3a) and 8.2(3c), areexisting NRC commitments and will continue through the period of extended operation.

3-59On the basis of its review of the completion of CRDRL nozzle-related modifications, thecompletion of commitments in response to GL 80-95, and operating experience for AMP B2.1.7, the staff found this exception acceptable.During the audit and review, the staff asked the applicant whether its current approved ISI reliefrequests or code cases affect any of its AMP program elements. In its letter dated August 31, 2005, the applicant identified the following additional exception to the GALL Report programelement:Exception 2: The GALL Report recommends the following for the Corrective Actions programelement associated with the exception taken:Repair is in conformance with IWB-4000 and replacement in accordance withIWB-7000.In its letter dated August 11, 2005, the applicant stated that an approved alternative allows theuse of the ASME Code,Section XI, 2001 edition in lieu of the 1995 edition with the 1996 addenda for repair/replacement activities.The staff concluded that this item is not an exception and that with regard to this item, theaffected program element is consistent with the GALL Report. SER Section 3.0.3.1.7documents the staff's evaluation.The staff reviewed those portions of AMP B2.1.7, "BWR Control Rod Drive Return Line NozzleProgram," that the applicant claimed are consistent with GALL AMP XI.M6 and found themconsistent. The staff found the applicant's LRA AMP acceptable because it conforms to the recommended GALL Report AMP with the exceptions as described above.Operating Experience. In LRA Section B2.1.7, the applicant stated that it implements the BWRControl Rod Drive Return Line Nozzle Program inspections through the Inservice Inspection Program, which incorporates applicable requirements of the ASME Code. The inspection and testing methodologies have been effective in detecting aging effects due to cracking.

Engineering evaluations were performed based on plant and industry experience and component and programmatic corrective actions implemented as required. For example, in

1977 the CRDRL nozzle safe end was removed and the CRDRL nozzle was capped. In 1986,the CRDRL nozzle was modified again by removing the portion of the existing weld butter layersusceptible to IGSCC by re-cladding the weld prep area with corrosion-resistant cladding, and by installing a new nozzle cap. As a result of capping the CRDRL nozzle as discussed above,the NUREG-0619 augmented examinations are no longer required.The staff reviewed the operating experience provided in the LRA and interviewed theapplicant's technical personnel to confirm that plant-specific operating experience revealed no degradation not bounded by industry experience.On the basis of its review of the above operating experience and discussions with theapplicant's technical personnel, the staff concluded that the applicant's BWR CRDRL NozzleProgram will adequately manage the aging effects identified in the LRA for which this AMP iscredited.

3-60USAR Supplement. In LRA Section A2.1.7, the applicant provided the USAR supplement forthe BWR CRDRL Nozzle Program. The staff reviewed this section and determined that theinformation in the USAR supplement adequately describes the program, as required by 10 CFR 54.21(d).Conclusion. On the basis of its review and audit of the applicant's BWR CRDRL NozzleProgram, the staff determined that those program elements for which the applicant claimedconsistency with the GALL Report are consistent with the GALL Report. In addition, the staffreviewed the exceptions and the associated justifications and determined that the AMP, with theexceptions, is adequate to manage the aging effects for which it is credited. The staff concluded that the applicant demonstrated that the effects of aging will be adequately managedso that intended functions will be maintained consistent with the CLB for the period of extendedoperation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.2.7 BWR Feedwater Nozzle Program Summary of Technical Information in the Application. In LRA Section B2.1.8, the applicantdescribed the BWR Feedwater Nozzle Program, stating that this existing program is consistent,with enhancements, with GALL AMP XI.M5, "BWR Feedwater Nozzle." The MNGP BWR Feedwater Nozzle Program is part of the MNGP ASME Section XI In-Service Inspection Program. The BWR Feedwater Nozzle Program is in accordance with the ASME Code,Section XI, 1995 edition through the 1996 addenda, with Appendix VIII. The program providesfor condition monitoring of the BWR FW nozzles. The BWR FW nozzles were all repaired in 1977 and the safe ends were all replaced in 1981 with a tuning fork design with a welded-in thermal sleeve. The BWR Feedwater Nozzle Program is not currently augmented by the recommendations of General Electric (GE) Topical Report NE-523-A71-0594, Revision 1, "Alternate BWR Feedwater Nozzle Inspection Requirement." The applicant will enhance theprogram by including the recommendations of GE-NE-523-A71-0594-A, Revision 1. The applicant updates the program periodically as required by 10 CFR 50.55a.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's audit evaluation of this AMP. The staff reviewed the enhancements and the associated justificationsto determine whether the AMP, with the enhancements, remains adequate to manage the agingeffects for which it is credited.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses consistency of the AMP elements with GALL AMP XI.M5.During the audit and review, the staff asked the applicant whether its current approved ISI reliefrequests or code cases affect any of its AMP program elements.In its letter dated August 31, 2005, the applicant identified the following additional exception tothe GALL Report program element.

3-61Exception: The GALL Report recommends for the Corrective Actions program elementassociated with the exception taken:Repair is in conformance with IWB-4000 and replacement in accordance withIWB-7000.In its letter dated August 11, 2005, the applicant stated that an approved alternative allows theuse of the ASME Code,Section XI, 2001 edition in lieu of the 1995 edition with the 1996 addenda for repair/replacement activities.The staff concluded that this item is not an exception and that with regard to this item, theaffected program element is consistent with the GALL Report. SER Section 3.0.3.1.7documents the staff's evaluation.In the LRA, the applicant described the following enhancement in meeting the GALL Reportelements.Enhancement: The GALL Report recommends the following for the Parameters Monitored orInspected, Detection of Aging Effects, and Monitoring and Trending program elements associated with the enhancement made:The aging management program (AMP) monitors the effects of cracking on theintended function of the component by detection and sizing of cracks by ISI inaccordance with ASME Section XI, Subsection IWB and the recommendation of GE NE-523-A71-0594, as described below.The extent and schedule of the inspection prescribed by the program aredesigned to ensure that aging effects will be discovered and repaired before theloss of intended function of the component. Inspection can reveal crack initiation and growth. GE NE-523-A71-0594 specifies ultrasonic testing (UT) of specific regions of the blend radius and bore. The UT examination techniques and personnel qualifications are in accordance with the guidelines of GE NE-523-A71-0594. Based on the inspection method and techniques and plant-specific fracture mechanics assessments, the inspection schedule is in accordance with Table 6-1 of GE NE-523-A71-0594. Leakage monitoring may be used to modify the inspection interval.Inspections scheduled in accordance with GE NE-523-A71-0594 provide timelydetection of cracks.In the LRA, the applicant stated that it will enhance the BWR Feedwater Nozzle Program byincluding the recommendations of GE-NE-523-A71-0594-A, Revision 1.By letter dated September 24, 1999, the BWR Owners Group (BWROG) submitted for staffreview Topical Report GE-NE-523-A71-0594-A, Revision 1". This report proposed an alternative to the recommendations of NUREG-0619". The topical report proposed to (1) accept the UT asthe basis to eliminate supplemental liquid PT of inside radii of the RPV nozzles, (2) lengthen the time interval between routine UT of inside radii of the RPV nozzles, and (3) reduce the inspection area of inside radii of the RPV nozzles. In its review of the topical report, the staff 3-62focused on the quality and reliability of the UT examinations. In its letter to BWROG, datedMarch 10, 2000, the staff approved the proposed inspection program and schedule as described in the BWROG topical report; therefore, GE-NE-523-A71-0594-A, Revision 1, is an acceptable alternative to the NUREG-0619 inspection guidelines.The applicant stated that it had made four long-term inspection commitments based onNUREG-0619 in 1989, as follows: (1)Review online FW nozzle thermal sleeve leak detection system data monthly. (2)Perform external UT examinations on two of the four FW nozzles each refueling outage. (3)Perform visual inspections of the spargers and the nozzle blend radius areas of all fourFW nozzles each refueling outage. (4)Perform PT examinations of nozzles at the next appropriate opportunity in the event that(a) UT examinations indicate a flaw or (b) online leakage monitoring systems identifyexcessive leakage (greater than 0.3 gallons per minute).In the corresponding SER, the staff stated that MNGP will continue inspections for "9 inspectioninterval-refueling cycles or 135 startup/shutdown cycles" as stated in NUREG-0619. Theinspection interval began with the installation of welded thermal sleeves during the 1981 refueling outage. With the completion of inspections during the 1998 refueling outage, the applicant had completed the required nine inspection interval-refueling cycles with no observeddegradation of the FW nozzles. The most recent FW nozzle inspections during the third 10-year ASME Section XI In-Service Inspection Program (ending on May 1, 2003) also revealed no cracking on these nozzles.During the audit and review, the staff asked the applicant to clarify plans to update its currentBWR Feedwater Nozzle Program to meet the recommendations in GE-NE-523-A71-0594, Revision 1. The applicant stated that (1) the requirement specified in ASME Code,Section XI,Table IWB-2500-1, Examination Category B-D, for full-penetration welded nozzles has been incorporated into the BWR Feedwater Nozzle Program, (2) the region inspected, examinationtechniques, and personnel qualifications will be consistent with the recommendations of GE-NE-523-A71-0594, Revision 1, Section 4.0, and (3) the requirement of Appendix VIII to ASMECode,Section XI, including IWB-2400 schedule requirements has been incorporated into the BWR Feedwater Nozzle Program, which will be enhanced for consistency with therecommendations of GE-NE-523-A71-0594, Revision 1, Sections 6.2 and 6.3. If defects are detected, the applicant will expand the scope of examinations pursuant to the requirements ofIWB-2430. The staff found this enhancement acceptable because the associated recommendations are based on (1) the availability of the proven improved UT techniques, (2)meeting the inspection commitments made in 1989, (3) acceptable performance history of the FW nozzles with the new thermal sleeves, and (4) the staff's approval of use of GE-NE-523-A71-0594, Revision 1.On the basis of its review of the above enhancement and discussions with the applicant'stechnical personnel, the staff found this enhancement acceptable as such changes to the applicant's program provide assurance that the effects of aging will be adequately managed.

3-63The staff reviewed those portions of AMP B2.1.8, "BWR Feedwater Nozzle Program," that theapplicant claimed are consistent with GALL AMP XI.M5 and found them consistent. The staff found the applicant's AMP acceptable because it conforms to the recommended GALL Report AMP with the exception and enhancement as described above.Operating Experience. In LRA Section B2.1.8, the applicant explained that it performedengineering evaluations based on plant and industry experience and component and programmatic corrective actions implemented as required:

  • Repairs were made to the FW nozzles and safe ends in 1977 to minimize damage to theFW nozzles due to thermal cycling. Cladding was removed from t he nozzle blend radiusand bore, and an FW sparger interference fit thermal sleeve with a piston ring seal was installed.
  • New FW nozzle safe ends were installed in 1981. These safe ends have a tuning forkdesign with a welded-in thermal sleeve and provide a significant reduction in thermal cycling.
  • The applicant incorporated considerations from NUREG-0619, along with NRC GL81-11, "BWR Feedwater Nozzle and Control Rod Drive Return Line Nozzle Cracking (NUREG-0619)," dated February 29, 1981, into the BWR Feedwater Nozzle Programduring the third 10-year inspection interval ending on May 1, 2003. No cracking was identified as a result of these inspections.The staff reviewed the operating experience provided in the LRA and interviewed theapplicant's technical personnel to confirm that plant-specific operating experience revealed no degradation not bounded by industry experience.On the basis of its review of the above operating experience and discussions with theapplicant's technical personnel, the staff concluded that the applicant's BWR Feedwater NozzleProgram will adequately manage the aging effects identified in the LRA for which this AMP iscredited.USAR Supplement. In LRA Section A2.1.8, the applicant provided the USAR supplement forthe BWR Feedwater Nozzle Program. The staff reviewed this section and determined that the information in the USAR supplement adequately describes the program, as required by 10 CFR 54.21(d).In its letter dated June 10, 2005, the applicant added the following three commitments to USARSection A2.1.8, documented as commitments 18-20 in Table A.5, that it will complete beforethe period of extended operation: (1)The parameters monitored and inspected are consistent with the recommendations ofGE-NE-523-A71-0594-A, Revision 1. (2)The regions being inspected, examination techniques, personnel qualifications, andinspection schedule are consistent with the recommendations of GE-NE-523-A71-0594-A, Revision 1. (3)The applicant will schedule inspections per recommendations of GE-NE-523-A71-0594-A, Revision 1.

3-64The BWR Feedwater Nozzle Program is not currently augmented by the recommendations ofGE-NE-523-A71-0594". The applicant will enhance the program by including therecommendations of GE-NE-523-A71-0594-A, Revision 1. The applicant updates this program periodically as required by 10 CFR 50.55a.Conclusion. On the basis of its review and audit of the applicant's BWR Feedwater NozzleProgram, the staff determined that those program elements for which the applicant claimedconsistency with the GALL Report are consistent with the GALL Report. In addition, the staffreviewed the enhancements and confirmed that their implementation before the period ofextended operation will result in the existing AMP being consistent with the GALL Report AMPto which it was credited. The staff concluded that the applicant demonstrated that the effects ofaging will be adequately managed so that intended functions will be maintained consistent withthe CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff alsoreviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.2.8 BWR Penetrations Program Summary of Technical Information in the Application. In LRA Section B2.1.9, the applicantdescribed the BWR Penetrations Program, stating that this existing program is consistent, with exceptions, with GALL AMP XI.M8, "BWR Penetrations." The MNGP BWR Penetrations Program is part of the MNGP ASME Section XI In-Service Inspection Program. The BWR Penetrations Program is in accordance with the ASME Code,Section XI, 1995 edition through the 1996 addenda (with approved ISI relief requests) and provides for condition monitoring of the BWR penetrations. The BWR water chemistry is controlled in accordance with the EPRI guidelines of BWRVIP-130 (TR-1008192), "BWR Water Chemistry Guidelines-2004 Revision."

This document supersedes previous revisions of the guidelines, including BWRVIP-29 (TR-103515), "BWR Water Chemistry Guidelines-1993 Revision." Program activities at MNGP incorporate the inspection and evaluation guidelines of BWRVIP-49, "BWR Vessel and Internals Project, Instrument Penetration Inspection and Flaw Evaluation Guidelines," for instrument penetrations and BWRVIP-27, "BWR Vessel and Internals Project, BWR Standby Liquid Control System/Core Plate DP Inspection and Flaw Evaluation Guidelines," for the standby liquid control (SLC) system. The applicant updates the program periodically as requiredby 10 CFR 50.55a and the BWRVIP.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's audit evaluation of this AMP. The staff reviewed the exceptions and the associated justifications todetermine whether the AMP, with the exceptions, remains adequate to manage the agingeffects for which it is credited.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses consistency of the AMP elements with GALL AMP XI.M8.In the LRA, the applicant stated the following exceptions to the program elements listed forAMP XI.M8 in the GALL Report.

3-65Exception 1: The GALL Report recommends the following for the program descriptionassociated with of the exception taken:The program includes monitoring and control of reactor coolant water chemistryin accordance with the guidelines of BWRVIP-29 (Electric Power Research

[EPRI] TR-103515) to ensure the long-term integrity and safe operation of boilingwater reactor (BWR) vessel internal components.The GALL Report recommends the following for the Preventive Actions program elementassociated with the exception taken:Maintaining high water purity reduces susceptibility to SCC or IGSCC, andreactor coolant water chemistry is monitored and maintained in accordance with the guidelines in BWRVIP-29 (EPRI TR-103515).In the LRA, the applicant stated that it controls BWR water chemistry using BWRVIP-130instead of the guidelines in BWRVIP-29 recommended by the GALL Report.The staff evaluated this exception as part of the Plant Chemistry Program. SER Section3.0.3.2.19 documents the Plant Chemistry Program description, evaluation, and technical basisfor monitoring reactor water chemistry.The applicant stated, in the LRA, that its BWR Penetrations Program is "in accordance withASME Section XI, 1995 Edition through 1996 Addenda (with approved ISI relief requests)."During the audit and review, the staff asked the applicant whether its current approved ISI reliefrequests or code cases affect any of its AMP elements. In its response, by letter dated August 31, 2005, the applicant identified the following additional exception to the GALL Report programelements.Exception 2: The GALL Report recommends the following for the Detection of Aging Effectsprogram element associated with the identified exception:Instrument penetrations and SLC system nozzles or housings are inspected inaccordance with the requirements of ASME Section XI, Subsection IWB.

Components are examined and tested as specified in Table IWB-2500-1, examination categories B-E for pressure-retaining partial penetration welds in vessel penetrations, B-D for full penetration nozzle-to-vessel welds, B-F for pressure-retaining-dissimilar metal nozzle-to-safe-end welds, or B-J for similar metal nozzle-to-safe end welds. In addition, these components are part of examination category B-P for pressure-retaining boundary.In its letter dated August 11, 2005, the applicant stated that its BWR Penetrations Program willdeviate from ASME Code,Section XI, Table IWB-2500-1 and Figure IWB-2500-7(b) requirements in terms of the examination volume for Category B-D components.In its evaluation of the effects of current approved ISI relief requests and code cases, theapplicant stated that during the current ISI inspection interval, which will extend approximately21 months into the period of extended operation, examination of Category B-D components 3-66(Full Penetration Welded Nozzles in Vessels) will deviate from the requirements of ASMECode,Section XI, Table IWB-2500-1, Item No. B3.90, and from the requirements of ASME Code,Section XI, Figure IWB-2500-7(b). Specifically, Figure IWB-2500-7(b) requires that a minimum volume of material equal to a distance of one-half the reactor vessel shell thickness (i.e., a distance of approximately 2-1/2 inches) be included in the examination on each side of the weld; however, the BWR Penetrations Program instead will examine a reduced volume ofone-half inch of base metal on each side of the widest portion of the weld. The applicant identified this reduction in weld examination volume as an exception to the recommendations of GALL AMP XI.M8. The applicant technically justified the reduction in examination volume as follows:The required examination volume for the reactor vessel pressure retainingnozzle-to-vessel welds extends far beyond the weld into the base metal, and is unnecessarily large. The proposed alternative re-defined the examination volume boundary to 1/2 inch of base metal on each side of the widest portion of the weld, removing from examination the base metal that was extensively examined during prior inspections, and that is not in the high residual stress region associated with the weld.The creation of flaws during plant service in the volume excluded from theproposed reduced examination is unlikely because of the low stress in the base metal away from the weld. The stresses caused by welding are concentrated at or near the weld. Cracks, should they initiate, occur in the high-stressed areas ofthe weld. These high-stress areas are contained in the volume that is defined by Code Case N-613-1 and are thus subject to examination. During previous examinations, no indications exceeding the allowable limits of the preservice or inservice criteria were found in the reactor vessel nozzle to shell examination volumes including the base metal areas proposed for exclusion from examination in this request.In its letter dated August 31, 2005, the applicant stated that it considers the alternativeexamination of Category B-D welds based on Code Case N-613-1 an exception to the Detection of Aging Effects program element as described in GALL AMP XI.M8. The staff reviewed the applicant's description and technical justification for this exception as summarized in the preceding paragraph. The staff also reviewed the applicant's letter dated February 27, 2004, which provides a similar technical justification and includes tables of previous examination results. Because the examination volume includes the heat-affected regions of base metal around the welds where new cracks are most likely to occur and previousexaminations of the base metal beyond the heat-affected regions have not detected anyunacceptable indications, the staff concluded that this exception is acceptable.During the audit and review, the staff noted that in the Detection of Aging Effects programelement the applicant referred parenthetically to "risk-informed ISI." Specifically, the first sentence of the Detection of Aging Effects program element reads as follows:The detection of aging effects is prescribed by the MNGP BWR PenetrationsProgram in accordance with the requirements of ASME Section XI, Table IWB-2500-1 for Examination Categories B-D, B-O and B-W and NRC approved alternatives for Categories B-F and B-J (risk-informed ISI (RI-ISI)).

3-67The staff asked the applicant to address the effects of its RI-ISI associated with the Detection ofAging Effects program element.In its response, by letter dated August 31, 2005, the applicant stated that its implementation ofRI-ISI affects the Detection of Aging Effects program element of its BWR Penetrations Program and is an exception to GALL AMP XI.M8.Exception 3: The GALL Report recommends the following for the Detection of Aging Effectsprogram element associated with the exception:Instrument penetrations and SLC system nozzles or housings are inspected inaccordance with the requirements of ASME Section XI, Subsection IWB.

Components are examined and tested as specified in Table IWB-2500-1, examination categories B-E for pressure-retaining partial penetration welds in vessel penetrations, B-D for full penetration nozzle-to-vessel welds, B-F for pressure-retaining dissimilar metal nozzle-to-safe end welds, or B-J for similar metal nozzle-to-safe-end welds. In addition, these components are part of examination category B-P for pressure-retaining boundary. Further details for examination are described in Chapter XI.M1, "ASME Section XI, In-Service Inspection, Subsection IWB, IWC, and IWD," of this report.In the LRA, the applicant stated that its ASME Section XI In-Service Inspection,Subsections IWB, IWC, and IWD Program will include an RI-ISI methodology as an alternativeto the ASME Code,Section XI ISI requirements in terms of (1) the number of locations inspected, (2) the locations inspected, and (3) the method of inspection. This alternative appliesto welds in ASME Code,Section XI Categories B-F (Class 1 pressure-retaining dissimilar metal welds in vessel nozzles), B-J (Class 1 pressure-retaining welds in piping), C-F-1 (Class 2 pressure-retaining welds in austenitic stainless steel or high-alloy piping), and C-F-2 (Class 2 pressure-retaining welds in carbon or low-alloy steel piping).In its letter dated August 31, 2005, the applicant stated that its implementation of RI-ISI duringthe current inspection interval affects both GALL AMP XI.M1 and GALL AMP XI.M8." The staff's evaluation documented in SER Section 3.0.3.2.2, exception 7, applies to this exception, so thestaff concluded that the applicant's implementation of RI-ISI is an acceptable exception formanaging applicable component aging effects through the end of the applicant's current ISI inspection interval on May 31, 2012, approximately 21 months into the extended operatingperiod.On the basis of the review of the above exceptions and of operating experience for the BWRPenetrations Program, the staff found these exceptions acceptable.The staff reviewed those portions of AMP B2.1.9, "BWR Penetrations Program," that theapplicant claimed are consistent with GALL AMP XI.M8 and found them consistent. The staff found the applicant's LRA AMP acceptable because it conforms to the recommended GALL Report AMP with the exceptions as described above.Operating Experience. In LRA Section B2.1.9, the applicant explained that it periodicallyexamines materials within the scope of the BWR Penetrations Program and evaluates them for corrective action as needed. The program incorporates vendor guidance (e.g., BWRVIP-49 and 3-68-27). The applicant has implemented corrective actions to replace materials susceptible tocracking. For example, (1) the SLC nozzle safe end was replaced in 1984 using different materials to resist IGSCC, (2) in 1984 the jet pump instrumentation safe end and penetration seal were replaced with a jet pump instrumentation nozzle penetration seal using 316L stainless steel materials to resist IGSCC, and (3) a corrosion-resistant clad overlay was applied to the inside diameter (ID) of the reactor vessel head vent nozzle (N7) and the reactor vessel head cooling spray nozzles N6A & B (penetrations). The corrosion-resistant clad overlay isolated the IGSCC susceptible weld butter from the reactor coolant.The staff reviewed the operating experience provided in the LRA and interviewed theapplicant's technical personnel to confirm that plant-specific operating experience revealed no degradation not bounded by industry experience.On the basis of its evaluation of the applicant's program against the program elementsdescribed in the GALL Report AMP, the above industry and plant-specific operating experience, and its discussions with the applicant's technical personnel, the staff concluded that the applicant's BWR Penetrations Program will adequately manage the aging effects identified inthe LRA for which this AMP is credited.USAR Supplement. In LRA Section A2.1.9, the applicant provided the USAR supplement forthe BWR Penetrations Program. The staff noted that this USAR supplement includes parenthetic mention of "approved ISI relief requests." In its letter dated August 31, 2005, the applicant stated that it will delete the reference to ISI relief requests from the USAR supplementdescription of the BWR Penetrations Program. The staff reviewed this section and determined that the information in the USAR supplement after deletion of the reference to ISI reliefrequests adequately describes the program as required by 10 CFR 54.21(d).Conclusion. On the basis of its review and audit of the applicant's BWR Penetrations Program,the staff determined that those program elements for which the applicant claimed consistencywith the GALL Report are consistent with the GALL Report. In addition, the staff reviewed theexceptions and the associated justifications and determined that the AMP, with the exceptions,is adequate to manage the aging effects for which it is credited. The staff concluded that the applicant demonstrated that the effects of aging will be adequately managed so that intendedfunctions will be maintained consistent with the CLB for the period of extended operation, asrequired by 10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.2.9 BWR Stress Corrosion Cracking Program Summary of Technical Information in the Application. In LRA Section B2.1.10, the applicantdescribed the BWR Stress Corrosion Cracking Program, stating that this existing program is consistent, with exception, with GALL AMP XI.M7, "BWR Stress Corrosion Cracking." The applicant is implementing ASME Code,Section XI, with UT volumetric, surface, and visual inspections and the RI-ISI program. The MNGP BWR Stress Corrosion Cracking Program incorporates NUREG-0313 and NRC GL 88-01, "NRC Position on IGSCC in BWR AusteniticStainless Steel Piping," dated January 25, 1988, and its Supplement 1. The applicant hasreplaced all IGSCC susceptible materials or protected them with a cladding of resistant weld material. Therefore, all piping welds are now classified as IGSCC Category A in accordance with NUREG-0313 and GL 88-01. As part of the MNGP recirculation piping replacement effort, 3-69the applicant replaced austenitic stainless steel portions of piping systems 4 inches in nominaldiameter or larger operating at temperatures above 200 F of the reactor coolant pressureboundary in accordance with the requirements of NUREG-0313. In addition, a hydrogen waterchemistry system now operates, which reduces the oxidizing environment by introducing excesshydrogen to the RCS that combines with the free oxygen produced by radiolysis.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's audit evaluation of this AMP. The staff reviewed the exception and the associated justifications todetermine whether the AMP, with the exception, remains adequate to manage the aging effectsfor which it is credited.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.M7.The applicant stated that the LRA mentioned relief requests, including RI-ISI, as parts of thecurrent ASME Code,Section XI programs credited with managing aging effects. The applicant further stated that it did not consider relief requests as exceptions to GALL Report because they are temporary and many will expire before the period of extended operation. The applicantstated that code cases and relief requests related to its ASME Section XI In-Service Inspection, Subsections IWB, IWC, IWD, and IWF Program are valid for approximately 21 months into the period of extended operation and that the current inspection interval ends on May 31, 2012. Inaddition, the applicant stated that except for one difference related to the Corrective Actionsprogram element, its implementation of RI-ISI and currently approved relief requests affect none of its BWR Stress Corrosion Cracking Program elements. Consequently, as documented in its letter dated August 31, 2005, the applicant stated that it will revise the LRA to delete allreferences to the RI-ISI program in the BWR Stress Corrosion Cracking Program description.The staff reviewed the applicant's BWR Stress Corrosion Cracking Program and additionaldescriptions of its RI-ISI program in the applicant's letter dated December 18, 2001". On the basis of its review, the staff concluded that the RI-ISI program and approved ISI relief requests affect no BWR Stress Corrosion Cracking Program elements. The staff also found that the applicant's change to delete all references to the RI-ISI program in the description of its BWR Stress Corrosion Cracking Program is acceptable.In the LRA, the applicant stated the following exceptions to the program elements listed forAMP XI.M7 in the GALL Report.Exception 1: The GALL Report recommends the following for the Preventive Actions programelement associated with the exception taken:The program delineated in NUREG-0313 and NRC GL 88-01 does not providespecific guidelines for controlling reactor water chemistry to mitigate IGSCC; however, 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 (Electric Power Research Institute (EPRI)

TR-103515).

3-70In the LRA, the applicant stated that it controls BWR water chemistry using BWRVIP-130. Thisdocument supersedes previous revisions of the BWR water chemistry guidelines, including BWRVIP-29 referenced in the GALL Report.The staff evaluated this exception as part of the Plant Chemistry Program. SER Section3.0.3.2.19 documents the Plant Chemistry Program description, evaluation, and technical basisfor monitoring reactor water chemistry.During the audit and review, the staff asked the applicant whether its current approved ISI reliefrequests or code cases affect any of its AMP elements. In its letter dated August 31, 2005, the applicant identified the following additional exception to the GALL Report program elements.Exception 2: The GALL Report recommends the following for the Corrective Actions programelement associated with the exception taken:The guidance for weld overlay repair and stress improvement or replacement isprovided in NRC GL 88-01; ASME Section XI, Subsections IWB-4000 andIWB-7000, IWC-4000 and IWC-7000, or IWD-4000 and IWD-7000, respectively, for Class 1, 2, or 3 components; and ASME Code Case 504-1.In its letter dated August 11, 2005, the applicant stated that an approved alternative allows theuse of the ASME Code,Section XI, 2001 edition in lieu of the 1995 edition with 1996 addenda for repair/replacement activities.The staff concluded that this alternative is not an exception and that with regard to this item, theaffected program element is consistent with the GALL Report. SER Section 3.0.3.1.7documents the staff's evaluation.The staff reviewed those portions of AMP B2.1.10, "BWR Stress Corrosion Cracking Program,"that the applicant claimed are consistent with GALL AMP XI.M7 and found them consistent. Thestaff found the applicant's AMP acceptable because it conforms to the recommended GALL Report AMP with the exceptions as described above.Operating Experience. In LRA Section B2.1.10, the applicant explained that a review of plantoperating experience for the BWR Stress Corrosion Cracking Program identified no adverse trends or issues with program performance. The applicant identified problems and corrected them before they caused any significant impact to safe operation, and it took adequatecorrective actions to prevent recurrence. The BWR Stress Corrosion Cracking Program effectively detects flaw indications in susceptible components and contains appropriate guidance for evaluation or repair of flaws. As needed, plant staff can adjust the inspection plan based on results to enhance program effectiveness. The applicant performs periodic self-assessments of the program and reviews of industry and plant experience to identify any needed improvements. Examples of corrective actions implemented as a result of program activities include the following:

  • In 1984, a corrosion-resistant cladding overlay was applied to the ID of the head ventnozzle and head cooling spray and instrumentation nozzles. The weld overlay of 308L isolated the IGSCC susceptible existing weld butter located in the weld residual stress area from the reactor coolant.

3-71

  • In 1984, the recirculation inlet safe ends and thermal sleeve assembly and therecirculation outlet safe ends were replaced using nuclear-grade stainless steel materials to resist IGSCC.
  • In 1986, new CSP nozzle safe ends featuring a tuning fork design with a thermal sleevewere installed. The applicant performed this modification to minimize IGSCC in the CSP system.The staff reviewed the operating experience provided in the LRA and interviewed theapplicant's technical personnel to confirm that plant-specific operating experience revealed no degradation not bounded by industry experience.On the basis of its evaluation of the applicant's program against the program elementsdescribed in the GALL Report AMP, the above industry and plant-specific operating experience, and discussions with the applicant's technical personnel, the staff concluded that the applicant'sBWR Stress Corrosion Cracking Program will adequately manage the aging effects identified inthe LRA for which this AMP is credited.USAR Supplement. In LRA Section A2.1.10, the applicant provided the USAR supplement forthe BWR Stress Corrosion Cracking Program. The staff reviewed this section and determined that the information in the USAR supplement adequately describes the program, as required by10 CFR 54.21(d). The staff noted that this USAR supplement describes "the risk-informed ISI program" in the same way as in the applicant's statement on consistency with the GALL Report.In its August 31, 2005, letter the applicant stated that it will delete the reference to the RI-ISIprogram from the USAR supplement description of the BWR Stress Corrosion Cracking Program.Conclusion. On the basis of its review and audit of the applicant's BWR Stress CorrosionCracking Program, the staff determined that those program elements for which the applicantclaimed consistency with the GALL Report are consistent with the GALL Report. In addition, thestaff reviewed the exception and the associated justifications and determined that the AMP,with the exception, is adequate to manage the aging effects for which it is credited. The staffconcluded that the applicant demonstrated that the effects of aging will be adequately managedso that intended functions will be maintained consistent with the CLB for the period of extendedoperation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.2.10 BWR Vessel ID Attachment Welds Program Summary of Technical Information in the Application. In LRA Section B2.1.11, the applicantdescribed the BWR Vessel ID Attachment Welds Program, stating that this existing program is consistent, with exception, with GALL AMP XI.M4, "BWR Vessel ID Attachment Welds." The MNGP BWR Vessel ID Attachment Welds Program is part of the MNGP ASME Section XI In-Service Inspection AMP. The BWR Vessel ID Attachment Weld Program is in accordance with the ASME Code,Section XI, 1995 edition through the 1996 addenda and approved ISI relief requests. The program provides for condition monitoring of the BWR vessel ID attachment welds. It includes inspection and flaw evaluation in accordance with BWRVIP-48 (EPRI TR-108724), "Vessel ID Attachment Weld and Inspection and Flaw Guidelines.". The 3-72BWR water chemistry is controlled in accordance with the EPRI guidelines of BWRVIP-130".The applicant updates the program periodically as required by 10 CFR 50.55a, and supplements it by implementing the guidelines of the BWRVIP documents.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's audit evaluation of this AMP. The staff reviewed the exception and the associated justifications todetermine whether the AMP, with the exception, remains adequate to manage the aging effectsfor which it is credited.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.M4.In the LRA, the applicant stated the following exception to the program elements listed for AMPXI.M4 in the GALL Report.Exception 1: The GALL Report recommends the following for the Preventive Actions programelement associated with the exception taken:The BWRVIP-48 provides guidance on detection, but does not provide guidanceon methods to mitigate cracking. Maintaining high water purity reduces susceptibility to SCC or IGSCC. Reactor coolant water chemistry is monitored and maintained in accordance with the guidelines in BWRVIP-29 (EPRI TR-103515). The program description and evaluation and technical basis of monitoring and maintaining reactor water chemistry are presented in Section XI.M2, "Water Chemistry."In the LRA, the applicant stated that it controls the BWR water chemistry using BWRVIP-130instead of the guidelines in BWRVIP-29 recommended by the GALL Report.The staff found this exception acceptable. SER Section 3.0.3.2.19, Exception 1, documents thestaff's evaluation.During the audit and review, the staff asked the applicant to address whether its currentapproved ISI relief requests or code cases affect any of its AMP program elements. In its letter dated August 31, 2005, the applicant identified the following additional exception to the GALLReport program elements.Exception 2: The GALL Report recommends the following for the Corrective Actions programelement associated with the exception taken:Repair and replacement procedures are equivalent to those requirements in theASME Section XI. Repair is in conformance with IWB-4000 and replacement occurs according to IWB-7000. As discussed in the appendix to this report, the staff found that licensee implementation of the guidelines in BWRVIP-48, as modified, will provide an acceptable level of quality for inspection and flawevaluation of the safety-related components addressed in accordance with 10 CFR Part 50, Appendix B, corrective actions.

3-73In its letter dated August 11, 2005, the applicant stated that an approved alternative allows theuse of the ASME Code,Section XI, 2001 edition in lieu of the 1995 edition with the 1996 addenda for repair/replacement activities.The staff concluded that this alternative is not an exception and that with regard to this item, theaffected program element is consistent with the GALL Report. SER Section 3.0.3.1.7documents the staff's evaluation.The staff reviewed those portions of AMP B2.1.11, "BWR Vessel ID Attachment WeldsProgram," that the applicant claimed are consistent with GALL AMP XI.M4 and found themconsistent. The staff found the applicant's AMP acceptable because it conforms to the recommended GALL Report AMP with the exceptions as described above.Operating Experience. In LRA Section B2.1.11, the applicant explained that it performed theengineering evaluations based on plant and industry experience and implemented component and programmatic corrective actions as required. For example, a vendor notification discussed the susceptibility of Alloy 182 welds to IGSCC/interdendritic SCC in shroud support structuressuch as those used in the MNGP vessel and shroud. BWRVIP-38, "BWR Shroud Support Inspection and Flaw Evaluation Guidelines," provides guidance on the inspection of the shroud support structure. The 2000 outage included inspection of the recommended 10-percent portions of the H8 and H9 welds using enhanced visual examination (EVT)-1 techniques around the access holes at the 0 and 180 degree locations. No indications were found. In addition, the applicant inspected 14 shroud support legs using a VT-3 technique because of flaw indications found on the initially examined support leg. The applicant continues to inspect the H8 and H9 welds in accordance with BWRVIP-38 but has found no operability impacts.The staff reviewed the applicant's operating experience evaluation for the BWR Vessel IDAttachment Welds Program and interviewed the applicant's program manager for this program to confirm that plant-specific operating experience revealed no degradation not identified byindustry experience.On the basis its evaluation of the applicant's program against the program elements describedin the GALL Report AMP, review of the above industry and plant-specific operating experience, and discussions with the applicant's technical personnel, the staff concluded that the applicant'sBWR Vessel ID Attachment Welds Program will adequately manage the aging effects identifiedin the LRA for which this AMP is credited.USAR Supplement. In LRA Section A2.1.11, the applicant provided the USAR supplement forthe BWR Vessel ID Attachment Welds Program. The staff reviewed this section and determined that the information in the USAR supplement adequately describes the program, asrequired by 10 CFR 54.21(d). The staff noted that this USAR supplement mentions "approved ISI relief requests." In its August 31, 2005, letter the applicant stated that it will delete thereference to ISI relief requests from the USAR supplement description of the BWR Vessel ID Attachment Welds Program.Conclusion. On the basis of its review and audit of the applicant's BWR Vessel ID AttachmentWelds Program, the staff determined that those program elements for which the applicantclaimed consistency with the GALL Report are consistent with the GALL Report. In addition, thestaff reviewed the exception and the associated justifications and determined that the AMP, 3-74with the exception, is adequate to manage the aging effects for which it is credited. The staffconcluded that the applicant demonstrated that the effects of aging will be adequately managedso that intended functions will be maintained consistent with the CLB for the period of extendedoperation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.2.11 BWR Vessel Internals Program Summary of Technical Information in the Application. In LRA Section B2.1.12, the applicantdescribed the BWR Vessel Internals Program, stating that this existing program is consistent, with exception and enhancement, with GALL AMP XI.M9, "BWR Vessel Internals." The BWR Vessel Internals Program is part of the ASME Section XI In-Service Inspection Program. The BWR Vessel Internals Program is in accordance with the ASME Code,Section XI, 1995 edition through the 1996 addenda and approved ISI relief requests. The program provides for condition monitoring of the BWR vessel internals for crack initiation and growth. MNGP activities include in-vessel examination procedures and plant water chemistry procedures. The in-vessel examination procedures implement the recommendations of the BWRVIP guidelines, as well as the requirements of the ASME Code,Section XI. This program relies on monitoring and control of water chemistry to keep peak levels of various contaminants below system-specific limitsbased on the EPRI guidelines in BWRVIP-130." This document supersedes previous revisions of the BWR water chemistry guidelines, including BWRVIP-29. The applicant updates this program periodically as required by 10 CFR 50.55a and the BWRVIP program.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's audit evaluation of this AMP. The staff reviewed the exception and enhancement and the associatedjustifications to determine whether the AMP, with the exception and enhancement, remainsadequate to manage the aging effects for which it is credited.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.M9.During the audit and review, the staff noted that, in the LRA, the applicant's program descriptionstated that the BWR Vessel Internals Program is "in accordance with ASME Section XI 1995 Edition through 1996 Addenda and approved ISI relief requests." The staff asked that the applicant clarify the phrase "and approved ISI relief requests." In its letter dated August 11, 2005, the applicant stated that the LRA mentions relief requests because they are parts of thecurrent ASME Code,Section XI programs credited with managing aging effects. The applicant further stated that it did not consider relief requests as exceptions to the GALL Report because they are temporary and many expire before the period of extended operation. The applicant stated that code cases and relief requests of its ASME Section XI In-Service Inspection, Subsections IWB, IWC, IWD and IWF Program are valid for approximately 21 months into the period of extended operation and that the current inspection interval ends on May 31, 2012.The applicant stated that none of its approved ISI relief requests affect any of the programelements of the BWR Vessel Internals Program. Subsequently, as documented in its letter dated August 31, 2005, the applicant revised the LRA to delete all references to ISI relief 3-75requests in the description of the BWR Vessel Internals Program. Upon review of theapplicant's evaluation of program elements against the approved relief requests, the staff found that no approved ISI relief requests affect any BWR Vessel Internals Program element. On this basis, the staff also found the applicant's revision to delete all references to ISI relief requests in the description of its BWR Vessel Internals Program acceptable.In the LRA, the applicant stated the following exception to the program elements listed for AMPXI.M9 in the GALL Report.Exception: The GALL Report recommends the following for the Preventive Actions programelement associated with the exception taken:Maintaining high water purity reduces susceptibility to cracking due to SSC orIGSCC. Reactor coolant water chemistry is monitored and maintained in accordance with the guidelines in BWRVIP-29 (EPRI TR-103515). The program description and evaluation, and technical basis of monitoring and maintaining reactor water chemistry are presented in Chapter XI.M2, "Water Chemistry."In the LRA, the applicant stated that it controls the BWR water chemistry using BWRVIP-130instead of the guidelines in BWRVIP-29 recommended by the GALL Report.The staff found this exception acceptable. SER Section 3.0.3.2.19, Exception 1, documents thestaff's evaluation.In the LRA, the applicant stated that the following enhancement will make this AMP consistentwith the recommendation in the GALL Report.Enhancement: The GALL Report recommends the following for the Scope of Program programelement associated with the enhancement made:The BWRVIP documents provide generic guidelines intended to present theapplicable inspection recommendations to assure safety function integrity of the subject safety-related reactor pressure vessel internal components...The various applicable BWRVIP guidelines are as follows:Core shroud: BWRVIPs -07, -63, and -76; and BWRVIP-02,Rev. 2.Core plate: BWRVIP-25; BWRVIP-50.Shroud support: BWRVIP-38; BWRVIP-52.Low-pressure coolant injection (LPCI) coupling: BWRVIP-42;BWRVIP-56.Top guide: BWRVIP-26; BWRVIP-50.Core spray: BWRVIP-18; BWRVIP-16 and BWRVIP-19.Jet pump assembly: BWRVIP-41; BWRVIP-51.

3-76Control rod drive (CRD) housing: BWRVIP-47; BWRVIP-58.Lower plenum: BWRVIP-47; BWRVIP-57.Steam Dryer: BWRVIP-139For each component or assembly, the first listed BWRVIP document provides guidelines forinspection and evaluation and the second, or last, listed provides guidelines for repair design criteria.In addition, BWRVIP-44 provides guidelines for weld repair of nickel alloys, and BWRVIP-45provides guidelines for weldability of irradiated structural components.In the LRA, the applicant stated that it will add the repair/replacement guidelines inBWRVIP-16, -19, -44, -45, -50, -51, -52, -57, and -58, as applicable, to its BWR VesselInternals Program.The applicant stated in the LRA that the enhancement is required to satisfy the GALL ReportAMP recommendations and that the enhancement is scheduled for completion before the period of extended operation. The staff found that the addition of the listed BWRVIP documentsis an appropriate enhancement to the applicant's current program that will make the applicant'sBWR Vessel Internals Program consistent with the recommendations of the GALL Report during the period of extended operation.The staff asked the applicant to verify that it will implement the applicable BWRVIP guidelinesduring the period of extended operation. In response, the applicant provided the followingdescription of its conformance with industry commitments for implementation of the BWRVIP guidelines:In a letter dated May 30, 1997, from Carl Terry (Niagara Mohawk PowerCompany, Chairman of BWR Vessel and Internals Project) to Brian Sheron (NRC), the BWRVIP member utilities commitments were expressed. The letter stated, 'We will implement the BWRVIP products at each of our plants asappropriate considering individual plant schedules, configurations and needs.'

One such document is BWRVIP-94, Program Implementation Guide.

BWRVIP-94 states that each member utility, of which Monticello/NMC is, will implement the BWRVIP guidelines to the fullest extent possible.Because the applicant's implementation documents indicate a very high degree of conformanceto BWRVIP guidelines, the staff considered this response acceptable. Additionally, in its letter, dated March 15, 2006, the applicant submitted commitment 57, which states that NMC is anactive member of the BWRVIP and will continue to follow applicable inspection guidelines andrecommendations that the executive committee of the BWRVIP has reviewed and approved throughout the period of extended operation.SER Section 4.8 discusses the staff's review of the impact of the time-limited aging analysis(TLAA) of the reactor internals core plate holddown bolts. During review of the issues, the staff requested that the applicant identify the results from the baseline inspections recommended forthe core plate holddown bolts in BWRVIP-25 (TR-107284), "BWR Core Plate Inspection and Flaw Evaluation Guidelines," issued December 1996. The applicant stated that it had not yet 3-77completed the recommended inspections because tooling had not been developed to performthe inspections. Therefore, the staff requested that the applicant complete this action beforeentering the period of extended operation. If tooling is not available, the applicant could usewedges that provide lateral restraint for the core plate, or propose alternative inspection methods that the staff will review and approve. In its letter dated March 31, 2006, the applicantprovided commitment 60 in Appendix A, stating that before the period of extended operation, itwould either inspect the core plate holddown bolts in accordance with the BWRVIP inspection guidelines, install the core plate wedges, or develop an alternative to the inspections identified in BWRVIP-25 and submit it to the staff for review and approval. The staff found this response acceptable because it is consistent with the inspection guidelines described in BWRVIP-25.The staff reviewed those portions of the AMP B2.1.12, "BWR Vessel Internals Program," thatthe applicant claimed are consistent with GALL AMP XI.M9 and found them consistent. The staff found the applicant's AMP acceptable because it conforms to the recommended GALL Report AMP with the exception and enhancement described above.During the aging management inspection, the inspectors identified that additional changes werenecessary to ensure that the applicant adequately managed plant aging effects relating to reactor vessel internals in accordance with the AMP.The inspectors noted that incore monitoring instrument dry tubes are within the scope of theAMP. However, these tubes are not subject to periodic inspections under the applicant's AMP that credits the BWRVIP-130 BWR water chemistry guidelines and the ASME Code,Section XI inspection programs. Because these tubes are subject to radiation-induced damage above the threshold for irradiation-assisted SCC (IASCC), they could crack and cause pressure boundary leakage. Operating experience for GALL AMP XI.M9 identified that cracking has been observedat other BWRs. Furthermore, GE Service Information Letter (SIL)-409, "Incore Dry Tube Cracks," recommended periodic (every other outage) visual examinations focused on the upper2 feet of the tube to detect cracking. The applicant voluntarily implemented these examinationsfor the current license; however, the applicant had not committed to continue with theseexaminations during the period of extended operation. The applicant stated that the next annualLRA revision will incorporate into its AMP the examinations of incore monitoring instrument dry tubes recommended in GE SIL-409. In its letter, dated March 15, 2006, the applicant providedcommitment 56 in Table A.5, which states that NMC has inspected the incore monitoring drytubes at every other refueling outage and will continue to perform this inspection during theperiod of extended operation, in accordance with the guidance provided in GE SIL-409. The staff found the applicant's response acceptable because it ensures that aging effects for the drytubes will be adequately managed during the period of extended operation.The inspectors determined that the steam dryer was within the scope of license renewal for itsstructural function, and the applicant conducted periodic inspection of steam dryer welds potentially subject to cracking. The applicant submitted the LRA before the issuance of theBWRVIP inspection program guidance defined in BWRVIP-139, "Steam Dryer Inspection and Flaw Evaluation Guidelines." The applicant stated that the next annual LRA revision would incorporate the BWRVIP-139 steam dryer weld examinations into the AMP. In its letter, dated March 15, 2006, the applicant provided commitment 58 in Table A.5, which states that NMC willfollow the guidance provided in BWRVIP-139 for the MNGP steam dryer inspections. The staff found the applicant's response acceptable because BWRVIP-139 provides specific guidelines 3-78to ensure that cracking of the steam dryer will be adequately managed during the period ofextended operation.In CAP 014359 (CR 20000209), the applicant documented that during the 2000 refuelingoutage, areas of the steam dryer in close proximity to the main steam (MST) nozzles appeared polished and that this wear could be caused by steam impingement. The applicant also documented in AR 000032000032that Vermont Yankee, with an identical steam dryer design, hadobserved evidence of steam erosion at the underside of the steam dryer. To evaluate if steam erosion was occurring, a degradation mechanism not identified for the steam dryer in GALL AMP XI.M9, the applicant stated that it will reinspect the affected areas of the MNGP steam dryer during the next refueling outage. The evaluation of the areas will determine if erosion isan aging mechanism that needs to be managed.The inspectors also identified that in LRA Table B1.6-11, the applicant stated that the internalCSP piping welds P1, P2, and P3 were not inspected in accordance with BWRVIP-18, "Core Spray Internals Inspection and Flaw Evaluation Guidelines," because mechanical clamps were installed to ensure the structural integrity of the sparger T-box welds, and that a visual inspection was conducted each outage to confirm that T-box integrity was maintained.

Specifically, the applicant performed a general visual examination (VT-3) of the mechanical clamp repair hardware installed around the welds, instead of an enhanced visual examination (EVT-1) of the welds.BWRVIP-18 does not require examination of repaired CSP pipe welds unless the integrity ofthe repair depends upon these welds. The inspectors noted that if cracks develop in thenoninspected CSP piping welds P1, P2, and P3, a cooling water flow diversion path would exist outside the core shroud that could adversely affect the applicant's peak fuel clad temperatureanalysis. Because the applicant's primary clad temperature analysis relied, to some extent, on the leakage integrity for these repaired welds, the inspectors determined that these weldsshould be inspected using EVT-1 methods to meet BWRVIP-18 requirements. Therefore, the inspectors concluded that the applicant had deviated from the BWRVIP-18 guidance and thatthis deviation should be identified as an exception to the GALL Report. The applicant stated that it will change the LRA to remove statements about not inspecting these welds during thenext annual LRA revision, and that it will also change the applicable inspection procedures toimplement enhanced visual examinations of these welds. In its letter, dated March 15, 2006, the applicant provided commitment 59 in Table A.5, which states that NMC will add inspectionrequirements for the P1, P2, and P3 CSP piping welds in accordance with guidance provided in BWRVIP-18, or subsequent revisions. The staff found the applicant's response acceptable because it will ensure that aging effects that might impact the welds will be adequatelymanaged in accordance with the guidance in BWRVIP-18.Operating Experience. In LRA Section B2.1.12, the applicant explained that the BWR VesselInternals Program is based on inspection requirements contained in plant procedures, which incorporate the requirements of the ASME Code. Further, the ASME Code inspections are enhanced with inspections requirements consistent with the BWRVIP. The inspection and testing methodologies have been effective in detecting aging effects due to crack initiation and growth. As shown in the following examples, the applicant performed engineering evaluations based on plant and industry experience and implemented component and programmatic corrective actions as required:

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  • In 2003, UT inspection of the CSP line found cracking in the CSP piping slip joint welds.The previous evaluation was determined to bound the current flaw size, and no further action was necessary.
  • In 1994, mechanical clamps were installed on both of the in-vessel tee box assembliesfor the CSP sparger loops A and B. This modification provided a permanent fix that mitigates the crack in the CSP in-vessel lateral header and ensures the CSP system'ssafety function.
  • In 1994, visual inspection of the jet pumps during the refueling outage revealed crackingof tack welds on the jet pump restrainer bracket adjusting screws. The cracking was attributed to high cycle fatigue from jet pump vibration. The applicant added new tackwelds to the jet pumps restrainer bracket adjusting screws.The staff reviewed the operating experience provided in the LRA and interviewed theapplicant's technical personnel to confirm that plant-specific operating experience revealed no degradation not bounded by industry experience.On the basis of its evaluation of the above industry and plant-specific operating experience anddiscussions with the applicant's technical personnel, the staff concluded that the applicant'sBWR Vessel Internals Program will adequately manage the aging effects identified in the LRAfor which this AMP is credited.USAR Supplement. In LRA Section A2.1.12, the applicant provided the USAR supplement forthe BWR Vessel Internals Program. The staff reviewed this section and determined that the information in the USAR supplement adequately describes the program, as required by 10 CFR 54.21(d).The staff noted that this USAR supplement also mentions "approved ISI relief requests." In itsletter, dated August 31, 2005, the applicant stated that it will delete the reference to ISI reliefrequests from the USAR supplement description of the BWR Vessel Internals Program.In its letter, dated June 10, 2005, the applicant committed to add the repair/replacementguidelines in BWRVIP-16, -19, -44, -45, -50, -51, -52, -57, and -58, as applicable, to the BWRVessel Internals Program before the period of extended operation. In addition, during the periodof extended operation, the applicant committed to add top guide grid inspections using theEVT-1 method of examination for the high fluence locations (grid beam and beam-to-beam crevice slot locations with fluence exceeding 5.0x10 20 neutrons per square centimeter (n/cm 2)).The applicant will inspect 10 percent of the total population within 12 years, with a minimum of5 percent inspected within the first 6 years.Conclusion. On the basis of its review and audit of the applicant's BWR Vessel InternalsProgram, the staff determined that those program elements for which the applicant claimedconsistency with the GALL Report are consistent with the GALL Report. In addition, the staffreviewed the exception and the associated justifications and determined that the AMP, with theexception, is adequate to manage the aging effects for which it is credited. The staff also reviewed the enhancement and confirmed that their implementation before the period ofextended operation will result in the existing AMP being consistent with the GALL Report AMPto which it was credited. The staff concluded that the applicant demonstrated that the effects ofaging will be adequately managed so that intended functions will be maintained consistent with 3-80the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff alsoreviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.2.12 Closed-Cycle Cooling Water System Program Summary of Technical Information in the Application. In LRA Section B2.1.13, the applicantdescribed the Closed-Cycle Cooling Water (CCCW) System Program, stating that this existingprogram is consistent, with exceptions and enhancement, with GALL AMP XI.M21, "Closed-Cycle Cooling Water System." The MNGP CCCW System Program includes (1)preventive measures to minimize corrosion and (2) periodic system and componentperformance testing and inspection to monitor the effects of corrosion and confirm that intended functions are met. Preventive measures include the monitoring and control of corrosion inhibitors and other chemical parameters, such as pH, in accordance with the guidelines of EPRI TR-1007820, "Closed Cooling Water Chemistry Guideline," vendor recommendations, and plant operating experience. EPRI TR-1007820 is the current revision (Revision 1) of EPRI-107396, "Closed Cooling Water Chemistry Guidelines." As the applicant made only minor changes to the MNGP CCCW System Program to implement EPRI TR-1007820, the programis also still in accordance with the EPRI Revision 0 guidelines identified in GALL AMP XI.M21(i.e., EPRI TR-107396). The applicant also performs periodic inspection and testing to confirm function and monitor corrosion, in accordance with EPRI TR-1007820, vendor recommendations, and industry and plant operating experience. A review of plant operating experience demonstrates these measures ensure CCCW systems are performing their intended functions.The applicant has four systems within the scope of license renewal meeting the definition forconsideration as CCCW systems and portions of three additional systems (heat exchangers orcoolers) serviced directly by these cooling water systems. These systems and portions ofsystems are not subject to significant sources of contamination, in which water chemistry is controlled and heat is not rejected directly to a heat sink. The adequacy of chemistry control is confirmed by routine sampling and monitoring for established limits and by equipment performance monitoring to identify aging effects. Corrosion inhibitor concentrations are maintained within limits based on a combination of EPRI TR-1007820 guidelines, vendor recommendations, and plant experience. System and component performance test results are evaluated in accordance with EPRI TR-1007820 guidelines and used as a basis for evaluating the effectiveness of actions to mitigate cracking, corrosion, and heat exchanger fouling.

Acceptance criteria and tolerances are also based on system design parameters and functions.Many chemical parameters monitored are based on ranges identical to or more restrictive than those noted in both EPRI TR-1007820 and EPRI TR-107396. Others are based on vendor recommendations and plant experience. The frequency of performance and functional tests is consistent with EPRI TR-1007820 and based on plant operating experience, trends, and equipment performance. System and component operability tests are typically more fr equentthan once per cycle, whereas more intrusive inspections (e.g., disassembly, eddy currenttesting) are performed less frequently.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's audit evaluation of this AMP. The staff reviewed the exceptions and enhancement and the associated 3-81justifications to determine whether the AMP, with the exceptions and enhancement, remainsadequate to manage the aging effects for which it is credited.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.M21.In the LRA, the applicant stated the following exceptions to the program elements listed forAMP XI.M21 in the GALL Report.Exception 1: The GALL Report recommends the following for the Scope of Program programelement associated with the exception taken:A CCCW system is defined as part of the service water system that is notsubject to significant sources of contamination, in which water chemistry is controlled and in which heat is not directly rejected to a heat sink. The program described in this section applies only to such a system. If one or more of theseconditions are not satisfi ed, the system is to be considered an open-cycle coolingwater system. The staff notes that if the adequacy of cooling water chemistrycontrol can not be confirmed, t he system is treated as an open-cycle system asindicated in Action III of Generic Letter (GL) 89-13.In the LRA, the applicant stated that its CCCW System Program uses EPRI TR-1007820, notEPRI TR-107396, as recommended by the GALL Report. EPRI TR-1007820 is the current revision (Revision 1) of EPRI TR-107396.The GALL Report recommends using EPRI TR-107396 to monitor for corrosion effects. Theapplicant uses EPRI TR-1007820, the revision of the same EPRI technical report. The staff reviewed the EPRI TR-107396 standards, compared them to EPRI TR-1007820, and noted that these EPRI reports contain both control and diagnostic parameters. EPRI defines control parameters (e.g., pH, conductivity, or corrosion inhibitor concentration) as those that have an immediate effect on corrosion and strict adherence to them is expected. EPRI defines diagnostic parameters as those that provide baseline information on system conditions or thatassist in problem troubleshooting and adherence to them is suggested. EPRI based the changes made to TR-1007820 on industry experience updated since the original EPRI technical report. The staff noted that the control parameters of the newer EPRI TR-1007820 are eitherthe same as or more conservative than those in the older EPRI TR-107396. On the basis of this comparison, the staff determined that no technical concerns are associated with the use ofEPRI TR-1007820 and found the exception acceptable.Exception 2: The GALL Report recommends the following for the Preventive Actions programelement associated with the exception taken:The program relies on the use of appropriate materials, lining, or coating toprotect the underlying metal surfaces and maintenance of system corrosioninhibitor concentrations within specified limits of EPRI TR-107396 to minimize corrosion. The program includes monitoring and control of cooling water chemistry to minimize exposure to aggressive environments and application of 3-82corrosion inhibitor in the CCCW system to mitigate general, crevice, and pittingcorrosion.In the LRA, the applicant stated that the Closed-Cycle Cooling Water System Program does notinclude some of the chemical parameters recommended for routine monitoring by EPRI TR-1007820 and EPRI TR-107396. Chosen parameters are deemed adequate based on a combination of system design features (which preclude the need for monitoring somechemicals), makeup water source requirements, EPRI TR-1007820 guidelines, vendor recommendations, and plant operating experience.The applicant stated in the LRA that it monitors most of the chemical parameters recommendedby the GALL Report and EPRI TR-1007820 in the closed-cycle cooling systems. The applicantalso stated that system design precludes any need to monitor several of these parameters, andoperating and inspection activities preclude the need to monitor others. The staff noted that the LRA indicates the specific parameters monitored or excluded for the inhibitor type of each CCCW system, and the PBD itemizes them on a parameter basis.The staff concluded that the parameters that the applicant monitored in its CCCW systemsaccomplished the same goal as did those recommended by the GALL Report. The only parameters recommended for monitoring by EPRI that the applicant did not monitor are thosenot used or applicable at MNGP.On the basis of the above review and a review of MNGP operating experience for AMP B2.1.13,the staff found this exception acceptable.Exception 3: The GALL Report recommends the following for the Parameters Monitored orInspected program element associated with the exception taken:The aging management program (AMP) monitors the effects of corrosion bysurveillance testing and inspection in accordance with standards in EPRI TR-107396 to evaluat e system and component performance. For pumps, theparameters monitored include flow and discharge and suction pressures. For heat exchangers, the parameters monitored include flow, inlet and outlet temperatures, and differential pressure.In the LRA, the applicant stated that some of the heat exchanger and pump performanceparameters recommended by the GALL Report are not monitored for specific pumps or smaller coolers serviced by the closed-cooling water systems. Some of these components are withinthe scope of license renewal only for pressure boundary considerations. Chemical control and established performance monitoring techniques based on plant experience have been

adequate to detect changes in system performance due to cracking or corrosion.The staff reviewed selected inspection and monitoring procedures, then compared the requiredheat exchanger and pump performance parameters against those recommended by the GALL Report. The staff noted the following exceptions to the GALL Report recommendations and the applicant's actions in lieu of those recommendations.The applicant stated that, as an exception to the GALL Report, inlet reactor building closedcooling water (RBC) heat exchanger temperature is not monitored; however, in addition to the 3-83recommendations of the GALL Report, the outlet RBC temperature and both inlet and outletraw water side temperatures are measured. After an evaluation, the staff found that theadditional information that the applicant had gathered is an adequate substitute for the information recommended by the GALL Report, because it verifies that no aging effects reduce heat transfer. The staff reviewed the applicant's additional information and found it acceptable.The applicant stated that, as an exception to the GALL Report, the RHR and REC pump sealcoolers pressure is not monitored; however, flow through these pump seal coolers is monitored, as are RBC surge tank level, various temperatures and flows, and radionuclide levels, all of which alarm when values go out of range. These parameters indicate pressure integrity failures within this closed l oop system. Reduced heat transfer performance from temperaturemonitoring results also can indicate internal corrosion. Additionally, the staff noted that the applicant performed UT measurements of pipe wall thickness to determine the extent ofcorrosion on select portions of RBC system piping, including piping connected to the RECsystem pump seal coolers inside the drywell, which confirmed the effectiveness of waterchemistry. However, the staff found no direct inspection confirming chemistry effectiveness in mitigating corrosion effects on the RBC system portion connected to the RHR system pumpseal coolers or CRD system pump coolers. The staff observed that as an enhancement aone-time inspection will monitor the effects of corrosion of the RHR system and CRD systempump coolers and nearby connected piping. The staff found that the additional information thatthe applicant had gathered adequately substituted for information recommended by the GALLReport, because the parameters monitored will ensure that the pressure boundary intendedfunction will continue through the period of extended operation. The staff reviewed theapplicant's additional information and found it acceptable.The applicant stated that, as an exception to the GALL Report, the emergency dieselgenerator (EDG) jacket water pump suction and discharge pressures and flow are not measured; however, water temperature, closed coolant level, lube oil pressure, and lube oil temperature are monitored quarterly as part of EDG operability tests. As part of the 12-yearpreventive maintenance (PM) requirements for the EDGs, the jacket water pumps are replaced, the jacket water header of the lube oil cooler is visually inspected, and the jacket water systemis inspected for any evidence of leakage from piping or joints (a leak detector dye is used in the coolant). The staff found that the additional information the applicant had gathered adequatelysubstituted for information recommended by the GALL Report, because the parameters monitored will identify aging effects that may impact the intended function of the EDG. The staffreviewed the applicant's additional information and found it acceptable.The applicant stated that, as an exception to the GALL Report, differential pressure across theEDG coolant heat exchangers is not monitored; however, heat exchanger performance is tested periodically by gathering temperature and flow results. Eddy current testing of the heat exchanger tubes is also periodic. The staff found that the additional information that the applicant had gathered adequately substituted for information recommended by the GALL Report, because it identifies aging effects reducing heat transfer. The staff reviewed the applicant's additional information and found it acceptable.The applicant stated that, as an exception to the GALL Report, it does not perform heating andventilation (HTV) system and component performance monitoring. The system contains no heatexchangers, but does contain a number of heating coils for heating to various plant locations.

The scope of license renewal includes the pipi ng system and heater coils for pressure integrity 3-84only. Some of the heating coils are visually inspected annually for leaks. After an evaluation, thestaff found that the additional information that the applicant had gathered adequatelysubstituted for information recommended by the GALL Report, because it will verify that thepressure integrity intended function will continue through the period of extended operation. Thestaff reviewed the applicant's additional information and found it acceptable.On the basis of the above review and of a review of operating experience for AMP B2.1.13, thestaff found this exception acceptable.Exception 4: The GALL Report recommends the following for the Acceptance Criteria programelement associated with the exception taken:Corrosion inhibitor concentrations are maintained within the limits specified in theEPRI water chemistry guidelines for CCCW. System and componentperformance test results are evaluated in accordance with the guidelines of EPRI TR-107396. Acceptance criteria and tolerances are also bas ed on system designparameters and functions.In the LRA, the applicant stated that some of the acceptance criteria (ranges) for monitoredchemistry parameters based on vendor recommendations and plant operating experience are not identical to the typical ranges specified by EPRI TR-1007820 or EPRI TR-107396. The ranges based on plant operating experience have been sufficient to manage aging effects.The staff observed that both EPRI TR-107396 and EPRI TR-1007820 specify normal operatingranges for chemical control parameters. They also specify diagnostic parameters, but do not include action levels and ranges, as these parameters are used for trending. Specifically, with regard to the four CCCW systems, the chemical control parameter ranges recommended byEPRI, and hence by the GALL Report, and the corresponding ranges used at MNGP are as follows:(1)The following applies to the chromate-based RBC system, which also serves the RHR,REC, and CRD coolers:a.Chromate-Chromate is monitored to a range of 500 to 1800 parts per million(ppm), not 150 to 300 ppm as recommended by the GALL Report and EPRI. As noted in EPRI TR-107396 and EPRI TR-1007820, this may have a detrimental impact on pump seal integrity. The RBC pump seals are consumables. The applicant installed a new design seal replaced on a 2-year frequency and has monitored for but not detected any impact to system pressure boundary integrity.b.pH-pH is monitored to a more restrictive range of 9.0 to 9.7 versus the EPRITR-107396 range of 8.5 to 10.5 and the EPRI TR-1007820 range of 8.0 to 11.0.c.Chloride-Chloride is not monitored in the RBC system. Chloride is monitored inthe makeup demineralized water source, which provides makeup to the RBC system. Chloride limits for demineralized water have a limit of 10 parts per billion (ppb), which is substantially lower than the limit of 10 ppm established by both EPRI reports.

3-85(2)The following applies to the cooling loops of the EDG system (DGN):a.Nitrite-The chemical range for nitrite is identical to that in EPRI TR-107396 (500to 1000 ppm) and more restrictive than that in EPRI TR-1007820 (50 to 1500 ppm).b.pH-The range for pH is 9.0 to 10.7, which is more restrictive than the 8.5 to11.0 range in EPRI TR-1007820 and close to the 8.5 to 10.5 range specified in EPRI TR-107396.c.Tolytriazole-The specified range for tolytriazole is 10 to 40 ppm, as opposed tothe 5 to 30 ppm range recommended in EPRI TR-107396, and more restrictive than the 5 to 100 ppm range recommended in EPRI TR-1007820. EPRI TR-107396 identified no adverse impacts for slightly higher tolytriazole ranges.d.Chloride-Chloride is not monitored in the cooling loops of the DGN. Chloride ismonitored in the makeup demineralized water source, which provides makeup to the cooling loops. Chloride limits for demineralized water have a limit of 10 ppb, which is substantially lower than the limit of 10 ppm established by the EPRI reports.(3)The following applies to the piping and heating coils of the HTV system:a.EPRI TR-107396 and EPRI TR-1007820 do not specify chemical ranges for thepiping and heating coils of the HTV system, so they are monitored in accordancewith vendor recommendations and plant experience. These include conductivity, pH, phosphate, sulfites, and total gamma activity and are specified by plant procedure.(4)The following applies to the closed cooling loop used on the #14 air compressor of theinstrument and service air (AIR) system:a.Glycol percent volume-Both EPRI TR-107396 and EPRI TR-1007820recommend that glycol percent volume remain above 30 percent to avoid becoming a nutrient for microbiological growth. Further, EPRI TR-1007820 recommends that the level remain below 60 percent. The applicant maintains a concentration of about 50 percent, which is within the range specified by the EPRI reports.b.pH-MNGP procedures do not provide a specific range for pH; however,procedures require routine sampling and measurement of pH, and pH is maintained within the range specified by EPRI TR-1007820 of 7.5 to 11.0.The staff reviewed the operating ranges of each of the above 10 chemical control parametersand noted that eight were either equivalent to or more conservative than the rangerecommended by the EPRI technical reports. One, the chromate, had a higher range, but the applicant took effective action to mitigate the effects of that higher range. The last was inaccordance with vendor recommendations and plant operating experience, as the GALL Report provides no recommendation.

3-86On the basis of the above review and a review of MNGP operating experience for AMP B2.1.13,the staff found this exception acceptable.In the LRA, the applicant stated that the following enhancement will make this AMP consistentwith the recommendation in the GALL Report.Enhancement: The GALL Report recommends the following for the Parameters Monitored orInspected program element associated with the enhancement made:The aging management program (AMP) monitors the effects of corrosion bysurveillance testing and inspection in accordance with standards in EPRI TR-107396 to evaluat e system and component performance. For pumps, theparameters monitored include flow and discharge and suction pressures. For heat exchangers, the parameters monitored include flow, inlet and outlet temperatures, and differential pressure.In the LRA, the applicant stated that a one-time inspection will monitor the effects of corrosionon select portions of CCCW systems that perform a pressure-integrity intended function.The staff reviewed the applicant's proposed enhancement and determined that augmenting theCCCW systems with a one-time inspection to monitor the effects of corrosion on select portionsof CCCW systems that perform a pressure-integrity intended function will provide additionalassurance that aging effects are identified before component failures, consistent with GALLAMP XI.M21". On the basis of its review, the staff found this enhancement acceptable, as such changes to the applicant's program provide assurance that the effects of aging will beadequately managed.The staff reviewed those portions of AMP B2.1.13, "Closed-Cycle Cooling Water SystemProgram," that the applicant claimed are consistent with GALL AMP XI.M21 and found themconsistent. The staff found the applicant's AMP acceptable because it conforms to the recommended GALL Report AMP with the exceptions and enhancement as described above.Operating Experience. In LRA Section B2.1.13, the applicant stated that, for the Closed-CycleCooling Water System Program, it initiates CRs/ARs when it finds that water chemistry is out of specification or equipment performance does not meet standards. The time duration of these conditions is typically short and no evidence of detrimental equipment impacts was found. The applicant did not identify any examples of CCCW system functional failures due to corrosion,SCC, or heat transfer degradation due to fouling resulting from inadequate chemistry control.

Steam leaks have occurred in various portions of the piping and heating coils of the HTV system (steam traps, temperature control valve packing/gaskets, heating coils, and fittings).These leaks have been isolated and corrected, were typically minor in nature, did not impact the operation of nearby safety equipment, and were not linked to inadequate chemistry or corrosion as the cause of the leak. Procedural requirements for chemistry limits are established based on EPRI and industry standards and routinely monitored. The applicant entered a CR into the site CAP because a liquid penetrant examination showed a pin-hole leak on the top side of a sampling line at the tubing end of a tubing-to-insert fillet weld (sampling line connectedon top of an RBC heat exchanger). Inadequate original welding of the connection was determined to be the cause of the leak. Adjacent and external surfaces did not show pitting or 3-87other signs of distress, suggesting this was a localized effect. The applicant removed andreplaced the affected section of stainless steel tubing.The staff reviewed the operating experience provided in the LRA and interviewed theapplicant's technical personnel to confirm that plant-specific operating experience revealed no degradation not bounded by industry experience.On the basis of its review of the above industry and plant-specific operating experience anddiscussions with the applicant's technical personnel, the staff concluded that the applicant'sCCCW System program will adequately manage the aging effects identified in the LRA forwhich this AMP is credited.USAR Supplement. In LRA Section A2.1.13, the applicant provided the USAR supplement forthe CCCW System Program. The staff reviewed this section and determined that theinformation in the USAR supplement adequately describes the program, as required by 10 CFR 54.21(d).In its letter dated June 10, 2005, the applicant added a commitment to USAR Section A2.1.13,documented as commitment 23 in Table A.5, that before the period of extended operation, it willconduct a one-time inspection to monitor the effects of corrosion on select portions of CCCWsystems performing a pressure-integrity intended function.Conclusion. On the basis of its review and audit of the applicant's CCCW System Program, thestaff determined that those program elements for which the applicant claimed consistency withthe GALL Report are consistent with the GALL Report. In addition, the staff reviewed the exceptions and the associated justifications and determined that the AMP, with the exceptions,is adequate to manage the aging effects for which it is credited. The staff also reviewed the enhancement and confirmed that their implementation before the period of extended operationwill result in the existing AMP being consistent with the GALL Report AMP to which it wascredited. The staff concluded that the applicant demonstrated that the effects of aging will beadequately managed so that intended functions will be maintained consistent with the CLB forthe period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.2.13 Compressed Air Monitoring Program Summary of Technical Information in the Application. In LRA Section B2.1.14, the applicantdescribed the Compressed Air Monitoring Program, stating that this existing program is consistent, with exceptions and enhancements, with GALL AMP XI.M24, "Compressed Air Monitoring." The MNGP Compressed Air Monitoring Program consists of inspection, monitoring, and testing of the AIR system to provide reasonable assurance that they will perform theirintended function for the duration of extended operation.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP 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.

3-88The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.M24.In the LRA, the applicant stated the following exceptions to the program elements listed forAMP XI.M24 in the GALL Report.Exception 1: The GALL Report recommends the following for the Parameters Monitored orInspected program element associated with the exception taken:In-service inspection (ISI) and testing is performed to verify proper air quality andconfirm that maintenance practices, emergency procedures, and training are adequate to ensure that the intended function of the air system is maintained.In the LRA, the applicant stated that it does not perform ISI and inservice testing to verifyproper air quality or confirm that maintenance practices, emergency procedures, and training are adequate to ensure that the air system intended function is maintained. This is not an ISI orinservice testing function or activity. Staff engineering personnel verify air quality through semiannual testing in accordance with procedures based on GL 88-14, "Instrument Air Supply System Problems Affecting Safety Equipment, dated August 8, 1988; American National Standards Institute (ANSI)/Instrument Society of America (ISA) S7.3, "Quality Standard for Instrument Air"; ANSI Z86.1-1973, "Commodity Specification for Air and Drager Operating Instruction"; and EPRI TR-103595, "Report of Instrument Air Working Group." Station administrative and training procedures control maintenance practices, emergency procedures, and training.On the basis of its review of NRC, EPRI, and other industry guidelines and standards, the staffdetermined that the applicant's inspection and testing verify proper air quality and confirm thatmaintenance practices, emergency procedures, and training are adequate to ensure that the intended function of the compressed air monitoring systems is maintained. Procedures andprograms at MNGP implement Compressed Air Monitoring Program activities recommended by the GALL Report. The MNGP audit and review report details the staff's review. On the basis of a review of the above exception and of operating experience for the Compressed Air Monitoring Program, the staff found this exception acceptable.Exception 2: The GALL Report recommends the following for the Detection of Aging Effectsprogram element associated with the exception taken:Guidelines in EPRI NP-7079, EPRI TR-108147, and ASME OM-S/G-1998, Part17, ensure timely detection of degradation of the compressed air systemfunction. Degradation of the piping and any equipment would become evident by observation of excessive corrosion, by the discovery of unacceptable leakage rates, and by failure of t he system or any item of equipment to meet specifiedperformance limits.In the LRA, the applicant stated that its program is based on the guidance provided inANSI/ISA-S7.3-1975, ANSI/ISA-Z86.1-1973, EPRI TR-103595, and GL 88-14 augmented by previous NRC IN 81-38, "Potentially Significant Equipment Failures Resulting for Contamination of Air-Operated Systems," dated December 17, 1981; IN 87-28, "Air System Problems at U.S.

3-89Light-Water Reactors," dated June 22, 1987; IN 87-28 Supplement 1, and by the INPOSignificant Operating Event Report (INPO SOER) 88-01. The applicant takes exception toANSI/ISA-S7.0.01-1996 because it uses ANSI/ISA-S7.3-1975 instead. The applicant takes exception to ASME OM-S/G-1998 Part 17 as specified in GALL AMP XI.M24.The staff observed that, in lieu of the EPRI NP-7079 guidelines recommended by the GALLReport to detect degradation of compressed air system function, the applicant developedprocedures and instructions based on GL 88-14, ANSI/ISA S7.3-1975, ANSI/ISA Z86.1-1973, EPRI TR-103595, INPO SOER 88-01 augmented by IN 81-38, and IN 87-28 with Supplement

1. The staff reviewed and compared ANSI/ISA-S7.3-1975 with ANSI/ISAS7.0.01-1996 and found ANSI/ISA-S7.3-1975 acceptable for use as its criteria are more conservative than recommended by ANSI/ISA-S7.0.01-1996.During the audit, the staff asked that the applicant clarify its reason for taking exception toASME OM-S/G-1998, Part 17, which provides guidance for performance testing of instrument air systems in light-water reactor power plants. The applicant responded that the scope ofcomponents included in the compressed air monitoring activities includes distribution piping, valves, accumulators for air-operated SR valves, and the containment isolation valves of the instrument air system. The applicant stated that the instrument air system compressors,receivers, filters, and dryers are not within the scope of license renewal. The applicant also stated that its Compressed Air Monitoring Program will adequately manage aging for thoseinstrument air system components within the scope of license renewal. The staff reviewedseveral procedures and instructions to determine their adequacy and completeness, their frequencies, and their results, including a sampling from the applicant's CAP, and concluded that the applicant is able to ensure timely detection of degradation of the compressed airsystem function, as shown by its ability to detect corrosion or high leak rates or the failure of any component to meet its performance limits. The staff found the applicant's response acceptable.On the basis of a review of the above exception and of a review of operating experience for theCompressed Air Monitoring Program, the staff found this exception acceptable.In the LRA, the applicant stated that the following enhancements will make this AMP consistentwith the recommendation in the GALL Report.Enhancement 1: The GALL Report recommends the following for the Scope of Programprogram element associated with the enhancement made:The program manages the effects of corrosion and the presence ofunacceptable levels of contaminants on the intended function of the compressedair system. The AMP includes frequent leak testing of valves, piping, and othersystem components, especially those made of carbon steel, and a preventivemaintenance program to check air quality at several locations in t he system.In the LRA, the applicant stated that it will revise the Compressed Air Monitoring Programprocedures to include corrective action requirements if water vapor, oil content, or particulate acceptance limits are not met. In addition, it will clarify the acceptance criteria for oil contenttesting and provide the acceptance limit bases for water vapor, oil content, and particulate tests.

3-90During the audit, the staff asked that the applicant clarify the above enhancement. Theapplicant responded that, although it regarded the guidance identified in Exception 2 asconservative compared to the guidance recommended by the GALL Report, it wanted to apply further conservatism in the event that acceptance criteria were not met in any area. The acceptance criteria of the compressed air monitoring systems procedures are evaluated underthe CAP. The staff reviewed the enhancement and found this potential augmentation of theacceptance criteria of the compressed air monitoring systems procedures consistent with therecommendations of the GALL Report as it provides additional assurance that aging effects are identified before compressed air monitoring system component failure. Therefore, the stafffound this enhancement acceptable.On the basis of a review of the above enhancement and a review of operating experience forthe Compressed Air Monitoring Program, the staff found the enhancement acceptable as such changes to the applicant's program provide assurance that the effects of aging will beadequately managed.Enhancement 2: The GALL Report recommends the following for the Detection of AgingEffects program element associated with the enhancement made:Guidelines in EPRI NP-7079, EPRI TR-108147, and ASME OM-S/G-1998, Part17, ensure timely detection of degradation of the compressed air systemfunction. Degradation of the piping and any equipment would become evident by observation of excessive corrosion, by the discovery of unacceptable leakage rates, and by failure of t he system or any item of equipment to meet specifiedperformance limits.In the LRA, the applicant stated that it will revise its Compressed Air Monitoring Program toinclude inspection of air distribution piping based on recommendations of EPRI TR-108147, "Compressor and Instrument Air System Maintenance Guide," issued March 1998.During the audit, the staff asked that the applicant clarify the above enhancement. Theapplicant responded that EPRI TR-108147 addressed the subject piping with updated recommendations. The staff reviewed the enhancement and determined that expanding thedetection of aging effects by including air distribution piping is consistent with the recommendations of the GALL Report and will provide additional assurance that aging effectsare identified before compressed air monitoring component failure.On the basis of a review of the above enhancement and a review of the operating experiencefor the Compressed Air Monitoring Program, the staff found this enhancement acceptable as such changes to the applicant's program provide assurance that the effects of aging will beadequately managed.The staff reviewed those portions of AMP B2.1.14 "Compressed Air Monitoring Program," thatthe applicant claimed are consistent with GALL AMP XI.M24 and found them consistent. The staff found the applicant's AMP acceptable because it conforms to the recommended GALL Report AMP with the exceptions and enhancements as described above.Operating Experience. In LRA Section B2.1.14, the applicant explained that it based theCompressed Air Monitoring Program on appropriate NRC requirements and industry guidance, 3-91including the MNGP response to NRC GL 88-14. It performs established PM ta sks and otherinspections on a routine basis. For example, it performed and completed a major PM task in June 2003. Plant staff identified a number of system leaks, notifi ed the system engineer, andinitiated and completed repair WOs to fix the leaks. Such PM activities and inspections, systemrepairs, ongoing monitoring, and review of plant and industry operating experience have been effective in maintaining air system performance. Unavailability targets for this system are well within established goals.The staff reviewed the operating experience provided in the LRA and interviewed theapplicant's technical personnel to confirm that plant-specific operating experience revealed no degradation not bounded by industry experience.On the basis of its review of the above industry and plant-specific operating experience anddiscussions with the applicant's technical personnel, the staff concluded that the CompressedAir Monitoring Program will adequately manage the aging effects identified in the LRA for whichthis AMP is credited.USAR Supplement. In LRA Section A2.1.14, the applicant provided the USAR supplement forthe Compressed Air Monitoring Program. The staff reviewed this section and determined that the information in the USAR supplement adequately describes the program, as required by 10 CFR 54.21(d).In its letter, dated June 10, 2005, the applicant added commitments to USAR Section A2.1.14,documented as commitments 24 and 25 in Table A.5, that before the period of extendedoperation, it will (1) revise Compressed Air Monitoring Program procedures to include correctiveaction requirements if the acceptance limits for water vapor, oil content, or particulate are not met, clarify acceptance criteria for oil content testing, and provide the basis for the acceptancelimits for the water vapor, oil content, and particulate tests and (2) revise the Compressed Air Monitoring Program to include inspection of air distribution piping based on the recommendations of EPRI TR-108147.Conclusion. On the basis of its review and audit of the applicant's Compressed Air MonitoringProgram, the staff determined that those program elements for which the applicant claimedconsistency with the GALL Report are consistent with the GALL Report. In addition, the staffreviewed the exceptions and the associated justifications and determined that the AMP, with theexceptions, is adequate to manage the aging effects for which it is credited. The staff also reviewed the enhancements and confirmed that their implementation before the period ofextended operation will result in the existing AMP being consistent with the GALL Report AMPto which it was credited. The staff concluded that the applicant demonstrated that the effects ofaging will be adequately managed so that intended functions will be maintained consistent withthe CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff alsoreviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.2.14Electrical Cables Not Subject to 10 CFR 50.49 Environmental QualificationRequirements Used in Instrumentation Circuits ProgramSummary of Technical Information in the Application. In LRA Section B2.1.16, the applicantdescribed the Electrical Cables Not Subject to 10 CFR 50.49 Environmental Qualification 3-92Requirements Used in Instrumentation Circuits Program, stating that this new program isconsistent, with exceptions, with GALL AMP XI.E2, "Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in InstrumentationCircuits." This program applies to non-EQ electrical cables used in radiation monitoring and nuclear instrumentation circuits with sensitive, low-level signals that are within scope of license renewal and are installed in adverse localized environments caused by heat, radiation, and moisture in the presence of oxygen. Exposure of electrical cables to adverse localized environments caused by heat or radiation can result in reduced insulation resistance (IR).

Reduced IR causes an increase in leakage currents between conductors and from individual conductors to ground. A reduction in IR is a concern for circuits with sensitive, low-level signals such as radiation monitoring and nuclear instrumentation since it may contribute to inaccuracies in the instrument loop.This AMP uses routine calibration tests performed as part of the plant surveillance test programto identify the potential existence of aging degradation. When an instrumentation loop is foundto be out of calibration during routine surveillance testing, troubleshooting is performed on the loop, including the instrumentation cable. In cases in which a calibration or surveillance programdoes not include the cabli ng system in the testing circuit, or as an alternative to the review ofcalibration results described above, the applicant will perform cable system testing. Plant staffwill perform a proven cable system test for detecting deterioration of the insulation system (such as IR tests, time domain reflectometry test, or other testing judged to be effective in determining cable insulation condition).Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's audit evaluation of this AMP. The staff reviewed the exceptions and the associated justifications todetermine whether the AMP, with the exceptions, remains adequate to manage the agingeffects for which it is credited.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.E2.In the LRA, the applicant stated the following exception to the program elements listed for AMPXI.E2 in the GALL Report.Exception: The GALL Report identifies the following criteria for the Parameters Monitored orInspected, Detection of Aging Effects, and Acceptance Criteria program elements associated with the exception taken:Parameters Monitored/Inspected:The parameters monitored are determined from the plant technicalspecifications and are specific to the instrumentation loop being calibrated, as documented in the surveillance testing procedure.

3-93Detection of Aging Effects:Calibration provides sufficient indication of the need for correctiveactions by monitoring key parameters and providing trending data based on acceptance criteria related to instrumentation loop performance. The normal calibration frequency specified in the plant technical specifications provides reasonable assurance that severe aging degradation will be detected prior to loss of the cable int endedfunction. The first tests for license renewal are to be completed before the period of extended operation.Acceptance Criteria:Calibration readings are to be within the loop-specific acceptancecriteria, as set out in the plant technical specifications surveillance test procedures.In the LRA, the applicant stated that the surveillance tests required by its TS either do notinclude all cables within the scope of license renewal or do not include the cable as part of the calibration procedure. The program will periodically test the cable insulation condition for thosecables not already tested by TS requirements.The applicant further stated that for those cables not tested as part of TS surveillanceprocedures, the program will periodically test the cable insulation. The staff reviewed theapplicant's exception and found it acceptable because Interim Staff Guidance (ISG)-15 statesthat either (1) calibration results or findings of surveillance testing or (2) direct testing of cable systems can be used to detect aging degradation of electrical cables not subject to10 CFR 50.49 EQ requirements used in instrumentation circuits.On the basis of its review of the Electrical Cables Not Subject to 10 CFR 50.49 EQRequirements Used in Instrumentation Circuits Program and in conjunction with the operating experience, the staff found this exception acceptable.The staff reviewed those portions of the AMP B2.1.16, "Electrical Cables Not Subject to10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation CircuitsProgram," that the applicant claimed are consistent with GALL AMP XI.E2 and found themconsistent. The staff found the applicant's AMP acceptable because it conforms to the recommended GALL Report AMP with the exception as described above.Operating Experience. In LRA Section B2.1.16, the applicant stated that the Electrical CablesNot Subject to 10 CFR 50.49 EQ Requirements Used in Instrumentation Circuits Program is a new program and as such has no plant-specific operating experience; however, as noted in the GALL Report, industry operating experience shows that exposure of electrical cables to adverse local environments caused by heat or radiation result in reduced IR. Reduced IR causes an increase in leakage currents between conductors and from individual conductors to ground. A reduction in IR is a concern for circuits with sensitive, low-level signals like radiation monitoring and nuclear instrumentation circuits as it may contribute to signal inaccuracies.

3-94During the audit and review, the staff asked the applicant how it captures operating experience.The applicant stated that its CAP identifies, tr acks, and trends site operating experience with allsite components. The applicant documents any site component identified as degraded, failed, or potentially unable to fulfill intended functions in the site CAP database. Plant engineeringstaff then evaluate these CAPs for the extent of the condition and take appropriate followupactions. Plant engineering staff also trend related CAPs to identify generic issues. They address trended site issues in program health reports and present them to site management on a scheduled basis. The CAP also addresses 10 CFR 54.21 issues and external operating events from the NRC, INPO, LIS, and the applicant's fleet. The staff reviewed the applicant'sresponse and found it acceptable.The staff recognizes that the CAP, which captures internal and external plant operatingexperience issues, ensures review and incorporation of operating experience as objective evidence to support the conclusion that aging effects are adequately managed.USAR Supplement. In LRA Section A2.1.16, the applicant provided the USAR supplement forthe Electrical Cables Not Subject to 10 CFR 50.49 EQ Requirements Used in Instrumentation Circuits Program. The staff reviewed this section and determined that the information in the USAR supplement adequately describes the program, as required by 10 CFR 54.21(d).In its letter, dated June 10, 2005, the applicant included a commitment to USARSection A2.1.16, documented as commitment 27 in Table A.5, which states the following:Prior to the period of extended operation, the Electrical Cables Not Subject to10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits Program will be implemented as a new program. With exceptions, it will be consistent with the recommendations of NUREG-1801Chapter XI Program XI.E2.Conclusion. On the basis of its review and audit of the applicant's Electrical Cables Not Subjectto 10 CFR 50.49 EQ Requirements Used in Instrumentation Circuits Program, the staff determined that those program elements for which the applicant claimed consistency with theGALL Report are consistent with the GALL Report. In addition, the staff reviewed the exceptions and the associated justifications and determined that the AMP, with the exceptions,is adequate to manage the aging effects for which it is credited. The staff concluded that the applicant demonstrated that the effects of aging will be adequately managed so that intendedfunctions will be maintained consistent with the CLB for the period of extended operation, asrequired by 10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.2.15 Fire Protection Program Summary of Technical Information in the Application. In LRA Section B2.1.17, the applicantdescribed the Fire Protection Program, stating that this existing program is consistent, with exception and enhancement, with GALL AMP XI.M26, "Fire Protection." For license renewal purposes, the MNGP Fire Protection Program includes a fire barrier inspection program, a diesel-driven fire pump inspection program, and a halon fire suppression system inspection.The fire barrier inspection program requires periodic visual inspection of fire barrier penetration seals, fire barrier walls, ceilings, and floors, and periodic visual inspection and functional tests 3-95of associated fire rated doors to ensure that their operability is maintained. The diesel-drivenfire pump inspection program requires that the pump be periodically tested and the diesel engine inspected to ensure that the fuel supply line can perform the intended function. Thehalon fire suppression system inspection included periodic inspection and testing of the cablespreading room halon fire suppression system.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's audit evaluation of this AMP. The staff reviewed the exception and enhancement and the associatedjustifications to determine whether the AMP, with the exception and enhancement, remainsadequate to manage the aging effects for which it is credited.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.M26.In the LRA, the applicant stated the following exception to the program elements listed for AMPXI.M26 in the GALL Report.Exception: The GALL Report recommends the following for the Parameters Monitored andInspected program element associated with the exception taken:Periodic visual inspection and function test at least once every six monthsexamines the signs of degradation of the halon/carbon dioxide fire suppression system. The suppression agent charge pressure is monitored in the test.Material conditions that may affect the performance of the system, such ascorrosion, mechanical damage, or damage to dampers, are observed during these tests. Inspections performed at least once every month to verify that the extinguishing agent supply valves are open and the system is in automaticmode.In the LRA, the applicant stated that it conducts periodic visual inspections and function tests ofhalon systems at least once every 6 months. The cable spreading room halon system isfunctionally tested and visually inspected every 18 months instead of every 6 months as recommended in GALL AMP XI.M26.In LRA Section B2.1.17 and the associated basis document, the applicant provided itsjustification conducting these activities every 18 months instead of every 6. According to the applicant, the surveillance interval specified in the Operations Manual is part of the

NRC-approved Fire Protection Program, and thus forms an element of the plant's CLB. Inresponse to the staff interviews, the applicant's personnel provided further information, including the System Health Report-Fire Protection.The applicant's technical personnel stated that they reviewed industry operating experience, theprevious cable spreading room halon system surveillance test results, and plant-specificoperating experience for this subsystem. This review of operating experience revealed noage-related degradation, and thus the applicant stated that the 18-month frequency isacceptable.

3-96The staff interviewed the applicant about parameters monitored or inspected as part of fireprotection (FP) relative to the guidelines for the frequency of inspections. The applicant stated that the program has specific guidelines for the frequency of inspections requiring, for example, visual inspections of penetration seal fire area boundaries protecting safe-shutdown equipment every 18 months or following repair or maintenance of such penetrations. These inspections cover 10 percent of each type of seal, consistent with GALL Report recommendations. The staff also reviewed other inspection criteria for fire doors, the diesel driven fire pump, and the halon/carbon dioxide systems. Based on the staff's review of industry and plant-specificoperating experience, performance of surveillance tests, and the FP system health reports, theexception of the inspection frequency of 18 months instead of 6 months is acceptable, becausethe incubation period for the effect is long, and the different inspection frequencies did notresult in any differences in finding aging effects.In the LRA, the applicant stated that the following enhancement will make this AMP consistentwith the recommendation in the GALL Report.Enhancement: The GALL Report recommends the following for the Detection of Aging Effectsprogram element associated with the enhancement made:...If any sign of degradation is detected within that 10 percent, the scope of theinspection and frequency is expanded to ensure timely detection of increased hardness and shrinkage of the penetration seal before the loss of the component intended function. Visual inspection (VT-1 or equivalent) of the fire barrier walls, ceilings, and floors performed in walkdown at least once every refueling outage ensures timely detection for concrete cracking, spalling, and loss of material.

Visual inspection (VT-3 or equivalent) detects any sign of degradation of the fire door such as wear and missing parts...In the LRA, the applicant stated that it will revise its existing Fire Protection Program cablespreading room halon visual inspection procedure to include inspection for any signs of degradation such as corrosion and mechanical damage. This visual inspection will m anageaging for external surfaces of the cable spreading room halon fire suppression system. Theapplicant will revise the Fire Protection Program plan document to include qualification criteriafor individuals visually inspecting penetration seals, fire barriers, and fire doors. The qualification criteria will be in accordance with VT-1 or equivalent and VT-3 or equivalent, asapplicable.The staff's evaluation and review of plant-specific operating experience found the enhancementto the Fire Protection Program to detect signs of aging by including qualification criteria for inspection personnel and VT-1 and VT-3 inspections of the penetration seals, fire barriers, and fire doors to be acceptable and consistent with the GALL Report for this AMP, which willmanage aging during the period of extended operation.On the basis of the staff evaluation of the above enhancement and review of the operatingexperience for the Fire Protection Program, the staff found this enhancement acceptable as such changes to the applicant's program provide assurance that the effects of aging will beadequately managed.

3-97The staff reviewed those portions of AMP B2.1.17, "Fire Protection Program," that the applicantclaimed are consistent with GALL AMP XI.M26 and found them consistent. The staff found the applicant's AMP acceptable because it conforms to the recommended GALL Report AMP with the exception and enhancement as described above.Operating Experience. In LRA Section B2.1.17, the applicant explained that, through the use ofestablished plant surveillance and procedures, its staff inspects barriers and other features on aperiodic basis. Recent assessments have noted that the overall material condition is good. Forexample, the December 2000 self-assessment using industry guidance (NEI Self- Assessment Guide 99-05) concluded that the observed seals and fireproofing appeared to be in good condition. The applicant documents and resolves problems through the site CAP. It entered prior issues with program performance noted during the NRC 2002 inspection into the site CAPdatabase for assessment and resolution. MNGP implemented a number of extensive corrective actions to improve program performance, including improved identification and resolution of deficiencies. It performed an extensive self-assessment in March 2004 to evaluate progress and program compliance. Though some areas of vulnerability were noted for correction andcontinued focus, a number of program strengths were identified and the assessment concluded that the MNGP program is consistent with corporate directive requirements and had madesignificant progress in addressing the findings from the 2002 inspection.The staff reviewed the operating experience provided in the LRA and interviewed theapplicant's technical personnel to confirm that plant-specific operating experience revealed no degradation not bounded by industry experience.On the basis of its review of the above operating experience and discussions with theapplicant's technical personnel, the staff concluded that the applicant's Fire Protection Program will adequately manage the aging effects identified in the LRA for which this AMP is credited.USAR Supplement. In LRA Section A2.1.17, the applicant provided the USAR supplement forthe Fire Protection Program. The staff reviewed this section and determined that the information in the USAR supplement adequately describes the program, as required by 10 CFR 54.21(d).In its letter, dated June 10, 2005, the applicant included the following two commitments toSection A2.1.17, documented as commitments 28 and 29 in Table A.5, that it will implementbefore the period of extended operation:(1)The applicant will revise the Fire Protection Program to include a visual inspection of thehalon fire suppressi on system to detect any signs of degradation, such as corrosion, ormechanical damage. This visual inspection will manage aging for external surfaces ofthe halon fire suppression system.(2)The applicant will revise the Fire Protection Program to include qualification criteria forindividuals visually inspecting penetration seals, fire barriers, and fire doors. The qualification criteria will be in accordance with VT-1, VT-3, or equivalent as applicable.Conclusion. On the basis of its review and audit of the applicant's Fire Protection Program, thestaff determined that those program elements for which the applicant claimed consistency withthe GALL Report are consistent with the GALL Report. In addition, the staff reviewed the 3-98exception and the associated justifications and determined that the AMP, with the exception, isadequate to manage the aging effects for which it is credited. The staff also reviewed the enhancement and confirmed that its implementation before the period of extended operationwill result in the existing AMP being consistent with the GALL Report AMP to which it wascredited. The staff concluded that the applicant demonstrated that the effects of aging will beadequately managed so that intended functions will be maintained consistent with the CLB forthe period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.2.16 Fire Water System Program Summary of Technical Information in the Application. In LRA Section B2.1.18, the applicantdescribed the Fire Water System Program, stating that this existing program is consistent, with enhancement, with GALL AMP XI.M27, "Fire Water System." The Fire Water System Program relies on testing of water-based FP system piping and components in accordance withapplicable National Fire Protection Association (NFPA) recommendations. In addition, the applicant will modify this program to include (1) portions of the FP sprinkler system that aresubjected to full flow tests before the period of extended operation and (2) portions of the FP system exposed to water that are internally visually inspected. To ensure that the aging mechanisms of corrosion and biofouling/fouling are properly being managed in the fire water system, the applicant conducts periodic full flow flush tests and system performance tests. Thesystem is also normally maintained at required operating pressure and is monitored such thatloss of system pressure is immediately detected and corrective actions initiated.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's audit evaluation of this AMP. The staff reviewed the enhancement and the associated justifications todetermine whether the AMP, with the enhancement, remains adequate to manage the agingeffects for which it is credited.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.M27.In the LRA, the applicant stated that the following enhancement will make this AMP consistentwith the recommendation in the GALL Report.Enhancement: The GALL Report recommends the following for the Program Descriptionprogram element associated with the enhancement made:...In addition, a sample of sprinkler heads is to be inspected by using theguidance of NFPA 25, Section 2.3.3.1. This NFPA section states that 'wheresprinklers have been in place for 50 years, they shall be replaced or representative samples from one or more sample areas shall be submitted to a recognized testing laboratory for field service testing.' It also contains guidance to perform this sampling every 10 years after the initial field service testing...

3-99In the LRA, the applicant stated it will enhance the Fire Water System Program byimplementing procedures that will be revised to include the extrapolation of inspection results tobelow-grade fire water piping with conditions similar to those within the above-grade fire water piping. It will inspect and test the Fire Water System Program sprinkler heads or replace thembefore the end of the 50-year sprinkler head service life and at 10-year intervals thereafter during the extended period of operation to ensure that signs of degradation, such as corrosion,are detected promptly. Enhancements are scheduled for completion before the period ofextended operation.The staff found in its evaluation and review of plant-specific operating experience that theenhancement to the Fire Water System Program to detect signs of aging by wall thickness evaluations on above-grade piping, inspections before the period of extended operation, andextrapolations of above-ground conditions to below-ground piping for further inspections is acceptable and consistent with GALL Report recommendations relying on NFPA codes and with GALL AMP XI.M27.On the basis of its review of the above enhancement and review of operating experience for theMNGP Fire Water System Program, the staff found this enhancement acceptable as such changes to the applicant's program provides assurance that the effects of aging will beadequately managed.The staff reviewed those portions of AMP B2.1.18, "Fire Water System Program," that theapplicant claimed are consistent with GALL AMP XI.M27 and found them consistent. The staff found the applicant's AMP acceptable because it conforms to the recommended GALL Report AMP with the enhancement as described above.Operating Experience. In LRA Section B2.1.18, the applicant explained that through the use ofestablished plant surveillances and procedures, the fire water system is periodically inspected,tested, flushed, and maintained. It evaluates industry and plant experience for systemperformance impacts. The applicant documents performance issues and evaluates them through the site CAP. System availability has been good; only six cases of system impairmentfor more than 48 hours5.555556e-4 days <br />0.0133 hours <br />7.936508e-5 weeks <br />1.8264e-5 months <br />, in order to perform required maintenance, have occurred since October 1996. System unavailability is within Maintenance Rule program goals. The applicant alsoprovided an example of program activities. It conducted a FP system walkdown that reported that the system was in good condition but identified two areas of concern. First, the FP systemengineer trended greater than minimal packing leakage on the screenwash/fire pump. The applicant will perform repacking when necessary to resolve this issue. The second concern waswith a seal leak on the FP jockey pump. Plant staff replaced the mechanical seal under the work control process.The staff reviewed the operating experience provided in the LRA and interviewed theapplicant's technical personnel to confirm that plant-specific operating experience revealed no degradation not bounded by industry experience.On the basis of its review of the above operating experience and discussions with theapplicant's technical personnel, the staff concluded that the applicant's Fire Water SystemProgram will adequately manage the aging effects identified in LRA for which this AMP iscredited.

3-100USAR Supplement. In LRA Section A2.1.18, the applicant provided the USAR supplement forthe Fire Water System Program. The staff reviewed this section and determined that the information in the USAR supplement adequately describes the program, as required by 10 CFR 54.21(d).In its letter dated June 10, 2005, the applicant added the following three commitments to LRASection A2.1.18, documented as commitments 30, 31, and 32 in Table A.5, which the applicantwill perform before the period of extended operation: (1)The applicant will revise the implementing procedures for the Fire Water SystemProgram to include extrapolation of inspection results to below-grade fire water piping with conditions similar to those within above-grade fire water piping. (2)Sprinkler heads will be inspected and tested in accordance with NFPA requirements orreplaced before the end of their 50-year service life and at 10-year intervals thereafter during the extended period of operation to ensure that degradation, such as corrosion, isdetected promptly. Procedures to be used for aging management activities (AMAs) of the Fire Water System Program will be verified and testing will be performed inaccordance with applicable NFPA codes and standards. The applicant will reviserelevant procedures as appropriate. (3)The applicant will verify that the procedures to be used for AMAs of the fire watersystem apply testing in accordance with the applicable NF PA codes and standards. Itwill revise the relevant procedures as appropriate.Conclusion. On the basis of its review and audit of the applicant's Fire Water System Program,the staff determined that those program elements for which the applicant claimed consistencywith the GALL Report are consistent with the GALL Report. In addition, the staff reviewed theenhancement and confirmed that its implementation before the period of extended operationwill result in the existing AMP being consistent with the GALL Report AMP to which it wascredited. The staff concluded that the applicant demonstrated that the effects of aging will beadequately managed so that intended functions will be maintained consistent with the CLB forthe period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.2.17 Fuel Oil Chemistry Program Summary of Technical Information in the Application. In LRA Section B2.1.20, the applicantdescribed the Fuel Oil Chemistry Program, stating that this existing program is consistent, with exceptions and enhancements, with GALL AMP XI.M30, "Fuel Oil Chemistry." The Fuel Oil Chemistry Program mitigates and manages aging effects on the internal surfaces of diesel fuel oil storage tanks and associated components in systems that contain diesel fuel oil. Theprogram includes (1) surveillance and monitoring procedures for maintaining diesel fuel oilquality by controlling contaminants in accordance with applicable ASTM standards, (2) periodic draining of water from diesel fuel oil tanks, if water is present, (3) periodic or conditional visual inspection of internal surfaces or wall thickness measurements (e.g., by UT) from external surfaces of diesel fuel oil tanks, and (4) one-time inspections of a representative sample of components in systems that contain diesel fuel oil.

3-101Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP 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 staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.M30.In the LRA, the applicant stated the following exceptions to the program elements listed forAMP XI.M30 in the GALL Report.Exception 1: The GALL Report recommends the following for the Preventive Actions programelement associated with the exception taken:The quality of fuel oil is maintained by additions of biocides to minimize biologicalactivity, stabilizers to prevent biological breakdown of the diesel fuel, and corrosion inhibitors to mitigate corrosion. Periodic cleaning of a tank allows removal of sediments, and periodic draining of water collected at the bottom of a tank minimizes the amount of water and the length of contact time. Accordingly, these measures are effective in mitigating corrosion inside diesel fuel oil tanks.

Coatings, if used, prevent or mitigate corrosion by protecting the internal surfaces of the tank from contact with water and microbiological organisms.In the LRA, the applicant stated that its Fuel Oil Chemistry Program does not currently usebiocides, stabilizers, and corrosion inhibitors.The staff found this exception acceptable based on its review of various documents on site,including a comparison of ASTM standards with those recommended in the GALL Report, historical oil analyses, the PBD, and discussions with plant personnel. The review of the historical oil analyses and discussions with plant personnel showed that there had been no biological breakdown of fuel oil and that the oil purchased to ASTM D 975 requirements has remained stable and free of corrosion during storage and use. On the basis of the above review and review of plant-specific operating experience for the Fuel Oil Chemistry Program, the staff found this exception acceptable.Exception 2: The GALL Report recommends the following for the Parameters Monitored orInspected program element associated with the exception taken:The AMP monitors fuel oil quality and the levels of water and microbiologicalorganisms in the fuel oil, which cause the loss of material of the tank internal surfaces. The ASTM Standard D 4057 is used for guidance on oil sampling. The ASTM Standards D 1796 and D 2709 are used for determination of water and sediment contamination in diesel fuel. For determination of particulates, modifiedASTM D 2276, Method A, is used. The modification consists of using a filter with a pore size of 3.0 m, instead of 0.8 m. These are the principal parametersrelevant to tank structural integrity.

3-102In the LRA, the applicant stated that it does not use ASTM D 2709 or ASTM D 2276, but ASTMD 6217, "Test Method for Particulate Contamination in Middle Distillate Fuels by LaboratoryFiltration," as a laboratory test to sample diesel fuel oil for suspended particulates. This standard applies to the grade of diesel fuel oil and also uses the more conservative

0.8 micrometer

(m) filter pore size instead of the recommended 3.0 m.The staff found this exception acceptable based on its review of various documents on site,including a comparison of ASTM standards with those recommended in the GALL Report.

Review of ASTM D 6217 showed that this laboratory analysis of the fuel oil specifically applies to the grade of oil used, and the applicant uses a more conservative filter pore size than that recommended by the GALL Report. On the basis of the above review and its review of plant-specific operating experience for the Fuel Oil Chemistry Program, the staff found this exception acceptable.Exception 3: The GALL Report recommends the following for the Acceptance Criteria programelement associated with the exception taken:The ASTM Standard D 4057 is used for guidance on oil sampling. The ASTMStandards D 1796 and D 2709 are used for guidance on the determination of water and sediment contamination in diesel fuel. Modified ASTM D 2276, Method A is used for determination of particulates. The modification consists of using a filter with a pore size of 3.0 m, instead of 0.8 m.In the LRA, the applicant stated that it does not use ASTM D 2709 or ASTM D 2276, but usesASTM D 6217 as a laboratory test to sample diesel fuel oil for suspended particulates. This standard applies to the grade of diesel fuel oil used at MNGP and uses the more conservative

0.8 m filter pore size instead of the recommended 3.0 m.The staff found this exception acceptable based on its review of various documents on site,including a comparison of ASTM standards with those recommended in the GALL Report.

Review of ASTM D 1796 showed that it specifically applies to the type of diesel fuel used and contains the necessary and sufficient requirements for sampling for sediment and water.

Additionally, a review of ASTM D 6217 showed that it contains test parameters, performed by an offsite laboratory, equivalent to ASTM D 2276 recommended in the GALL Report. On the basis of the above review and its review of plant-specific operating experience for the Fuel Oil Chemistry Program, the staff found this exception acceptable.In the LRA, the applicant stated that the following enhancements will make this AMP consistentwith the recommendation in the GALL Report.Enhancement 1: The GALL Report recommends the following for the Scope of Programprogram element associated with the enhancement made:The program is focused on managing the conditions that cause general, pitting,and microbiologically influenced corrosion (MIC) of the diesel fuel tank internal surfaces. The program serves to reduce the potential of exposure of the tank internal surface to fuel oil contaminated with water and microbiological organisms.

3-103In the LRA, the applicant stated that it will revise the procedures for the diesel fuel oil system toinclude requirements to check for general, pitting, crevice, and galvanic corrosion, MIC, and cracking.The staff review of various documents on site, including a comparison of ASTM standards withthose recommended in the GALL Report, the PBD, and discussions with plant personnel determined that the requirements to check for general, pitting, crevice, and galvanic corrosion,MIC, and cracking will continually verify the effectiveness of the program. On the basis of theabove review and its review of plant-specific operating experience for the Fuel Oil Chemistry Program, the staff found this enhancement acceptable as such changes to the applicant's program provide assurance that the effects of aging will be adequately managed.Enhancement 2: The GALL Report recommends the following for the Preventive Actionsprogram element associated with the enhancement made:The quality of fuel oil is maintained by additions of biocides to minimize biologicalactivity, stabilizers to prevent biological breakdown of the diesel fuel, and corrosion inhibitors to mitigate corrosion. Periodic cleaning of a tank allows removal of sediments, and periodic draining of water collected at the bottom of a tank minimizes the amount of water and the length of contact time. Accordingly, these measures are effective in mitigating corrosion inside diesel fuel oil tanks.

Coatings, if used, prevent or mitigate corrosion by protecting the internal surfaces of the tank from contact with water and microbiological organisms.In the LRA, the applicant stated that it will revise its Fuel Oil Chemistry Program to require tankdraining, cleaning, and inspection if deemed necessary based on trends indicated by results of the diesel fuel oil analysis, or if recommended by the system engineer based on equipmentoperating experience.The staff review of various documents on site, including a comparison of ASTM standards withthose recommended in the GALL Report, the PBD, and discussions with plant personnel determined that these requirements (i.e., to provide tank draining, cleaning, and inspection ifdeemed necessary based on the trends indicated by the results of the diesel fuel oil analysis or as recommended by t he system engineer based on equipment operating experience) willprovide a continuing check on the effectiveness of the program. On the basis of the above review and its review of plant-specific operating experience for the Fuel Oil Chemistry Program, the staff found this enhancement acceptable as such changes to the applicant's program provide assurance that the effects of aging will be adequately managed.Enhancement 3: The GALL Report recommends the following for the Detection of AgingEffects program element associated with the enhancement made:Degradation of the diesel fuel oil tank cannot occur without exposure of the tankinternal surfaces to contaminants in the fuel oil, such as water and microbiological organisms. Compliance with diesel fuel oil standards in item 3, above, and periodic multilevel sampling provide assurance that fuel oil contaminants are below acceptable levels. Internal surfaces of tanks that are drained for cleaning are visually inspected to detect potential degradation.

However, corrosion may occur at locations in which contaminants may 3-104accumulate, such as a tank bottom, and an ultrasonic thickness measurement ofthe tank bottom surface ensures that significant degradation is not occurring.In the LRA, the applicant stated it will write a procedure or revise existing procedures in theMNGP Fuel Oil Chemistry Program to require periodic inspections of the diesel fuel oil tanks.The staff review of various documents on site, including a comparison of ASTM standards withthose described in the GALL Report, the PBD, and discussions with plant personnel, determined that the requirement to write or revise the Fuel Oil Chemistry Program proceduresto require periodic inspections of the diesel fuel oil tanks will be a continuing check on theeffectiveness of the program. The addition of periodic tank inspections will make the programconsistent with the recommendations of the GALL Report. On the basis of the above reviewand its review of plant-specific operating experience for the Fuel Oil Chemistry Program, the staff found this enhancement acceptable as such changes to the applicant's program provide assurance that the effects of aging will be adequately managed.The staff reviewed those portions of the AMP B2.1.20, "Fuel Oil Chemistry Program," that theapplicant claimed are consistent with GALL AMP XI.M30 and found them consistent. The staff found the applicant's AMP acceptable because it conforms to the recommended GALL Report AMP with the exceptions and enhancements as described above.Operating Experience. In LRA Section B2.1.20, the applicant explained that monthly andquarterly diesel fuel oil sampling and trending activities have confirmed the adequacy of the diesel fuel oil supply. Past tank cleanings and inspections have shown that the condition of the tanks has not degraded.The staff reviewed the operating experience provided in the LRA and interviewed theapplicant's technical personnel to confirm that plant-specific operating experience revealed no degradation not bounded by industry experience.On the basis of its review of the above industry and plant-specific operating experience anddiscussions with the applicant's technical personnel, the staff concluded that the Fuel Oil Chemistry Program will adequately manage the aging effects identified in the LRA for which thisAMP is credited.USAR Supplement. In LRA Section A2.1.20, the applicant provided the USAR supplement forthe Fuel Oil Chemistry Program. The staff reviewed this section and determined that the information in the USAR supplement adequately describes the program, as required by 10 CFR 54.21(d).In its letter dated June 10, 2005, the applicant included commitments to LRA Section A2.1.20,documented as commitments 33, 34, and 35 in Table A.5, to perform the following before theperiod of extended operation: (1)The applicant will revise its procedures related to the diesel fuel oil system to includerequirements to check for general, pitting, crevice, and galvanic corrosion, MIC, and cracking.

3-105 (2)The applicant will revise its Fuel Oil Chemistry Program procedures to require tankdraining, cleaning, and inspection if deemed necessary based on the trends indicated by the results of the diesel fuel oil analysis, or as recomm ended by the system engineerbased on equipment operating experience. (3)The applicant will develop or revise procedures for the MNGP Fuel Oil ChemistryProgram to require periodic inspections of the diesel fuel oil tanks.Conclusion. On the basis of its review and audit of the applicant's Fuel Oil Chemistry Program,the staff determined that those program elements for which the applicant claimed consistencywith the GALL Report are consistent with the GALL Report. In addition, the staff reviewed theexceptions and the associated justifications and determined that the AMP, with the exceptions,is adequate to manage the aging effects for which it is credited. The staff also reviewed the enhancements and confirmed that their implementation before the period of extended operationwill result in the existing AMP being consistent with the GALL Report AMP to which it wascredited. The staff concluded that the applicant demonstrated that the effects of aging will beadequately managed so that intended functions will be maintained consistent with the CLB forthe period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.2.18Inspection of Overhead Heavy Load and Light Load (Related to Refueling) HandlingSystems ProgramSummary of Technical Information in the Application. In LRA Section B2.1.22, the applicantdescribed the Inspection of Overhead Heavy Load and Light Load (Related to Refueling)

Handling Systems Program, stating that this existing program is consistent, with exception and enhancement, with GALL AMP XI.M23, "Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems." The Inspection of Overhead Heavy Load & Light Load (Related to Refueling) Handling Systems Program, which the applicant implements through plant procedures and PM, manages loss of material of structural components for heavy load and fuel handling components within the scope of license renewal. The Inspection of Overhead Heavy Load & Light Load (Related to Refueling) Handling Systems Program provides for visual and NDE inspections of load-handling components within the scope of license renewal. The applicant also performs functional tests to assure their integrity. The cranes also comply with the Maintenance Rule requirements provided in 10 CFR 50.65, "Requirements forMonitoring the Effectiveness of Maintenance at Nuclear Power Plants."Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's audit evaluation of this AMP. The staff reviewed the exception and enhancement and the associatedjustifications to determine whether the AMP, with the exception and enhancement, remainsadequate to manage the aging effects for which it is credited.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.M23.

3-106In the LRA, the applicant stated the following exception to the program elements listed for AMPXI.M23 in the GALL Report.Exception: The GALL Report recommends the following for the Parameters Monitored orInspected program element associated with the exception taken:The program evaluates the effectiveness of the maintenance monitoringprogram and the effects of past and future usage on the structural reliability ofcranes. The number and magnitude of lifts made by the crane are also reviewed.In the LRA, the applicant stated, except for special lifts made by the turbine building crane, itsprogram does not track the number and size of lifts because administrative controls ensure that only allowable loads are handled, and fatigue failure of structural elements is not expected with the limited number of lifts.The staff reviewed information on the reactor building crane that notes that it has the designcapacity for many more lifts at a higher rated tonnage than are expected to take place over its 60-year life. Additionally, the applicant informed the staff that it also performs inspections and functional che cks on the other cranes periodically and before use. The applicant also providedoperating experience showing no degradation caused by aging since plant startup. The staff found this exception acceptable based on its review of information that demonstrates the design capabilities of the reactor building crane and the required inspections before the operation ofother cranes, and review of operating experience.In the LRA, the applicant stated that the following enhancement will make this AMP consistentwith the recommendation in the GALL Report.Enhancement: The GALL Report recommends the following for Detection of Aging Effectsprogram element associated with the enhancement made:Crane rails and structural components are visually inspected on a routine basisfor degradation. Functional tests are also performed to assure their integrity.The applicant will enhance the program to specify a 5-year inspection frequency for the fuelpreparation machines.The staff review of various documents on site, including a comparison of the GALL Reportrecommendations with the proposed enhancements, the PBD, and discussions with plant personnel, determined that this requirement, a 5-year inspection frequency for the fuel preparation machines, continually verifies the effectiveness of the program. The 5-year frequency is acceptable as operating experience shows no degradation caused by aging since installation; therefore, any aging mechanisms appear to act slowly. The addition of a specified period for fuel preparation machine inspection ensures that each component is visually inspected routinely for degradation and conforms with the recommendation in the GALL Report.On the basis of the above review and a review of operating experience for the AMP, the stafffound this enhancement acceptable as such changes to the applicant's program provide assurance that the effects of aging will be adequately managed.

3-107The staff reviewed those portions of AMP B2.1.22, "Inspection of Overhead Heavy Load andLight Load (Related to Refueling) Handling Systems Program," that the applicant claimed areconsistent with GALL AMP XI.M23 and found them consistent. The staff found the applicant'sAMP acceptable because it conforms to the recommended GALL Report AMP with the exception and enhancement as described above.Operating Experience. In LRA Section B2.1.22, the applicant explained that no incidents offailure of passive components for cranes and special lifting devices because of aging have occurred at MNGP. The inspection activities have detected and managed aging effects in crane and special lifting device components. A magnetic particle inspection of the dryer and steam separator sling found a linear indication, which was repaired before to use. An inspection of the reactor vessel head lifting device noted some minor degradation, which, in accordance with procedure, was repaired and painted.The staff reviewed the operating experience provided in the LRA and interviewed theapplicant's technical personnel to confirm that plant-specific operating experience revealed no degradation not bounded by industry experience.On the basis of its review of the above industry and plant-specific operating experience anddiscussions with the applicant's technical personnel, the staff concluded that the Inspection ofOverhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program willadequately manage the aging effects identified in the LRA for which this AMP is credited.USAR Supplement. In LRA Section A2.1.22, the applicant provided the USAR supplement forthe Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program. The staff reviewed this section and determined that the information in the USAR supplement adequately describes the program, as required by 10 CFR 54.21(d).In its letter dated June 10, 2005, the applicant included a commitment to LRA Section A2.1.22,documented as commitment 37 in Table A.5, that before the period of extended operation, theapplicant will enhance the Inspection of Overhead Heavy Load & Light Load (Related toRefueling) Handling Systems Program to specify a 5-year inspection frequency for the fuel preparation machines.Conclusion. On the basis of its review and audit of the applicant's Inspection of OverheadHeavy Load and Light Load (Related to Refueling) Handling Systems Program, the staff determined that those program elements for which the applicant claimed consistency with theGALL Report are consistent with the GALL Report. In addition, the staff reviewed the exceptionand the associated justifications and determined that the AMP, with the exception, is adequateto manage the aging effects for which it is credited. The staff also reviewed the enhancement and confirmed that its implementation before the period of extended operation will result in theexisting AMP being consistent with the GALL Report AMP to which it was credited. The staff concluded that the applicant demonstrated that the effects of aging will be adequately managedso that intended functions will be maintained consistent with the CLB for the period of extendedoperation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).

3-1083.0.3.2.19 Plant Chemistry ProgramSummary of Technical Information in the Application. In LRA Section B2.1.25, the applicantdescribed the Plant Chemistry Program, stating that this existing program is consistent, with exceptions, with GALL AMP XI.M2, "Water Chemistry." The MNGP Plant Chemistry Program mitigates the aging effects on component surfaces that are exposed to water as the process fluid; chemistry programs are used to control water chemistry for impurities (e.g., chloride and sulfate) that accelerate corrosion or crack initiation and growth and that cause heat transfer degradation due to fouling in select heat exchangers. This program relies on monitoring and control of water chemistry to keep peak levels of various contaminants below system-specificlimits based on BWRVIP-130". This document supersedes previous revisions of the BWR water chemistry guidelines, including BWRVIP-29. For low-flow or stagnant portions of a system, aone-time inspection of selected components at susceptible locations provides verification of the effectiveness of the Plant Chemistry Program.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's audit evaluation of this AMP. The staff reviewed the exceptions and the associated justifications todetermine whether the AMP, with the exceptions, remains adequate to manage the agingeffects for which it is credited.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.M2.In the LRA, the applicant stated the following exceptions to the program elements listed forAMP XI.M2 in the GALL Report.Exception 1: The GALL Report recommends the following for the Scope of Program elementassociated with the exception taken:The program includes periodic monitoring and control of known detrimentalcontaminants such as chlorides, fluorides (PWRs only), dissolved oxygen, and sulfate concentrations below the levels known to result in loss of material or crack initiation and growth. Water chemistry control is in accordance with the guidelines in BWRVIP-29 (EPRI TR-103515) for water chemistry in BWRs; EPRI TR-105714, Rev. 3, for primary water chemistry in PWRs; EPRI TR102134, Rev. 3, for secondary water chemistry in PWRs; or later revisions or updates of these reports as approved by the staff.In the LRA, the applicant stated that the Plant Chemistry Program uses BWRVIP-130, whichsupersedes previous revisions of the BWR water chemistry guidelines, including BWRVIP-29.Based on technical analysis, the staff found the provisions of Revision 2 of BWRVIP-29, issuedin 2000, acceptable based on updated industry experience. BWRVIP-130 is the current updateof the BWR water chemistry guidelines and supersedes BWRVIP-29, Revision 2. BWRVIP-130 is based on updated industry experience with increased emphasis on fuel performance concerns, while retaining the chemistry parameters, action levels, and associated measurement frequencies essentially unchanged.

3-109LRA Section B2.1.25 states that this program has one exception in that the Plant ChemistryProgram uses the 2004 revision, not the 1993, 1996, or 2000 revisions, of the EPRI BWR waterchemistry guidelines. BWRVIP-130 replaced BWRVIP-29, Revision 2. The applicant stated that the new program incorporates updated industry experience with increased focus on fuel performance, while retaining the chemistry parameters, action levels, and associated measurement frequencies essentially unchanged. The staff interviewed the applicant regarding the relationship of the existing Plant Chemistry Program and the elements of BWRVIP-130 to the 2000 revision of the BWR water chemistry guidelines. The applicant stated that the PlantChemistry Program has the elements of BWRVIP-29 and incorporates updated guidelines based on industry experience. The staff comparison of the EPRI 2000 revision of the guidelines against the EPRI 2004 revision used by the applicant also shows that the guideline wasupdated to show industry experience.The staff determined from the documentation of these chemistry revisions that the adoption ofthe 2004 revision (BWRVIP-130) resulted in no significant changes to critical program elements, and that the revision includes updates to the technical basis and guidance to reflect additional industry experience with increased focus on fuel performance, while retaining the same chemistry parameters, action levels, and associated measurement frequencies.

Therefore, the staff found the exception acceptable.Exception 2: The GALL Report recommends the following for the Parameters Monitored orInspected program elements associated with the exception taken:BWR Water Chemistry: The guidelines in BWRVIP-29 (EPRI TR-103515) forBWR reactor water recommend that the concentration of chlorides, sulfates, and dissolved oxygen are monitored and kept below the recommended levels to mitigate corrosion. The two impurities, chlorides and sulfates, determine the coolant conductivity; dissolved oxygen, hydrogen peroxide, and hydrogen determine electrochemical potential (ECP). The EPRI guidelines recommend that the coolant conductivity and ECP are also monitored and kept below the recommended levels to mitigate SCC and corrosion in BWR plants. The EPRI guidelines in BWRVIP-29 (TR-103515) for BWR feedwater, condensate, and control rod drive water recommends that conductivity, dissolved oxygen level, and concentrations of iron and copper (feedwater only) are monitored and kept below the recommended levels to mitigate SCC. The EPRI guidelines in BWRVIP-29 (TR-103515) also include recommendations for controlling waterchemistry in auxiliary systems: torus/pressure suppression chamber, condensatestorage tank, and spent fuel pool.In the LRA, the applicant stated the Plant Chemistry Program does not measure hydrogenperoxide. Instead, plant staff perform site-specific radiolysis modeling. As noted in BWRVIP-130, reliable measurements of hydrogen peroxide are exceptionally difficult to obtain, and concentration can be estimated from radiolysis models.The staff interviewed the applicant for technical justification for its initial use of reactor vendormodels as the basis for hydrogen water chemistry. Since then, EPRI had developed a software program, known as the BWR Vessel and Internals Application, as part of the BWRVIP now used for radiolysis and ECP monitoring for specific regions inside the reactor vessel. Results from this model have been compared to prior reactor vendor models to confirm appropriate 3-110application of the software modeling applications. The applicant runs the model at least twiceduring each operating cycle to account for changes in reactor flux and core flow on modelresults.The staff found in its evaluation and review of plant-specific operating experience that theexception to the Plant Chemistry Program to use site-specific radiolysis modeling instead of measuring hydrogen peroxide is acceptable and consistent with the GALL Report because radiolysis models are acceptable for establishing hydrogen injection rates (to reduce oxidants in the RCS, and thus SCC) as established by EPRI guidelines for BWR vessel internals.On the basis of its review of the above exception and of operating experience for the PlantChemistry Program, the staff found this exception acceptable.The staff reviewed those portions of AMP B2.1.25, "Plant Chemistry Program," that theapplicant claimed are consistent with GALL AMP XI.M2 and found them consistent. The staff found the applicant's AMP acceptable because it conforms to the recommended GALL Report AMP with the exceptions as described above.Operating Experience. In LRA Section B2.1.25, the applicant explained that CRs/ARs areinitiated when water chemistry is found to be out of specification. Many of these conditions result from equipment or plant transient conditions (e.g., plant startup) that are resolved oncethe transient condition subsides. The time duration of these conditions is typically short and no evidence of detrimental equipment impacts could be found. Further, no examples of component functional failures due to corrosion, cracking, or heat transfer degradation resulting from inadequate chemistry control were identified. The applicant addressed industry experience related to IGSCC issues by replacing components with less susceptible materials, implementation of hydrogen water chemistry, and improvements in water chemistry standards.

It replaced the entire recirculation system piping, a number of safe ends connec ted to thereactor vessel, the jet pump holddown beam assemblies, and the shroud head bolts with materials less susceptible to IGSCC. No adverse trends in water chemistry control were identified based on a review of various chemistry performance indicators. Established procedural requirements for chemistry limits are based on EPRI and industry standards and routinely monitored by the site. Recent external and internal assessments have identified chemistry trending as a strength and personnel knowledge as good. These conclusions are based on a review of CAP issues on chemistry (and out of specification chemistry limits) from January 1, 1996, through May 1, 2004, recent external and internal Chemistry Department assessment results, system health reports, and chemistry performance indicators and trends.The staff reviewed the operating experience provided in the LRA and interviewed theapplicant's technical personnel to confirm that plant-specific operating experience revealed no degradation not bounded by industry experience.On the basis of its review of the above operating experience and discussions with theapplicant's technical personnel, the staff concluded that the applicant's Plant ChemistryProgram will adequately manage the aging effects identified in the LRA for which this AMP iscredited.USAR Supplement. In LRA Section A2.1.25, the applicant provided the USAR supplement forthe Plant Chemistry Program. The staff reviewed this section and determined that the 3-111information in the USAR supplement adequately describes the program, as required by10 CFR 54.21(d).Conclusion. On the basis of its review and audit of the applicant's Plant Chemistry Program, thestaff determined that those program elements for which the applicant claimed consistency withthe GALL Report are consistent with the GALL Report. In addition, the staff reviewed the exceptions and the associated justifications and determined that the AMP, with the exceptions,is adequate to manage the aging effects for which it is credited. The staff concluded that the applicant demonstrated that the effects of aging will be adequately managed so that intendedfunctions will be maintained consistent with the CLB for the period of extended operation, asrequired by 10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.2.20 Protective Coating Monitoring & Maintenance ProgramSummary of Technical Information in the Application. In LRA Section B2.1.27, the applicantdescribed the Protective Coating Monitoring & Maintenance Program, stating that this existingprogram is consistent, with enhancements, with GALL AMP XI.S8, "Protective Coating Monitoring and Maintenance Program." The Protective Coating Monitoring and Maintenance Program applies to Service Level 1 protective coatings inside containment to address the concerns of NRC GL 98-04, "Potential for Degradation of the Emergency Core Cooling Systemand the Containment Spray System after a Loss-of-Cooling Accident because of Construction and Protective Coating Deficiencies and Foreign Material in Containment," dated July 14, 1998.

The Protective Coating Monitoring & Maintenance Program prevents the degradation ofcoatings that could lead to the clogging of Emergency Core Cooling System (ECCS) suppression pool suction strainers. MNGP does not credit the Protective Coating Monitoring and Maintenance Program for the prevention of corrosion of carbon steel components. As outlined in the MNGP response to GL 98-04, the Protective Coating Monitoring and Maintenance Program is a comparable program for monitoring and maintaining protective coatings inside the primary containment and subject to the requirements of ANSI N101.4-1972,to the extent specified in ANSI N18.7-1976 and as modified by RG 1.54, "Service Level I, II, and III Protective Coatings Applied to Nuclear Power Plants," issued June 1973.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's audit evaluation of this AMP. The staff reviewed the enhancements and the associated justificationsto determine whether the AMP, with the enhancements, remains adequate to manage the agingeffects for which it is credited.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part,documents cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.S8.In the LRA, the applicant stated that the following enhancements will make this AMP consistentwith the recommendation in the GALL Report.Enhancement 1: The GALL Report recommends the following for the Scope of Programprogram element associated with the enhancement made:

3-112The minimum scope of the program is Service Level 1 coatings, defined inRG 1.54, Rev 1, as follows: "Service Level 1 coatings are used in areas inside the reactor containment where the coating failure could adversely affect the operation of post-accident fluid systems and thereby impair safe shutdown."In the LRA, the applicant stated that it will update the MNGP Protective Coating Monitoring &Maintenance Program to include inspection of all accessible painted surfaces inside containments.The staff noted that the GALL Report states that a comparable program for monitoring andmaintaining protective coatings inside containments, developed in accordance with RG 1.54, Revision 0, or the ANSI standards (since withdrawn) referenced in RG 1.54, Revision 0, and coatings maintenance programs described in licensee responses to GL 98-04, is also acceptable as an AMP for license renewal. The applicant's program is a "comparable program,"

as defined above. The staff determined that this enhancement (i.e., requiring an inspection of all accessible painted surfaces inside containment) makes the program consistent with theGALL Report recommendation of Service Level 1 coatings as defined in RG 1.54, Revision 1.

On the basis of the above review and its review of operating experience for the Protective Coating Monitoring & Maintenance Program, the staff found the enhancement acceptable assuch changes to the applicant's program provide assurance that the effects of aging will beadequately managed.Enhancement 2: The GALL Report recommends the following for the Detection of AgingEffects program element associated with the enhancement made:ASTM D 5163-96, paragraph 5, defines the inspection frequency to be eachrefueling outage or during other major maintenance outages as needed.

ASTM D 5163-96, paragraph 8, discusses the qualifications for inspection personnel, the inspection coordinator, and the inspection results evaluator.

ASTM D 5163-96, subparagraph 9.1, discusses development of the inspection plan and the inspection methods to be used. It states, "A general visual inspection shall be conducted on all readily accessible coated surfaces during a walk-through. After a walk-through, thorough visual inspections shall be carried out on previously designated areas and on areas noted as deficient during the walk-through. A thorough visual inspection shall also be carried out on all coatings near sumps or screens associated with the Emergency Core Cooling System (ECCS)." This subparagraph also addresses field documentation of inspection results. ASTM D 5163-96, subparagraph 9.5, identifies instruments and equipment needed for inspection.In the LRA, the applicant stated that before the period of extended operation, all coatinginspectors will meet the requirements of ANSI N45.2.6, "Qualification of Inspection,Examination, and Testing Personnel for the Construction Phase of Nuclear Power Plants."The staff review noted that the relevant ASTM standard requires that coating inspectors bequalified in accordance with ANSI N45.2.6 or the ASTM requirements. The staff queried the applicant about the qualification requirement for inspectors. The applicant agreed to add this enhancement. By letter dated August 11, 2005, the applicant stated that before the period ofextended operation all coating inspectors will meet ANSI N45.2.6 requirements. The staff 3-113determined that this enhancement (i.e., requiring all coating inspectors to be qualified inaccordance with ANSI N45.2.6) makes this program consistent with the GALL Report recommendation of qualification under the requirements in paragraph 8 of ASTM D 5163-96, "Standard Guide for Establishing Procedures To Monitor the Performance of Safety Related Coatings in an Operating Nuclear Power Plant," for inspection personnel, inspection coordinators, and inspection results evaluators. On the basis of the above review and its review of operating experience for the Protective Coating Monitoring & Maintenance Program, the stafffound this enhancement acceptable as such changes to the applicant's program provide assurance that the effects of aging will be adequately managed.Enhancement 3: The GALL Report recommends the following for the Monitoring and Trendingprogram element associated with the enhancement made:ASTM D 5163-96 identifies monitoring and trending activities insubparagraph 6.2, which specifies a pre-inspection review of the previous two monitoring reports, and in subparagraph 10.1.2, which specifies that the inspection report should prioritize repair areas as either needing repair during the same outage or postponed to future outages, but under surveillance in theinterim period.In the LRA, the applicant stated it will include a preinspection review of the previous twoinspection reports to identify trends.The staff review has determined that this enhancement (i.e., a preinspection review of theprevious two inspection reports to identify trends) makes this program consistent with the GALL Report recommendation above. On the basis of the above review and its review of operating experience for the Protective Coating Monitoring & Maintenance Program, the staff found this enhancement acceptable as such changes to the applicant's program provide assurance that the effects of aging will be adequately managed.Enhancement 4: The GALL Report recommends the following for the Acceptance Criteriaprogram element associated with the enhancement made:ASTM D 5163-96, subparagraphs 9.2.1 thr ough 9.2.6, 9.3, and 9.4, containguidance for characterization, documentation, and testing of defective or deficient coating surfaces. Additional ASTM and other recognized test methods are identified for use in characterizing the severity of observed defects and deficiencies. The evaluation covers blistering, cracking, flaking, peeling, delamination, and rusting. ASTM D 5163-96, paragraph 11, addresses evaluation. It specifies that the inspection report is to be evaluated by the responsible evaluation personnel, who prepare a summary of findings and recommendations for future surveillance or repair, including an analysis ofreasons or suspected reasons for failure. Repair work is prioritized as major or minor defective areas. A recommended corrective action plan is required for major defective areas so that these areas can be repaired during the same outage, if appropriate.In the LRA, the applicant stated that it will revise the AMP implementation procedures to includeanalysis of suspected reasons for coating failure.

3-114The staff review determined that this enhancement (i.e., revising implementation procedures toinclude analysis of suspected reasons for coating failure) makes this program consistent with the GALL Report recommendation. On the basis of the above review and its review of operatingexperience for the Protective Coating Monitoring & Maintenance Program, the staff found this enhancement acceptable as such changes to the applicant's program provide assurance that the effects of aging will be adequately managed.The staff reviewed those portions of AMP B2.1.27, "Protective Coating Monitoring andMaintenance Program," that the applicant claimed are consistent with GALL AMP XI.S8 andfound them consistent. The staff found the applicant's AMP acceptable because it conforms to the recommended GALL Report AMP with the enhancements as described above.Operating Experience. In LRA Section B2.1.27, the applicant explained that it does not relyupon the Protective Coating Monitoring & Maintenance Program to manage the loss of material due to corrosion of carbon steel structural elements. Therefore, only the operating experience concerned with degradation of coatings and their consequential clogging of the ECCS strainersis of importance. Since there currently are no coating inspection requirements for allcomponents inside containment, the only inspection experience to date is from those inspections of the drywell and torus shells. Inspections of the drywell and torus shell have identified the following signs of paint degradation-chipping, rusting, peeling, blistering,cracking, and other signs of degradation. All unacceptable coating degradation has beenrepaired or in the case of the torus is scheduled for repair during the next torus draining. These inspections have detected and evaluated aging effects before the loss of intended function of the ECCS suction strainers. Where applicable, the applicant made repairs to minimize further degradation of the coatings, which may lead to clogging of the ECCS suction strainers.The staff reviewed the operating experience provided in the LRA and interviewed theapplicant's technical personnel to confirm that plant-specific operating experience revealed no degradation not bounded by industry experience.On the basis of its review of the above industry and plant-specific operating experience anddiscussions with the applicant's technical personnel, the staff concluded that the ProtectiveCoating Monitoring & Maintenance Program will adequately manage the aging effects identifiedin the LRA for which this AMP is credited.USAR Supplement. In LRA Section A2.1.27, the applicant provided the USAR supplement forthe Protective Coating Monitoring & Maintenance Program. The staff reviewed this section and determined that the information in the USAR supplement adequately describes the program, asrequired by 10 CFR 54.21(d).In its letter dated June 10, 2005, the applicant included the commitments to USARSection A2.1.27, documented as commitments 39, 40, and 41 in Table A.5, which the applicantwill complete before the period of extended operation: (1)The applicant will update procedures to include inspection of all accessible paintedsurfaces inside containment. (2)The applicant will revise the program to include a preinspection review of the previoustwo inspection reports so that trends can be identified.

3-115 (3)The applicant will revise implementation procedures to include provisions for analysis ofsuspected reasons for coating failure.In a letter dated August 11, 2005, the applicant provided a new commitment, stating that beforethe period of extended operation, coating inspectors will meet ANSI N45.2.6 requirements.Conclusion. On the basis of its review and audit of the applicant's Protective Coating Monitoring& Maintenance Program, the staff determined that those program elements for which theapplicant claimed consistency with the GALL Report are consistent with the GALL Report. Inaddition, the staff reviewed the enhancements and confirmed that their implementation beforethe period of extended operation will result in the existing AMP being consistent with the GALLReport AMP to which it was credited. The staff concluded that the applicant demonstrated thatthe effects of aging will be adequately managed so that intended functions will be maintainedconsistent with the CLB for the period of extended operation, as required by10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.2.21 Reactor Vessel Surveillance Program Summary of Technical Information in the Application. In LRA Section B2.1.29, the applicantdescribed the Reactor Vessel Surveillance Program, stating that this existing program isconsistent, with enhancement, with GALL AMP XI.M31, "Reactor Vessel Surveillance."The applicant stated that the Reactor Vessel Surveillance Program is part of the BWRVIPIntegrated Surveillance Program (ISP) that uses data from BWR member surveillance programs to select the "best" representative material for monitoring radiation embrittlement for a particular plant. The BWRVIP ISP monitors capsule test results from various member plants.The program was implemented to comply with Appendix H, "Reactor Vessel MaterialSurveillance Program Requirements," to 10 CFR Part 50. The BWRVIP ISP guidance describes the scope of the Reactor Vessel Surveillance Program. BWRVIP-86-A, "BWR Vessel andInternals Project: BWR Integrated Surveillance Program (ISP) Implementation," includes the ISP capsule removal schedule, and BWRVIP-78, "BWR Vessel and Internals Project: BWR Integrated Surveillance Program (ISP) Plan," describes its technical basis.The applicant stated in the Detection of Aging Effects program element of the Reactor VesselSurveillance Program that the ISP performs Charpy V-notch testing on specimens to measure the applicable aging effect, loss of fracture toughness. The applicant further stated that the Reactor Vessel Surveillance Project uses the BWRVIP ISP to monitor the effect of irradiation on the vessel.Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the information inLRA Section B2.1.29 about the applicant's demonstration of the Reactor Vessel SurveillanceProgram to ensure that the effects of aging will be adequately managed so that intendedfunctions will be maintained consistent with the CLB throughout the period of extendedoperation.Appendix H to 10 CFR Part 50 provides the NRC's requirements for implementing surveillanceprograms required for a plant's reactor vessel beltline materials. The programs are used to 3-116monitor for any changes in fracture toughness properties of a plant's reactor vessel beltlinebase metal and weld materials from neutron irradiation during the plant's service lifetime.Section III.C of Appendix H to 10 CFR Part 50 provides the specific requirements forimplementation of an ISP.The BWRVIP has developed an ISP for the reactor vessel base metal and weld materials in alloperating BWRs. The BWRVIP ISP is in proprietary topical reports BWRVIP-78, "BWR Integrated Surveillance Program (ISP) Plan," and BWRVIP-86, "BWR Vessel and Internals Project: BWR Integrated Surveillance Program (ISP) Implementation." The NRC approvedthese proprietary reports applying the design and implementation of the ISP by BWRs during their first 40-year operating period in its February 1, 2002, final safety evaluation report to the BWRVIP.The BWRVIP issued proprietary topical report BWRVIP-116, "BWR Vessel and InternalsProject Integrated Surveillance Program (ISP) Implementation for License Renewal," to address ISP changes necessary for LRAs for operating BWRs. This report was approved by the NRC ina letter dated March 1, 2006, from M.A. Mitchell (NRC) to B. Eaton (BWRVIP).The applicant identified the Reactor Vessel Surveillance Program as an existing ISP designedto comply with the requirements for ISPs in Appendix H to 10 CFR Part 50 and to conform with recommended guidelines in GALL AMP XI.M31. The applicant stated that USAR supplement Section A2.1.29 describes the Reactor Vessel Surveillance Program.The applicant stated that it based the Reactor Vessel Surveillance Program on the BWRVIPISP as described and discussed in BWRVIP-78 and BWRVIP-86. The ISP provides for a number of surveillance capsules to be removed from specified BWRs and to be available for testing during the license renewal period for the BWR fleet. The ISP establishes acceptable technical criteria for capsule withdrawal and testing.The staff approved the application of the BWRVIP ISP to the applicant's reactor vessel in theApril 22, 2003, SE, in which the staff concurred that the BWRVIP ISP, as approved inBWRVIP-78 and BWRVIP-86-A (the staff-approved version of BWRVIP-86), met requirements in Appendix H to 10 CFR Part 50 for the RPV.Proprietary topical reports BWRVIP-78 and BWRVIP-86-A, the staff's February 1, 2002,generic final safety evaluation report, and the staff's April 22, 2003, SE provide an acceptable basis for approving the Reactor Vessel Surveillance Program for the current operating period.To address the impacts of license renewal on the program, the applicant will enhance the AMPthrough the period of extended operation.The applicant stated that the BWRVIP ISP has been enhanced to address the impact of licenseextension on the ISP for BWR facilities and that proprietary topical report BWRVIP-116discusses the enhanced program.The BWRVIP submitted BWRVIP-116 to the staff in 2003 to address the impacts of licenseextension on the proposed surveillance capsule withdrawal schedule and to determine whetheradditional ISP capsules will need to be designated for the proposed surveillance capsulewithdrawal schedule.

3-117The staff's review of LRA Section B2.1.29 identified an area for which it needed additionalinformation to complete its evaluation of the applicant's program. The applicant responded to the staff's RAI as discussed below.In RAI B2.1.29-1, dated September 28, 2005, the staff requested that the applicant commit toenhancing the Reactor Vessel Surveillance Program to ensure that any additional requirementsthat result from the staff review of BWRVIP-116 will be addressed before the period ofextended operation.In its response, by letter dated October 28, 2005, the applicant stated that it will enhance theReactor Vessel Surveillance Program to address additional requirements from the staff review before the period of extended operation.In its letter dated March 15, 2006, the applicant provided commitment 42 in Table A.5, whichwill ensure that it will incorporate into the Reactor Vessel Surveillance Program any changes tothe withdrawal schedule requirements for the ISP, as approved in the staff's acceptance ofBWRVIP-116 and found applicable to the reactor vessel, will be incorporated into its R VSP.With this RVSP enhancement included as a commitment for the LRA, the staff found the applicant's response acceptable.Operating Experience. In the Operating Experience program attribute for the Reactor VesselSurveillance Program, the applicant stated that it participates in the BWRVIP ISP to ensure theprogram meets accepted industry practices. The staff has accepted the ISP methodology for monitoring radiation embrittlement at BWRVIP plants as reasonable assurance that the applicant will continue to evaluate aging effects of reactor vessel material loss of fracturetoughness by sampling, analysis, and testing. The staff has confirmed that these topical reports and NRC evaluations apply to the staff's approval of the Reactor Vessel Surveillance Programfor the applicant's CLB. The staff therefore concluded that the applicant's Operating Experienceattribute for the Reactor Vessel Surveillance Program is acceptable.USAR Supplement. In LRA Section A2.1.29, the applicant provided the USAR supplement forthe Reactor Vessel Surveillance Program. The staff reviewed this section and determined that the information in the USAR supplement adequately describes the program, as required by 10 CFR 54.21(d).In its letter dated June 10, 2005, the applicant included the following commitments to USARSection A2.1.29, documented as commitments 42 and 43 in Table A.5:(1)NMC intends to use the ISP for MNGP during the period of extended operation byimplementing the requirements of BWRVIP-116, which the NRC is currently reviewing.(2)NMC will retain the capsules removed from the MNGP reactor vessel as part of theReactor Vessel Surveillance Program.Conclusion. On the basis of its review and audit of the applicant's Reactor Vessel SurveillanceProgram, the staff determined that those program elements for which the applicant claimedconsistency with the GALL Report are consistent with the GALL Report. In addition, the staffreviewed the enhancement and confirmed that its implementation before the period of extendedoperation will result in the existing AMP being consistent with the GALL Report AMP to which it 3-118was credited. The staff concluded that the applicant demonstrated that the effects of aging willbe adequately managed so that intended functions will be maintained consistent with the CLBfor the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.2.22 Selective Leaching of Materials Program Summary of Technical Information in the Application. In LRA Section B2.1.30, the applicantdescribed the Selective Leaching of Materials Program, stating that this new program is consistent, with exception, with GALL AMP XI.M33, "Selective Leaching of Materials." The program includes a one-time visual inspection and hardness measurement of selected components that are susceptible to selective leaching. In situations where hardness testing isnot practical, the applicant will use a qualitative method by other NDE or metallurgical methodsto determine the presence and extent of selective leaching. The program will determine ifselective leaching is occurring for selected components. The applicant will write any requiredinstructions or procedures during development of the program, and may use existing MNGP procedures or work instructions.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's audit evaluation of this AMP. The staff reviewed the exception and the associated justifications todetermine whether the AMP, with the exception, remains adequate to manage the aging effectsfor which it is credited.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part,documents cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.M33.In the LRA, the applicant stated the following exceptions to the program elements listed forAMP XI.M33 in the GALL Report.Exceptions 1 and 2: The GALL Report recommends the following for the Detection of AgingEffects program element associated with the exceptions taken:The one-time visual inspection and hardness measurement includes closeexamination of a select set of components to determine whether selective leaching has occurred and whether the resulting loss of strength and/or material will affect the intended functions of these components during the period ofextended operation. Selective leaching generally does not cause changes in dimensions and is difficult to detect. However, in certain brasses it causes plug-type dezincification, which can be detected by visual inspection. One acceptable procedure is to visually inspect the susceptible components closely and conduct Brinell Hardness testing on the inside surfaces of the selected set of components to determine if selective leaching has occurred. If it is occurring, an engineering evaluation is initiated to determine acceptability of the affectedcomponents for further service.

3-119In the LRA, the applicant stated that the first exception is that the program may use hardnesstesting, other than Brinell hardness testing, to detect selective leaching of material. In the second exception, the applicant stated that it will use qualitative methods in lieu of hardnesstesting to detect selective leaching where hardness testing is not practical.The staff discussed these exceptions with the applicant's technical personnel. With regard toException 1, the staff concurred that Brinell hardness testing is one of several methodologiesthat are currently being used and is only a GALL Report recommendation. The staff found the applicant's position acceptable. With regard to Exception 2, the staff asked that the applicantclarify the use of qualitative methods versus hardness testing.In its letter dated August 11, 2005, the applicant stated that the methods used to detectselective leaching include visual inspection in conjunction with mechanistic techniques like scratch testing, hardness testing, or NDEs. The staff found the applicant's position acceptable because the applicant is using qualitative mechanistic techniques in addition to visual inspection, as recommended by the GALL Report.The staff reviewed those portions of AMP B2.1.30, "Selective Leaching of Materials Program,"that the applicant claimed are consistent with GALL AMP XI.M33 and found them consistent.The staff found the applicant's AMP acceptable because it conforms to the recommended GALL Report AMP with the exceptions as described above.Operating Experience. In LRA Section B2.1.30, that applicant stated that the SelectiveLeaching of Materials Program is a new program with no operating experience.During the audit and review, the staff asked the applicant how it captures operating experience.The applicant indicated that the CAP identifies, tracks, and trends site operating experiencerelated to all site components. The site CAP database documents any site components identified as degraded, as failed, or as potentially unable to fulfill intended functions. Plantengineering staff then evaluate these CAPs for the extent of the condition and take appropriatefollowup actions. Plant engineering staff also trend related CAP data to identify generic issues.

They address trended site issues in program health reports presented to site management on a scheduled basis. The CAP also addresses 10 CFR 54.21 issues and external operating events from the NRC, INPO, LIS, and the applicant's fleet. The staff reviewed the applicant's responseand found it acceptable.A review of CRs for leaching identified a possible selective leaching issue, a higher than normallead content in the number 12 EDG lube oil. A document review indicated that INPOSOER 80-04 recommends that if lead soldered joint coolers are installed, there should be inspections for exfoliation-type solder corrosion. A work history review determined that the number 11 EDG lube oil cooler had been replaced with the rolled tube design in 1991, but that the number 12 EDG lube oil cooler st ill had its original cooler. The applicant replaced thenumber 12 EDG lube oil cooler during the 2003 refueling outage with a rolled tube design.The staff recognized that the CAP captures, evaluates, and incorporates internal and externalplant operating experience for objective evidence of adequate management of aging effects.USAR Supplement. In LRA Section A2.1.30, the applicant provided the USAR supplement forthe Selective Leaching of Materials Program. The staff reviewed this section and determined 3-120that the information in the USAR supplement adequately describes the program, as required by10 CFR 54.21(d).In its letter dated June 10, 2005, the applicant included the commitment to USARSection A2.1.30, documented as commitment 44 in Table A.5, that before the period ofextended operation, it will implement the Selective Leaching of Materials Program as a newprogram consistent, with exceptions, to the recommendations of GALL AMP XI.M33.Conclusion. On the basis of its review and audit of the applicant's Selective Leaching ofMaterials Program, the staff determined that those program elements for which the applicantclaimed consistency with the GALL Report are consistent with the GALL Report. In addition, thestaff reviewed the exception and the associated justifications and determined that the AMP,with the exception, is adequate to manage the aging effects for which it is credited. The staffconcluded that the applicant demonstrated that the effects of aging will be adequately managedso that intended functions will be maintained consistent with the CLB for the period of extendedoperation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.2.23 Structures Monitoring Program Summary of Technical Information in the Application. In LRA Section B2.1.31, the applicantdescribed the Structures Monitoring Program, stating that this existing program is consistent,with enhancements, with GALL AMP XI.S6, "Structures Monitoring Program." The Structures Monitoring Program is based on the guidance provided in RG 1.160, Revision 2, "Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," issued March 1997, and NUMARC 93-01, Revision 2, "Industry Guideline for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," issued April 1996. The applicant implements the Structures Monitoring Program as part of the structures monitoring done under the MNGP Maintenance Rule program and with additional inspections of the intake structure and diesel fuel oil transfer house. The Structures Monitoring Program also implements GALL AMP XI.S5, "Masonry Wall Program." Masonry block wall inspections are performed as part of the Maintenance Rule inspections and are based on Inspection and Enforcement Bulletin 80-11 with administrative controls in accordance with IN 87-67, "Lessons Learned from Regional Inspections of Licensee Actions in Response to IE Bulletin 80-11," dated December 21, 1987.

As permitted by GALL AMP XI.S7, "RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants," the Structures Monitoring Program includes the inspection of water control structures. The only water control structure in scope for license renewal is the intake structure. Maintenance Rule inspections are performed on the portions of the intake structure above the water line. The Structures Monitoring Program includes separate inspections of the underwater portions of the intake structure. In addition, special settlement checks of the diesel fuel oil transfer house are performed outside the Maintenance Ruleinspections. The Structures Monitoring Program does not rely upon protective coatings to manage the effects of aging.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's audit evaluation of this AMP. The staff reviewed the enhancements and the associated justifications 3-121to determine whether the AMP, with the enhancements, remains adequate to manage the agingeffects for which it is credited.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP XI.S6.In the LRA, the applicant stated that it will implement the following enhancements to make thisAMP consistent with the recommendations in the GALL Report.Enhancement 1: The GALL Report recommends the following for the Scope of Programprogram element for GALL AMPs XI.S5 and XI.S7 associated with the enhancement made:The scope includes all masonry walls identified as performing functions inaccordance with 10 CFR 54.4.RG 1.127 applies to water-control structures associated with emergency coolingwater systems or flood protection of nuclear power plants.The applicant indicated that it is not committed to RG 1.127, Revision 1, "Inspection of Water-Control Structures Associated with Nuclear Power Plants," March 1978. The StructuresMonitoring Program includes inspections of water control structures as recommended by the GALL Report.In the LRA, the applicant stated that it will expand the Structures Monitoring Program, asnecessary, to include inspections of structures and structural elements within the scope of license renewal not inspected as part of another AMP.According to AMP B2.1.31, "Structures Monitoring Program," the program includes masonryblock walls and water control structures within the scope of license renewal. The Scope of Program program element lists water control structures, which include the access tunnel and diesel fire pump house.On the basis of its review of Structures Monitoring Program operating experience and based onsatisfying the GALL Report recommendations as discussed above, the staff found this enhancement acceptable as such changes to the applicant's program provide assurance that the effects of aging will be adequately managed.Enhancement 2: The GALL Report recommends the following for the Scope of Programprogram element for GALL AMP XI.S7 associated with the enhancement made:The water-control structures included in the RG 1.127 program are concretestructures; embankment structures; spillway structures and outlet works;reservoirs; cooling water channels and canals, and intake and discharge structures; and safety and performance instrumentation.In the LRA, the applicant stated that it will enhance implementing procedures for the StructuresMonitoring Program to ensure that structural inspections are performed on submerged portions of the intake structure from the service water bays to the wing walls.

3-122The applicant stated, in the LRA, that the Structures Monitoring Program includes separateinspections of the underwater portions of the intake structure and that under the Scope of Program element, the program also provides inspection requirements to manage aging effects described in the Parameters Monitored or Inspected element. As documented in the audit and review report, the applicant's structural inspections of the service water bays will include moredetailed inspection criteria. In addition, the frequency of the applicant's structural inspections of the submerged portions of the intake structure will meet or exceed that required by AmericanConcrete Institute (ACI) 349.3R-96, "Evaluation of Existing Nuclear Safety Related Concrete Structures."On the basis of its review of Structures Management Program operating experience and basedon satisfying the GALL Report recommendations as discussed above, the staff found this enhancement acceptable as such changes to the applicant's program provide assurance that the effects of aging will be adequately managed.Enhancement 3: The GALL Report recommends the following for the Parameters Monitored orInspected program element associated with the enhancement made:...ACI 349.3R-96 and ANSI/ASCE 11-90 provide an acceptable basis forselection of parameters to be monitored or inspected for concrete or steel structural elements...In the LRA, the applicant stated that it will enhance existing implementing procedures for theStructures Monitoring Program to include monitoring/inspection parameters for structural components within the scope of license renewal.The staff reviewed the Structures Monitoring Program PBD, which incorporates intakestructures and masonry walls, and found it to be in general agreement with the above recommendations.On the basis of its review of Structures Management Program operating experience and basedon satisfying the GALL Report recommendations as discussed above, the staff found this enhancement acceptable as such changes to the applicant's program provide assurance that the effects of aging will be adequately managed.Enhancements 4 and 5: The GALL Report recommends the following for the ParametersMonitored or Inspected program element associated with the enhancement made:Parameters monitored or inspected are to be commensurate with industry codes,standards and guidelines, and are to also consider industry and plant-specific operating experience.In the LRA, the applicant stated that it will enhance the Structures Monitoring Program tosample ground water for pH, chloride concentration, and sulfate concentration.The applicant stated, in the LRA, that to ensure that the soil environment remainsnonaggressive, it will enhance the Structures Monitoring Program to include periodicground-water sampling for pH, chloride concentration, and sulfate concentration. The PBD 3-123reiterates this statement, providing the limiting values of pH greater than 5.5, chlorides greaterthan 500 ppm, and sulfates greater than 1500 ppm for a nonaggressive environment.On the basis of its review of Structures Management Program operating experience and basedon satisfying the GALL Report recommendations as discussed above, the staff found this enhancement acceptable as such changes to the applicant's program provide assurance that the effects of aging will be adequately managed.In the LRA, the applicant stated that it will enhance the Structures Monitoring Program toinclude concrete evaluations of inaccessible areas if degradation of accessible areas is detected to ensure the soundness of the buried concrete. The PBD reiterates this statement.On the basis of its review of the Structures Management Program operating experience andbased on satisfying the GALL Report recommendations as discussed above, the staff found this enhancement acceptable as such changes to the applicant's program provide assurance that the effects of aging will be adequately managed.Enhancement 6: The GALL Report recommends the following for the Acceptance Criteriaprogram element of GALL AMP XI.S7 associated with the enhancement made:"Evaluation Criteria" provided in Chapter 5 of ACI 349.3R-96 providesacceptance criteria (including quantitative criteria) for determining the adequacy of observed aging effects and specifies criteria for further evaluation. Although not required, plant-specific acceptance criteria based on Chapter 5 of ACI 349.3R-96 are acceptable.In the LRA, the applicant stated that it will enhance the implementing procedures for theStructures Monitoring Program to include acceptance criteria for structural inspections of submerged portions of the intake structure.The applicant's technical personnel stated that for structural components of the intake structurein a raw water/river water environment, acceptance criteria will be based on relevant industrycodes and standards. ACI 349.3R-96 will guide evaluation of concrete degradation.On the basis of its review of Structures Monitoring Program operating experience and based onsatisfying the GALL Report recommendations as discussed above, the staff found this enhancement acceptable as such changes to the applicant's program provide assurance that the effects of aging will be adequately managed.The staff reviewed those portions of AMP B2.1.31, "Structures Monitoring Program," that theapplicant claimed are consistent with GALL AMP XI.S6 and found them consistent. The staff found the applicant's AMP acceptable because it conforms to the recommended GALL Report AMP with the enhancements as described above.Operating Experience. In LRA Section B2.1.31, the applicant stated that the StructuresMonitoring Program, including the Masonry Block Wall Program and RG 1.127 and implemented through the Maintenance Rule and other procedures, has detected aging effectsof structural components and has ensured that repairs were made in a timely manner before the loss of intended function. The program also evaluates external operating experience for 3-124impact on structures and structural inspections through administrative procedures and thecorrective action process.The two most recent inspections, performed in 1998 and 2001/2002, noted several deficiencies.The 1998 inspection noted 21 deficiencies and the 2001/2002 inspection noted 30 deficiencies.

However, not all of these deficiencies were directly attributed to an aging effect. The aging effects detected during the structural inspections were concrete spalling, cracking, surface deterioration and flaking, grout deterioration, corroded rebar or other steel components, andcracked welds. Applicant personnel created WOs and/or corrective actions to repair the deficiencies. Several deficiencies were evaluated and determined to be acceptable as-is and subjected to further inspections.The staff reviewed the operating experience provided in the LRA and interviewed theapplicant's technical personnel to confirm that plant-specific operating experience revealed no degradation not bounded by industry experience.On the basis of its review of the above industry and plant-specific operating experience anddiscussions with the applicant's technical personnel, the staff concluded that the applicant'sStructures Monitoring Program will adequately manage the aging effects identified in the LRAfor which this AMP is credited.USAR Supplement. In LRA Section A2.1.31, the applicant provided the USAR supplement forthe Structures Monitoring Program. The staff reviewed this section and determined that the information in the USAR supplement adequately describes the program, as required by 10 CFR 54.21(d).By letter dated June 10, 2005, the applicant included the following commitments to USARSection A2.1.31 that it will perform before the period of extended operation: (1)The program will be expanded, as necessary, to include inspections ofstructures and structural elements in scope for License Renewal that are not inspected as part of another aging management program. (2)Implementing procedures will be enhanced to ensure that structuralinspections are performed on submerged portions of the Intake Structure from the service water bays to the wing walls. (3)Implementing procedures will be revised to incl ude themonitoring/inspection parameters for structural components within the scope of License Renewal. (4)The program will be enhanced to include a requirement to sample groundwater for pH, chloride concentration and sulfate concentration. (5)The program will be enhanced to include concrete evaluations ofinaccessible areas if degradation of accessible areas is detected. (6)Implementing procedures will be enhanced to include acceptance criteriafor structural inspections of submerged portions of the Intake Structure.

3-125Conclusion. On the basis of its review and audit of the applicant's Structures MonitoringProgram, the staff determined that those program elements for which the applicant claimedconsistency with the GALL Report are consistent with the GALL Report. In addition, the staffreviewed the enhancements and confirmed that their implementation before the period ofextended operation will result in the existing AMP being consistent with the GALL Report AMPto which it was credited. The staff concluded that the applicant demonstrated that the effects ofaging will be adequately managed so that intended functions will be maintained consistent withthe CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3). The staff alsoreviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.2.24 Metal Fatigue of the Reactor Coolant Pressure Boundary Program Summary of Technical Information in the Application. In LRA Section B3.2, the applicantdescribed the Metal Fatigue of the Reactor Coolant Pressure Boundary Program, stating that this existing program is consistent, with enhancement, with GALL AMP X.M1, "Metal Fatigue of Reactor Coolant Pressure Boundary." The Metal Fatigue of the Reactor Coolant Pressure Boundary Program is part of the Thermal Fatigue Monitoring Program (FMP). The MNGP Thermal FMP provides for the periodic review of plant transients for impact on selected components. In addition, environmental effects have been evaluated in accordance with NUREG/CR-6260, "Application of NUREG/CR-5999 Interim Fatigue Curves for SelectedNuclear Power Plant Components." Selected components were evaluated using material specific guidance presented in NUREG/CR-6583, "Effects of LWR Coolant Environments onFatigue Design Curves of Carbon and Low-Alloy Steels," issued February 1998, for carbon and low alloy steels and in NUREG/CR-5704, "Effects of LWR Coolant Environments on FatigueDesign Curves of Austenitic Stainless Steels," issued April 1999. The MNGP program ensures that limiting components remain within the acceptance criteria for cumulative fatigue usage throughout the licensed term and, if trends indicate otherwise, appropriate corrective action can be implemented.Staff Evaluation. During its audit and review, the staff confirmed the applicant's claim ofconsistency with the GALL Report. The MNGP audit and review report details the staff's audit evaluation of this AMP. The staff reviewed the enhancement and the associated justifications todetermine whether the AMP, with the enhancement, remains adequate to manage the agingeffects for which it is credited.The staff interviewed the applicant's technical personnel and reviewed, in whole or in part, thedocuments cited in the staff's audit and review report, which assesses the consistency of the AMP elements with GALL AMP X.M1.In the LRA, the applicant stated that it will implement the following enhancement to make thisAMP consistent with the recommendation in the GALL Report.Enhancement: The GALL Report recommends the following for the Scope of Program programelement associated with the enhancement made:The program includes preventive measures to mitigate fatigue cracking of metalcomponents of the reactor coolant pressure boundary caused by anticipated cyclic strains in the material.

3-126In the LRA, the applicant stated that it will incorporate requirements for inclusion ofNUREG/CR-6260 locations in implementing procedures for the Thermal FMP.During the audit and review, the staff noted that this enhancement also affects the Monitoringand Trending program element as described in GALL AMP X.M1.The GALL Report recommends the following for the Monitoring and Trending program element:The program monitors a sample of high fatigue usage locations. As a minimum,this sample is to include the locations identified in NUREG/CR-6260.The staff found the applicant's enhancement to the Metal Fatigue of the Reactor CoolantPressure Boundary Program (to include all NUREG/CR-6260 locations in implementingprocedures for the Thermal FMP necessary for consistency with the GALL Report AMP description and acceptable.During the audit and review, the staff asked whether the applicant has plant-specific locationswhere fatigue cumulative usage factors (CUFs) are projected to be higher than the values projected for NUREG/CR-6260 locations. In response, the applicant stated that the LRAidentified other areas as acceptable in accordance with 10 CFR 54.21(c)(1)(iii) projected tohave cumulative fatigue usage values higher than those for NUREG/CR-6260 locations. Theapplicant stated that it will revise its FMP to include these locations as well as theNUREG/CR-6260 locations. The applicant stated that it updates fatigue evaluations conductedin accordance with this program once per cycle and projects them to a 60-year end of life (EOL)and that it will take appropriate corrective actions for any locations projected to exceed the codeacceptance criteria for fatigue before its occurrence.The staff reviewed the applicant's response together with the pertinent section of the LRA.Because the applicant's Thermal Fatigue Management Program includes most limiting locations and all of the applicable NUREG/CR-6260 locations, the staff found the applicant's responseacceptable.For the "Acceptance Criteria" program element, the applicant indicated that an alternativeapproach will be taken if the fatigue usage limit for the monitored components can not bedemonstrated to remain less than 1.0. In accordance with GALL program X.M1, acceptable corrective actions include a more rigorous analysis of the component to demonstrate that the design code limit will not be exceeded, repair, or replacement of the component. The applicantindicated that an alternative approach would be to show that potential cracking is maintainedbelow the criteria of ASME Section XI, Appendix L, or an approved NRC limit. The staff has notendorsed an alternative approach which relies on inspection in lieu of meeting the ASME Code fatigue limit of 1.0. The staff notes that, if this alternative option is selected, the inspectiondetails, including scope, qualification, method, and frequency must be provided to the NRC forreview and approval prior to the period of extended operation. An aging management program under this option would be a departure from the design basis CUF evaluation, described in the USAR supplement, and therefore, would require a license amendment pursuant to 10 CFR

50.59.

3-127The staff reviewed those portions of AMP B3.2, "Metal Fatigue of the Reactor Coolant PressureBoundary Program," that the applicant claimed are consistent with GALL AMP X.M1 and foundthem consistent. The staff found the applicant's AMP acceptable because it conforms to the recommended GALL Report AMP with the enhancement as described above.Operating Experience. In LRA Section B3.2, the applicant explained that the MNGP technicalstaff monitors industry operating experience through peer groups, industry information (e.g.,

INs, licensee event reports, SILs), and by communications with other plant's subject matter experts. The staff evaluates information from these sources for impact on the Metal Fatigue of the Reactor Coolant Pressure Boundary Program. In addition, the MNGP technical staff updates internal operating experience to account for operating cycles and their effect on fatigueof limiting components on a frequency of at least once per refueling cycle. This ensures theadequacy of the program in terms of providing a periodic means of evaluating fatigue margins and establishing corrective action plans as necessary. For example, in May 1999, MNGP experienced several transients as indicated by FW and RWCU flow data. Subsequent review concluded that these transients could have an impact on FW nozzle fatigue usage and that theydid not conform to the transient descriptions that will normally be considered in the Thermal FMP. An evaluation of these transients found that the effect on fatigue was not significant(0.003 addition). However, the applicant incorporated the results into the Thermal FMP which is updated at least once every refueling cycle. The MNGP CAP database documents thisoperating experience.The staff reviewed the operating experience provided in the LRA and interviewed theapplicant's technical personnel to confirm that plant-specific operating experience revealed no degradation not bounded by industry experience.On the basis of its evaluation of the applicant's program against the program elementsdescribed in the GALL Report AMP, its review of the above industry and plant-specific operating experience, and its discussions with the applicant's technical personnel, the staff concluded that the applicant's Metal Fatigue of the Reactor Coolant Pressure Boundary Program willadequately manage the aging effects identified in LRA for which this AMP is credited.USAR Supplement. In LRA Section A4.2, the applicant provided the USAR supplement for theMetal Fatigue of the Reactor Coolant Pressure Boundary Program. The staff reviewed this section and determined that the information in the USAR supplement adequately describes theprogram, as required by 10 CFR 54.21(d).By letter dated June 10, 2005, the applicant included commitment 52, that before the period ofextended operation, it will incorporate requirements for inclusion of NUREG/CR-6260 locationsin implementing procedures for the Thermal Fatigue Monitoring Program; however, USAR supplement Section A4.2 did not capture this commitment. The applicant stated that it willupdate the USAR supplement to include the commitment in the annual LRA update letter. In itsletter dated February 28, 2005, the applicant provided a revision to USAR supplement Section A4.2, which included the commitment.Conclusion. On the basis of its review and audit of the applicant's Metal Fatigue of the ReactorCoolant Pressure Boundary Program, the staff determined that those program elements forwhich the applicant claimed consistency with the GALL Report are consistent with the GALLReport. In addition, the staff reviewed the enhancement and confirmed that its implementation 3-128before the period of extended operation will result in the existing AMP being consistent with theGALL Report AMP to which it was credited. The staff concluded that the applicant demonstrated that the effects of aging will be adequately managed so that intended functionswill be maintained consistent with the CLB for the period of extended operation, as required by10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.3 AMPs That Are Not Consistent with or Not Addressed in the GALL Report In LRA Appendix B, the applicant identified the following plant-specific AMPs:

  • Bus Duct Inspection Program (B2.1.6)
  • System Condition Monitoring Program (B2.1.32)For AMPs that are not consistent with or not addressed by the GALL Report, the staffperformed a complete review of the AMPs to determine if they are adequate to manage aging.

The following sections of this SER document the staff's review of these plant-specific AMPs.3.0.3.3.1 Bus Duct Inspection Program Summary of Technical Information in the Application. In LRA Section B2.1.6, the applicantdescribed the Bus Duct Inspection Program, stating that this new program will be consistentwith the applicable 10 elements described in SRP-LR Appendix A. In the LRA, the applicantstated that the primary purpose of this new, plant-specific program is to demonstrate that agingeffects will be adequately managed so that nonsegregated bus ducts within the scope oflicense renewal will perform their intended function in accordance with the CLB during theperiod of extended operation. The intended function of nonsegregated bus ducts is to provide electrical connections to specified sections of an electrical circuit to deliver voltage, current, or signals.Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the informationincluded in LRA Section B2.1.6 regarding the applicant's demonstration of the Bus Duct Inspection Program to ensure that the effects of aging, as discussed above, will be adequatelymanaged so that intended functions will be maintained consistent with the CLB for the period ofextended operation.The applicant credited the Bus Duct Inspection Program with aging management of thenonsegregated phase bus. The applicant stated that the Bus Duct Inspection Program is a new plant-specific program. Its purpose is to demonstrate that the aging effects caused by ingress of moisture or contaminants (dust and debris), insulation degradation from heat or radiation in the presence of oxygen, and bolt relaxation from thermal cycling will be adequately managed sothat the nonsegregated bus ducts subject to an AMR will perform their intended function inaccordance with the CLB during the period of extended operation.To determine whether the applicant's AMP is adequate to manage the effects of aging so thatintended functions will be maintained consistent with the CLB for the period of extendedoperation, the staff evaluated the (1) scope of program, (2) preventive actions, (3) parametersmonitored or inspected, (4) detection of aging effects, (5) monitoring and trending, (6) acceptance criteria, and (7) operating experience. SER Section 3.0.4 provides the staff's 3-129evaluation of the applicant's corrective actions, confirmation process, and administrativecontrols.(1) Scope of Program-This program applies to all bus ducts within the scope of licenserenewal. The program manages the aging effects for components in the offsite power/station blackout (SBO) recovery path commodity group. The staff reviewed the specific components that the program identified.The staff confirmed that the Scope of Program element satisfies the SRP-LR A.1.2.3 criterion.The program includes all bus ducts within the scope of license renewal. On this basis, the staff found the applicant's program scope acceptable.(2) Preventive Actions-The Bus Duct Inspection Program monitors conditions. The programdoes not include any actions to prevent or mitigate aging degradation, and the staff identified noneed for such actions.The staff confirmed that the Preventive Actions element satisfies the SRP-LR A.1.2.3 criterion.The staff identified no need for preventive actions for this AMP as a condition monitoring program. On this basis, the staff found the applicant's Preventive Actions program element acceptable.(3) Parameters Monitored or Inspected-The applicant stated that this program will check asample of accessible bolted connections (bus joints and ending devices) for proper torque, or the resistance of bolted joints for resistance with a micro-ohmmeter of sufficient current capacity for checking bus bar connections. This program will also inspect internal portions ofaccessible bus ducts for cracks, corrosion, foreign debris, dust buildup, and moisture intrusion.The applicant will inspect the bus insulating system for signs of embrittlement, cracking, melting, swelling, or discoloration that may indicate overheating or aging degradation. It willinspect the bus supports for structural integrity and cracking.The staff confirmed that the Parameters Monitored or Inspected element satisfies theSRP-LR A.1.2.3 criteria and is capable of detecting the presence and extent of aging effects.On this basis, the staff found the applicant's Parameters Monitored or Inspected program element acceptable.(4) Detection of Aging Effects-The applicant stated that this program visually inspects internalportions of bus ducts, the bus insulating system, and the bus supports. In addition, a torque testor resistance test of a sample of accessible bolted connections will be performed. The applicantwill complete the program before the end of the initial 40-year license term and every 10 yearsthereafter, a period adequate for preventing failures of the bus ducts as experience shows that aging degradation is a slow process. A 10-year inspection frequency provides two data points during a 20-year period to characterize the degradation rate.In RAI B2.1.6-1, dated November 7, 2005, the staff noted that vendors do not recommend there-torque of bolted connections unless the joint requires service or the bolted connections are clearly loose. The torque required to turn the fastener in the tightening direction (restart torque) is not a good indication of the preload after the fastener is in service. Because of relaxation of parts of the joint, the final loads are likely to be lower than the installed loads; therefore, the 3-130staff requested that the applicant justify that re-torquing of bolted connections is a goodindicator of the preload after the fastener is in service.In its response dated December 7, 2005, the applicant stated that it will follow the guidance ofEPRI TR-104213, Section 8.2, "Inspection of Electrical Bolted Joints," which does not recommend re-torquing of bolted connections. It will check a sample of accessible boltedconnections loose connections by thermography or by connection resistance measurement with a low-range ohmmeter. Metal enclosed bus (MEB) internal surfaces will be visually inspectedfor aging degradation of insulating material, foreign debris and excessive dust buildup, and evidence of moisture intrusion. Bus insulation will be visually inspected for signs ofembrittlement, cracking, melting, swelling, or discoloration that may indicate overheating or aging degradation. Internal bus supports will be visually inspected for structural integrity andcracks. The applicant will complete this program before the period of extended operation andevery 10 years thereafter if visual inspection is not used to check bolted connections. A 10-year inspection interval will provide two data points during a 20-year period to characterize the degradation rate. This inspection frequency is adequate to prevent failures of the MEBs, as experience shows that aging degradation is a slow process.The applicant will use visual inspection as an alternative to thermography or connectionresistance measurement for accessible bolted connections covered with heat-shrink tape, sleeving, insulating boots, and other materials. Visual inspection of the insulation material willdetect surface anomalies, such as discoloration, cracking, chipping, or surface contamination.

When this alternative visual inspection is used to check bolted connections, the first inspection will be completed before the period of extended operation and every 5 years thereafter.Based on its review, the staff found that the visual inspection of bus ducts and internal bussupports will indicate aging effects and that thermography or resi stance checks of a sample ofbolted joints will ensure that bolted connections do not loosen from ohmic heating. The staffalso found that the 10-year inspection frequency is adequate to prevent failures of bus ducts as industry experience shows that the aging degradation is a slow process. Therefore, the staff'sconcern described in RAI B2.1.6-1 is resolved.The staff confirmed that the Detection of Aging Effects element satisfies SRP-LRSection A.1.2.3 criteria and is capable of detecting the presence and extent of aging effects. Onthis basis, the staff found the applicant's proposed Detection of Aging Effects program element acceptable.(5) Monitoring and Trending-The applicant stated that this program does not include trendingactions because the ability to trend inspection results is limited. The staff found this acceptablebecause trending will be performed under a controlled administrative process.The staff confirmed that the Monitoring and Trending element satisfies SRP-LR Section A.1.2.3criteria, as it takes into consideration plant-specific and industry operating experience. On this basis, the staff found the applicant's proposed Monitoring and Trending program element acceptable.(6) Acceptance Criteria-The applicant stated that in this program, bolted connections mustmeet the manufacturer's minimum torque specifications or the resistance of bolted joints must meet required specifications. Bus ducts must be free from any surface anomalies that suggest 3-131conductor insulation degradation exists. An additional acceptance criterion requires noindication of unacceptable corrosion, cracking, foreign debris, dust buildup, or moisture intrusion. Any condition or situation that, if not corrected, could lead to a loss of intendedfunction is considered unacceptable.As discussed above, the staff expressed concern about re-torquing of the bolted connections.The applicant stated that it will revise its acceptance criteria to remove reference to checking the torque of bolted connections, and to use thermography or resist ance checks of a sample ofbolted joints for reasonable assurance that bolted connections do not loosen from ohmic heating. In its letter dated February 28, 2006, the applicant revised the acceptance criteria toremove reference to checking bolt torque, which resolved the staff's concern.The staff confirmed that the Acceptance Criteria element satisfies SRP-LR A.1.2.3 criteria. TheAcceptance Criteria element provides a basis for evaluation of the need for corrective actions to ensure that the bus duct intended function will be maintained during the period of extendedoperation. On this basis, the staff found the applicant's Acceptance Criteria program elementacceptable.After reviewing the Corrective Actions program element, the staff identified an area for which itneeded additional information to complete its evaluation of the applicant's Bus Duct Inspection Program. In RAI B2.1.6-2, dated November 7, 2005, the staff noted that, with regard to this element, the applicant had stated that requirements of Appendix B, "Quality Assurance Criteriafor Nuclear Power Plants and Fuel Processing Plants," to 10 CFR Part 50 apply; however, it is the staff's position that the Corrective Actions element should provide for further investigation and evaluation when acceptance criteria are not met. Corrective actions may include but are not limited to cleaning, drying, increased inspection frequency, repair, or replacement of the affected metal enclosed bus components. If an unacceptable condition or situation is identified, a determination is made as to whether the same condition or situation applies to otheraccessible or inaccessible metal enclosed bus. Therefore, the staff requested that the applicantrevise the corrective actions in LRA Section B2.1.6 to add specific requirements or justify why corrective actions are not necessary.In its response, by letter dated December 7, 2005, the applicant stated that it will add thefollowing statement to the Corrective Actions element:Further investigation and evaluation are performed when the acceptance criteriaare not met. Corrective actions may include, but are not limited to, cleaning, drying, increased inspection frequency, replacement, or repair of the affected metal enclosed bus components. If an unacceptable condition or situation is identified, a determination is made as to whether the same condition or situationis applicable to other accessible or inaccessible metal enclosed bus.Based on its review, the staff found the applicant's response to RAI B2.1.6-2 acceptable;therefore, the staff's concern described in RAI B2.1.6-2 is resolved.The staff confirmed that the Corrective Actions element satisfies the SRP-LR A.1.2.3 criteria.The Corrective Actions element describes actions to be taken when the acceptance criteria are not met to ensure that the bus duct intended function will be maintained during the period of 3-132extended operation. On this basis, the staff found the applicant's Corrective Actions programelement acceptable.Operating Experience. In LRA Section B2.1.6, the applicant explained that the Bus DuctInspection Program is a new program and no site operating experience exists. Industry operating experience has demonstrated that the failures of bus ducts are caused by cracked insulation of the bus combined with moisture or debris buildup internal to the bus ducts. It has also been shown that bus duct internals exposed to appreciable ohmic heating during operation may experience loosening of bolted connections related to repeated cycling of connected loads.The staff found that the proposed program will ensure that bus ducts are not exposed toexcessive ohmic or ambient heating.USAR Supplement. In LRA Section A2.1.6, the applicant provided the USAR supplement forthe Bus Duct Inspection Program. The staff reviewed this section and determined that the information in the USAR supplement adequately describes the program, as required by 10 CFR 54.21(d).In its letter dated June 10, 2005, the applicant added a commitment to USAR Section A2.1.6,documented as commitment 17 in Table A.5, which states that before the period of extendedoperation, the applicant will implement the Bus Duct Inspection Program consistent with theappropriate 10 elements described in Appendix A to the SRP-LR.Conclusion. On the basis of its review and audit of the applicant's Bus Duct InspectionProgram, the staff concluded that the applicant demonstrated that the effects of aging will beadequately managed so that intended functions will be maintained consistent with the CLB forthe period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.3.3.2 System Condition Monitoring Program Summary of Technical Information in the Application. In LRA Section B.2.1.32, the applicantdescribed its System Condition Monitoring Program". The applicant stated that this existing plant-specific MNGP program with enhancements, will be consistent with the applicable 10elements described in SRP-LR Appendix A.The applicant stated that the System Condition Monitoring Program is an existing plant-specificprogram that is based on system engineer monitoring. Although MNGP performs manymonitoring activities, this AMP brings aging management into the scope of the monitoring activities. Other groups augment this program by identifying and reporting adverse material conditions via the corrective action process or work control process. This monitoring consists of system-level performance monitoring, inspections and walkdowns, health and status reporting,and PM.The applicant will enhance this program to include specific activities and criteria for managingage-related degradation for SSCs within the scope of license renewal. This program manages aging effects for normally accessible external surfaces of piping, tanks, hangers and supports, racks, panels, and other components and equipment within the scope of license renewal. These 3-133aging effects are managed through visual inspection and monitoring of external surfaces forleakage and evidence of material degradation.Staff Evaluation. In accordance with 10 CFR 54.21(a)(3), the staff reviewed the informationincluded in LRA Section B2.1.32 to demonstrate that the System Condition Monitoring Program will ensure that the effects of aging will be adequately managed so that the intended functionwill be maintained consistent with the CLB throughout the period of extended operation.The staff reviewed the System Condition Monitoring Program against the AMP elements foundin the GALL Report, SRP-LR Section A.1.2.3, and SRP-LR Table A.1-1, and focused on theprogram's management of aging effects through the effective incorporation of the 10 program elements. The applicant indicated that the site-controlled Quality Assurance Program includesthe corrective actions, confirmation process, and administrative controls. SER Section 3.0.4 discusses the staff's evaluation of the Quality Assurance Program.(1) Scope of Program-The applicant stated that the System Condition Monitoring Programvisually inspects and monitors the accessible external surfaces of systems and componentswithin the scope of license renewal for signs of excessive and/or abnormal aging effects and material degradation. The System Condition Monitoring Program consists of activities that manage the aging effects for components of various mechanical and civil/structure systems,including alternate nitrogen supply, automatic pressure relief, chemistry sampling, circulating water (CWT), combustible gas control (CGC), condensate and FW, condensate storage, CRD,CSP, demineralized water, EDGs, emergency filtration train, ESW, FIR, fuel pool cooling and cleanup (FPC), hangers and supports, HTV, HPCI, AIR, main condenser (MC), MST, primary containment mechanical, radwaste solid and liquid, reactor building, RBC, reactor core isolation cooling (RCIC), reactor head vent, REC, reactor vessel instrumentation, RWCU, RHR,secondary containment, service and seal water, SLC, turbine generator, and wells and domestic water.The staff's review of LRA Section B2.1.32 identified areas for which it needed additionalinformation to complete its evaluation of the applicant's program elements. The applicant responded to the staff's RAIs as discussed below.In RAI B2.1.32-1, dated July 20, 2005, the staff requested that the applicant list anyinaccessible surfaces of components (including lagged/insulated piping <212 F) to bemanaged by this program and discuss the bases for determining that the inaccessible surfaces will be adequately managed.In its response, by letter dated August 16, 2005, the applicant stated the following:The System Condition Monitoring Program manages aging effects through visualinspection and monitoring of SSCs that are accessible during normal operation, during refueling outages, or as part of planned maintenance.Accessible areas are those areas that are available for inspection and monitoringduring routine operations or that become accessible for inspection and monitoring during refueling or maintenance activities. Insulated piping can be made accessible, as needed, for inspection and monitoring for the presence of age related degradation of SSCs within the scope of license renewal. For 3-134example, insulated piping at operating temperatures >212 degrees F cannormally be evaluated for aging effects based on the inspection of uninsulated piping of the same materials in the same environment. Because of this temperature, a wetted environment is not expected. For insulated pipingoperating <212 degrees F (e.g., HVAC cooling loops), inspections will includeremoval of insulation where it is determined that inspections of uninsulated portions cannot be extrapolated for managing relevant aging effects.Visual inspections will be performed of observable indicators that detectage-related degradation. Examples of observable indicators are crack-like indications, corrosion, erosion, leakage, presence of moisture (condensation), or physical displacement.Inaccessible areas are those areas that have no access due to facilityconstruction (i.e., require a plant modification to access) or that present a significant health, safety, and/or radiological hazard. SSCs that require aging management that are inaccessible will be evaluated for the impact of agingbased on comparable accessible locations. This evaluation will be performed on accessible SSCs on the basis of same material(s) and the same or more severe environment(s) as those portions that are considered inaccessible.If an unacceptable condition or situation is identified in an accessible portion of asystem, an extent of condition evaluation will be performed to determine whetherthe same condition or situation is applicable to other accessible or inaccessible portions of t he system. Appropriate follow-up inspection and corrective actionswill be implemented as needed.Based on its review, the staff found the applicant's response to RAI B2.1.32-1 acceptable. Theapplicant stated that it will evaluate inaccessible surfaces for the impact of aging based on comparable accessible locations. For insulated piping, inspections will include removal ofinsulation where inspections of uninsulated portions cannot be extrapolated. This will allow formanaging relevant aging effects consistent with the staff's position for management of inaccessible surfaces for the External Surfaces Monitoring Program in Revision 1 of the GALL Report. Therefore, the staff's concern described in RAI B2.1.32-1 is resolved.The staff confirmed that the Scope of Program element satisfies the SRP-LR A.1.2.3 criteria.The scope of the program identifies mechanical, civil, and structural components from various systems included in the program. On this basis, the staff found the applicant's program scopeacceptable.(2) Preventive Actions-The applicant stated that no preventive actions are associated with thisAMP, the objective of which is to identify and manage aging effects of concern before the loss of intended function (i.e., condition monitoring).The staff confirmed that the Preventive Actions element satisfies the SRP-LR A.1.2.3 criteria.The staff identified no need for preventive actions for this AMP as a condition monitoring program. On this basis, the staff found the applicant's Preventive Actions program element acceptable.

3-135(3) Parameters Monitored or Inspected-The applicant stated that the System ConditionMonitoring Program uses periodic plant system inspections and walkdowns to monitor formaterial degradation of mechanical systems/components and civil structures. It will also inspecthanger and support, rack, panel, and anchorage material condition for excessive and/or abnormal material degradation conditions such as cracking, paint deterioration (an indicator of possible underlying degradation), loose, worn or missing parts/components, fluid leaks, bolting or fastener degradation, evidence of corrosion, sealant deterioration, and other problems. It willrevise implementing instructions and procedures to include specific parameters to be monitored and inspected. These parameters will be generated based on industry practices from INPO,EPRI, and other organizations.The staff confirmed that the Parameters Monitored or Inspected element satisfies theSRP-LR A.1.2.3 criteria and is capable of detecting the presence and extent of aging effects.On this basis, the staff found the applicant's Parameters Monitored or Inspected program element acceptable.(4) Detection of Aging Effects-The applicant stated that the readily accessible externalsurfaces of various components (e.g., pump casings, valve bodies, piping, expansion joints) are visually inspected for leakage and evidence of excessive and abnormal material degradation.

The minimum walkdown frequency is once per year for systems and components accessibleduring normal operation. The inspection frequency may be increased according to the safety significance, production significance, and/or operating experience of each system. Theapplicant inspects systems and components accessible only during plant outages at least onceper refueling interval.In RAI B2.1.32-2, dated July 20, 2005, the staff requested that the applicant discuss theinspection methods and acceptance criteria for the aging effects listed below:a)change in material properties and cracking for neoprene ventilation seals inESF systems,b)SCC for stainless steel piping and fittings in auxiliary systems,c)crevice corrosion for steel and copper alloy components in the auxiliarysystems,d)crevice corrosion for copper alloy components in the steam and powerconversion systems,e)SCC and crevice corrosion for stainless steel spent fuel pool liner.In its response, by letter dated August 16, 2005, the applicant stated the following:The methods and techniques for the detection of the above aging effects will beaccomplished in accordance with the recommendations of industry guidelines.

Direct visual inspection may be augmented by the use of tools such as mirrors, binoculars, and flashlights. EPRI documents will be the general source forguidance on aging detection techniques. These guidance documents include field guides and aging identification and assessment checklists. These documents provide descriptions of observable indicators relative to specific aging degradation.

3-136Examples of EPRI guidance documents are:

  • EPRI TR-107668, "Guidelines for System Monitoring by System Engineers"
  • EPRI TR-104514, "How to Conduct Material Condition Inspections"
  • EPRI 1007933, "Aging Assessment Field Guide."EPRI 1007933 is a field guide for assessing aging degradation. This field guideprovides a description of the aging degradation and photographic images of the actual degradation. This field guide has specific indicators to identify aging degradation. For example, the polymers (including neoprene) section lists indicators for chemical, thermal, radiation, ultraviolet, etc. induced degradation.

Crevice corrosion is also included under the topic of metal degradation.Instruction to understand age-related degradation of plant SSCs and to identifythe leading indicators of various degradation mechanisms and effects will beprovided. EPRI guidance, supplemented by other related materials, will be usedto establish this instruction. Examples of training topics are:

  • Fundamentals
  • Metals Aging Degradation
  • Concrete Aging Degradation
  • Polymers Aging Degradation
  • Protective Coatings and Linings Aging Degradation
  • Electrical Components Aging DegradationShould there be indication of an unacceptable degradation, the visual inspectionwill be supplemented with other examine techniques or analytical evaluation asneeded. For example, visual observation of crack-like-indications identified during monitoring will be reported via the corrective action process. As part ofthe corrective action process, further evaluation will be performed using applicable techniques such as non-destructive examination methods (e.g., dye penetrant testing), to determine the extent of degradation and needed correctiveactions. This process would be used to confirm the presence of stress corrosion cracking.In response to the specific items in this question, the following information isprovided:Item aRegarding changes in material condition or cracking inelastomers, including neoprene, visual inspection will detectdegradation indicators such as discoloration, surface films, wrinkling, distortion, and crack-like indications. The presence of any of these indicators will trigger an evaluation to determine theextent of degradation.

3-137Item bVisual inspection will identify crack-like indications that will requirefurther evaluation via the corrective action process. Further evaluation, via NDE methods, will identify the specific type ofcracking, such as stress corrosion cracking. See response to RAI 3.3.2.3-1.Items c and dVisual inspection will identify loss of material due to corrosion asevidenced by the presence of localized corrosion products, such as scale and metal oxides. The majority of the remaining exposed base metal will appear unaffected. Identification of the corrosionas crevice corrosion is based on locations and materials that would be susceptible to this type of corrosion because of crevice geometry (e.g., presence of crevices or crevice forming materials, bolted versus welded connections) and stagnant liquid environment. Additional guidance (from industry sources such as NACE International) will be used to identify crevice corrosion aswell as other types of corrosion as appropriate. Significant surface degradation will be evaluated via the corrective action process.Item eCracking due to stress corrosion cracking and loss of material dueto crevice corrosion for the stainless steel spent fuel pool liner in a treated water environment is managed by the Plant Chemistry Program as stated in LRA Table 3.5.2-15 (Page 3-748). This is consistent with GALL line item IlI.A5.2-b......Additionally, Note 539 states, "The System Condition MonitoringProgram is credited for monitoring the spent fuel pool water level and spent fuel pool leakage". This note was specifically added to define the consistency with GALL and to differentiate between the two AMPs with regard to what aging effect/mechanism was managed by each.Based on its review, the staff found the applicant's response to RAI B2.1.32-2 acceptable. Theapplicant addressed inspection methods and acceptance criteria for various aging effects, including change in material properties for elastomers, SCC, pitting, and crevice corrosion. The methods described by the applicant are acceptable detection techniques for the aging effectsaddressed; therefore, the staff's concern described in RAI B2.1.32-2 is resolved

.The staff confirmed that the Detection of Aging Effects element satisfies SRP-LRSection A.1.2.3 criteria. The Detection of Aging Effects element links the Parameters Monitored or Inspected element to the aging effects managed, the System Condition Monitoring Program adequately describes data collection, and examination methods and frequency are adequately 3-138linked to plant-specific and industry operating experience. On this basis, the staff found theapplicant's proposed Detection of Aging Effects program element acceptable.(5) Monitoring and Trending-The applicant stated that the System Condition MonitoringProgram is capable of detecting the effects of aging before a structure's (hangers and supports) or component's loss of function can occur. Visual inspections performed at least once per year for systems and components accessible during normal plant operation may increase infrequency based on the safety significance, production significance, or operating experience of

each system. The applicant inspects systems and components accessible only during plantoutages at least once per refueling interval. These inspections and walkdowns provide timely detection of aging effects (i.e., before the loss of intended function). It documents inspection and walkdown results for condition trending information.The staff confirmed that the Monitoring and Trending element satisfies SRP-LR Section A.1.2.3criteria. The System Condition Monitoring Program monitors and trends certain attributes like leakage and addresses the predictability of the extent of degradation and, thus, timelycorrective action. On this basis, the staff found the applicant's proposed Monitoring and Trending program element acceptable.(6) Acceptance Criteria-The applicant stated that it will use normal design standards,procedural requirements, CLB information, and industry codes or standards (e.g., EPRI, INPO) to determine acceptance criteria. Implementing instructions and procedures will includeacceptance criteria for age-related degradation such as corrosion, leakage, deformation, cracking, and other adverse conditions that negatively impact performance of a license renewal intended function. The applicant will use references such as EPRI field guides for acceptancecriteria guidance. It will enter excessive or abnormal conditions not meeting acceptance criteriainto the corrective action process based on evaluation results.The staff confirmed that the Acceptance Criteria element satisfies SRP-LR A.1.2.3 criteria. TheAcceptance Criteria element provides a basis for evaluation of the need for corrective actions to ensure that the SC intended function will be maintained during the period of extendedoperation. On this basis, the staff found the applicant's Acceptance Criteria program elementacceptable.Operating Experience. The applicant stated that the System Condition Monitoring Program hasbeen effective in monitoring system performance and, as enhanced, provides reasonableassurance of effective management of aging effects from external visible aging mechanisms.

The System Condition Monitoring Program is based on routine walkdowns by qualified systemengineers. The Engineering Department monitors walkdown progress monthly as a performance indicator, with a goal of 90 percent completed as scheduled. Since data gathering began in May 2003, the applicant completed 100 percent of the monthly walkdowns through August 2004 as scheduled. Numerous examples were noted where system engineersdocumented needed corrective actions through minor maintenance tasks, WOs, or AR (enteredinto the site CAP). System engineers maintain system health reports as one way to track theprogress of system performance, outstanding work, and the results of their operatingexperience reviews. Of the 82 systems tracked by system health reports, all but three met orexceeded performance expectations as of September 2004.

3-139The staff confirmed that the Operating Experience element satisfies SRP-LR A.1.2.3 criteria.Operating experience with the existing program shows that the System Condition MonitoringProgram detects system degradation in a timely manner. On this basis, the staff found theapplicant's Operating Experience program element acceptable.The applicant credited the System Condition Monitoring Program with managing aging effectsfor structural components like concrete anchors and elastomers. The GALL Report recommends the Structures Monitoring Program for management of these types of components. As documented in the audit and review report, the staff asked the applicant to discuss how the System Condition Monitoring Program addresses the GALL Report recommendations for the Structures Monitoring Program for managing aging effects of these components. The applicant stated that it reassigned a number of components to be managedby the Structures Monitoring Program as recommended by the GALL Report to the System Condition Monitoring Program. For these components, the 10 attributes of both AMPs are compatible in that they address similar scope, preventive actions, parameters monitored orinspected, detection of aging effects, monitoring and trending, acceptance criteria, corrective actions, confirmation process, and administrative controls elements. On the basis of its review and the information provided by the applicant, the staff found that the System ConditionMonitoring Program provides acceptable aging management for these structural components.USAR Supplement. In LRA Section A2.1.32, the applicant provided the USAR supplement forthe System Condition Monitoring Program. The staff reviewed this section and determined that the information in the USAR supplement adequately describes the program, as required by 10 CFR 54.21(d).Conclusion. On the basis of its review and audit of the applicant's System Condition MonitoringProgram, the staff concluded that the applicant demonstrated that the effects of aging will beadequately managed so that intended functions will be maintained consistent with the CLB forthe period of extended operation, as required by 10 CFR 54.21(a)(3). The staff also reviewed the USAR supplement for this AMP and concluded that it adequately describes the program, as required by 10 CFR 54.21(d).3.0.4 Quality Assurance Program Attributes Integral to Aging Management Programs Pursuant to 10 CFR 54.21(a)(3), a license renewal applicant must demonstrate that the effectsof aging on SCs subject to an AMR will be adequately managed so that their intended functionswill be maintained consistent with the CLB for the period of extended operation.Branch Technical Position IQMB-1, "Quality Assurance For Aging Management Programs,"(SRP-LR Section A.2) provides the following guidance with regard to the QA attributes of AMPs:

  • SR SCs are subject to the requirements of Appendix B to 10 CFR Part 50, which areadequate to address all quality-related aspects of an AMP consistent with the CLB of the facility for the period of extended operation.
  • For NSR SCs that are subject to an AMR, an applicant has an option to expand thescope of its program for Appendix B to 10 CFR Part 50 to include these SCs to address corrective actions, the confirmation process, and administrative controls for aging 3-140management during the period of extended operation. In this case, the applicant shoulddocument such a commitment in the USAR supplement in accordance with 10 CFR 54.21(d).3.0.4.1 Summary of Technical Information in the Application LRA Section A2, "Programs That Manage the Effects of Aging," states that the elements ofCorrective Actions, Confirmation Process, and Administrative Controls in the Quality Assurance Program apply to both SR and NSR SSCs subject to an AMR. In LRA Section B1.3, "Quality Assurance Program and Administrative Controls," the applicant described the quality attributes of the plant-specific AMPs and summarized them as follows:
  • A single corrective actions process is applied regardless of the safety classification ofthe SC. Corrective actions are implemented through the initiation of an AR in accordance with plant procedures established in response to Appendix B to 10 CFR Part 50.
  • The programs correct equipment deficiencies through the initiation of a WO inaccordance with plant procedures. Although a WO may initially document equipment deficiencies, the corrective action process specifies that an AR also be initiated for actual or potential problems, including failures, malfunctions, discrepancies, deviations, defective material and equipment, nonconformances, and administrative control discrepancies. Site-specific administrative work instructions will apply to both SR andNSR SCs that are subject to an AMR consistent with the CLB during the period of extended operation.
  • The confirmation process is part of the CAP. The confirmation process focuses on thefollowup actions that must be taken to verify effective implementation of corrective actions. Effectiveness is measured in terms of correcting the adverse condition and precluding repetition of significant conditions adverse to quality. Plant procedures include provisions for timely evaluation of adverse conditions and implementation of any corrective actions required, including root cause determinations and prevention of recurrence where appropriate (e.g., significant conditions adverse to quality). These procedures provide for tracking, coordinating, monitoring, reviewing, verifying, validating, and approving corrective actions to ensure that effective corrective actions are taken. The AR process is also monitored for potentially adverse trends. The existence of an adverse trend because of recurring or repetitive adverse conditions willresult in the initiation of an AR. The AMAs required for license renewal will also uncoverany unsatisfactory condition resulting from ineffective corrective action. The applicant

will enhance site documents that implement AMAs for license renewal to ensure that anAR is prepared in accordance with plant procedures whenever nonconforming conditions are found (i.e., the acceptance criteria are not met).

  • The document control process applies to all MNGP documents, procedures, andinstructions regardless of safety classification of the associated SC. The applicant implements the document control processes in accordance with the requirements ofAppendix B to 10 CFR Part 50. The document control requirements will apply to AMPs.

3-141In its letter dated June 10, 2005, the applicant revised Appendix A to its LRA to addSection A.5, which contains a commitment list related to license renewal aging management that will be added to the USAR following receipt of the extended license.3.0.4.2 Staff Evaluation The staff reviewed portions of the applicant's AMPs described in LRA Sections A2, A5, andB1.3 to ensure that the AMAs are consistent with the staff's guidance in Branch Technical Position IQMB-1 regarding AMP QA attributes. The staff confirmed that the descriptions, commitments, and applicability of the plant-specific AMPs and their associated quality attributesprovided in LRA Sections A2, A5, and B1.3 are consistent with the staff position in Branch Technical Position IQMB-1 regarding aging management QA.3.0.4.3 Conclusion The applicant described the quality attributes of the programs and activities for managing theeffects of aging for both SR and NSR SSCs within the scope of license renewal. The staff found that the QA attributes of the applicant's AMPs as described in LRA Sections A2, A5, and B1.3 are consistent with the staff position in Branch Technical Position IQMB-1. Therefore, the QA attributes of the applicant's AMPs appropriately ensure adequate management of aging effects to maintain intended functions consistent with the CLB in accordance with 10 CFR 54.21(a)(3).

The staff also found the commitment in the applicant's letter dated June 10, 2005, to revise theUSAR to specify commitments related to license renewal aging management consistent with Branch Technical Position IQMB-1. Therefore, it meets the requirement in 10 CFR 54.21(d).3.1 Aging Management of Reactor Coolant SystemThis section of the SER documents the staff's review of the applicant's AMR results for theRCS components and component groups associated with the following systems:

  • reactor head vent system
  • reactor recirculation system
  • reactor vessel instrumentation3.1.1 Summary of Technical Information in the Application In LRA Section 3.1, the applicant provided AMR results for the RCS components andcomponent groups. In LRA Table 3.1.1, the applicant provided a summary comparison of its AMRs with the AMRs evaluated in the GALL Report for the reactor vessel, internals, and RCS components and component groups.The applicant's AMRs incorporated applicable operating experience in the determination ofAERMs. These reviews included evaluation of plant-specific and industry operating experience.

The plant-specific evaluation included reviews of CRs and discussions with appropriate site personnel to identify AERMs. The applicant's review of industry operating experience included a 3-142review of the GALL Report and operating experience issues identified since the issuance of theGALL Report.3.1.2 Staff Evaluation The staff reviewed LRA Section 3.1 to determine if the applicant provided sufficient informationto demonstrate that the effects of aging for the RCS components that are within the scope oflicense renewal and subject to an AMR will be adequately managed so that intended functionswill be maintained consistent with the CLB for the period of extended operation, as required by10 CFR 54.21(a)(3).In addition, the staff performed an onsite audit of AMRs to confirm the applicant's claim thatcertain identified AMRs are consistent with the GALL Report. The staff did not repeat its reviewof the matters described in the GALL Report; however, the staff did verify that the material presented in the LRA is applicable and that the applicant had identified the appropriate GALLReport AMRs. SER Section 3.0.3 documents the staff's evaluations of the AMPs. The MNGP audit and review report details the staff's audit evaluation, which is summarized in SER Section 3.1.2.1.The staff also performed an onsite audit of those selected AMRs that are consistent with theGALL Report and for which further evaluation is recommended. The staff confirmed that the applicant's further evaluations are consistent with the acceptance criteria in Section 3.1.2.2 ofthe SRP-LR. The MNGP audit and review report documents the staff's audit evaluations, which are summarized in SER Section 3.1.2.2.The staff performed an onsite audit and conducted a technical review of the remaining AMRsthat are not consistent with, or not addressed in, the GALL Report. The audit and technicalreview included evaluating whether the applicant identified all plausible aging effects and whether the aging effects listed are appropriate for the combination of materials and environments specified. The MNGP audit and review report documents the staff's audit evaluations. SER Section 3.1.2.3 documents the staff's audit evaluations and technical review. Finally, the staff reviewed the AMP summary descriptions in the USAR supplement to ensurethat they adequately describe the programs credited with managing or monitoring aging for theRCS components.Table 3.1-1 below summarizes the staff's evaluation of components, aging effects/mechanisms,and AMPs listed in LRA Section 3.1, that are addressed in the GALL Report.

3-143Table 3.1-1 Staff Evaluation for Reactor Coolant System Components in the GALLReportComponent GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff EvaluationReactor coolantpressure boundarycomponents(Item Number3.1.1-01)Cumulative fatiguedamageTLAA, evaluated inaccordance with10 CFR 54.21(c)TLAAThis TLAA isevaluated inSection 4.3, MetalFatigue of the RPVand Internals, andReactor CoolantPressure BoundaryPiping andComponentsSteam generatorshell assembly(Item Number3.1.1-02)Loss of materialdue to pitting andcrevice corrosionInserviceinspection; waterchemistryNot applicable,PWR onlyIsolation condenser(Item Number3.1.1-03)Loss of materialdue to general,pitting, and crevicecorrosionInserviceinspection; waterchemistryNot applicable (seeSection 3.1.2.2.2)Pressure vesselferritic materialsthat have a neutronfluence greater than 10 17 n/cm 2(E > 1 MeV)

(Item Number3.1.1-04)Loss of fracturetoughness due toneutron irradiationembrittlementTLAA, evaluated inaccordance withAppendix G to10 CFR 50 andRG 1.99TLAAThis TLAA isevaluated inSection 4.2,NeutronEmbrittlement of theReactor PressureVessel andInternalsReactor vesselbeltline shell andwelds(Item Number3.1.1-05)Loss of fracturetoughness due toneutron irradiationembrittlementReactor vesselsurveillanceReactor VesselSurveillanceProgram (B2.1.29) Consistent withGALL, whichrecommends furtherevaluation (seeSection 3.1.2.2.3)Westinghouse andB&W baffle/formerbolts(Item Number3.1.1-06)Loss of fracturetoughness due toneutron irradiationembrittlement andvoid swellingPlant specificNot applicable,PWR onlySmall-bore reactorcoolant system andconnected systemspiping(Item Number3.1.1-07)Crack initiation andgrowth due to SCC,intergranular SCC,and thermal andmechanical loadingInserviceinspection; waterchemistry, one-timeinspectionASME Section XIIn-ServiceInspection,Subsections IWB,IWC, and IWDProgram (B2.1.2);One-TimeInspection Program(B2.1.23); PlantChemistry Program(B2.1.25) Consistent withGALL, whichrecommends furtherevaluation (seeSection 3.1.2.2.4)

Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation3-144Jet pump sensingline, and reactorvessel flange leakdetection line(Item Number3.1.1-08)Crack initiation andgrowth due to SCC,intergranular stresscorrosion cracking(IGSCC), or cyclicloadingPlant specificASME Section XIIn-ServiceInspection,Subsections IWB,IWC, and IWDProgram (B2.1.2);One-TimeInspection Program(B2.1.23); PlantChemistry Program(B2.1.25) The jet pumpsensing linesinternal to thereactor vessel areoutside the scope oflicense renewal.The vessel flangeleak detection lineis covered by ItemNumber 3.1.1-07.Further evaluationin Section 3.1.2.2.4Isolation condenser(Item Number3.1.1-09)Crack initiation andgrowth due to stresscorrosion cracking(SCC) or cyclicloadingInserviceinspection; waterchemistryNot applicable (seeSection 3.1.2.2.4)Vessel shell(Item Number3.1.1-10)Crack growth due tocyclic loadingTLAANot applicable,PWR onlyReactor internals(Item Number3.1.1-11)Changes indimension due tovoid swellingPlant specificNot applicable,PWR onlyPWR core supportpads, instrumenttubes (bottom headpenetrations),pressurizer sprayheads, and nozzlesfor the steamgeneratorinstruments anddrains(Item Number3.1.1-12)Crack initiation andgrowth due to SCCand/or primarywater stresscorrosion cracking(PWSCC)Plant specificNot applicable,PWR onlyCast austeniticstainless steel(CASS) reactorcoolant systempiping(Item Number3.1.1-13)Crack initiation andgrowth due to SCCPlant specificNot applicable,PWR onlyPressurizerinstrumentationpenetrations andheater sheaths andsleeves made ofNi-alloys(Item Number3.1.1-14)Crack initiation andgrowth due toPWSCCInserviceinspection; waterchemistryNot applicable,PWR only Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation3-145Westinghouse andB&W baffle formerbolts(Item Number3.1.1-15)Crack initiation andgrowth due to SCCand IASCCPlant specificNot applicable,PWR onlyWestinghouse andB&W baffle formerbolts(Item Number3.1.1-16)Loss of preload dueto stress relaxationPlant specificNot applicable,PWR onlySteam generatorfeedwaterimpingement plateand support(Item Number3.1.1-17)Loss of sectionthickness due toerosionPlant specificNot applicable,PWR only(Alloy 600) steamgenerator tubes,repair sleeves, andplugs(Item Number3.1.1-18)Crack initiation andgrowth due toPWSCC, outsidediameter stresscorrosion cracking(ODSCC), and/orintergranular attack(IGA) or loss ofmaterial due towastage and pittingcorrosion, andfretting and wear; ordeformation due tocorrosion at tubesupport plateintersectionsSteam generatortubing integrity;water chemistryNot applicable,PWR onlyTube support latticebars made ofcarbon steel(Item Number3.1.1-19)Loss of sectionthickness due to FACPlant specificNot applicable,PWR onlyCarbon steel tubesupport plate(Item Number3.1.1-20)Ligament crackingdue to corrosionPlant specificNot applicable,PWR onlySteam generatorfeedwater inlet ringand supports(Item Number3.1.1-21)Loss of materialdue toflow-corrosionCombustionengineering (CE)steam generatorfeedwater ringinspectionNot applicable,PWR onlyReactor vesselclosure studs andstud assembly(Item Number3.1.1-22)Crack initiation andgrowth due to SCCand/or IGSCCReactor headclosure studsReactor HeadClosure StudsProgram (B2.1.28) Consistent withGALL Report, whichrecommends nofurther evaluation Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation3-146CASS pump casingand valve body(Item Number3.1.1-23)Loss of fracturetoughness due tothermal agingembrittlementInservice inspectionASME Section XIIn-ServiceInspection,Subsections IWB,IWC, and IWDProgram (B2.1.2)Consistent withGALL Report (seeSection 3.1.2.1.1)CASS piping(Item Number3.1.1-24)Loss of fracturetoughness due tothermal agingembrittlementThermal agingembrittlement of CASSNot applicable,MNGP does nothave CASS pipingBWR piping andfittings; steamgeneratorcomponents(Item Number3.1.1-25)Wall thinning due toflow-acceleratedcorrosionFlow-acceleratedcorrosionFlow-AcceleratedCorrosion Program(B2.1.19) Consistent withGALL Report forBWR piping andfittings in the RCS.MNGP is a BWRand does not havea steam generatorReactor coolantpressure boundary(RCPB) valveclosure bolting,manway andholding bolting, andclosure bolting inhigh pressure andhigh-temperaturesystems(Item Number3.1.1-26)Loss of materialdue to wear, loss ofpreload due tostress relaxation,crack initiation andgrowth due to cyclicloading and/or SCCBolting integrityBolting IntegrityProgram (B2.1.4) Consistent withGALL Report, whichrecommends nofurther evaluationFeedwater andcontrol rod drive(CRD) return linenozzles(Item Number3.1.1-27)Crack initiation andgrowth due to cyclicloadingFeedwater nozzle,CRD return linenozzleBWR Control RodDrive Return LineNozzle Program(B2.1.7), BWRFeedwater NozzleProgram (B2.1.8) Consistent withGALL Report, whichrecommends nofurther evaluationVessel shellattachment welds(Item Number3.1.1-28)Crack initiation andgrowth due to SCC,IGSCCBWR vessel IDattachment welds,water chemistryBWR Vessel IDAttachment WeldsProgram (B2.1.11),Plant ChemistryProgram (B2.1.25) Consistent withGALL Report, whichrecommends nofurther evaluation Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation3-147Nozzle safe ends,recirculation pumpcasing, connectedsystems piping andfittings, body andbonnet of valves(Item Number3.1.1-29)Crack initiation andgrowth due to SCC,IGSCCBWR stresscorrosion cracking;water chemistryASME Section XIIn-ServiceInspection,Subsections IWB,IWC, and IWDProgram (B2.1.2);BWR StressCorrosion CrackingProgram (B2.1.10);One-TimeInspection Program(B2.1.23); PlantChemistry Program(B2.1.25) Consistent withGALL Report, whichrecommends nofurther evaluationPenetrations(Item Number3.1.1-30)Crack initiation andgrowth due to SCC,IGSCC, cyclicloadingBWR penetrations,water chemistryBWR PenetrationsProgram (B2.1.9),Plant ChemistryProgram (B2.1.25) Consistent withGALL Report, whichrecommends nofurther evaluationCore shroud andcore plate, supportstructure, top guide,core spray lines andspargers, jet pumpassemblies, controlrod drive housing,nuclearinstrumentationguide tubes(Item Number3.1.1-31)Crack initiation andgrowth due to SCC,IGSCC, IASCCBWR vesselinternals, waterchemistryBWR VesselInternals Program(B2.1.12), PlantChemistry Program(B2.1.25) Consistent withGALL Report, whichrecommends nofurther evaluationCore shroud andcore plate accesshole cover (weldedand mechanicalcovers)(Item Number3.1.1-32)Crack initiation andgrowth due to SCC,IGSCC, IASCCASME Section XIinserviceinspection; waterchemistryASME Section XIIn-ServiceInspection,Subsections IWB,IWC, and IWDProgram (B2.1.2);Plant ChemistryProgram (B2.1.25) Consistent withGALL Report, whichrecommends nofurther evaluationJet pump assemblycastings, orificedfuel support(Item Number3.1.1-33)Loss of fracturetoughness due tothermal aging andneutronembrittlementThermal aging andneutron irradiationembrittlementThermal Aging &Neutron IrradiationEmbrittlement ofCast AusteniticStainless Steel(CASS) Program(B2.1.33) Consistent withGALL Report, whichrecommends nofurther evaluationUnclad top headand nozzles(Item Number3.1.1-34)Loss of materialdue to general,pitting, and crevicecorrosionInserviceinspection; waterchemistryNot applicable. Thetop head enclosureis clad at MNGPCRD nozzle(Item Number3.1.1-35)Crack initiation andgrowth due toPWSCCNi-alloy nozzles andpenetrations, waterchemistryNot applicable,PWR only Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation3-148Reactor vesselnozzles safe endsand CRD housing,reactor coolantsystem components(except CASS andbolting)(Item Number3.1.1-36)Crack initiation andgrowth due to cyclicloading, and/or SCCand PWSCCInserviceinspection; waterchemistryNot applicable,PWR onlyReactor vesselinternals CASScomponents(Item Number3.1.1-37)Loss of fracturetoughness due tothermal aging,neutron irradiationembrittlement, andvoid swellingThermal aging andneutron irradiationembrittlementNot applicable,PWR onlyExternal surfaces ofcarbon steelcomponents inreactor coolantsystem pressureboundary(Item Number3.1.1-38)Loss of materialdue to boric acidcorrosionBoric acid corrosionNot applicable,PWR onlySteam generatorsecondarymanways andhandholds (CS)(Item Number3.1.1-39)Loss of materialdue to erosionInservice inspectionNot applicable,PWR onlyReactor internals,reactor vesselclosure studs, andcore support pads(Item Number3.1.1-40)Loss of materialdue to wearInservice inspectionNot applicable,PWR onlyPressurizer integralsupport(Item Number3.1.1-41)Crack initiation andgrowth due to cyclicloadingInservice inspectionNot applicable,PWR onlyUpper and lowerinternals assembly(Westinghouse)(Item Number3.1.1-42)Loss of preload dueto stress relaxationInserviceinspection; loosepart and/or neutronnoise monitoringNot applicable,PWR onlyReactor vesselinternals in fuelzone region (exceptWestinghouse andB&W baffle bolts)(Item Number3.1.1-43)Loss of fracturetoughness due toneutron irradiationembrittlement, andvoid swellingPWR vesselinternals, waterchemistryNot applicable,PWR only Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation3-149Steam generatorupper and lowerheads, tubesheets,primary nozzles andsafe ends(Item Number3.1.1-44)Crack initiation andgrowth due to SCC,PWSCC, IASCCInserviceinspection; waterchemistryNot applicable,PWR onlyVessel internals(exceptWestinghouse andB&W baffle formerbolts)(Item Number3.1.1-45)Crack initiation andgrowth due to SCCand IASCCPWR vesselinternals, waterchemistryNot applicable,PWR onlyReactor internals(B&W screws andbolts)(Item Number3.1.1-46)Loss of preload dueto stress relaxationInserviceinspection; loosepart monitoringNot applicable,PWR onlyReactor vesselclosure studs andstud assembly(Item Number3.1.1-47)Loss of materialdue to wearReactor headclosure studsNot applicable,PWR onlyReactor internals(Westinghouseupper and lowerinternal assemblies;CE bolts and tierods)(Item Number3.1.1-48)Loss of preload dueto stress relaxationInserviceinspection; loosepart monitoringNot applicable,PWR onlyThe staff's review of the MNGP component groups followed one of several approaches. Oneapproach, documented in SER Section 3.1.2.1, involves the staff's review of the AMR resultsfor components in the RCS that the applicant indicated are consistent with the GALL Reportand do not require further evaluation. Another approach, documented in SER Section 3.1.2.2,involves the staff's review of the AMR results for components in the RCS that the applicantindicated are consistent with the GALL Report and for which further evaluation is recommended. A third approach, documented in SER Section 3.1.2.3, involves the staff'sreview of the AMR results for components in the RCS that the applicant indicated are notconsistent with, or not addressed in, the GALL Report. SER Section 3.0.3 documents the staff'sreview of AMPs that are credited to manage or monitor aging effects of the RCS components.3.1.2.1 AMR Results That Are Consistent with the GALL Report Summary of Technical Information in the Application. In LRA Section 3.1.2.1, the applicantidentified the materials, environments, and AERMs. The applicant identified the following programs that manage the aging effects related to the RCS components:

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  • ASME Section XI In-Service Inspection, Subsections IWB, IWC, and IWDProgram (B2.1.2)
  • Bolting Integrity Program (B2.1.4)
  • BWR Vessel ID Attachment Welds Program (B2.1.11)
  • BWR Vessel Internals Program (B2.1.12)
  • Closed-Cycle Cooling Water System Program (B2.1.13)
  • Flow-Accelerated Corrosion Program (B2.1.19)
  • One-Time Inspection Program (B2.1.23)
  • Plant Chemistry Program (B2.1.25)
  • Reactor Head Closure Studs Program (B2.1.28)
  • Reactor Vessel Surveillance Program (B2.1.29)
  • System Condition Monitoring Program (B2.1.32)
  • Thermal Aging & Neutron Irradiation Embrittlement of Cast Austenitic StainlessSteel (CASS) Program (B2.1.33)Staff Evaluation. In LRA Tables 3.1.2-1 through 3.1.2-5, the applicant provided a summary ofAMRs for the RCS components, and identified which AMRs it considered to be consistent with the GALL Report.For component groups evaluated in the GALL Report for which the applicant has claimedconsistency with the GALL Report, and for which the GALL Report does not recommend further evaluation, the staff performed an audit and review to determine whether the GALL Reportevaluation bounds the plant-specific components contained in these GALL Report componentgroups.The applicant provided a note for each AMR line item. The notes describe how the informationin the tables aligns with the information in the GALL Report. The staff audited those AMRs with Notes A through E, which indicate that 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 AMP identified in the GALL Report. The staff audited these line items to verify consistency with the GALL Report and the validity of the AMR for the site-specific conditions.Note B 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 AMP identified in the GALL Report. The staff audited these line items to verify consistency with 3-151the GALL Report. The staff verified that it had reviewed and accepted the identified exceptionsto the GALL Report AMPs. The staff also determined whether the AMP identified by the applicant is consistent with the AMP identified in the GALL Report and whether the AMR is validfor the site-specific conditions.Note C indicates that the component for the AMR line item, although different, is consistent withthe GALL Report for material, environment, and aging effect. In addition, the AMP is consistent with the AMP identified by the GALL Report. This note indicates that the applicant was unableto find a listing of some system components in the GALL Report. However, the applicantidentified a different component in the GALL Report that has 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 determined whether the AMR line item of the different component is applicable to the component under review and whether the AMR isvalid for the site-specific conditions.Note D indicates that the component for the AMR line item, although different, is consistent withthe GALL Report for material, environment, and aging effect. In addition, the AMP takes some exceptions to the AMP identified in the GALL Report. The staff audited these line items to verify consistency with the GALL Report. The staff verified whether the AMR line item of the different component is applicable to the component under review. The staff verified that it had reviewed and accepted the identified exceptions to the GALL Report AMPs. The staff also determinedwhether the AMP identified by the applicant is consistent with the AMP identified in the GALLReport and whether the AMR is 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 the applicant credited a different AMP. The staff audited these line items to verify consistency with the GALL Report. The staff also determined whether the identified AMP will manage the aging effect consistent with the AMP identified by the GALLReport and whether the AMR is valid for the site-specific conditions.The staff conducted an audit and review of the information provided in the LRA, as documentedin the MNGP audit and review report. The staff did not repeat its review of the matters described in the GALL Report; however, the staff did verify that the material presented in the LRA is applicable and that the applicant identified the appropriate GALL Report AMRs. The following sections discuss the staff's evaluation.3.1.2.1.1 Loss of Fracture Toughness Due to Thermal Aging Embrittlement NRC Audit Item 3.1-18In the discussion section of LRA Table 3.1.1, Item Number 3.1.1-23, the applicant stated thefollowing:This line item is not used at MNGP. The reactor coolant systems components ofCASS material are portions of the Jet Pump, Fuel Support, and CRD assemblies. See items 3.1.1-31 and 3.1.1-33 for these components. In addition,CASS valve bodies in the ESF system are discussed in item 3.2.1-11 ofTable 3.2.1.

3-152During the audit and review, the staff noted that the LRA states that, "This line item is not usedat MNGP." Based on the LRA discussion in Table 3.1.1, Item 3.1.1-23, the staff reviewed ESFItem Number 3.2.1-11 in LRA Table 3.2.1 for CASS piping and fittings in the ECCS. The staff confirmed that the LRA includes AMR results for CASS valve bodies in the CSP system (LRATable 3.2.2-3) and in the RHR system (LRA Table 3.2.2-7), which the applicant had referencedappropriately to GALL Report line IV.C1.3-b. The staff also confirmed that the material, environment, aging effect, and AMP combination specified in the LRA for these valves is consistent with GALL Report line IV.C1.3-b, which applies to CASS valves in a reactor coolant water environment with an aging effect of loss of fracture toughness due to thermal aging embrittlement and which specifies the ASME Section XI In-Service Inspection, Subsections IWB, IWC, and IWD Program as the AMP for Class 1 components. However, the staff noted that the applicant had linked these AMR results with Item 3.1.1-23 in LRATable 3.1.1, where the discussion states that, "This line item is not used at MNGP."Therefore, the staff asked that the applicant resolve the LRA discrepancy linking AMR resultsfor components in one table with an item number in another table, while stating that MNGPdoes not use the item number. In its response, dated August 11, 2005, the applicant stated thefollowing:LRA Table 3.1.1, Item Number 3.1.1-23, should be revised to read, 'CASScomponents in the ESF systems subject to an environment that supports loss offracture toughness due to thermal aging embrittlement were assigned to the ASME Section XI In-Service Inspection, Subsections IWB, IWC and IWD Program. Those CASS components that are subject to this aging effect/

mechanism are valves.'Based on its review, the staff found the applicant's response to NRC Audit Item 3.1-18acceptable because the components, material, aging effect, and AMP identified in the LRA are consistent with the GALL Report. The staff found that the applicant had appropriatelyaddressed the aging management for these components. SER Section 3.0.3.2.2 documents thestaff's evaluation of the applicant's ASME Section XI In-Service Inspection, Subsections IWB, IWC, and IWD Program.On the basis of its review, the staff found that the applicant addressed the aging effects andmechanisms as identified in the GALL Report.Conclusion. The staff evaluated the applicant's claim of consistency with the GALL Report. Thestaff also reviewed information pertaining to the applicant's consideration of recent operating experience and proposals for managing associated aging effects. On the basis of its review, the staff concluded that the AMR results, which the applicant claimed to be consistent with theGALL Report, are consistent with the AMRs in the GALL Report; therefore, the staff concludedthat the applicant has demonstrated that the effects of aging for these components will beadequately managed so that their intended function(s) will be maintained consistent with theCLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3-1533.1.2.2AMR Results That Are Consistent with the GALL Report, for Which Further EvaluationIs RecommendedSummary of Technical Information in the Application. In LRA Section 3.1.2.2, the applicantprovided further evaluation of aging management as recommended by the GALL Report for the RCS components. The applicant provided information concerning how it will m anage thefollowing aging effects:

  • cumulative fatigue damage
  • loss of material due to pitting and crevice corrosion
  • loss of fracture toughness due to neutron irradiation embrittlement
  • crack initiation and growth due to thermal and mechanical loading or stress corrosioncracking
  • crack growth due to cyclic loading
  • changes in dimension due to void swelling
  • loss of preload due to stress relaxation
  • loss of section thickness due to erosion
  • crack initiation and growth due to PWSCC, ODSCC, or intergranular attack or loss ofmaterial due to wastage and pitting corrosion or loss of section thickness due to fretting and wear or denting due to corrosion of carbon steel tube support plate
  • loss of section thickness due to flow-accelerated corrosion
  • ligament cracking due to corrosion
  • loss of material due to flow-accelerated corrosionStaff Evaluation. For component groups evaluated in the GALL Report for which the applicanthas claimed consistency with the GALL Report, and for which the GALL Report recommends further evaluation, the staff audited and reviewed the applicant's evaluation to determinewhether it adequately addressed the issues that were further evaluated. In addition, the staffreviewed the applicant's further evaluations against the criteria contained in Section 3.1.2.2 ofthe SRP-LR. The staff's audit and review report details the staff's audit. The following sections discuss the staff's evaluation of the aging effects.3.1.2.2.1 Cumulative Fatigue Damage In LRA Section 3.1.2.2.1, the applicant stated that fatigue is a TLAA, as defined in10 CFR 54.3, "Definitions." 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 evaluationof this TLAA.

3-1543.1.2.2.2 Loss of Material Due to Pitting and Crevice CorrosionThe staff reviewed LRA Sections 3.1.2.2.2.1 and 3.1.2.2.2.2 against SRP-LR Section 3.1.2.2.2criteria.In LRA Section 3.1.2.2.2.1, the applicant addressed loss of material due to pitting and crevicecorrosion in the steel pressurized-water reactor (PWR) steam generator shell assembly.Loss of material for a steam generator shell assembly applies to PWRs only. The staff foundthis aging effect not applicable.In LRA Section 3.1.2.2.2.2, the applicant addressed loss of material due to pitting and crevicecorrosion in BWR isolation condenser components.MNGP has no isolation condenser. The staff found this aging effect not applicable.

3.1.2.2.3 Loss of Fracture Toughness Due to Neutron Irradiation Embrittlement The staff reviewed LRA Sections 3.1.2.2.3.1 through 3.1.2.2.3.3 against SRP-LRSection 3.1.2.2.3 criteria.In LRA Section 3.1.2.2.3.1, the applicant addressed loss of fracture toughness due to neutronirradiation embrittlement for pressure vessel ferritic materials with a neutron fluence greater

than 10 17 n/cm 2. The applicant stated that neutron irradiation embrittlement is a TLAA asdefined in 10 CFR 54.3. Applicants must evaluate TLAAs in accordance with 10 CFR 54.21(c)(1). LRA Section 4.2 describes the applicant's evaluation of this TLAA.In LRA Section 3.1.2.2.3.2, the applicant addressed loss of fracture toughness due to neutronirradiation embrittlement for the reactor vessel, stating that the Reactor Vessel SurveillanceProgram, described in LRA Section B2.1.29, manages loss of fracture toughness due to neutron irradiation embrittlement for the reactor vessel. SER Section 3.0.3.2.21 documents thestaff's review of the Reactor Vessel Surveillance Program.SRP-LR Section 3.1.2.2.3 states that certain aspects of neutron irradiation embrittlement areTLAAs as defined in 10 CFR 54.3 and that TLAAs must be evaluated in accordance with 10 CFR 54.21(c)(1). SER Section 4.2 documents the staff's review of the applicant's evaluationof this TLAA. SRP-LR Section 3.1.2.2.3 also states that for loss of fracture toughness due toneutron embrittlement of the reactor vessel beltline shell, nozzle, and welds exposed to reactor coolant and neutron flux, a reactor vessel materials surveillance program monitors neutronirradiation embrittlement of the reactor vessel.Appendix H to 10 CFR Part 50 requires the applicant's Reactor Vessel Surveillance Program.BWRVIP ISP guidance describes the scope of the Reactor Vessel Surveillance Program.BWRVIP-86-A includes the ISP capsule removal schedule, and BWRVIP-78 describes its technical basis. The NRC approved the ISP in an SE to the BWRVIP, dated February 1, 2002,concluding that, if implemented in accordance with the conditions in the SE, the ISP is an acceptable alternative to all existing BWR plant-specific RPV surveillance programs for maintaining compliance with the requirements of Appendix H to 10 CFR Part 50 through the end of the current facility 40-year operating license period.

3-155BWRVIP-116 incorporates the technical criteria specified in BWRVIP-78 and BWRVIP-86 andextends the ISP to cover the BWR fleet through an extended period of operation. The applicantcommitted to implement the requirements of BWRVIP-116, when approved.In LRA Section 3.1.2.2.3.3, the applicant addressed loss of fracture toughness due to neutronirradiation embrittlement in Westinghouse and Babcock and Wilcox (B&W) baffle/former bolts.

This section applies to PWRs only. The staff found this aging effect not applicable.On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LRSection 3.1.2.2.3. For those line items that apply to LRA Sections 3.1.2.2.3.1 through3.1.2.2.3.3, the staff determined that the applicant's AMRs are consistent with the GALL Reportand the applicant has demonstrated that the effects of aging will be adequately managed sothat the intended function(s) will be maintained consistent with the CLB during the period ofextended operation, as required by 10 CFR 54.21(a)(3).3.1.2.2.4Crack Initiation and Growth Due to Thermal and Mechanical Loading or Stress-Corrosion CrackingThe staff reviewed LRA Sections 3.1.2.2.4.1 through 3.1.2.2.4.3 against SRP-LRSection 3.1.2.2.4 criteria.In LRA Section 3.1.2.2.4.1, the applicant addressed crack initiation and growth due to thermaland mechanical loading or SCC in small-bore RCS and connect ed system piping less than 4-inch nominal pipe size (NPS). The applicant stated that the ASME Section XI In-Service Inspection, Subsections IWB, IWC, and IWD Program, together with the Plant Chemistry Program and One-Time Inspection Program manage the aging effect. The applicant further stated that the ASME Code,Section XI, does not require volumetric examination of pipes lessthan 4-inch NPS and that the scope of the One-Time Inspection Program validates AMPeffectiveness by verifying unacceptable degradation. The applicant stated that the aging effectsmonitored/inspected by its One-Time Inspection Program include crack initiation and growth and that this program includes one-time inspections to monitor a component's degradation using a variety of NDE methods.SRP-LR Section 3.1.2.2.4, item 1, states the following:Crack initiation and growth due to thermal and mechanical loading or SCC(including intergranular stress corrosion cracking [IGSCC]) could occur in small-bore reactor cool ant system and connected system piping less than NPS4. The existing program relies on ASME Section XI ISI and on control of water chemistry to mitigate SCC. The GALL report recommends that a plant-specific destructive examination or a nondestructive examination (NDE) that permits inspection of the inside surfaces of the piping be conducted to ensure that cracking has not occurred and the component intended function will bemaintained during the extended period. The AMPs should be augmented by verifying that service-induced weld cracking is not occurring in the small-bore piping less than NPS 4, including pipe, fittings, and branch connections. A one-time inspection of a sample of locations is an acceptable method to ensure that the aging effect is not occurring and the component's intended function willbe maintained during the period of extended operation.

3-156The staff reviewed LRA Section 3.1.2.2.4.1, Tables 3.1.2-1 through 3.1.2-5, and LRAAppendix B2.1.23, and confirmed that the applicant's One-Time Inspection Programappropriately includes the small bore, Class 1 piping in the head vent system and the reactorvessel instrumentation system.The staff also reviewed the applicant's drawings of the RCS and connected systems andidentified a number of small-bore, Class 1 pipe segments. The staff asked the applicant whether the One-Time Inspection Program includes each of the segments. In its response, by letter dated August 11, 2005, the applicant provided additional information including references to LRA table entries. The staff reviewed the applicant's response and concluded that theapplicant's One-Time Inspection Program appropriately includes all Class 1 small-bore pipe segments.As part of its response, the applicant stated that in Class 1, small-bore stainless steel piping,the aging effect managed by the Plant Chemistry and One-Time Inspection Programs is cracking due to SCC; however, in Class 1, small-bore carbon steel piping, the aging effect managed by the Plant Chemistry and One-Time Inspection Programs is loss of material due to corrosion. Because different examination techniques are typically required to detect the aging effect of cracking versus that of loss of material, the staff asked the applicant to justify why it does not manage the Class 1, small-bore carbon steel piping for an aging effect of crack initiation and growth due to thermal and mechanical loading.In its response dated August 11, 2005, the applicant stated that it had performed an analyticalevaluation to classify all Class 1 and 2 piping welds by failure potential based on methodology in EPRI TR-112657, Revision B-A. Based on this evaluation, the applicant determined that ithas no Class 1, small-bore carbon steel piping in an environment where cracking due to mechanical or thermal loading will occur. Consequently, one-time inspection of Class 1,small-bore carbon steel piping will focus on the loss of material, but not on the crack initiationand growth aging effect.The staff reviewed the applicant's response together with the applicant's calculation providingthe analytical basis for excluding cracking as an aging effect in Class 1, small-bore carbon steel piping. The staff noted that SRP-LR Section 3.1.2.2.4 makes no distinction between stainlesssteel and carbon steel piping, and that the purpose of the one-time inspection is to validate the absence of cracks that the ASME Code,Section XI, examinations required for small-bore pipingmight not detect. Because the applicant used an appropriate methodology to exclude the agingeffect of cracking in carbon steel small-bore piping and will perform a one-time inspection forcracking in stainless steel small-bore piping, the staff found the applicant's programs for managing aging effects in Class 1, small-bore piping acceptable. SER Sections 3.0.3.2.2, 3.0.3.2.19, and 3.0.3.1.4 document the staff's evaluations of the applicant's ASME Section XI,In-Service Inspection, Subsections IWB, IWC, and IWD Program, Plant Chemistry Program, and One-Time Inspection Program, respectively.On the basis of its review, the staff concluded that the applicant has met the SRP-LRSection 3.1.2.2.4.1 criteria for further evaluation. For those line items that apply to LRASection 3.1.2.2.4.1, the staff found that the applicant's AMRs are consistent with the GALLReport and the applicant has demonstrated that the effects of aging will be adequatelymanaged so that the intended functions will be maintained during the period of extendedoperation as required by 10 CFR 54.21(a)(3).

3-157In LRA Section 3.1.2.2.4.2, the applicant addressed crack initiation and growth due to thermaland mechanical loading or SCC in reactor vessel flange leak detection lines and jet pump sensing lines.SRP-LR Section 3.1.2.2.4, item 2, states the following:Crack initiation and growth due to thermal and mechanical loading or SCC(including IGSCC) could occur in BWR reactor vessel flange leak detection line and BWR jet pump sensing line. The GALL report recommends that a plant specific aging management program be evaluated to mitigate or detect crack initiation and growth due to SCC of vessel flange leak detection line.In LRA Section 3.1.2.2.4.2, the applicant stated that the jet pump sensing lines internal to thereactor vessel are not within the scope of license renewal, referring to the LRA's "Further Evaluation" description of crack initiation and growth due to thermal and mechanical loading or SCC regarding management of the reactor vessel flange leak detection line and other small-bore RCS and c onnected system piping.The staff noted that the jet pump sensing lines external to the vessel are small-bore piping andincluded in LRA Table 3.1.2-5 as piping and fittings made of stainless steel in a treated water environment with an aging effect of cracking due to SCC/IGA. For this component, material, environment, and aging effect, the LRA stated that the applicable AMPs are the ASME Section XI In-Service Inspection, Subsections IWB, IWC, and IWD Program, the One-Time Inspection Program, and the Plant Chemistry Program. This is consistent with the GALL Report recommendation for small-bore, stainless steel pipe in a reactor coolant water environment.

Based on consistency with the GALL Report recommendations, the staff found the applicant'sAMPs for these components acceptable as consistent with the GALL Report recommendations.For aging management of the reactor vessel flange leak detection line, the applicant, in LRASection 3.1.2.2.4.2, stated that the aging effects/mechanisms for this component are the sameas for other small-bore RCS and connect ed system piping. For these components, theapplicable AMPs are the ASME Section XI In-Service Inspection, Subsections IWB, IWC, and IWD Program together with the Plant Chemistry Program and the One-Time Inspection Program. As the reactor vessel flange leak detection line has the same material and environment and, consequently, the same aging effects as Class 1 small-bore piping, the staffconcluded that the AMPs that the applicant identified for this component are acceptable. SERSections 3.0.3.2.2, 3.

0.3.2.19, and 3.0.3.1.4 document the staff reviews and evaluations of theapplicant's ASME Section XI In-Service Inspection, Subsections IWB, IWC, and IWD Program, Plant Chemistry Program, and One-Time Inspection Program, respectively.On the basis of its review, the staff concluded that the applicant has met SRP-LRSection 3.1.2.2.4.2 criteria for further evaluation. For those line items that apply to LRASection 3.1.2.2.4.2, the staff found that the applicant's AMRs are consistent with the GALLReport and the applicant has demonstrated that the effects of aging will be adequatelymanaged so that the intended functions will be maintained during the period of extendedoperation as required by 10 CFR 54.21(a)(3).

3-158In LRA Section 3.1.2.2.4.3, the applicant addressed crack initiation and growth due to thermaland mechanical loading or SCC in the BWR isolation condenser. Because there is no isolation condenser, the staff found this aging effect not applicable.3.1.2.2.5 Crack Growth Due to Cyclic Loading The staff reviewed LRA Section 3.1.2.2.5 against SRP-LR Section 3.1.2.2.5 criteria.In LRA Section 3.1.2.2.5, the applicant stated that this aging effect applies to PWRs only.SRP-LR Section 3.1.2.2.5 states that crack growth due to cyclic loading could occur in thereactor vessel shell and the RCS piping and fittings. SRP-LR Table 3.1-1 states that further evaluation for this aging effect is for PWR plants only.The staff found this aging effect not applicable.

3.1.2.2.6 Changes in Dimension Due to Void SwellingThe staff reviewed LRA Section 3.1.2.2.6 against SRP-LR Section 3.1.2.2.6 criteria.In LRA Section 3.1.2.2.6, the applicant stated that this aging effect applies to PWRs only.SRP-LR Section 3.1.2.2.6 states that changes in dimension due to void swelling could occur inreactor internal components. SRP-LR Table 3.1-1 states that further evaluation for this aging effect is for PWR plants only.The staff found this aging effect not applicable.

3.1.2.2.7 Crack Initiation and Growth Due to Stress-Corrosion Cracking or Primary WaterStress-Corrosion CrackingThe staff reviewed LRA Sections 3.1.2.2.7.1 through 3.1.2.2.7.3 against SRP-LRSection 3.1.2.2.7 criteria.In LRA Sections 3.1.2.2.7.1 through 3.1.2.2.7.3, the applicant stated that this aging effectapplies to PWRs only.SRP-LR Section 3.1.2.2.7 states that crack initiation and growth due to SCC and PWSCC couldoccur (1) in PWR core support pads (or core guide lugs), instrument tubes (bottom head penetrations), pressurizer spray heads, and nozzles for the steam generator instruments and drains, (2) in PWR CASS RCS piping and fittings and pressurizer surge line nozzles, and (3) in PWR pressurizer instrumentation penetrations and heater sheaths and sleeves made of nickel alloys. SRP-LR Table 3.1-1 states that further evaluation for this aging effect is for PWR plants only.The staff found this aging effect not applicable.

3-1593.1.2.2.8Crack Initiation and Growth Due to Stress-Corrosion Cracking or Irradiation-AssistedStress-Corrosion CrackingThe staff reviewed LRA Section 3.1.2.2.8 against SRP-LR Section 3.1.2.2.8 criteria.In LRA Section 3.1.2.2.8, the applicant stated that this aging effect applies to PWRs only.SRP-LR Section 3.1.2.2.8 states that crack initiation and growth due to SCC or IASCC couldoccur in baffle/former bolts in Westinghouse and B&W reactors. SRP-LR Table 3.1-1 states that further evaluation for this aging effect is for PWR plants only.The staff found this aging effect not applicable.

3.1.2.2.9 Loss of Preload Due to Stress Relaxation The staff reviewed LRA Section 3.1.2.2.9 against SRP-LR Section 3.1.2.2.9 criteria.In LRA Section 3.1.2.2.9, the applicant stated that this aging effect applies to PWRs only.SRP-LR Section 3.1.2.2.9 states that loss of preload due to stress relaxation could occur inbaffle/former bolts in Westinghouse and B&W reactors. SRP-LR Table 3.1-1 states that further evaluation for this aging effect is for PWR plants only.The staff found this aging effect not applicable.

3.1.2.2.10 Loss of Section Thickness Due to Erosion The staff reviewed LRA Section 3.1.2.2.10 against SRP-LR Section 3.1.2.2.10 criteria.In LRA Section 3.1.2.2.10, the applicant stated that this aging effect applies to PWRs only.SRP-LR Section 3.1.2.2.10 states that loss of section thickness due to erosion could occur insteam generator FW impingement plates and supports. SRP-LR Table 3.1-1 states that furtherevaluation for this aging effect is for PWR plants only.The staff found this aging effect not applicable.

3.1.2.2.11Crack Initiation and Growth Due to Primary Water Stress-Corrosion Cracking,Outside-Diameter Stress-Corrosion Cracking, or Intergranular Attack or Loss of Material Due to Wastage and Pitting Corrosion or Loss of Section Thickness Due to Fretting and Wear or Denting Due to Corrosion of Carbon Steel Tube Support PlateThe staff reviewed LRA Section 3.1.2.2.11 against SRP-LR Section 3.1.2.2.11 criteria.In LRA Section 3.1.2.2.11, the applicant stated that this aging effect applies to PWRs only.SRP-LR Section 3.1.2.2.11 states that crack initiation and growth due to PWSCC, ODSCC, orIGA or loss of material due to wastage and pitting corrosion or deformation due to corrosion 3-160could occur in Alloy 600 components of the steam generator tubes, repair sleeves, and plugs.SRP-LR Table 3.1-1 states that further evaluation for this aging effect is for PWR plants only.The staff found this aging effect not applicable.

3.1.2.2.12 Loss of Section Thickness Due to Flow-Accelerated Corrosion The staff reviewed LRA Section 3.1.2.2.12 against SRP-LR Section 3.1.2.2.12 criteria.In LRA Section 3.1.2.2.12, the applicant stated that this aging effect applies to PWRs only.SRP-LR Section 3.1.2.2.12 states that loss of section thickness due to FAC could occur in tubesupport lattice bars made of carbon steel. SRP-LR Table 3.1-1 states that further evaluation for this aging effect is for PWR plants only.The staff found this aging effect not applicable.

3.1.2.2.13 Ligament Cracking Due to Corrosion The staff reviewed LRA Section 3.1.2.2.13 against SRP-LR Section 3.1.2.2.13 criteria.In LRA Section 3.1.2.2.13, the applicant stated that this aging effect applies to PWRs only.SRP-LR Section 3.1.2.2.13 states that ligament cracking due to corrosion could occur in carbonsteel components in the steam generator tube support plate. SRP-LR Table 3.1-1 states thatfurther evaluation for this aging effect is for PWR plants only.The staff found this aging effect not applicable.

3.1.2.2.14 Loss of Material Due to Flow-Accelerated Corrosion The staff reviewed LRA Section 3.1.2.2.14 against SRP-LR Section 3.1.2.2.14 criteria.In LRA Section 3.1.2.2.14, the applicant stated that this aging effect applies to PWRs only.SRP-LR Section 3.1.2.2.14 states that loss of material due to FAC could occur in FW inlet ringand supports. SRP-LR Table 3.1-1 states that further evaluation for this aging effect is for PWR plants only.The staff found this aging effect not applicable.

Conclusion. On the basis of its review, for component groups evaluated in the GALL Report forwhich the applicant has claimed consistency with the GALL Report, and for which the GALL Report recommends further evaluation, the staff determined that the applicant adequatelyaddressed the applicable issues that were further evaluated. The staff found that the effects ofaging will be adequately managed so that intended functions will be maintained consistent withthe CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).

3-1613.1.2.3 AMR Results That Are Not Consistent with or Not Addressed in the GALL ReportSummary of Technical Information in the Application. In LRA Tables 3.1.2-1 through 3.1.2-5,the staff reviewed additional details of the results of the AMRs for material, environment, AERM, and AMP combinations that are not consistent with the GALL Report, or that are notaddressed in the GALL Report.In LRA Tables 3.1.2-1 through 3.1.2-5, the applicant indicated, via Notes F through J, that thecombination of component type, material, environment, and AERM does not correspond to a line item in the GALL Report, and provided information concerning the management of the aging effect. Specifically, Note F indicates that the GALL Report does not evaluate the material for the AMR line item component. Note G indicates that the GALL Report does not evaluate the environment for the AMR line item component and material. Note H indicates that the GALL Report does not evaluate the aging effect for the AMR line item component, material, and environment combination. Note I indicates that the aging effect identified in the GALL Report forthe line item component, material, and environment combination does not apply. Note J indicates that the GALL Report does not evaluate either the component or the material andenvironment combination for the line item.Staff Evaluation. For component type, material, and environment combinations that the GALLReport does not evaluate, the staff reviewed the applicant's evaluation to determine whetherthe applicant had demonstrated that the effects of aging will be adequately managed so that theintended function(s) will be maintained consistent with the CLB during the period of extendedoperation. The following sections discuss line items that are not consistent with the GALLReport or not addressed in the GALL Report.In LRA Tables 3.1.2-1 through 3.1.2-5, the applicant identified AMR line items for which it hadnot identified any aging effects as a result of the aging review process. Specifically, the applicant stated that no aging effects occurred when components fabricated from stainlesssteel material were exposed to a primary containment air or plant indoor air environment, or when components fabricated from stainless steel or carbon steel were exposed to a lubricating oil internal environment. The applicant stated that a material science evaluation for these materials in these environments discovered no aging effects.Because stainless steels are highly resistant to corrosion in dry atmospheres in the absence ofcorrosive species, as stated in the Metals Handbook, Ninth Edition, American Society for MetalsInternational, the staff accepted the position that stainless steel in an indoor, uncontrolled airenvironment (e.g., plant indoor air) or in a gas environment (e.g., primary containment air inerted with nitrogen) exhibits no aging effect and that the SC will therefore remain capable ofperforming intended functions consistent with the CLB for the period of extended operation.Because both oxygen and moisture must be present to corrode steel, also stated in the MetalsHandbook, Ninth Edition, the staff likewise accepted the position that steel (carbon or stainless)in a lubricating oil internal environment with no water pooling exhibits no aging effect and that the SC will therefore remain capable of performing intended functions consistent with the CLBfor the period of extended operation.On the basis of its review of current industry research and operating experience, the staff foundthat plant indoor air or primary containment air on stainless steel, or lubricating oil on stainlesssteel or carbon steel, will not cause aging of concern during the period of extended operation; 3-162therefore, the staff concluded that no AERMs apply to the component, material, andenvironment described in the preceding discussion.3.1.2.3.1Reactor Coolant System - Reactor Head Vent System - Summary of AgingManagement Evaluation - Table 3.1.2-1The staff reviewed LRA Table 3.1.2-1, which summarizes the results of AMR evaluations for thereactor head vent system component groups.On the basis of its review of the applicant's programs, aging effects, and plant-specific andindustry operating experience, the staff determined that the applicant had demonstrated thatthe effects of aging will be adequately managed so intended functions will be maintainedconsistent with the CLB during the period of extended operation, as required by10 CFR 54.21(a)(3).3.1.2.3.2Reactor Coolant System-Reactor Pressure Vessel-Summary of AgingManagement Evaluation-Table 3.1.2-2The staff reviewed LRA Table 3.1.2-2, which summarizes the results of AMR evaluations for theRPV component groups.In LRA Table 3.1.2-2, the applicant stated that the aging effect of cumulative fatigue damage ofType 316NG stainless steel materials for the component type of nozzle safe end/CRDRL capexposed to a reactor coolant water environment does not apply and no AMP is specified. The LRA assigns Note I to this item, indicating that the aging effect in the GALL Report for this component, material, and environment combination does not apply. An additional note in the LRA states that the CRD hydraulic return nozzle was capped with a 4-inch diameter pipe cap in 1977, that the CRD return nozzle weld butter was removed and the weld preparation reclad withchromium carbide to improve resistance to IGSCC, and that a new nozzle cap was installed in 1986. LRA Table 3.1.2-2 also states that the aging effect of crack initiation and growth due toSCC or IGSCC also applies to this component, and that the BWR SCC Program (AMP B2.1.10) and the Plant Chemistry Program (AMP B2.1.25) manage the aging effect.The staff noted that the applicant's evaluation of this component refers to GALL Report,Volume 2, Item IV.A1.4-b, which is the CRDRL nozzle safe end. The GALL Report line item isbased on an inservice CRDRL safe end that will routinely experience cyclic flow, not oneeffectively out of service by removal of the previously attached pipe and installation of a cap on the safe end. Capping the CRDRL safe end eliminated the cyclic flow environment to which thesafe end had been exposed and thereby eliminated the potential for the aging effect ofcumulative fatigue damage. In addition, review of operating experience since the CRDRLnozzle cap replacement in 1986 indicates that no new cracking has occurred at this location.

Because there is no potential for cumulative fatigue damage from flow cycling at the cappedCRDRL safe end and no new cracking has been detected at this location since the nozzle wascapped, the staff found the applicant's statement that cumulative fatigue damage does notapply to the CRDRL safe end cap in the RPV acceptable.The applicant proposed to manage crack initiation and growth/SCC for the top head torus,flange, and dollar plate using the ASME Section XI In-Service Inspection, Subsections IWB, 3-163IWC, and IWD Program and Plant Chemistry Program. The material is identified as alloy steel(A533 Grade B Class and A508 Class 2) and clad (308/309).The staff's review of LRA Section 3.1.2 identified an area for which it needed additionalinformation to complete its evaluation of the applicant's results. The applicant responded to the staff's RAI as discussed below.In RAI 3.1.2-1, dated September 28, 2005, the staff requested that the applicant identify whichmaterials provide the pressure boundary function and provide the basis, including any operating experience, for concluding that these materials are susceptible to crack initiation and growth due to SCC.In its response, by letter dated October 28, 2005, the applicant responded that the basematerial provided the pressure boundary function and that operating experience identified in BWRVIP-74-A, "BWR Reactor Pressure Vessel Inspection and Flaw Evaluation Guidelines for License Renewal," indicates that the base material was susceptible to SCC. The staff reviewed this BWRVIP report and could find no operating experience indicating that the alloy steel base material will be susceptible to SCC. In its letter dated December 16, 2005, the applicant agreedwith the staff that this aging mechanism does not affect the low-alloy base material and stated that it will revise the LRA accordingly as part of the annual update. By letter dated March 15,2006, the applicant removed crack initiation and growth due to SCC as an AERM from the top head enclosure components in LRA Table 3.1.2-2. The staff agreed that crack initiation andgrowth is not an AERM for the alloy steel base material in a steam environment; therefore, the staff's concerns described in RAI 3.1.2-1 are resolved.The applicant identified no aging effect for the external surface of the reactor vessel exposed toprimary containment air. The staff agreed with this conclusion because the primary containment air has not caused degradation of the reactor vessel.On the basis of its review of the applicant's programs, aging effects, and plant-specific andindustry operating experience, the staff determined that the applicant had demonstrated thatthe effects of aging will be adequately managed so that the intended functions will bemaintained during the period of extended operation, as required by 10 CFR 54.21(a)(3).3.1.2.3.3Reactor Coolant System-Reactor Pressure Vessel Internals-Summary of AgingManagement Evaluation-Table 3.1.2-3The staff reviewed LRA Table 3.1.2-3, which summarizes the results of AMR evaluations for theRPV internals component groups.In LRA Table 3.1.2-3, the applicant proposed to manage crack initiation and growth due tocyclic loading of stainless steel materials for the steam dryer exposed to reactor coolant water or steam environment using AMP B2.1.12.SER Section 3.0.3.2.11 documents the staff's evaluation of the BWR Vessel Internals Program.The applicant's BWR Vessel Internals Program monitors the condition of the BWR vessel internals for crack initiation and growth. The program includes in-vessel examination and plant water chemistry procedures. The in-vessel examination procedures implement the recommendations of the BWRVIP guidelines as well as the requirements of the ASME Code, 3-164Section XI. As a result of steam dryer failure at Quad Cities following an extended poweruprate, steam dryers have been within the scope of license renewal pursuant to 10 CFR 54.4(a)(2), because it was shown that failure of the NSR component could prevent satisfactory accomplishment of intended functions of SR components. They may exhibit cracking due to flow-induced vibration or cyclic loading and therefore require an AMP.LRA Table 3.1.2-3 identifies AMP B2.1.12 as the applicable program to manage the agingeffect/mechanism of crack initiation and growth due to cyclic loading. The applicant, in note 136of the LRA, stated that it will inspect the steam dryer using the guidelines in the approvedBWRVIP topical report for steam dryer inspection and will reevaluate the inspectionrequirements if it installs a new steam dryer. Because the applicant's steam dryer inspections will be consistent with approved, industry-consensus inspection guidelines, the staff found thatthe applicant's proposed AMP is acceptable to manage the aging effect of crack initiation and growth due to cyclic loading of stainless steel material in the steam dryer exposed to a reactorcoolant water or steam environment.On the basis of its review of the applicant's programs, aging effects, and plant-specific andindustry operating experience, the staff determined that the applicant has demonstrated that theeffects of aging will be adequately managed so that intended functions will be maintainedduring the period of extended operation, as required by 10 CFR 54.21(a)(3).3.1.2.3.4Reactor Coolant System-Reactor Recirculation System-Summary of AgingManagement Evaluation-Table 3.1.2-4The staff reviewed LRA Table 3.1.2-4, which summarizes the results of AMR evaluations for theREC system component groups.In LRA Table 3.1.2-4, the applicant identified no aging effect for stainless steel fasteners, heatexchangers, manifolds, piping and fittings, pump casings, thermowells, and valve bodies exposed to a primary containment air environment.In addition, it identified no aging effects for carbon steel and stainless steel componentsexposed to a lubricating oil environment. SER Section 3.1.2.3 documents the staff's evaluation.On the basis of its review of the applicant's programs, aging effects, and plant-specific andindustry operating experience, the staff determined that the applicant has demonstrated that theeffects of aging will be adequately managed so that intended functions will be maintainedduring the period of extended operation, as required by 10 CFR 54.21(a)(3).3.1.2.3.5Reactor Coolant System-Reactor Vessel Instrumentation-Summary of AgingManagement Evaluation-Table 3.1.2-5The staff reviewed LRA Table 3.1.2-5, which summarizes the results of AMR evaluations for thereactor vessel instrumentation component groups.In LRA Table 3.1.2-5, the applicant identified no aging effect for stainless steel fasteners,manifolds, piping and fittings, restricting orifices, thermowells, and valve bodies exposed to a primary containment air environment. SER Section 3.1.2.3 documents the staff's evaluation.

3-165On the basis of its review of the applicant's programs, aging effects, and plant-specific andindustry operating experience, the staff determined that the applicant has demonstrated that theeffects of aging will be adequately managed so that intended functions will be maintainedduring the period of extended operation, as required by 10 CFR 54.21(a)(3).Conclusion. On the basis of its review, the staff found that the applicant appropriately evaluatedAMR results involving material, environment, AERM, and AMP combinations that the GALL Report does not evaluate. The staff found that the applicant has demonstrated that the effectsof aging will be adequately managed so that intended functions will be maintained consistentwith the CLB for the period of extended operation, as required by 10 CFR 54.21(a)(3).3.1.3 Conclusion The staff concluded that the applicant provided sufficient information to demonstrate that theeffects of aging for the RCS components that are within the scope of license renewal and subject to an AMR will be adequately managed so that intended function(s) will be maintainedconsistent with the CLB for the period of extended operation, as required by10 CFR 54.21(a)(3).The staff also reviewed the applicable USAR supplement program summaries and concludedthat they adequately describe the AMPs credited for managing aging of the RCS, as requiredby 10 CFR 54.21(d).3.2 Aging Management of Engineered Safety FeaturesThis section of the SER documents the staff's review of the applicant's AMR results for the ESFcomponents and component groups associated with the following systems:

  • automatic pressure relief system
  • combustible gas control system
  • secondary containm ent system3.2.1 Summary of Technical Information in the Application In LRA Section 3.2, the applicant provided AMR results for the ESF components andcomponent groups. In LRA Table 3.2.1, the applicant provided a summary comparison of its AMRs with the AMRs evaluated in the GALL Report for the ESF components and component groups.The applicant's AMRs incorporated applicable operating experience in the determination ofAERMs. These reviews involved evaluation of plant-specific and industry operating experience.

The plant-specific evaluation included reviews of CRs and discussions with appropriate site personnel to identify AERMs. The applicant's review of industry operating experience included a 3-166review of the GALL Report and operating experience issues identified since the issuance of theGALL Report.3.2.2 Staff Evaluation The staff reviewed LRA Section 3.2 to determine if the applicant provided sufficient informationto demonstrate that the effects of aging for the ESF components that are within the scope oflicense renewal and subject to an AMR will be adequately managed so that intended functionswill be maintained consistent with the CLB for the period of extended operation, as required by10 CFR 54.21(a)(3).In addition, the staff performed an onsite audit of AMRs to confirm the applicant's claim thatcertain identified AMRs are consistent with the GALL Report. The staff did not repeat its reviewof the matters described in the GALL Report; however, the staff did verify that the material presented in the LRA is applicable and that the applicant had identified the appropriate GALLReport AMRs. SER Section 3.0.3 documents the staff's evaluations of the AMPs. The MNGP audit and review report details the staff's audit evaluation, as summarized in SER Section 3.2.2.1.The staff also performed an onsite audit of those selected AMRs that are consistent with theGALL Report and for which further evaluation is recommended. The staff confirmed that the applicant's further evaluations were consistent with the acceptance criteria in Section 3.2.2.2 ofthe SRP-LR. The MNGP audit and review report documents the staff's audit evaluations, which are summarized in SER Section 3.2.2.2.The staff performed an onsite audit and conducted a technical review of the remaining AMRsthat are not consistent with, or not addressed in, the GALL Report. The audit and technicalreview included evaluating whether the applicant identified and evaluated all plausible agingeffects and evaluating whether the aging effects listed are appropriate for the combination ofmaterials and environments specified. The MNGP audit and review report documents the staff's audit evaluations. SER Section 3.2.2.3 documents these audit evaluations as well as the staff'sevaluation of its technical review.Finally, the staff reviewed the AMP summary descriptions in the USAR supplement to ensurethat they adequately describe the programs credited with managing or monitoring aging for theESF components.Table 3.2-1 below summarizes the staff's evaluation of components, aging effects/mechanisms,and AMPs listed in LRA Section 3.2, that are addressed in the GALL Report.

3-167Table 3.2-1 Staff Evaluation for Engineered Safety Features Components in the GALLReportComponent GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff EvaluationPiping, fittings, andvalves inemergency corecooling system(Item Number3.2.1-01)Cumulative fatiguedamageTLAA, evaluated inaccordance with10 CFR 54.21(c)TLAAThis TLAA isevaluated in Section4.3, Metal Fatigueof the RPV andInternals, andReactor CoolantPressure BoundaryPiping andComponentsPiping, fittings,pumps, and valvesin emergency corecooling system(Item Number3.2.1-02)Loss of materialdue to generalcorrosionWater chemistry,one-time inspectionOne-TimeInspection Program(B2.1.23), PlantChemistry Program(B2.1.25) Components incontainment spray(PWR only),standby gastreatment (BWRonly), andcontainmentisolation, andemergency corecooling systems(Item Number3.2.1-03)Loss of materialdue to generalcorrosionPlant specificOne-TimeInspection Program(B2.1.23), SystemConditionMonitoring Program(B2.1.32) Piping, fittings, pumps, and valvesin emergency corecooling system(Item Number3.2.1-04)Loss of materialdue to pitting andcrevice corrosionWater chemistry,one-time inspectionOne-TimeInspection Program(B2.1.23), PlantChemistry Program(B2.1.25) Consistent withGALL, whichrecommends furtherevaluation (seeSection 3.2.2.2.3)Components incontainment spray(PWR only),standby gastreatment (BWRonly), containmentisolation, andemergency corecooling systems(Item Number3.2.1-05)Loss of materialdue to pitting andcrevice corrosionPlant specificOne-TimeInspection Program(B2.1.23), PlantChemistry Program(B2.1.25) Containment isolation valves andassociated piping(Item Number3.2.1-06)Loss of materialdue tomicrobiologicallyinfluenced corrosionPlant specificOne-TimeInspection Program(B2.1.23), PlantChemistry Program(B2.1.25) Consistent withGALL, whichrecommends furtherevaluation (seeSection 3.2.2.2.4)

Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation3-168Seals in standbygas treatmentsystem(Item Number3.2.1-07)Changes inproperties due toelastomerdegradationPlant specificOne-TimeInspection Program(B2.1.23), SystemConditionMonitoring Program(B2.1.32) Consistent withGALL, whichrecommends furtherevaluation (seeSection 3.2.2.2.5)High-pressuresafety injection(charging) pumpminiflow orifice(Item Number3.2.1-08)Loss of materialdue to erosionPlant specificNot applicable,PWR only (seeSection 3.2.2.2.6)Drywell andsuppressionchamber spraysystem nozzles andflow orifices(Item Number3.2.1-09)Plugging of nozzlesand flow orificesdue to generalcorrosionPlant specificNot applicable (seeSection 3.2.2.2.7)External surface ofcarbon steelcomponents (ItemNumber 3.2.1-10)Loss of materialdue to generalcorrosionPlant specificOne-TimeInspection Program(B2.1.23), SystemConditionMonitoring Program(B2.1.32)Consistent withGALL, whichrecommends furtherevaluation (seeSection 3.2.2.2.2)Piping and fittingsof CASS inemergency corecooling system(Item Number3.2.1-11)Loss of fracturetoughness due tothermal agingembrittlementThermal agingembrittlement of CASSNot applicable.No CASScomponentssusceptible tothermal agingembrittlement inengineered safetyfeaturesComponentsserviced byopen-cycle coolingsystem(Item Number3.2.1-12)Local loss ofmaterial due tocorrosion and/orbuildup of depositdue to biofoulingOpen-cycle coolingwater systemOne-TimeInspection Program(B2.1.23),Open-Cycle CoolingWater SystemProgram (B2.1.24),

Plant ChemistryProgram (B2.1.25) Consistent withGALL Report, whichrecommends nofurther evaluationComponentsserviced byclosed-cycle coolingsystem(Item Number3.2.1-13)Loss of materialdue to general,pitting, and crevicecorrosionClosed-cyclecooling watersystemClosed-CycleCooling WaterSystem Program(B2.1.13)

Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation3-169Emergency corecooling systemvalves and lines toand from HPCI andRCIC pumpturbines(Item Number3.2.1-14)Wall thinning due toflow-acceleratedcorrosionFlow-acceleratedcorrosionThis line item is notused at MNGP (seeSection 3.2.2.1.1)Pumps, valves,piping, and fittingsin containmentspray andemergency corecooling systems(Item Number3.2.1-15)Crack initiation andgrowth due to SCCWater chemistryNot applicable,PWR onlyPumps, valves,piping, and fittingsin emergency corecooling systems(Item Number3.2.1-16)Crack initiation andgrowth due to SCCand IGSCCWater chemistry,BWR stresscorrosion crackingBWR StressCorrosion CrackingProgram (B2.1.10),One-TimeInspection Program(B2.1.23), PlantChemistry Program(B2.1.25) Consistent withGALL Report, whichrecommends nofurther evaluationCarbon steelcomponents(Item Number3.2.1-17)Loss of materialdue to boric acidcorrosionBoric acid corrosionNot applicable,PWR onlyClosure bolting inhigh-pressure orhigh-temperaturesystems(Item Number3.2.1-18)Loss of materialdue to generalcorrosion, loss ofpreload due tostress relaxation,and crack initiationand growth due tocyclic loading or SCCBolting integrityBolting IntegrityProgram (B2.1.4) Consistent withGALL Report, whichrecommends nofurther evaluationThe staff's review of the MNGP component groups followed one of several approaches. Oneapproach, documented in Section 3.2.2.1, involves the staff's review of the AMR results forcomponents in the ESF systems that the applicant indicated are consistent with the GALLReport and do not require further evaluation. Another approach, documented in Section 3.2.2.2,involves the staff's review of the AMR results for components in the ESF systems that theapplicant indicated are consistent with the GALL Report and for which further evaluation isrecommended. A third approach, documented in Section 3.2.2.3, involves the staff's review ofthe AMR results for components in the ESF systems that the applicant indicated are notconsistent with, or not addressed in, the GALL Report. SER Section 3.0.3 documents the staff'sreview of AMPs that are credited to manage or monitor aging effects of the ESF systemscomponents.

3-1703.2.2.1 AMR Results That Are Consistent with the GALL ReportSummary of Technical Information in the Application. In LRA Section 3.2.2.1, the applicantidentified the materials, environments, and AERMs. The applicant identified the following programs that manage the aging effects related to the ESF components:

  • ASME Section XI In-Service Inspection, Subsections IWB, IWC, and IWDProgram (B2.1.2)
  • Bolting Integrity Program (B2.1.4)
  • Buried Piping & Tanks Inspection Program (B2.1.5)
  • Closed-Cycle Cooling Water System Program (B2.1.13)
  • Flow-Accelerated Corrosion Program (B2.1.19)
  • One-Time Inspection Program (B2.1.23)
  • Open-Cycle Cooling Water System Program (B2.1.24)
  • Plant Chemistry Program (B2.1.25)
  • Selective Leaching of Materials Program (B2.1.30)
  • System Condition Monitoring Program (B2.1.32)Staff Evaluation. In LRA Tables 3.2.2-1 through 3.2.2-8, the applicant summarized the AMRsfor the ESF components and identified which AMRs it considered to be consistent with the GALL Report.For component groups evaluated in the GALL Report for which the applicant has claimedconsistency with the GALL Report, and for which the GALL Report does not recommend further evaluation, the staff performed an audit and review to determine whether the GALL Reportevaluation bounds the plant-specific components contained in these GALL Report componentgroups.The applicant provided a note for each AMR line item. The notes describe the relationship ofthe information in the tables to the information in the GALL Report. The staff audited thoseAMRs with Notes A through E, which indicate that 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 AMP identified in the GALL Report. The staff audited these line items to verify consistency with the GALL Report and the validity of the AMR for the site-specific conditions.Note B 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 AMP identified in the GALL Report. The staff audited these line items to verify consistency with the GALL Report. The staff verified that the staff had reviewed and accepted the identifiedexceptions to the GALL Report AMPs. The staff also determined whether the AMP identified by 3-171the applicant is consistent with the AMP identified in the GALL Report and whether the AMR isvalid for the site-specific conditions.Note C indicates that the component for the AMR line item, although different, is consistent withthe GALL Report for material, environment, and aging effect. In addition, the AMP is consistent with the AMP identified by the GALL Report. This note indicates that the applicant could not finda listing of some system components in the GALL Report. However, the applicant identified adifferent component in the GALL Report that has 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 determined whether the AMR line item of the different component is applicable to the component under review and whether the AMR is valid for the site-specific conditions.Note D indicates that the component for the AMR line item, although different, is consistent withthe GALL Report for material, environment, and aging effect. In addition, the AMP takes some exceptions to the AMP identified in the GALL Report. The staff audited these line items to verify consistency with the GALL Report. The staff verified whether the AMR line item of the different component applies to the component under review. The staff verified whether it had reviewed and accepted the identified exceptions to the GALL Report AMPs. The staff also determinedwhether the AMP identified by the applicant is consistent with the AMP identified in the GALLReport and whether the AMR is 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 the applicant credited a different AMP. The staff audited these line items to verify consistency with the GALL Report. The staff also determined whether the identified AMP will manage the aging effect consistent with the AMP identified by the GALLReport and whether the AMR is valid for the site-specific conditions.The staff conducted an audit and review of the information provided in the LRA, as documentedin the MNGP audit and review report. The staff did not repeat its review of the matters described in the GALL Report; however, the staff did verify that the material presented in the LRA is applicable and that the applicant identified the appropriate GALL Report AMRs. The following sections discuss the staff's evaluation.3.2.2.1.1 Wall Thinning Due to Flow-Accelerated Corrosion In the discussion section of LRA Table 3.2.1, Item Number 3.2.1-14, the applicant stated thefollowing:Aging effect is managed by the Flow-Accelerated Corrosion program.

Consistent with NUREG-1801, some sections of the High Pressure CoolantInjection (HPC) and Reactor Core Isolation Cooling (RCI) systems aresusceptible to flow-accelerated corrosion (FAC) and the Flow-Accelerated Corrosion Program is credited to manage the aging effect. The predominate sections of the HPC and RCI systems were evaluated as not susceptible to FACbased on material type or the components have no flow or operate less than 2%

of the plant operating time. The components that fall in the latter category do notrequire aging management for FAC in accordance with EPRI, NSAC-202L, R2 3-172 and NUREG-1557, 'Summary of Technical Information and Agreements from theNuclear Regulatory Management and Resources Council Industry Reports Addressing License Renewal.'During the audit and review, the staff noted that the applicant did not use Table 3.2.1, Item3.2.1-14, for Table 2 data. The staff reviewed the GALL Report (Sections V.D2.1-f, V.D2.3-a),which contains no line item covering ECCS piping in treated water susceptible to FAC. The applicant did not use Table 3.2.1, Item 3.2.1-14; instead, the applicant included ECCS pipingand fittings exposed to treated water and susceptible to FAC in LRA Table 3.1.1, Item 3.1.1-25.This line item was a better match for the GALL Report (Section IV.C1.1-c) for materials, environment, aging effects, and components. The staff asked the applicant the reason for crediting another line item for this aging effect. The applicant responded that the GALL Report, Chapter V, contains no line item for ECCS piping in treated water susceptible to FAC; for this reason, the applicant did not use this line item. Instead the applicant used Table 1 Item 3.1.1-25as a better match with the GALL Report (Section IV.C.1.1-c). By its letter dated August 11, 2005, the applicant revised the LRA Table 1, Item 3.2.1-14, from "Aging effect is managed bythe FAC Program," to, "This line item is not used at MNGP."On this basis, the staff found this program acceptable for managing aging of wall thinning dueto FAC for some sections of the HPC and RCI systems. SER Section 3.0.3.1.2 documents thestaff evaluation of the FAC Program.On the basis of its review, the staff found that the applicant addressed the agingeffect/mechanism as identified in the GALL Report.Conclusion. The staff evaluated the applicant's claim of consistency with the GALL Report. Thestaff also reviewed information pertaining to the applicant's consideration of recent operating experience and proposals for managing associated aging effects. The staff's review concluded that the AMR results, which the applicant claimed to be consistent with the GALL Report, areconsistent with the AMRs in the GALL Report; therefore, the staff concluded that the applicanthas demonstrated that the effects of aging for these components will be adequately managedso that their intended function(s) will be maintained consistent with the CLB for the period ofextended operation, as required by 10 CFR 54.21(a)(3).3.2.2.2AMR Results That Are Consistent with the GALL Report, for Which Further EvaluationIs RecommendedSummary of Technical Information in the Application. In LRA Section 3.2.2.2, the applicantprovided further evaluation of aging management as recommended by the GALL Report for the ESF components. The applicant provided information concerning its management of the following aging effects:

  • cumulative fatigue damage
  • loss of material due to general corrosion
  • local loss of material due to pitting and crevice corrosion
  • local loss of material due to microbiologically influenced corrosion
  • changes in properties due to elastomer degradation
  • local loss of material due to erosion
  • buildup of deposits due to corrosion 3-173Staff Evaluation. For component groups evaluated in the GALL Report for which the applicanthas claimed consistency with the GALL Report, and for which the GALL Report recommends further evaluation, the staff audited and reviewed the applicant's evaluation to determinewhether it adequately addressed the issues that were further evaluated. In addition, the staffreviewed the applicant's further evaluations against the criteria contained in Section 3.2.2.2 ofthe SRP-LR. The staff's audit and review report details the staff's audit. The following sections discuss the staff's evaluation of the aging effects.3.2.2.2.1 Cumulative Fatigue Damage In LRA Section 3.2.2.2.1, the applicant stated that fatigue is a TLAA, as defined in10 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 General Corrosion The staff reviewed LRA Sections 3.2.2.2.2.1 and 3.2.2.2.2.2 against the criteria in SRP-LRSection 3.2.2.2.2.In LRA Section 3.2.2.2.2.1, the applicant addressed the loss of material due to generalcorrosion of piping, fittings, pumps, and valves in the ECCS. The applicant stated that the One-Time Inspection Program or a combination of the One-Time Inspection Program and Plant Chemistry Program manages the aging effect.SRP-LR Section 3.2.2.2.2 states the following:The management of loss of material due to general corrosion of pumps, valves,piping, and fittings associated with some of the BWR emergency core cooling systems (high-pressure coolant injection, reactor core isolation cooling, high-pressure core spray, low-pressure core spray, low-pressure coolant injection (residual heat removal)) and with lines to the suppression chamber and to the drywell and suppression chamber spray system should be furtherevaluated. The existing aging management program relies on monitoring and control of primary water chemistry based on BWRVIP 29 (EPRI TR-103515) for BWRs to mitigate degradation. However, control of primary water chemistry does not preclude loss of material due to general corrosion at locations of stagnant flow conditions. Therefore, verification of the effectiveness of the chemistry control program should be performed to ensure that corrosion is not occurring.

The GALL Report recommends further evaluation of programs to manage loss of material due to general corrosion to verify the effectiveness of the chemistry control program. A one-time inspection of select components at susceptible locations is an acceptable method to determine whether an aging effect is not occurring or an aging effect is progressing very slowly such that the component's intended function will be maintained during the period of extended operation.In LRA Section 3.2.2.2.2.1, the applicant stated that loss of material due to general corrosion ofpiping, fittings, pumps, and valves could occur in the ECCS and will be managed by theOne-Time Inspection Program, or a combination of the One-Time Inspection Program and the Plant Chemistry Program. The applicant stated that, when applied in combination with the Plant 3-174Chemistry Program, the scope of the One-Time Inspection Program incorporates activities toverify the effectiveness of the Plant Chemistry Program, including a sample of components where the flow of water is low or stagnant conditions exist.SER Sections 3.0.3.1.4 and 3.0.3.2.19 document the staff's evaluations of the One-TimeInspection Program and the Plant Chemistry Program, respectively.The applicant, in the LRA, included some component types subject to general corrosion(fans/blower housings and turbines) not consistent with the GALL Report; however, the materials, environments, and aging effects are similar. The staff found that these items will beproperly managed during the period of extended operation. In addition, there are some agingmechanisms, galvanic corrosion and MIC, covered in LRA Section 3.2.2.2.2, managed by the One-Time Inspection Program and Plant Chemistry Program not consistent with the GALL Report. The staff requested that the applicant explain why it added these aging mechanisms.The applicant responded that these mechanisms could cause the aging effect, loss of material, and that this approach was conservative. The staff concluded that the applicant had taken a conservative approach to aging management and was consistent with the GALL Report.Based on the technical information provided in LRA Section 3.2 and review of the One-TimeInspection and Plant Chemistry Programs, the staff found that the applicant appropriately addressed the aging effect/mechanism of loss of material due to general corrosion of pumps, valves, piping, and fittings associated with some of the ECCSs (HPC, RCI, low-pressure CSP, LPCI (RHR)) and lines to the suppression chamber and to the drywell and suppression chamber spray system for components in the ESF systems.In LRA Section 3.2.2.2.2.2, the applicant addressed the loss of material due to generalcorrosion of components in the standby gas treatment and containment isolation systems, andECCS. The applicant stated that the One-Time Inspection Program or the System ConditionMonitoring Program manages the aging effect.SRP-LR Section 3.2.2.2.2.2 states the following:Loss of material due to general corrosion could occur in the drywell andsuppression chamber spray (BWR) systems header and spray nozzlecomponents, standby gas treatment system components (BWR), containmentisolation valves and associated piping, the automatic depressurization systempiping and fittings (BWR), emergency core cooli ng system header piping andfittings and spray nozzles (BWR), and the external surfaces of BWR carbon steel components. The GALL Report recommends further evaluation on a plant-specific basis to ensure that the aging effect is adequately managed.The applicant stated in LRA Section 3.2.2.2.2.2, that the One-Time Inspection Program and/orthe System Condition Monitoring Program manages the aging effect for an air/gas environment.The LRA describes the One-Time Inspection Program as a new AMP. The scope of this newAMP includes activities to verify potential long incubation periods for certain aging effects on SCs. The environments applicable to this item are characteristic of long incubation periods (air/gas environments with the potential for moisture). The staff evaluated the One-TimeInspection Program and found it acceptable for managing the aging effects of loss of material 3-175due to general corrosion. SER Section 3.0.3.1.4 documents the evaluation of the One-TimeInspection Program.The LRA describes the System Condition Monitoring Program as an existing plant-specificprogram that manages aging effects for normally accessible, external surfaces of piping, tanks, and other components and equipment within the scope of license renewal. The applicant manages these aging effects through visual inspection and monitoring of external surfaces for leakage and evidence of material degradation.The staff considers visual inspection an examination technique capable of detecting loss ofmaterial due to various aging mechanisms (e.g., general or galvanic corrosion) on the exterior surface of components, and the staff considers an examination frequency of once per year or per refueling outage adequate for the detection of this effect before the loss of component function occurs. The staff's review found the System Condition Monitoring Program acceptable for managing aging of general corrosion during the period of extended operation. SER Section 3.0.3.3.2 documents the evaluation of the System Conditioning Monitoring Program.The System Conditioning Monitoring Program and One-Time Inspection Program cover agingmanagement in the drywell and suppression chamber spray, systems header and spray nozzlecomponents, standby gas treatment system (SGTS) components, containment isolation valvesand associated piping, the automatic depressurizati on system piping and fittings, ECCS headerpiping and fittings and spray nozzles, and the external surfaces of carbon steel components.On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LRSection 3.2.2.2.2. For those line items that apply to LRA Sections 3.2.2.2.2.1 and 3.2.2.2.2.2,the staff determined that the applicant's AMRs are consistent with the GALL Report and theapplicant has demonstrated that the effects of aging will be adequately managed so that theintended function(s) will be maintained consistent with the CLB during the period of extendedoperation, as required by 10 CFR 54.21(a)(3).3.2.2.2.3 Local Loss of Material Due to Pitting and Crevice Corrosion The staff reviewed LRA Sections 3.2.2.2.3.1 and 3.2.2.2.3.2 against the criteria in SRP-LRSection 3.2.2.2.3.In LRA Section 3.2.2.2.3.1, the applicant addressed the loss of material due to pitting andcrevice corrosion of piping, fittings, pumps, and valves in the ECCS. The applicant stated that the One-Time Inspection Program, or the combination of the One-Time Inspection Program and Plant Chemistry Program, manages the aging effect.SRP-LR Section 3.2.2.2.3 states the following:The management of local loss of material due to pitting and crevice corrosion ofpumps, valves, piping, and fittings associated with some of the BWR emergency core cooling system piping and fittings (high-pressure coolant injection, reactorcore isolation cooling, high-pressure core spray, low-pressure core spray, low-pressure coolant injection (residual heat removal)) and with lines to the suppression chamber and to the drywell and suppression chamber spray systemshould be evaluated further. The existing aging management program relies on 3-176monitoring and control of primary water chemistry based on EPRI guidelines ofTR-105714 for PWRs and BWRVIP 29 (EPRI TR-103515) for BWRs to mitigate degradation. However, control of coolant water chemistry does not preclude loss of material due to crevice and pitting corrosion at locations of stagnant flow conditions. Therefore, verification of the effectiveness of the chemistry control program should be performed to ensure that corrosion is not occurring. The GALL Report recommends further evaluation of programs to manage the loss of material due to pitting and crevice corrosion to verify the effectiveness of the chemistry control program. A one-time inspection of select components at susceptible locations is an acceptable method to determine whether an aging effect is not occurring or an aging effect is progressing very slowly so that the component's intended function will be maintained during the period of extendedoperation.In LRA Section 3.2.2.2.3.1, the applicant addressed loss of material due to pitting and crevicecorrosion of piping, fittings, pumps, and valves in the ECCS. The applicant stated that the One-Time Inspection Program, or the combination of the One-Time Inspection Program and Plant Chemistry Program, manages the aging effect. When applied in combination with the Plant Chemistry Program, the scope of the One-Time Inspection Program incorporates activities to verify the effectiveness of the Plant Chemistry Program, including a sample of components where the flow of water is low or stagnant conditions exist. Implementation of the One-Time Inspection Program and the Plant Chemistry Program to manage the aging effect provides added assurance that the aging effect is not occurring or that the aging effect isprogressing very slowly, such that the component's intended function will be maintained duringthe period of extended operation.As documented in the audit and review report, the applicant stated that in some instances, thecomponent within the scope of license renewal has an environment that does not lend itself to benefits from the Plant Chemistry Program (low-flow stagnant conditions, or an air/gas environment). The staff determined that the use of the One-Time Inspection Program alone incertain cases, such as no-flow conditions, in which the use of the Plant Chemistry Program is not a viable option, is acceptable. The staff concluded, based on MNGP technical procedures,that this is an appropriate aging management method based on the details of the program'ssampling locations, frequencies, and corrective actions.The applicant uses the One-Time Inspection Program, or the combination of the One-TimeInspection Program and the Plant Chemistry Program, to manage the aging effect/mechanism of loss of material due to pitting and crevice corrosion for areas of stagnant flow. The staff evaluated the One-Time Inspection Program and Plant Chemistry Program, as documented in SER Sections 3.0.3.1.4 and 3.0.3.2.19, respectively.The staff reviewed the applicant's programs credited for aging management for the materials,environment, and aging effects/mechanisms. The pumps, valves, piping, and fittings associated with some of the BWR ECCS piping and fittings (HPC, RCI, low-pressure CSP, LPCI (RHR))and with lines to the suppression chamber and to the drywell and suppression chamber spray system are subject to local loss of material due to pitting and crevice corrosion. The One-TimeInspection Program or the combination of the Plant Chemistry Program and the One-Time Inspection Program manages the aging effects.

3-177In LRA Section 3.2.2.2.3.2, the applicant addressed loss of material due to pitting and crevicecorrosion of components in the standby gas treatment and containment isolation systems, andECCS. The applicant stated that the One-Time Inspection Program, or the combination of theOne-Time Inspection Program and Plant Chemistry Program, manages the aging effect.SRP-LR Section 3.2.2.2.3.2 states the following:Local loss of material from pitting and crevice corrosion could occur in thecontainment isolation valves and associated piping, and automaticdepressurizati on system piping and fittings (BWR). The GALL Reportrecommends further evaluation to ensure that the aging effect is adequately managed.In LRA Section 3.2.2.2.3.2, the applicant stated that the One-Time Inspection Program is a newAMP. The scope of this new AMP will include activities to verify potential long incubationperiods for certain aging effects on SCs. The environments applicable to this item are characteristic of long incubation periods (air/gas environments with the potential for moisture).This program is sometimes used by itself in locations where the Plant Chemistry Program will not be effective (such as air/gas or low-flow/stagnant environments). The staff determined that the use of the One-Time Inspection Program alone in certain cases, such as no-flow conditions, in which the use of the Plant Chemistry Program is not a viable option, is acceptable.The staff evaluated the Plant Chemistry and One-Time Inspection Programs and found themacceptable for managing the aging effect of local loss of material from pitting and crevice corrosion that could occur in the containment isolation valves and associated piping, and ADSpiping and fittings. SER Sections 3.0.3.2.19 and 3.0.3.1.4 document the staff's evaluation of thePlant Chemistry Program and One-Time Inspection Program, respectively.The staff evaluated both of these AMPs with respect to applications to the materials,environment, and aging effects. The applicant included an additional aging mechanism (galvanic corrosion) not consistent with the GALL Report (Sections V.C.1-a/b, V.D2.1-e). Thestaff determined that the applicant used a conservative approach for aging management byincluding this additional aging mechanism, and that this is consistent with the GALL Report for the aging effect.3.2.2.2.4 Local Loss of Material Due to Microbiologically Influenced CorrosionThe staff reviewed LRA Section 3.2.2.2.4 against the criteria in SRP-LR Section 3.2.2.2.4.In LRA Section 3.2.2.2.4, the applicant addressed loss of material due to MIC of valves andassociated piping in containment isolation.

3-178SRP-LR Section 3.2.2.2.4 states the following:Local loss of material due to microbiologically influenced corrosion (MIC) couldoccur in BWR and PWR containment isolation valves and associated piping in systems that are not addressed in other chapters of the GALL Report. The GALLReport recommends further evaluation to ensure that the aging effect is adequately managed.Although the applicant does not use this line item at MNGP, the loss of material due to MIC ispredicted for ESF system valve bodies and associated piping. The applicant credited acombination of the Plant Chemistry Program and the One-Time Inspection Program for the aging effect. The staff evaluated the Plant Chemistry Program and One-Time Inspection Program and found them acceptable for managing aging of local loss of material from MIC that could occur in the containment isolation valves and associated piping, and ADS piping andfittings. SER Sections 3.0.3.2.19 and 3.0.3.1.4 document the evaluation of the Plant ChemistryProgram and One-Time Inspection Program, respectively.The applicant's LRA is consistent with the GALL Report (Section V.C.1-a/b) for components,materials, environment, and programs for managing aging for the containment isolation valves.

Based on the information provided by the applicant, as noted in the LRA, the staff's review and audit found that the applicant's AMPs are acceptable for management of loss of material due to MIC for the containment isolation valves and associated piping.3.2.2.2.5 Changes in Properties Due to Elastomer DegradationThe staff reviewed LRA Section 3.2.2.2.5 against the criteria in SRP-LR Section 3.2.2.2.5.In LRA Section 3.2.2.2.5, the applicant addressed the change in material properties of seals inthe SGTS. The applicant stated that the One-Time Inspection Program manages the agingeffect for the internal environment and the System Condition Monitoring Program manages it for the external environment. The System Condition Monitoring Program is an existing plant-specific program.SRP-LR Section 3.2.2.2.5 states the following:Changes in properties due to elastomer degradation could occur in sealsassociated with the standby gas treatm ent system ductwork and filters. TheGALL Report recommends further evaluation to ensure that the aging effect is adequately managed.The One-Time Inspection Program is a new AMP, the scope of which includes activities toverify potential long incubation periods for certain aging effects on SCs. The environments 3-179applicable to this item are characteristic of long incubation periods (high-temperature air orozone). The staff evaluated the One-Time Inspection Program and found it acceptable and consistent with the GALL Report for managing this aging effect. SER Section 3.0.3.1.4documents the evaluation of the One-Time Inspection Program.The System Condition Monitoring Program is an existing plant-specific program that is based on system engineer monitoring, and it is used to manage the aging effect/mechanisms onsystem components in the ESF, including elastomer degradation of seals in the SGTS ductworkand filters. The staff reviewed the System Condition Monitoring Program and found it acceptable and consistent with the GALL Report for managing this aging effect/mechanism.

SER Section 3.0.3.3.2 documents the evaluation of the System Condition Monitoring Program.The staff reviewed the applicant's use of the One-time Inspection Program and SystemMonitoring Program (which is periodic) and determined that it is acceptable and consistent with the GALL Report (Sections V.B.1-b, V.B.2-b) as the programs will verify the condition of theelastomer seals and provide reasonable assurance that hardening and cracking do not occur.

The staff found that the materials, environment, aging effects, and the aging programs are consistent with the GALL Report. The applicant manages these aging effects through visual inspection of internal surfaces and monitoring of external surfaces for leakage and evidence of material degradation.On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LRSection 3.2.2.2.5. For those line items that apply to LRA Secti on 3.2.2.2.5, the staff determinedthat the applicant's AMRs are consistent with the GALL Report and the applicant hasdemonstrated that the effects of aging will be adequately managed so that the intendedfunction(s) will be maintained consistent with the CLB during the period of extended operation,as required by 10 CFR 54.21(a)(3).3.2.2.2.6 Local Loss of Material Due to Erosion The staff reviewed LRA Section 3.2.2.2.6 against the criteria in SRP-LR Section 3.2.2.2.6.In LRA Section 3.2.2.2.6, the applicant stated that this aging effect applies to PWRs only.SRP-LR Section 3.2.2.2.6 states that local loss of material due to erosion could occur in thehigh-pressure safety injection pump miniflow orifice. SRP-LR Table 3.2-1 states that further evaluation for this aging effect is for PWR plants only.The staff found this aging effect not applicable.

3.2.2.2.7 Buildup of Deposits Due to Corrosion The staff reviewed LRA Section 3.2.2.2.7 against the criteria in SRP-LR Section 3.2.2.2.7.In LRA Section 3.2.2.2.7, the applicant addressed plugging of nozzles and flow orifices in thedrywell and suppression chamber spray system due to general corrosion. The drywell andsuppression chamber spray system nozzles are fabricated from copper alloy materials, whichare not susceptible to loss of material (plugging of nozzles and flow orifices) due to general 3-180corrosion; therefore, no aging management is required. The associated GALL Report line item(Section V.D2.5-b) does not evaluate copper alloy material.SRP-LR Section 3.2.2.2.7 states the following:The plugging of components due to general corrosion could occur in the spraynozzles and flow orifices of the drywell and suppression chamber spray system.This aging mechanism and effect will apply since the spray nozzles and floworifices are occasionally wetted, even though the majority of the time this systemis on standby. The wetting and drying of these components can aid in the acceleration of this particular corrosion. The GALL Report recommends further evaluation to ensure that the aging effect is adequately managed.The staff reviewed the GALL Report (Section V.D2.5-b), which addresses only carbon steel inan air environment for drywell suppression chamber spray systems. The materials at MNGP aremade of copper in an air/potential water environment, which the GALL Report does not address. After reviewing documentation from the GALL Report for aging effects, materials, and environments, the staff concurred that these nozzles are not subject to aging effects in the environments listed according to material science evaluations (as noted below) and, therefore,are not susceptible to corrosion product buildup that could cause plugging.As shown in the Metals Handbook, Ninth Edition, Volume 13, "Corrosion," comprehensive testsover a 20-year period under the supervision of ASTM confirmed the suitability of copper alloysfor atmospheric exposure. Additionally, the gaseous internal environments to which components within the scope of license renewal may be subject include air, nitrogen, carbon dioxide, freon, and halon. Industry experience suggests that copper piping exposed to an internal gaseous operating condition will be resistant to any age-related degradation; therefore,the SC will remain capable of performing intended functions consistent with the CLB for theperiod of extended operation.On the basis of its review of current industry research and operating experience, the staff foundthat effects of the listed environments on the listed materials will not cause aging of concern during the period of extended operation; therefore, the staff concluded that there are noapplicable AERMs for the component material and environment described in the preceding discussion.On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LRSection 3.2.2.2.7. For those line items that apply to LRA Secti on 3.2.2.2.7, the staff determinedthat the applicant's AMRs are consistent with the GALL Report and the applicant hasdemonstrated that the effects of aging will be adequately managed so that the intendedfunction(s) will be maintained consistent with the CLB during the period of extended operation,as required by 10 CFR 54.21(a)(3).Conclusion. On the basis of its review, for component groups evaluated in the GALL Report forwhich the applicant has claimed consistency with the GALL Report, and for which the GALL Report recommends further evaluation, the staff determined that the applicant adequatelyaddressed the issues that were further evaluated. The staff found that the applicant hasdemonstrated that the effects of aging will be adequately managed so that intended functions 3-181will be maintained consistent with the CLB for the period of extended operation, as required by10 CFR 54.21(a)(3).3.2.2.3 AMR Results That Are Not Consistent with or Not Addressed in the GALL ReportSummary of Technical Information in the Application. In LRA Tables 3.2.2-1 through 3.2.2-8,the staff reviewed additional details of the results of the AMRs for material, environment, AERM, and AMP combinations that are not consistent with the GALL Report, or that are notaddressed in the GALL Report.In LRA Tables 3.2.2-1 through 3.2.2-8, the applicant indicated, via Notes F through J, that thecombination of component type, material, environment, and AERM does not correspond to a line item in the GALL Report, and provided information concerning the management of the aging effect. Specifically, Note F indicates that the GALL Report does not evaluate the material for the AMR line item component. Note G indicates that the GALL Report does not evaluate the environment for the AMR line item component and material. Note H indicates that the GALL Report does not evaluate the aging effect for the AMR line item component, material, and environment combination. Note I indicates that the aging effect identified in the GALL Report forthe line item component, material, and environment combination is not applicable. Note J indicates that the GALL Report evaluates neither the component nor the material andenvironment combination for the line item.Staff Evaluation. For component type, material, and environment combinations that the GALLReport does not evaluate, the staff reviewed the applicant's evaluation to determine whether theapplicant had demonstrated that the effects of aging will be adequately managed so that theintended function(s) will be maintained consistent with the CLB during the period of extendedoperation. The following sections discuss the staff's evaluation.In LRA Tables 3.2.2-1 through 3.2.2-8, the staff identified AMR line items for which theapplicant stated that there were no aging effects as a result of the AMR process. In mostinstances, the applicant identified materials that have no aging effects in the environments theyare exposed to during plant operations. The applicant stated that no aging effects occur forESF system components fabricated from the following materials: *copper *carbon steel

  • nickel alloy
  • stainless steel
  • CASS
  • insulationThese materials are exposed to the following environments:
  • plant indoor air (external/internal) *primary containment air (external/internal)
  • air/gas (internal)
  • gas-instrument air (internal)
  • gas-nitrogen (internal) 3-182 *lubricating oil (external/internal) *outdoor air protectedThe applicant stated that components fabricated from these materials in these environmentshave no aging effects based on material science evaluations of these materials exposed to atmospheric conditions. Specifically, the applicant stated that no aging effects occur whencomponents fabricated from stainless steel material are exposed to a primary containment air, plant indoor air (and outdoor air protected), lubricating oil, or gas (instrument air) environment,or when components fabricated from copper alloys are exposed to a primary containment air, plant indoor air, lubricating oil, or gas (instrument air) environment. The applicant also stated that no aging effects occur in components fabricated from carbon steel in a gas (nitrogen or instrument air) or lubricating oil environment. In addition, the applicant stated that no agingeffects occur in components fabricated from CASS or nickel alloys in a primary containment air or plant indoor air environment. The applicant stated that a material science evaluation for these materials in these environments found no aging effects.The GALL Report states that steel, copper, nickel alloy, and stainless steel in an environment ofplant indoor air (external), gas, and lubricating oil are not subject to any aging mechanisms.

The staff reviewed this technical information against LRA Tables 3.2.2-1 through 3.2.2-8 and concluded that the applicant's analysis of the material and environment combinations will allowcomponents within the scope of license renewal fabricated from these materials in these environments to perform their intended functions through the period of extended operation. Thisconclusion is based on industry and plant operating experience of these components in these environments.As cited in Metals Handbook, Ninth Edition, Volume 13, stainless steels are highly resistant tocorrosion in dry atmospheres in the absence of corrosive species; therefore, stainless steel in an indoor, uncontrolled air environment (e.g., plant indoor air) or in a gas environment (e.g.,

primary containment air inerted with nitrogen) exhibits no aging effect, and such an SC willremain capable of performing intended functions consistent with the CLB for the period of extended operation. Because both oxygen and moisture must be present to corrode steel, as cited in Metals Handbook, Ninth Edition, steel (carbon or stainless) and copper alloys in alubricating oil internal environment with no water pooling exhibit no aging effect, and such an SC will therefore remain capable of performing intended functions consistent with the CLB forthe period of extended operation. Because components fabricated from CASS, copper, andnickel alloys are highly resistant to corrosion in dry atmospheres in the absence of corrosive species, as cited in the Metals Handbook, Ninth Edition, the staff accepted the position thatCASS, copper, and nickel alloys in an indoor (primary containment), uncontrolled air environment (e.g., plant indoor air), or gas environment (e.g., plant instrument air) exhibit no aging effect, and such SCs will therefore remain capable of performing intended functionsconsistent with the CLB for the period of extended operation.LRA Tables 3.2.2.4 and 3.2.2.7 list insulation for piping and heat exchangers in the HPC andRHR systems exposed to plant indoor air. LRA Section 3.2.1 states that the GALL Report doesnot show this material for this component as subject to aging management.The staff reviewed technical information based on industry experience and concluded that theapplicant's analysis of the material and environment is acceptable, and insulation exposed to 3-183plant indoor air will remain capable of performing its intended function during the period ofextended operation.The staff reviewed the materials and environments for this section and compared thisinformation with the technical references noted above. Except for carbon steel in outdoor air, the ESF components fabricated from carbon steel, nickel alloy, stainless steel, CASS, and insulation subject to plant indoor air (external/internal), primary containment air (external/internal), air/gas (internal), gas (instrument air/nitrogen), lubricating oil (external/internal), or outdoor air are not subject to aging effects/mechanisms.On the basis of its review of current industry research and operating experience, the staff foundthat the listed materials in the listed environments will not experience aging effects of concern during the period of extended operation; therefore, the staff concluded that there are noapplicable AERMs for the component material and environment described in the preceding discussion.3.2.2.3.1Engineered Safety Features-Automatic Pressure Relief System-Summary ofAging Management Evaluation-Table 3.2.2-1The staff reviewed LRA Table 3.2.2-1, which summarizes the results of AMR evaluations for theautomatic pressure relief system component groups.All line items in this table are consistent with the GALL Report or are included in the discussionin Section 3.2.2.3 above.3.2.2.3.2Engineered Safety Features-Combustible Gas Control System-Summary of AgingManagement Evaluation-Table 3.2.2-2In its letter dated March 15, 2006, the applicant stated that it deactivated the CGC system bycutting and capping process lines connecting to interfacing systems during the 2005 refuelingoutage because of NRC approval of License Amendment 138, which eliminated therequirements for hydrogen recombiners and relaxed the requirements for hydrogen and oxygen monitoring. Therefore, the system has been removed from the scope of license renewal.3.2.2.3.3Engineered Safety Features-Core Spray System-Summary of Aging ManagementEvaluation-Table 3.2.2-3The staff reviewed LRA Table 3.2.2-3, which summarizes the results of AMR evaluations for theCSP system component groups.In LRA Table 3.2.2-3, the applicant proposed to manage loss of material due to crevicecorrosion, MIC, and pitting corrosion of copper alloys for ESF heat exchangers exposed to a raw water environment using the Open-Cycle Cooling Water Program.The OCCW System Program relies on the implementation of the recommendations of GL 89-13to ensure that the effects of aging on the raw water service water systems will be managed forthe period of extended operation. This program manages the aging effects of meta lliccomponents in water systems (e.g., piping and heat exchangers) exposed to raw, untreated(e.g., service) water. The staff reviewed the OCCW System Program and found it to be 3-184acceptable and consistent with the GALL Report. SER Section 3.0.3.1.5 documents theevaluation of the OCCW System Program. The staff determined that this AMP is adequate formanaging this material, environment, and aging effect.In LRA Table 3.2.2-3, the applicant proposed to manage loss of material due to selectiveleaching of copper alloys for ESF heat exchangers in a raw water environment using the Selective Leaching of Materials Program.The staff reviewed the applicant's Selective Leaching of Materials Program, and SERSection 3.0.3.2.22 documents its evaluation. This new program includes a one-time visualinspection and hardness measurement of certain components susceptible to selective leaching.

The program will determine if selective leaching occurs for certain components. The staffdetermined that this AMP is adequate for managing this material, environment, and aging effect.the aging effect of loss of material dueto crevice corrosion, MIC, and pitting corrosion and loss of material due to selective leaching of copper alloys for ESF heat exchangers exposed to raw water environment in LRA Table 3.2.2-3 are effectively managed using the OCCW System Program and the Selective Leaching of Materials Program, respectively.3.2.2.3.4Engineered Safety Features-High-Pressure Coolant Injection System-Summaryof Aging Management Evaluation-Table 3.2.2-4The staff reviewed LRA Table 3.2.2-4, which summarizes the results of AMR evaluations for theHPC system component groups.In LRA Table 3.2.2-4, the applicant proposed to manage heat transfer degradation and foulingof heat exchangers fabricated from copper alloy in lubricating oil (external)/treated water (internal) environments with the One-Time Inspection Program, and in steam (external)/treated water (internal) environments using the Plant Chemistry Program combined with the One-TimeInspection Program. The applicant also proposed to manage the loss of material due to crevice corrosion and pitting corrosion of heat exchangers fabricated from copper alloy in steam (external)/treated water (internal) environments, and MIC in a treated water (internal) environment using the Plant Chemistry Program, combined with the One-Time Inspection Program.The staff reviewed the applicant's Plant Chemistry Program and the One-Time InspectionProgram, and SER Sections 3.0.3.2.19 and 3.0.3.1.4, respectively, document its evaluation ofeach. The Plant Chemistry Program mitigates the aging effects on component surfaces exposed to water as the process fluid; chemistry programs are used to control water chemistry for impurities (e.g., chloride and sulfate) that accelerate corrosion or crack initiation and growth or that cause heat transfer degradation due to fouling in select heat exchangers. This program relies on monitoring and control of water chemistry to keep peak levels of various contaminants below system-specific limits. The new One-Time Inspection Program is consistent with therecommendations of GALL AMP XI.M32. This program will include measures to verify theeffectiveness of the Plant Chemistry Program. This program will also confirm the absence of age degradation in selected components (e.g., flow restrictors, venturis, and small bore piping) 3-185within the scope of license renewal. The One-Time Inspection Program addresses concernsand provides confirmation for the potential long incubation period for certain aging effects on SCs. If system contaminants are maintained within the limits specified by the Plant ChemistryProgram, the corrosion exhibited by the copper alloy in a closed system is adequatelymanaged. The applicant has chosen a different combination of AMPs to manage the AERM.

The staff found this combination adequate and acceptable for managing this material, environment, and aging effect, because contaminants are maintained within limits to inhibit corrosion of the copper alloy.The staff's review of LRA Section 3.2 identified areas for which it needed additional informationto complete its evaluation of the applicant's results. The applicant responded to the staff's RAIs as discussed below.In RAI 3.2-1, dated July 20, 2005, the staff noted that in LRA Table 3.2.2-4, the applicant statedthat it would manage heat transfer degradation due to fouling of heat exchangers fabricatedfrom copper alloy in a lubricating oil environment using the One Time Inspection Program. On the basis of the staff's review of the information provided in the LRA, it was not clear what preventive measures the applicant was taking to ensure that the lubricating oil remains free ofcontaminants that might degrade the tubing. Therefore, the staff requested that the applicantprovide the following:iiii)Specific material composition of the copper alloys.jjjj)A description of the oil analysis program and/or other methods to ensure thatthe lubricating oil remains free of contaminants which might degrade the tubing.kkkk)PM procedures to ensure that heat transfer degradation does not reachunacceptable levels.In its response, by letter dated August 16, 2005, the applicant stated the following:llll)The High Pressure Coolant Injection System (HPC) lubricating oilcooler (E-206) is an American Standard (Whitlock) cooler of carbon steel construction with 5/8" O.D. Admiralty tubes in accordance with the vendor's technical manual. Admiralty brass is composed of 71Cu-28Zn-1Sn.

mmmm)Lube oil samples from the HPC lube oil cooler are obtained everysix months in accordance with MNGP site procedures, and the sample results are evaluated and trended. These parameters include iron, copper, etc. for indications of wear, dielectric, viscosity, etc. for chemical analysis and water, silicon, etc. forindication of contamination. Sampling is performed IAW EPRI 1007459 (November 2002) for the HPC lube oil cooler.

Electric Power Research Institute (EPRI) Report 1007459 recommends that 'oil moisture content be verified on a monthly basis and that acidity, viscosity, and particle count be verified each quarter until a data trending program can justify extending the inspection frequency.' This frequency, based upon data trending results, was extended to a six-month frequency. Any 3-186indication of an anomalous condition or adverse trend will result inan investigation under the site corrective action program. All results have been acceptable to date to ensure that the lubricatingoil remains free of contaminants that could potentially degrade the heat exchanger (cooler) tubes, with the last sample taken and evaluated in March 2005.nnnn)Preventive maintenance procedures are in effect to both clean andinspect the HPC lube oil cooler and perform eddy current testing every three cycles. Eddy current testing was last performed in January 2000 onthe originally installed cooler. All tubes were inspected. No tubes required plugging and no unacceptable defects were detected.Based on its review, the staff found the applicant's response to RAI 3.2-1 acceptable becausethe lube oil coolers are monitored and tested in accordance with industry standards and NRC guidelines. In addition, the applicant's operational experience supports the adequacy of its maintenance practices; therefore, the staff's concern described in RAI 3.2-1 is resolved.In RAI 3.2-2, dated July 20, 2005, the staff noted that in LRA Table 3.2.2-4, the applicant statedthat it will manage heat transfer degradation due to fouling of the copper alloy heat exchangertubes in a steam environment with the Plant Chemistry and One-Time Inspection Programs.

The applicant further stated that the GALL Report does not evaluate either the components orthe material and environment combination; therefore, the staff requested that the applicantverify that the steam in the heat exchangers identified above originated from treated water. Inaddition, the staff requested the applicant to justify not considering erosion and FAC as agingmechanisms for this material and environment combination.In its response, by letter dated August 16, 2005, the applicant stated the following:Per LRA 2.3.2.4, High Pressure Coolant Injection (HPC) System, 'The HPCturbine is driven with steam from the RPV. Two sources of water are available for the HPC System. Normally, water is supplied to the suction of the HPC pump from the two condensate storage tanks (CST). When the level in either CST falls to the predetermined setpoint, the pump suction is automatically transferred to the suppression pool.' The HPC heat exchanger in question is the HPC Gland Seal Condenser, E-204, which condenses the gland seal steam from the HPC turbine by using cooling water from the discharge of the HPC pump. Therefore, the steam in this heat exchanger is produced by the treated water in the RPV.EPRI NSAC 202L, R2, 'Recommendations for an Effective Flow-AcceleratedCorrosion (FAC) Program,' page 4-3, allows an exclusion from FAC for systemswhich operate less than 2% of the time, which would be applicable to this HPC condenser. In addition, this component is not subject to high velocity, constricted flow, or fluid direction changes. Therefore, in accordance with EPRI 1003056,

'Non-Class 1 Mechanical Implementation Guideline and Mechanical Tools,'

Revision 3, loss of material due to erosion or FAC are not potential aging mechanisms.

3-187Based on its review, the staff found the applicant's response to RAI 3.2-2 acceptable becausethe applicant provided satisfactory explanations of the purity of the steam environment and the absence of erosion and FAC as aging mechanisms for the heat exchanger in question; therefore, the staff's concern described in RAI 3.2-2 is resolved.In LRA Table 3.2.2-4, the applicant proposed to manage the loss of material due to selectiveleaching of heat exchangers fabricated from copper alloy in a steam (external)/treated water (internal) environment with the Selective Leaching of Materials Program.The staff reviewed the applicant's Selective Leaching of Materials Program, and SERSection 3.0.3.2.22 documents its evaluation. This new program includes a one-time visualinspection and hardness measurement of selected components susceptible to selective leaching. The program will determine if selective leaching occurs for selected components. Thestaff found this program adequate for managing this material, environment, and aging effect.3.2.2.3.5Engineered Safety Features-Primary Containment Mechanical System-Summaryof Aging Management Evaluation-Table 3.2.2-5The staff reviewed LRA Table 3.2.2-5, which summarizes the results of AMR evaluations for theprimary containment mechanical system component groups.All line items in this table are consistent with the GALL Report or are included in the discussionin Section 3.2.2.3 above.3.2.2.3.6Engineered Safety Features-Reactor Core Isolation Cooling System-Summary ofAging Management Evaluation-Table 3.2.2-6The staff reviewed LRA Table 3.2.2-6, which summarizes the results of AMR evaluations for theRCI system component groups.In LRA Table 3.2.2-6, the applicant proposed to manage heat transfer degradation and foulingof heat exchangers fabricated from copper alloy in a lubricating oil (external) environment with the One-Time Inspection Program, and in a treated water (internal) environment with the Plant Chemistry Program, combined with the One-Time Inspection Program. The applicant also proposed to manage the loss of material due to crevice corrosion, pitting corrosion, and MIC of heat exchangers fabricated from copper alloy in a treated water (internal) environment with the Plant Chemistry Program, combined with the One-Time Inspection Program.The staff reviewed and evaluated the applicant's Plant Chemistry Program and the One-TimeInspection Program, as documented in SER Sections 3.0.3.2.19 and 3.0.3.1.4, respectively.The Plant Chemistry Program mitigates the aging effects on component surfaces exposed to water as the process fluid; chemistry programs are used to control water chemistry for impurities (e.g., chloride and sulfate) that accelerate corrosion or crack initiation and growth or that cause heat transfer degradation due to fouling in select heat exchangers. This program relies on monitoring and control of water chemistry to keep peak levels of various contaminants below system-specific limits. The new One-Time Inspection Program is consistent with therecommendations of GALL AMP XI.M32. This program will include measures to verify theeffectiveness of the Plant Chemistry Program. This program will also confirm the absence of age degradation in selected components (e.g., flow restrictors, venturis, and small bore piping) 3-188within scope of license renewal. The One-Time Inspection Program addresses concerns andprovides confirmation for the potential long incubation period for certain aging effects on SCs. If system contaminants are maintained within the limits specified by the Plant Chemistry Program,the corrosion exhibited by the copper alloy in a closed system is adequately managed. Theapplicant has chosen a different combination of AMPs to manage the AERM. The staff found this combination adequate and acceptable for managing this material, environment, and aging effect, because contaminants are maintained within limits to inhibit corrosion of the copper alloy.The response to RAI 3.2-1, discussed in SER Section 3.2.2.3.4, is generally applicable to thecopper alloy components of the heat exchangers in the RCI system.The staff found the applicant's response reasonable and acceptable because the lube oilcoolers are monitored and tested in accordance with industry standards and NRC guidelines. Inaddition, the applicant's operational experience supports the adequacy of its maintenancepractices.In LRA Table 3.2.2-6, the applicant proposed to manage the loss of material due to selectiveleaching of heat exchangers fabricated from copper alloy in a treated water (internal) environment using the Selective Leaching of Materials Program.The staff reviewed and evaluated the applicant's Selective Leaching of Materials Program, asdocumented in SER Section 3.0.3.2.22. This new program includes a one-time visual inspection and hardness measurement of certain components susceptible to selective leaching. The program will determine if selective leaching occurs for certain components. The staff found thisprogram adequate and acceptable for managing this material, environment, and aging effect.3.2.2.3.7Engineered Safety Features-Residual Heat Removal System-Summary of AgingManagement Evaluation-Table 3.2.2-7The staff reviewed LRA Table 3.2.2-7, which summarizes the results of AMR evaluations for theRHR system component groups.In LRA Table 3.2.2-7, the applicant proposed to manage heat transfer degradation and foulingof heat exchangers fabricated from copper alloy in a lubricating oil (external) environment with the One-Time Inspection Program, and in a raw water (internal) environment using the Open-Cycle Cooling Water System Program. The applicant also proposed to manage the loss of material due to crevice corrosion, MIC, and pitting corrosion of heat exchangers fabricated from copper alloy in a raw water (internal) environment using the Open-Cycle Cooling Water System Program.The staff reviewed and evaluated the applicant's One-Time Inspection Program, asdocumented in SER Section 3.0.3.1.4. The new One-Time Inspection Program, consistent withthe recommendations of GALL AMP XI.M32, will confirm the absence of age degradation inselected components (e.g., flow restrictors, venturis, and small bore piping) within the scope of license renewal. The One-Time Inspection Program addresses concerns and provides confirmation for the potential long incubation period for certain aging effects on SCs.

3-189The OCCW System Program relies on the implementation of the recommendations of GL 89-13to ensure that the effects of aging on the raw water service water systems will be managed forthe period of extended operation. This program manages the aging effects of meta lliccomponents in water systems (e.g., piping and heat exchangers) exposed to raw, untreated(e.g., service) water. The staff reviewed the OCCW System Program and found it acceptable and consistent with the GALL Report. SER Section 3.0.3.1.5 documents the evaluation of theOCCW System Program. The staff has found this AMP adequate and acceptable for managing this material, environment, and aging effect.In LRA Table 3.2.2-7, the applicant proposed to manage the loss of material due to MIC,crevice corrosion, and pitting corrosion of RHR nozzles fabricated from copper alloy in a treatedwater (internal) environment with the Plant Chemistry Program, combined with the One-Time Inspection Program.The staff reviewed and evaluated the applicant's Plant Chemistry Program and the One-TimeInspection Program, as documented in SER Sections 3.0.3.2.19 and 3.0.3.1.4, respectively.The Plant Chemistry Program mitigates the aging effects on component surfaces exposed to water as the process fluid; chemistry programs are used to control water chemistry for impurities (e.g., chloride and sulfate) that accelerate corrosion or crack initiation and growth, or that cause heat transfer degradation due to fouling in select heat exchangers. This program relies on monitoring and control of water chemistry to keep peak levels of various contaminants below system-specific limits.The new One-Time Inspection Program, consistent with the recommendations of GALL AMPXI.M32, will include measures to verify the effectiveness of the Plant Chemistry Program andwill also confirm the absence of age degradation in selected components (e.g., flow restrictors,venturis, and small bore piping) within the scope of license renewal. The One-Time Inspection Program addresses concerns and provides confirmation for the potential long incubation period for certain aging effects on SCs. If system contaminants are maintained within the limitsspecified by the Plant Chemistry Program, the corrosion exhibited by the copper alloy in a closed system is adequately managed. The applicant has chosen a different combination ofAMPs to manage the AERM. The staff found this combination adequate and acceptable for managing this material, environment, and aging effect, because contaminants are maintained within limits to inhibit corrosion of the copper alloy.In LRA Table 3.2.2-7, the applicant proposed to manage the loss of material due to selectiveleaching of heat exchangers fabricated from copper alloy in a raw water (internal) environment, and RHR nozzles fabricated from copper alloy in a treated water (internal) environment with theSelective Leaching of Materials Program.The staff reviewed and evaluated the applicant's Selective Leaching of Materials Program, asdocumented in SER Section 3.0.3.2.22. This new program includes a one-time visual inspection and hardness measurement of certain components susceptible to selective leaching. Because the program will determine if selective leaching occurs for certain components, the staff foundthis AMP adequate and acceptable for managing this material, environment, and aging effect.In LRA Table 3.2.2-7, the applicant contends that no aging effects are associated with thermalinsulation installed on heat exchangers and exposed to an indoor plant air environment. The 3-190staff concurred with the applicant's assessment and found the applicant's routine maintenancepractices adequate to maintain the thermal insulation of the RHR heat exchangers effectively.3.2.2.3.8Engineered Safety Features-Secondary Containment System-Summary of AgingManagement Evaluation-Table 3.2.2-8The staff reviewed LRA Table 3.2.2-8, which summarizes the results of AMR evaluations for thesecondary containment system component groups.All line items in this table are consistent with the GALL Report or are included in the discussionin Section 3.2.2.3 above.Conclusion. On the basis of its review, the staff found that the applicant appropriately evaluatedAMR results involving material, environment, AERMs, and AMP combinations that are not evaluated in the GALL Report. The staff found that the applicant has demonstrated that theeffects of aging will be adequately managed so that intended functions will be maintainedconsistent with the CLB for the period of extended operation, as required by10 CFR 54.21(a)(3).3.2.3 Conclusion The staff concluded that the applicant provided sufficient information to demonstrate that theeffects of aging for the ESF 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 bemaintained consistent with the CLB for the period of extended operation, as required by10 CFR 54.21(a)(3).The staff also reviewed the applicable USAR supplement program summaries and concludedthat they adequately describe the AMPs credited for managing aging of the ESF, as required by10 CFR 54.21(d).3.3 Aging Management of Auxiliary SystemsThis section of the SER documents the staff's review of the applicant's AMR results for theauxiliary systems components and component groups associated with the following systems:

  • alternate nitr ogen system
  • chemistry sampling system
  • demineralized water system
  • emergency filtration train system
  • fire system 3-191
  • heating and ventilati on syst em
  • instrument and service air system
  • radwaste solid and liquid system
  • reactor building closed cooling water system
  • reactor water cl eanup system
  • service and seal water system
  • wells and domestic water system3.3.1 Summary of Technical Information in the Application In LRA Section 3.3, the applicant provided AMR results for the auxiliary systems com ponentsand component groups. In LRA Table 3.3.1,the applicant provided a summary comparison of its AMRs with the AMRs evaluated in the GALL Report for the auxiliary systems components andcomponent groups.The applicant's AMRs incorporated applicable operating experience in the determination ofAERMs. These reviews included evaluation of plant-specific and industry operating experience.

The plant-specific evaluation included reviews of CRs and discussions with appropriate site personnel to identify AERMs. The applicant's review of industry operating experience included a review of the GALL Report and operating experience issues identified since the issuance of the GALL Report.3.3.2 Staff Evaluation The staff reviewed LRA Section 3.3 to determine if the applicant provided sufficient informationto demonstrate that the effects of aging for the auxiliary systems components that are within thescope of license renewal and subject to an AMR will be adequately managed so that intendedfunctions will be maintained consistent with the CLB for the period of extended operation, asrequired by 10 CFR 54.21(a)(3).In addition, the staff performed an onsite audit of AMRs to confirm the applicant's claim thatcertain identified AMRs are consistent with the GALL Report. The staff did not repeat its reviewof the matters described in the GALL Report; however, the staff did verify that the material presented in the LRA is applicable and that the applicant identified the appropriate GALLReport AMRs. SER Section 3.0.3 documents the staff's evaluations of the AMPs. The MNGP audit and review report details the staff's audit evaluation, which is summarized in SER Section 3.3.2.1.The staff also performed an onsite audit of those selected AMRs that were consistent with theGALL Report and for which further evaluation is recommended. The staff confirmed that the applicant's further evaluations were consistent with the acceptance criteria in Section 3.3.2.2 ofthe SRP-LR. The staff's audit evaluations are documented in the MNGP audit and review report and are summarized in SER Section 3.3.2.2.The staff performed an onsite audit and conducted a technical review of the remaining AMRsthat are not consistent with, or not addressed in, the GALL Report. The audit and technical 3-192review included evaluating whether the applicant identified all plausible aging effects andwhether the aging effects listed are appropriate for the combination of materials and environments specified. The MNGP audit and review report documents the staff's audit evaluations. SER Section 3.3.2.3 summarizes the staff's audit evaluations and documents itstechnical review.Finally, the staff reviewed the AMP summary descriptions in the USAR supplement to ensurethat they adequately describe the programs credited with managing or monitoring aging for theauxiliary systems components.Table 3.3-1 below summarizes the staff's evaluation of components, aging effects/mechanisms,and AMPs listed in LRA Section 3.3 that are addressed in the GALL Report.Table 3.3-1 Staff Evaluation for Auxiliary Systems Components in the GALL ReportComponent GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff EvaluationComponents inspent fuel poolcooling and cleanup(Item Number3.3.1-01)Loss of materialdue to general,pitting, and crevicecorrosionWater chemistry,one-time inspectionOne-TimeInspection Program(B2.1.23), PlantChemistry Program(B2.1.25) Consistent withGALL, whichrecommends furtherevaluation (seeSection 3.3.2.2.1)Linings in spent fuelpool cooling andcleanup system,seals and collars inventilation systems(Item Number3.3.1-02)Hardening, crackingand loss of strengthdue to elastomerdegradation; loss ofmaterial due towearPlant specificNot applicable (seeSection 3.3.2.2.2)Components in loadhandling, chemicaland volume controlsystem (PWR), andreactor watercleanup andshutdown coolingsystems (olderBWR)(Item Number3.3.1-03)Cumulative fatiguedamageTLAA, evaluated inaccordance with10 CFR 54.21(c)TLAAThis TLAA isevaluated in Section4.3, Metal Fatigueof the RPV andInternals, andReactor CoolantPressure BoundaryPiping andComponents andSection 4.9,Reactor BuildingCrane Load CyclesHeat exchangers inreactor watercleanup system(BWR); highpressure pumps inchemical andvolume controlsystem (PWR)(Item Number3.3.1-04)Crack initiation andgrowth due to SCCor crackingPlant specific Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation3-193Components inventilation systems,diesel fuel oilsystem, andemergency dieselgenerator systems;external surfaces ofcarbon steelcomponents(Item Number3.3.1-05)Loss of materialdue to general,pitting, and crevicecorrosion, and MICPlant specificFire ProtectionProgram (B2.1.17),Fire Water SystemProgram (B2.1.18),One-TimeInspection Program(B2.1.23), SystemCondition MonitoringProgram (B2.1.32) Components in reactor coolantpump oil collectsystem of fireprotection(Item Number3.3.1-06)Loss of materialdue to galvanic,general, pitting, andcrevice corrosionOne-timeinspectionNot applicable (seeSection 3.3.2.2.6)Diesel fuel oil tanksin diesel fuel oilsystem andemergency dieselgenerator system(Item Number3.3.1-07)Loss of materialdue to general,pitting, and crevicecorrosion, MIC, andbiofoulingFuel oil chemistry,one-time inspectionPiping, pumpcasing, and valvebody and bonnets inshutdown coolingsystem (older BWR)(Item Number3.3.1-08)Loss of materialdue to pitting andcrevice corrosionWater chemistry,one-time inspectionCompressed AirMonitoring Program(B2.1.14), One-TimeInspection Program(B2.1.23), PlantChemistry Program(B2.1.25)Heat exchangers in chemical andvolume controlsystem(Item Number3.3.1-09)Crack initiation andgrowth due to SCCand cyclic loadingWater chemistryand a plant-specificverification programNot applicable,PWR onlyNeutron-absorbingsheets in spent fuelstorage racks(Item Number3.3.1-10)Reduction ofneutron-absorbingcapacity and loss ofmaterial due togeneral corrosion(boral, boron steel)Plant specificOne-TimeInspection Program(B2.1.23), PlantChemistry Program(B2.1.25)Consistent withGALL, whichrecommends furtherevaluation (seeSection 3.3.2.2.10)New fuel rackassembly(Item Number3.3.1-11)Loss of materialdue to general,pitting, and crevicecorrosionStructuresmonitoringNoneNot applicable Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation3-194Neutron-absorbingsheets in spent fuelstorage racks(Item Number3.3.1-12)Reduction ofneutron-absorbingcapacity due toBoraflexdegradationBoraflex monitoringSpent fuel storageracks and valves inspent fuel poolcooling and cleanup(Item Number3.3.1-13)Crack initiation andgrowth due to stresscorrosion crackingWater chemistryPlant ChemistryProgram (B2.1.25) Closure bolting and external surfaces ofcarbon steel andlow-alloy steelcomponents(Item Number3.3.1-14)Loss of materialdue to boric acidcorrosionBoric acid corrosionComponents in orserviced byclosed-cycle coolingwater system(Item Number3.3.1-15)Loss of materialdue to general,pitting, and crevicecorrosion, and MICClosed-cyclecooling watersystemCranes includingbridge and trolleysand rail system inload handlingsystem(Item Number3.3.1-16)Loss of materialdue to generalcorrosion and wearOverhead heavyload and light loadhandling systemsInspection ofOverhead HeavyLoad and Light Load(Related toRefueling) HandlingSystems Program(B2.1.22)Components in or serviced byopen-cycle coolingwater systems(Item Number3.3.1-17)Loss of materialdue to general,pitting, crevice, andgalvanic corrosion,MIC, and biofouling;buildup of depositdue to biofoulingOpen-cycle coolingwater systemOne-TimeInspection Program(B2.1.23),Open-Cycle CoolingWater SystemProgram (B2.1.24)Consistent withGALL Report, whichrecommends nofurther evaluationBuried piping andfittings(Item Number3.3.1-18)Loss of materialdue to general,pitting, and crevicecorrosion, and MICBuried piping andtanks surveillance or Buried piping andtanks inspectionBolting IntegrityProgram (B2.1.4),Buried Piping &Tanks InspectionProgram (B2.1.5)

Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation3-195Components incompressed airsystem(Item Number3.3.1-19)Loss of materialdue to general andpitting corrosionCompressed airmonitoringComponents (doorsand barrierpenetration seals)and concretestructures in fireprotection(Item Number3.3.1-20)Loss of materialdue to wear;hardening andshrinkage due toweatheringFire protectionFire ProtectionProgram (B2.1.17)Components in water-based fireprotection(Item Number3.3.1-21)Loss of materialdue to general,pitting, crevice, andgalvanic corrosion,MIC, and biofoulingFire water systemFire ProtectionProgram (B2.1.17),Fire Water SystemProgram (B2.1.18) (seeSection 3.3.2.1.1)Components indiesel fire system(Item Number3.3.1-22)Loss of materialdue to galvanic,general, pitting, andcrevice corrosionFire protection, fueloil chemistryFire ProtectionProgram (B2.1.17),Fuel Oil ChemistryProgram (B2.1.20),One-TimeInspection Program(B2.1.23),and the aging effectis managed by theFuel Oil Chemistryand One-TimeInspectionProgramsTanks in diesel fueloil system(Item Number3.3.1-23)Loss of materialdue to general,pitting, and crevicecorrosionAbovegroundcarbon steel tanks Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation3-196Closure bolting(Item Number3.3.1-24)Loss of materialdue to generalcorrosion, crackinitiation and growthdue to cyclicloading and SCCBolting integrityBolting IntegrityProgram (B2.1.4) Components in contact with sodiumpentaboratesolution in standbyliquid controlsystem (BWR)(Item Number3.3.1-25)Crack initiation andgrowth due to SCCWater chemistryNot applicable. AtMNGP, thecomponentsexposed to sodiumpentaboratesolution are in anenvironment suchthat thecomponents are notsusceptible to SCCComponents inreactor watercleanup system(Item Number3.3.1-26)Crack initiation andgrowth due to SCCand IGSCCReactor watercleanup systeminspectionConsistent withGALL Report, whichrecommends nofurther evaluationComponents inshutdown coolingsystem (older BWR)(Item Number3.3.1-27)Crack initiation andgrowth due to SCCBWR stresscorrosion crackingand waterchemistryBWR StressCorrosion CrackingProgram (B2.1.10),Closed-CycleCooling WaterSystem Program(B2.1.13), One-TimeInspection Program(B2.1.23), PlantChemistry Program(B2.1.25) Consistent withGALL Report, whichrecommends nofurther evaluationComponents inshutdown coolingsystem (older BWR)(Item Number3.3.1-28)Loss of materialdue to pitting andcrevice corrosion,and MICClosed-cyclecooling watersystemComponents (aluminum bronze,brass, cast iron,cast steel) inopen-cycle andclosed-cycle coolingwater systems, andultimate heat sink(Item Number3.3.1-29)Loss of materialdue to selectiveleachingSelective leachingof materialsSelective Leachingof MaterialsProgram (B2.1.30)Consistent withGALL Report, whichrecommends nofurther evaluation Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation3-197Fire barriers, walls,ceilings, and floorsin fire protection(Item Number3.3.1-30)Concrete crackingand spalling due tofreeze-thaw,aggressivechemical attack,and reaction withaggregates; loss ofmaterial due tocorrosion ofembedded steelFire protection,structuresmonitoringFire ProtectionProgram (B2.1.17),StructuresMonitoring Program(B2.1.31)Consistent withGALL Report, whichrecommends nofurther evaluationThe staff's review of the MNGP component groups followed one of several approaches. Oneapproach, documented in SER Section 3.3.2.1, involves the staff's review of the AMR resultsfor components in the auxiliary systems that the applicant indicated are consistent with theGALL Report and do not require further evaluation. Another approach, documented in SERSection 3.3.2.2, involves the staff's review of the AMR results for components in the auxiliarysystems that the applicant indicated are consistent with the GALL Report and for which furtherevaluation is recommended. A third approach, documented in SER Section 3.3.2.3, involves thestaff's review of the AMR results for components in the auxiliary systems that the applicantindicated are not consistent with, or not addressed in, the GALL Report. SER Section 3.0.3documents the staff's review of AMPs that are credited to manage or monitor aging effects of the auxiliary systems components.3.3.2.1 AMR Results That Are Consistent with the GALL Report Summary of Technical Information in the Application. In LRA Section 3.3.2.1, the applicantidentified the materials, environments, and AERMs. The applicant identified the following programs that manage the aging effects related to the auxiliary systems components:

  • Bolting Integrity Program (B2.1.4)
  • Buried Piping & Tanks Inspection Program (B2.1.5)
  • Closed-Cycle Cooling Water System Program (B2.1.13)
  • Compressed Air Monitoring Program (B2.1.14)
  • Fire Water System Program (B2.1.18)
  • Flow-Accelerated Corrosion Program (B2.1.19)
  • Fuel Oil Chemistry Program (B2.1.20)
  • One-Time Inspection Program (B2.1.23)
  • Open-Cycle Cooling Water System Program (B2.1.24)
  • Plant Chemistry Program (B2.1.25)
  • Selective Leaching of Materials Program (B2.1.30)
  • System Condition Monitoring Program (B2.1.32)Staff Evaluation. In LRA Tables 3.3.2-1 through 3.3.2-18, the applicant summarized the AMRsfor the auxiliary systems components and identified which AMRs it considered to be consistentwith the GALL Report.

3-198For component groups evaluated in the GALL Report for which the applicant has claimedconsistency with the GALL Report, and for which the GALL Report does not recommend further evaluation, the staff performed an audit and review to determine whether the GALL Reportevaluation bounds the plant-specific components contained in these GALL Report componentgroups.The applicant provided a note for each AMR line item. The notes describe how the informationin the tables aligns with the information in the GALL Report. The staff audited those AMRs with Notes A through E, which indicate that 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 AMP identified in the GALL Report. The staff audited these line items to verify consistency with the GALL Report and the validity of the AMR for the site-specific conditions.Note B 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 AMP identified in the GALL Report. The staff audited these line items to verify consistency with the GALL Report. The staff verified that it had reviewed and accepted the identified exceptionsto the GALL Report AMPs. The staff also determined whether the AMP identified by the applicant is consistent with the AMP identified in the GALL Report and whether the AMR is validfor the site-specific conditions.Note C indicates that the component for the AMR line item, although different, is consistent withthe GALL Report for material, environment, and aging effect. In addition, the AMP is consistent with the AMP identified by the GALL Report. This note indicates that the applicant could not finda listing of some system components in the GALL Report; however, the applicant identified adifferent component in the GALL Report that has 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 determined whether the AMR line item of the different component is applicable to the component under review and whether the AMR is valid for the site-specific conditions.Note D indicates that the component for the AMR line item, although different, is consistent withthe GALL Report for material, environment, and aging effect. In addition, the AMP takes some exceptions to the AMP identified in the GALL Report. The staff audited these line items to verify consistency with the GALL Report. The staff verified whether the AMR line item of the different component applies to the component under review. The staff verified whether it had reviewed and accepted the identified exceptions to the GALL Report AMPs. The staff also determinedwhether the AMP identified by the applicant is consistent with the AMP identified in the GALLReport and whether the AMR is 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 the applicant credited a different AMP. The staff audited these line items to verify consistency with the GALL Report. The staff also determined whether the identified AMP will manage the aging effect consistent with the AMP identified by the GALLReport and whether the AMR is valid for the site-specific conditions.

3-1993.3.2.1.1 Loss of Material for Components in Water-Based Fire ProtectionIn the discussion section of LRA Table 3.3.1, Item 3.3.1-21, the applicant stated the following:Loss of material due to general, pitting, crevice, galvanic corrosion, and MIC aswell as heat transfer degradation due to fouling for components in the fire system are managed by the Fire Protection and Fire Water System Programs.The Fire Water System Program is applied for the majority of the components in the fire system. The Fire Protection Program is applied to those components inthe fire system associated with the diesel fire pump with the exception of thediesel fire pump diesel engine fuel oil supply. In addition, the Fire Protection Program is applied to non-water-based fire protection subsystems such asHalon. Exceptions apply to NUREG-1801 recommendations for Fire ProtectionProgram implementation. Implementation of the Fire Water System and FireProtection Programs to manage the aging effect provides added assurance that the aging effect is not occurring; or that the aging effect is progressing very slowly such that the component's intended function will be maintained during theperiod of extended operation.In RAI 3.3.2.1.9-3, the staff noted that in LRA Table 3.3.2-9 for FIRs, the applicant credited theFire Protection Program with managing loss of material due to general, pitting, crevice, and galvanic corrosion, and MIC for copper alloy, and loss of material due to general and galvanic corrosion for gray cast iron material in a raw water environment, referring to GALL Report item VII.G6-b, which evaluates filter, fire hydrant, mulsifier, pump casing, sprinkler, strainer, and valve bodies from various materials including cast iron, bronze, and copper. The GALL Report also recommends the Fire Water System Program for managing this aging effect. The applicant referenced Note E, which indicates that a different AMP, Fire Protection Program, is used. As stated above, the applicant, in Table 3.3-1, Item 3.3.1-21, indicated that it applies the FireProtection Program to nonwater-based fire protection systems. This indication conflicts with theTable 3.3.2-9 line items. Furthermore, the LRA does not identify in the program description how the Fire Protection Program will manage this aging effect in water-based systems.Therefore, the staff requested that the applicant clarify how the Fire Protection Program willmanage loss of material due to general, pitting, crevice, and galvanic corrosion in water-based FP systems.In its response, dated November 22, 2005, the applicant stated the following:Although the LRA does not expressly identify how the Fire Protection Program will manage loss of material in water-based subsystems (i.e., diesel fire pump) inthe Program Description of Appendix B, this is specifically addressed in the Fire Protection AMP Program Basis Document (PBD). Under the heading

'Diesel-Driven Fire Pump,' the PBD states that the water initiated aging effects 3-200will be managed by the Fire Water System AMP. Therefore, the Fire ProtectionProgram invokes the Fire Water System Program to manage loss of material due to crevice, galvanic, general and pitting corrosion in the water-based subsystem for the diesel fire pump. This is confirmed in the Fire Water System PBD.As a result, the Fire Protection AMP will adequately manage the effect of loss ofmaterial due to crevice, galvanic, general and pitting corrosion for these components in the Fire System by invoking the Fire Water System AMP for the water initiated aging effects related to the diesel fire pump water-based subsystem.The applicant's response also stated, "Although the Fire Water System AMP is credited in thelicense renewal database for managing the aging effect of loss of material for copper alloy filters and strainers in a raw water environment, it was inadvertently omitted from LRA Table 3.3.2-9. The Fire Water System AMP is credited for managing these components in thewater-based portion of the Fire System."The applicant agreed to revise the Fire Protection Program in the LRA to specifically addresshow it intends to credit the Fire Water System Program with managing loss of material in water-based subsystems. The applicant will also provide revised AMR line items to correct theinadvertent omission of the Fire Water System Program for managing the aging effect of loss of material for copper alloy filters and strainers in a raw water environment.In its letter dated February 28, 2006, the applicant provided an update to LRA Table 3.3.2-9,adding the Fire Water System Program to the Fire Protection Program for managing the aging effect of loss of material for copper alloy filters and strainers in a raw water environment. In addition, the applicant amended the program description of the Fire Protection Program to invoke the Fire Water System Program for water-initiated aging effects related to the diesel fire pump water-based subsystem. Because the Fire Protection Program credits the Fire WaterSystem Program for managing the aging effects of loss of material in water-based subsystems,the staff found the applicant's response acceptable. Therefore, the staff's concern described inRAI 3.3.2.1.9-3 is resolved.Conclusion. The staff evaluated the applicant's claim of consistency with the GALL Report. Thestaff also reviewed information pertaining to the applicant's consideration of recent operating experience and proposals for managing associated aging effects. The staff's review concluded that the AMR results, which the applicant claimed to be consistent with the GALL Report, areconsistent with the AMRs in the GALL Report; therefore, the staff concluded that the applicanthas demonstrated that the effects of aging for these components will be adequately managedso that their intended function(s) will be maintained consistent with the CLB for the period ofextended operation, as required by 10 CFR 54.21(a)(3).3.3.2.2AMR Results That Are Consistent with the GALL Report, for Which Further EvaluationIs RecommendedSummary of Technical Information in the Application. In LRA Section 3.3.2.2, the applicantprovided further evaluation of aging management as recommended by the GALL Report for the 3-201auxiliary systems components. The applicant provided information concerning how it willmanage the following aging effects:

  • loss of material due to general, pitting, and crevice corrosion
  • hardening and cracking or loss of strength due to elastomer degradation or loss ofmaterial due to wear
  • cumulative fatigue damage
  • loss of material due to general, microbiologically influenced, pitting, and crevicecorrosion
  • loss of material due to general, galvanic, pitting, and crevice corrosion
  • loss of material due to general, pitting, crevice, and microbiologically influencedcorrosion and biofouling
  • reduction of neutron-absorbing capacity and loss of material due to general corrosion
  • loss of material due to general, pitting, crevice, and microbiologically influencedcorrosionStaff Evaluation. For component groups evaluated in the GALL Report for which the applicanthas claimed consistency with the GALL Report, and for which the GALL Report recommends further evaluation, the staff audited and reviewed the applicant's evaluation to determinewhether it adequately addressed the issues that were further evaluated. In addition, the staffreviewed the applicant's further evaluations against the criteria contained in Section 3.3.2.2 ofthe SRP-LR. The staff's audit and review report details the staff's audit. The following sections discuss the staff's evaluation of the aging effects.3.3.2.2.1 Loss of Material Due to General, Pitting, and Crevice Corrosion The staff reviewed LRA Sections 3.3.2.2.1.1 and 3.3.2.2.1.2 against the criteria in SRP-LRSection 3.3.2.2.1.In LRA Section 3.3.2.2.1.1, the applicant addressed loss of material due to general, pitting, andcrevice corrosion of heat exchanger components in the auxiliary systems.SRP-LR Section 3.3.2.2.1.1 states the following:Loss of material due to general, pitting, and crevice corrosion could occur in thechannel head and access cover, tubes, and tubesheets of the heat exchanger in the spent fuel pool cooling and cleanup (system). The Water Chemistry programrelies on monitoring and control of reactor water chemistry based on EPRI guidelines of BWRVIP-29 (TR-103515) for water chemistry in BWRs to manage the effects of loss of material from general, pitting or crevice corrosion. However, high concentrations of impurities at crevices and locations of stagnant flow conditions could cause general, pitting, or crevice corrosion. Therefore, 3-202verification of the effectiveness of the chemistry control program should beperformed to ensure that corrosion is not occurring. The GALL Report recommends further evaluation of programs to manage loss of material from general, pitting, and crevice corrosion to verify the effectiveness of the Water Chemistry program. A one-time inspection of select components at susceptible locations is an acceptable method to ensure that corrosion is not occurring and that the component's intended function will be maintained during the period ofextended operation.In LRA Section 3.3.2.2.1.1, the applicant stated thatThe staff determined that the use of the One-Time Inspection Program alone isacceptable in certain cases, such as no-flow conditions, in which the Plant Chemistry Program is not a viable option. These AMPs are appropriate for the aging effects/mechanisms identified and assure effective management through the period of extended operation. The staff reviewed the Plant Chemistry Program and the One-Time Inspection Program and found them acceptable for managing aging degradation. SER Sections 3.0.3.

2.19 and 3.0.3.1.4,respectively, document the evaluations.In LRA Section 3.3.2.2.1.2, the applicant addressed loss of material due to pitting and crevicecorrosion of components in the auxiliary systems.SRP-LR Section 3.3.2.2.1.2 states the following:Loss of material due to pitting and crevice corrosion could occur in the piping,filter housing, valve bodies, and shell and nozzles of the ion exchanger in the spent fuel pool cooling and cleanup system. The Water Chemistry program relieson monitoring and control of reactor water chemistry based on EPRI guidelines of BWRVIP-29 (TR-103515) for water chemistry in BWRs to manage the effects of loss of material from pitting or crevice corrosion. However, high concentrations of impurities at crevices and locations of stagnant flow conditions could cause pitting or crevice corrosion. Therefore, verification of the effectiveness of the chemistry control program should be performed to ensure that corrosion is not occurring. The GALL Report recommends further evaluation of programs to manage loss of material from pitting and crevice corrosion to verify the effectiveness of the Water Chemistry program. A one-time inspection of select 3-203components at susceptible locations is an acceptable method to ensure thatcorrosion is not occurring and that the component's intended function will bemaintained during the period of extended operation.In the One-Time Inspection Program and the Plant Chemistry Program, or theCompressed Air Monitoring Program manages the loss of material due to pitting and crevice corrosion of these components. The scope of the One-Time Inspection Program incorporates activities to verify the effectiveness of the Plant Chemistry Program, including a sample of components where the water flow is low or stagnant conditions exist. Implementation of the One-Time Inspection Program and the Plant Chemistry Program to manage the aging effect adds assurance that the aging effect does not occur or progresses very slowly such that the component's intended function will be maintained during the period of extended operation. Insome cases in which the Plant Chemistry Program is not a viable option and aging effects/mechanisms are not expected to be significant, the One-Time Inspection Program alone is credited with managing aging effects. The Compressed Air Monitoring Program is used to manage loss of material of stainless steel valve bodies of the AIR system in an air/gasenvironment (the applicant conservatively treats components with a "wet air/gas" environment in the same manner as treated water). The scope of the Compressed Air Monitoring Program includes procedurally required testing for water vapor, oil content, and particulate to ensure that instrument air quality does not have unacceptable levels of contaminants. In addition, external visual inspections of the AIR systems check once per cycle for corrosion and system pressureboundary degradation.The staff's review determined that the applicant's Plant Chemistry Program exceptions arenontechnical and that the program is based on a more recent EPRI document for BWR water chemistry instead of the EPRI document recommended by the GALL Report, BWRVIP-29. The staff determined that the use of the One-Time Inspection Program alone is acceptable incertain cases, such as no flow conditions, in which the use of the Plant Chemistry Program is not a viable option. The Compressed Air Monitoring Program includes procedurally required testing for water vapor, oil content, and particulate to ensure that instrument air quality does not have unacceptable levels of contaminants. In addition, external visual inspections of the AIR systems check once per cycle for corrosi on and system pressure boundary degradation.Engineering personnel must conduct a system walkdown and look for vibrating piping, leaks, orother indications of pending failures. These AMPs are appropriate for the aging effects/mechanisms identified and assure effective management through the period of extended operation. The staff reviewed the Plant Chemistry Program, the One-Time InspectionProgram, and the Compressed Air Monitoring Program and found them acceptable for managing aging degradation. SER Sections 3.0.3.2.19, 3.0.3.1.4, and 3.0.3.2.13, respectively,document the evaluations.On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LRSection 3.3.2.2.1. For those line items that apply to LRA Sections 3.3.2.2.1.1 and 3.3.2.2.1.2,the staff determined that the applicant's AMRs are consistent with the GALL Report and theapplicant has demonstrated that the effects of aging will be adequately managed so that theintended function(s) will be maintained consistent with the CLB during the period of extendedoperation, as required by 10 CFR 54.21(a)(3).

3-2043.3.2.2.2Hardening and Cracking or Loss of Strength Due to Elastomer Degradation or Lossof Material Due to WearThe staff reviewed LRA Section 3.3.2.2.2 against the criteria in SRP-LR Section 3.3.2.2.2.In LRA Section 3.3.2.2.2, the applicant addressed hardening and cracking or loss of strengthdue to elastomer degradation or loss of material due to wear in the auxiliary systems.SRP-LR Section 3.3.2.2.2 states the following:Hardening and cracking due to elastomer degradation could occur in elastomerlinings of the filter, valve, and ion exchangers in spent fuel pool cooling and cleanup systems (BWR and PWR). Hardening and loss of strength due toelastomer degradation could occur in the collars and seals of the duct and in the elastomer seals of the filters in the control room area, auxiliary and radwastearea, and primary containment heating ventilation systems and in the collars andseals of the duct in the diesel generator building ventilation system. Loss ofmaterial due to wear could occur in the collars and seals of the duct in the ventilation systems. The GALL report recommends further evaluation to ensurethat these aging effects are adequately managed.In LRA Section 3.3.2.2.2, the applicant stated that elastomer (e.g., neoprene, rubber)components are indoors and not subject to ultraviolet (UV) radiation, ozone, or significant radiation exposure. In addition, they are not subject to temperatures where change in material properties or cracking could occur. Therefore, the applicant claims that aging management is not required.The applicant provided a detailed discussion of the technical basis for determining that agingmanagement is not required in response to RAI 3.2.2.3-3, dated August 16, 2005. SER Section3.3.2.3 documents the discussion and the staff's evaluation.On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LRSection 3.3.2.2.2. For those line items that apply to LRA Secti on 3.3.2.2.2, the staff determinedthat the applicant's AMRs are consistent with the GALL Report and the applicant hasdemonstrated that the effects of aging will be adequately managed so that the intendedfunction(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 Cumulative Fatigue Damage In LRA Section 3.3.2.2.3, the applicant stated that fatigue is a TLAA, as defined in10 CFR 54.3. Applicants must evaluate TLAAs in accordance with 10 CFR 54.21(c)(1). SER Sections 4.3 and 4.9 document the staff's review of the applicant's evaluation of this TLAA formechanical auxiliary systems and the reactor building crane, respectively.3.3.2.2.4 Crack Initiation and Growth Due to Cracking or Stress-Corrosion Cracking 3-205Crack initiation and growth due to SCC could occur in the regenerative andnon-regenerative heat exchanger components in the reactor water cleanup system of BWR plants. The GALL Report recommends further evaluation toensure that these aging effects are managed adequately.does not occur and no aging management isrequired.The staff's review determined that the applicant's assessment that SCC does not apply to thecarbon steel shell is acceptable; therefore, the staff concluded that the applicant's furtherevaluation is acceptable because SRP-LR Section 3.3.2.2.4 does not apply.On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LRSection 3.3.2.2.4. For those line items that apply to LRA Secti on 3.3.2.2.4, the staff determinedthat the applicant's AMRs are consistent with the GALL Report and the applicant hasdemonstrated that the effects of aging will be adequately managed so that the intendedfunction(s) will be maintained consistent with the CLB during the period of extended operation,as required by 10 CFR 54.21(a)(3).3.3.2.2.5Loss of Material Due to General, Microbiologically Influenced, Pitting, and CreviceCorrosion 3-206F in the ventilation systems. The GALL Report recommends furtherevaluation to ensure that these aging effects are adequately managed.In LRA Section 3.3.2.2.5, the applicant stated that loss of material due to corrosion ofmechanical components could occur on surfaces exposed to air/gas under a range of atmospheric conditions. For the internal surfaces of mechanical components in the EDGs, emergency filtration train, and HTV systems, the One-Time Inspection Program is credited withmanaging the aging effect. For the external surfaces of mechanical components in all auxiliarysystems, the applicant credits the Fire Water System Program, Fire Protection Program,System Condition Monitoring Program, and/or One-Time Inspection Program with managing the aging effect.The staff's review determined that the applicant's Fire Water System Program and the FireProtection Program together manage aging effects in the water-based FP system piping andcomponents in accordance with applicable NFPA recommendations and aging effects for components in the FIR, including components for the diesel fire pump. The staff also reviewed the System Condition Monitoring Program and determined that this existing plant-specific AMP manages aging effects for normally accessible external surfaces of piping, tanks, and other components and equipment within the scope of license renewal. The applicant manages these aging effects through visual inspection and monitoring of external surfaces for leakage and evidence of material degradation. The staff's review also determined that the One-TimeInspection Program includes a sample of components in which flow is low or stagnant conditions exist. Implementation of the One-Time Inspection Program adds assurance that the aging effect does not occur or progresses very slowly, such that the component's intended function will be maintained during the period of extended operation. The staff reviewed theapplicant's Fire Water System Program, the Fire Protection Program, the One-Time Inspection Program, and the System Condition Monitoring Program and found them acceptable for managing aging degradation. SER Sections 3.0.3.2.

16, 3.0.3.2.15, 3.0.

3.1.4, and 3.0.3.3.2,respectively, document the evaluations. These AMPs are appropriate for the aging effects/mechanisms identified and assure effective management of aging effects through the period of extended operation.On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LRSection 3.3.2.2.5. For those line items that apply to LRA Secti on 3.3.2.2.5, the staff determinedthat the applicant's AMRs are consistent with the GALL Report and the applicant hasdemonstrated that the effects of aging will be adequately managed so that the intendedfunction(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 Loss of Material Due to General, Galvanic, Pitting, and Crevice Corrosion The staff reviewed LRA Section 3.3.2.2.6 against the criteria in SRP-LR Section 3.3.2.2.6.In LRA Section 3.2.2.2.6, the applicant addressed loss of material due to general, galvanic,pitting, and crevice corrosion for components in the reactor coolant pump (RCP) oil collection system for FP.SRP-LR Section 3.2.2.2.6 states the following:

3-207Loss of material due to general, galvanic, pitting, and crevice corrosion couldoccur in tanks, piping, valve bodies, and tubing in the reactor coolant pump oil collection system in fire protection. The Fire Protection program relies on a combination of visual and volumetric examinations in accordance with the guidelines of 10 CFR Part 50 Appendix R and Branch Technical Position 9.5-1 to manage loss of material from corrosion. However, corrosion may occur at locations where water from wash downs may accumulate. Therefore, verification of the effectiveness of the program should be performed to ensure that corrosion is not occurring. The GALL Report recommends further evaluation of programs to manage loss of material due to general, galvanic, pitting, and crevice corrosion to verify the effectiveness of the program. A one-time inspection of the bottom half of the interior surface of the tank of the reactor coolant pump oil collection system is an acceptable method to ensure that corrosion is notoccurring and that the component's intended function will be maintained duringthe period of extended operation.In LRA Section 3.3.2.2.6, the applicant stated that MNGP is not designed with an RCP(recirculation pump) oil collection system because these pumps are within the primarycontainment, which is inerted with nitrogen during normal operation.On the basis of its review, the staff determined that the applicant has no components coveredby SRP-LR Section 3.3.2.2.6. The staff found this aging effect not applicable.3.3.2.2.7Loss of Material Due to General, Pitting, Crevice, and Microbiologically InfluencedCorrosion and BiofoulingThe staff reviewed LRA Section 3.3.2.2.7 against the criteria in SRP-LR Section 3.3.2.2.7.In LRA Section 3.3.2.2.7, the applicant addressed loss of material due to general, pitting, andcrevice corrosion, MIC, and biofouling for components in the EDGs.SRP-LR Section 3.3.2.2.7 states the following:Loss of material due to general, pitting, and crevice corrosion, MIC, andbiofouling could occur on the internal surface of tanks in the diesel fuel oil system and due to general, pitting, and crevice corrosion and MIC in the tanks ofthe diesel fuel oil system in the EDG system. The existing AMP relies on the fueloil chemistry program for monitoring and control of fuel oil contamination in accordance with the guidelines of ASTM Standards D4057, D1796, D2709 and D2276 to manage loss of material due to corrosion or biofouling. Corrosion or biofouling may occur at locations where contaminants accumulate. Verification of the effectiveness of the chemistry control program should be performed to ensure that corrosion is not occurring. The GALL Report recommends further evaluation of programs to manage corrosion/biofouling to verify the effectiveness of the program. A one-time inspection of selected components at susceptible locations is an acceptable method to ensure that corrosion is not occurring and that the component's intended function will be maintained during the period ofextended operation.

3-208In LRA Section 3.3.2.2.7, the applicant stated that its Fuel Oil Chemistry Program managesloss of material for all components wetted by fuel oil. The One-Time Inspection Program confirms the effectiveness of the Fuel Oil Chemistry Program. The Fuel Oil Chemistry Program uses existing diesel oil system procedures that encompass the GALL Report programrequirements. The Fuel Oil Chemistry Program mitigates and manages aging effects on the surfaces wetted by fuel oil in fuel oil storage tanks and associated components, including the tank and other components supplying fuel to the diesel fire pump. The program includes (1) surveillance and monitoring procedures for maintaining fuel oil quality by controllingcontaminants in accordance with applicable ASTM standards, (2) periodic draining of water from fuel oil tanks, (3) periodic or conditional visual inspection of internal surfaces or wall thickness measurements (e.g., by UT) from external surfaces of fuel oil tanks, and (4) one-time inspections of a representative sample of components in systems that contain fuel oil. TheOne-Time Inspection Program includes (1) determination of sample size based on an assessment of materials of fabrication, environment, plausible aging effects, and operating experience, (2) identification of the inspection locations in the system or component based onthe aging effect, (3) determination of the examination technique, including acceptance criteriathat will be effective in managing the aging effect for which the component is examined; and (4)evaluation of the need for followup examinations to monitor the progression of any aging degradation.The staff reviewed the applicant's Fuel Oil Chemistry Program and the One-Time InspectionProgram and found them acceptable for managing aging degradation. SER Sections 3.0.3.2.17and 3.0.3.1.4, respectively, document the evaluation.On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LRSection 3.3.2.2.7. For those line items that apply to LRA Secti on 3.3.2.2.7, the staff determinedthat the applicant's AMRs are consistent with the GALL Report and the applicant hasdemonstrated that the effects of aging will be adequately managed so that the intendedfunction(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 Quality Assurance for Aging Management of Nonsafety-Related ComponentsSER Section 3.0.4 provides the staff's evaluation of the applicant's Quality Assurance Program.3.3.2.2.9 Crack Initiation and Growth Due to Stress-Corrosion Cracking and Cyclic Loading The staff reviewed LRA Section 3.3.2.2.9 against the criteria in SRP-LR Section 3.3.2.2.9.In LRA Section 3.3.2.2.9, the applicant stated that this aging effect applies to PWRs only.SRP-LR Section 3.3.2.2.9 states that crack initiation and growth due to SCC and cyclic loadingcould occur in the channel head and access cover, tubesheet, tubes, shell and access cover, and closure bolting of the regenerative heat exchanger and in the channel head and access cover, tubesheet, and tubes of the letdown heat exchanger in the chemical and volume controlsystem (CVCS). SRP-LR Table 3.3-1 states that further evaluation for this aging effect is for PWR plants only.The staff found this aging effect not applicable.

3-2093.3.2.2.10Reduction of Neutron-Absorbing Capacity and Loss of Material Due to GeneralCorrosionThe staff reviewed LRA Section 3.3.2.2.10 against the criteria in SRP-LR Section 3.3.2.2.10.In LRA Section 3.3.2.2.10, the applicant addressed reduction of neutron-absorbing capacity andloss of material due to general corrosion for boral.SRP-LR Section 3.3.2.2.10 states the following:Reduction of neutron-absorbing capacity and loss of material due to generalcorrosion could occur in the neutron-absorbing sheets of the spent fuel storage rack in the spent fuel storage. The GALL Report recommends further evaluation to ensure that these aging effects are adequately managed.In LRA Section 3.3.2.2.10. By letter dated November 17, 2005, the applicantstated that it will visually examine the unclad boral coupon sample before the period ofextended operation. The applicant will remove the coupon from the spent fuel pool for a briefperiod of time, visually examine it, and then immediately return it to the spent fuel pool.The staff's review determined that the Plant Chemistry Program, supplemented by the One-Time Inspection Program, will manage reduction of neutron-absorbing capacity and loss ofmaterial due to general corrosion. The one-time inspection of boral coupon test specimens willconfirm that no significant aging degradation will occur and that the neutron-absorbingcapability of the boral has not been reduced.These AMPs are appropriate for the aging effects/mechanisms identified and assure effectivemanagement through the period of extended operation. The staff reviewed the Plant ChemistryProgram and the One-Time Inspection Program and found them acceptable for managing aging degradation. SER Sections 3.0.3.2.19 and 3.0.3.1.4, respectively, document theevaluations.On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LRSection 3.3.2.2.10. For those line items that apply to LRA Section 3.3.2.2.10, the staffdetermined that the applicant's AMRs are consistent with the GALL Report and the applicanthas demonstrated that the effects of aging will be adequately managed so that the intendedfunction(s) will be maintained consistent with the CLB during the period of extended operation,as required by 10 CFR 54.21(a)(3).

3-2103.3.2.2.11Loss of Material Due to General, Pitting, Crevice, and Microbiologically InfluencedCorrosionThe staff reviewed LRA Section 3.3.2.2.11 against the criteria in SRP-LR Section 3.3.2.2.11.In LRA Section 3.3.2.2.11, the applicant addressed loss of material due to general, pitting, andcrevice corrosion and MIC of underground (buried) piping and fittings in the DGN, FIR, and ESW systems.SRP-LR Section 3.3.2.2.11 states the following:Loss of material due to general, pitting, and crevice corrosion and MIC couldoccur in the underground piping and fittings in the open-cycle cooling watersystem (SW system) and in the diesel fuel oil system. The buried piping andtanks inspection program relies on industry practice, frequency of pipe excavation, and operating experience to manage the effects of loss of material from general, pitting, and crevice corrosion and MIC. The effectiveness of the buried piping and tanks inspection program should be verified to evaluate an applicant's inspection frequency and operating experience with buried components, ensuring that loss of material is not occurring.In LRA Section 3.3.2.2.11, the applicant stated that the Buried Piping & Tanks InspectionProgram manages the loss of material due to general, pitting, and crevice corrosion, MIC, galvanic corrosion, and selective leaching for buried valve bodies, piping, and fittings. The Bolting Integrity Program manages loss of material due to general, pitting, and crevice corrosion, MIC, and galvanic corrosion for buried fasteners. The Buried Piping & Tanks Inspection Program consists of preventive and condition monitoring measures to manage the aging effect. Preventive measures consist of protective coatings and/or wraps on buried components. Condition monitoring consists of periodic inspections of buried components. The applicant's operating experience shows no buried pipe/tank failures for components within the scope of license renewal. The Bolting Integrity Program consists of guidelines on materials selection, strength and hardness properties, installation procedures, lubricants and sealants, corrosion considerations in the selection and installation of pressure-retaining bolting for nuclear applications, and inspection techniques.The staff's review determined that the Buried Piping & Tanks Inspection Program providesadequate management of aging effects for buried pipes, components, and tanks during the period of extended operation. The Bolting Integrity Program references and invokes the provisions of the Buried Piping & Tanks Inspection Program to implement inspection of these components. The staff reviewed the Buried Piping & Tanks Inspection Program and the Bolting Integrity Program and found them acceptable for managing aging degradation. SER Sections 3.0.3.2.5 and 3.0.3.2.4, respectively, document the evaluations.

3-211Conclusion. On the basis of its review, for component groups evaluated in the GALL Report forwhich the applicant has claimed consistency with the GALL Report, and for which the GALL Report recommends further evaluation, the staff determined that the applicant adequatelyaddressed the issues that were further evaluated. The staff found that the applicant hasdemonstrated that the effects of aging will be adequately managed so that intended functionswill be maintained consistent with the CLB for the period of extended operation, as required by10 CFR 54.21(a)(3).3.3.2.3 AMR Results That Are Not Consistent with or Not Addressed in the GALL ReportSummary of Technical Information in the Application. In LRA Tables 3.3.2-1 through 3.3.2-18,the staff reviewed additional details of the results of the AMRs for material, environment, AERM, and AMP combinations that are not consistent with the GALL Report, or that are notaddressed in the GALL Report.In LRA Tables 3.3.2-1 through 3.3.2-18, the applicant indicated, via Notes F through J, that thecombination of component type, material, environment, and AERM does not correspond to a line item in the GALL Report and provided information concerning the management of the aging effect. Specifically, Note F indicates that the GALL Report does not evaluate the material for the AMR line item component. Note G indicates that the GALL Report does not evaluate the environment for the AMR line item component and material. Note H indicates that the GALL Report does not evaluate the aging effect for the AMR line item component, material, and environment combination. Note I indicates that the aging effect identified in the GALL Report forthe line item component, material, and environment combination does not apply. Note J indicates that the GALL Report evaluates neither the component nor the material andenvironment combination for the line item.Staff Evaluation. For component type, material, and environment combinations that the GALLReport does not evaluate, the staff reviewed the applicant's evaluation to determine whetherthe applicant had demonstrated that the effects of aging will be adequately managed so thatintended functions will be maintained consistent with the CLB during the period of extendedoperation. This section addresses the AMR results for which LRA Tables 3.3.2-1 through 3.3.2-18 do not identify any aging effects. Each table discussion separately addresses otherline items not consistent with or not addressed in the GALL Report. The following sections discuss the staff's evaluation.The staff's review of LRA Tables 3.3.2-1 through 3.3.2-18 identified areas for which it neededadditional information to complete its evaluation of the applicant's results. The applicant responded to the staff's general RAIs as discussed below.In RAI 3.3.2.3-2, dated July 20, 2005, the staff noted that LRA Tables 3.3.2-6 and 3.3.2-8identify heat transfer degradation due to fouling as an AERM for copper heat exchangers (heat transfer and pressure boundary functions) in a lubricating oil environment. The applicant credited the One-Time Inspection Program with managing this aging effect. The One-Time Inspection Program verifies the effectiveness of an AMP and confirms the absence of an aging effect. For fouling of heat exchangers in a lubricating oil environment, mitigation of the aging effect depends on a lubricating oil monitoring program to maintain the integrity of the oil; therefore, the staff requested that the applicant identify an AMP to mitigate the effects of fouling 3-212in the heat exchangers during the period of extended operation and verify the effectiveness ofthat program with a one-time inspection.In its response, by letter dated August 16, 2005, the applicant stated the following:Table 3.3.2-6, Emergency Diesel Generators System (EDG) and Table 3.3.2-8,Emergency Service Water System (ESW) identify copper alloy heat exchanger tubes for both the EDG lube oil coolers and RHR Service Water (RSW) pumpmotor thrust bearing oil coolers, with lubricating oil as an external environment for these Auxiliary Systems.The NMC position concerning the potential aging effect of heat transferdegradation due to fouling in a lubricating oil environment is that degradationeffects are insignificant for lubricating oil systems if the oil remains free of waterand other contaminants. Under these conditions, lubricating oil systems andassociated components have few, if any, significant aging effects. The purity of the EDG and ESW lubricating oil systems is maintained and chemically analyzedperiodically. For equipment not normally in operation during power operation such as the EDG lube oil coolers and the RSW motor thrust bearing oil coolers, periodic testing of the equipment, in conjunction with oil sampling, is performed to detect any contaminants or water in the oil.Lubricating oil is usually non-corrosive and flow rates for lube oil systems aretypically low. Strict controls for the quality and purity of the lubricating oil procured and scheduled sampling techniques and parameters monitored are requirements of the MNGP lubricating oil sampling procedures. Very little corrosion occurs in lubricating oil systems due to low oxygen content, the factthat lubricating oils are not good electrolytes and purification systems aregenerally installed and/or corrosion inhibitors added to maintain the lubricating oil free of corrosion products.Lube oil samples for the EDG lube oil coolers are obtained quarterly andsamples for the RSW pump motor thrust bearing oil coolers are obtained annually in accordance with MNGP site procedures. The sample results are evaluated and trended for these components. Any indication of an anomalous condition or adverse trend will result in an investigation under the site correctiveaction program. All sample results have been acceptable to date to ensure that the lubricating oil remains free of moisture and contaminants that could potentially degrade the heat exchanger tubes, with the last samples taken and evaluated for both the EDG and ESW systems in 2005. Although MNGPoperating experience did result in the replacement of the EDG lube oil coolers due to the lead solder joints and resultant exfoliation corrosion, this was a design issue and not age-related (Institute of Nuclear Power Operations SOER 80-04).Based on the above procurement and sampling requirements to maintain theintegrity of the lubricating oil and MNGP plant-specific operating experience thatconfirms the absence of this aging effect, MNGP conservatively credits the One-Time Inspection Program to verify the absence of the aging effect of heat transfer degradation due to fouling for these components in the EDG and ESW 3-213Systems. The MNGP One-Time Inspection Program will use the CorrectiveAction Program to evaluate indications or relevant conditions of degradation. The need to increase the number of selected components for inspection will also beevaluated when indications or relevant conditions of degradation or unacceptable conditions are found.Based on its review, the staff found the applicant's response to RAI 3.3.2.3-2 acceptable,because the applicant satisfactorily identified procurement and sampling requirements to maintain the integrity of the lubricating oil and use of the One-Time Inspection Program to verify the absence of the aging effect of heat transfer degradation due to fouling in the DGN and ESW system heat exchangers; therefore, the staff's concern described in RAI 3.3.2.3-2 isresolved.In RAI 3.3.2.3-3, dated July 20, 2005, the staff noted that LRA Tables 3.3.2-3 and 3.3.2-16identify no aging effects for rubber expansion joints in a raw water environment; therefore, the staff requested that the applicant identify an AMP to manage hardening and loss of strength forrubber expansion joints in a raw water environment.In its response, by letter dated August 16, 2005, the applicant stated the following:Several EPRI Technical Reports and Industry handbooks were reviewed foraging of elastomers. A summary of the review is provided below.EPRI Report 1008035, 'Expansion Joint Maintenance Guide', Revision 1, May2003, Table 5-4, rates elastomers against oxidation, tensile strength, andradiation. Elastomers, such as neoprene, natural rubber, Chlorobutyl, Buna-N, viton, and EPDM, are rated as good or better in the categories of oxidation, tensile strength, and radiation.EPRI Report NP-6608, 'Shelf Life of Elastomeric Components,' May 1994,Appendix A, provides curves that describe the change in physical properties for different elastomers as they undergo natural aging. The figures demonstrate that there is very little change in the hardness and tensile strength of elastomers over a 33 year period.EPRI Report NP-6408, 'Guidelines for Establishing, Maintaining, and Extendingthe Shelf Life Capability of Limited Life Items (NCIG-13)', May 1992,section 4.3.2, states that test results demonstrated Viton and Neoprene ashaving excellent weather resistance and are therefore UV resistant.

Section 4.4.2 states that these elastomers are also highly resistant to ozone.The Parker O-Ring Handbook, Page 2-24, in a discussion about aging of rubberseals states, 'It is environment and not age that is significant to seal life, both instorage and actual service.' The following is a discussion of the role of environment on the aging of elastomers.EPRI 1003056, November 2001, 'Non-Class 1 Mechanical ImplementationGuideline and Mechanical Tools, Revision 3, states 'For a complete discussion of the aging effects of typical elastomers used in nuclear plants, the applicant is 3-214referred to EPRI TR-114881, 'Aging Effects for Structures and StructuralComponents (Structural Tools)'. EPRI TR-114881 has been superceded by EPRI 1002950, 'Aging Effects for Structures and Structural Components (Structural Tools), Revision 1', May 2003. This report discusses the three stressors: (1) Ultraviolet, (2) Thermal, and (3) Radiation listed below. (135)Ultraviolet: The Structural Tools state 'Rubber is decomposed byexposure to ultraviolet radiation. Ultraviolet radiation sources at nuclear plants include solar radiation and ultraviolet or fluorescent lamps. The deterioration of rubber is greatly accelerated in the presence of oxygen. Cracking and checking (splitting), which may occur when rubber is exposed to air and sunlight, are due mainly to reaction with ozone.' None of the elastomers in the scope of license renewal at MNGP are exposed to solar radiation. EPRI Report NP-6408, Section 4.3.2, states that UV on elastomers caused by artificial light is of little concern since the amount of UV is very small. For conservatism, MNGP took the position that any elastomers in close proximity to fluorescent lamps would be managed for aging, however none were found. Therefore, given the absence of solar radiation and the negligible effects from artificial light, these elastomers are not susceptible to hardening and loss of strength, which could be caused by the ultraviolet radiation exposure. (136)Thermal: The Structural Tools state, 'In general, if the ambienttemperature is less than about 95 °F, then thermal aging may be considered not significant for the period of extended operation'.

Since these elastomers are not exposed to temperatures

>95 degrees F, they are therefore not susceptible to hardening and loss of strength caused by thermal exposure. (137)Radiation: The Structural Tools state, 'Material property changesand cracking owing to radiation is an applicable aging effect for rubber, neoprene, and s ilicone elastomers in environments wherethe radiation exceeds the limits defined above.' The limit listed for rubber is 10 7 Rads, Butyl Rubber 10 6 Rads, and Neoprene 10 6Rads. Since these elastomers are not exposed to this degree of ionizing radiation exposure, which is orders of magnitude above that corresponding to 60 years of normal plant operation, they are therefore not susceptible to hardening and loss of strength caused by radiation.EPRI 1002950, 'Structural Tools,' reviewed industry failure data and NRCgeneric communications to determine if there was any additional aging effects that should be considered for elastomers. The review did not uncover any new aging effects.EPRI Report 1007933, 'Aging Assessment Field Guide,' December 2003, pages60 through 65, lists degradation mechanisms brought on by the stressors:

Thermal, Radiation, and Ultraviolet. Since these elastomers are not exposed to 3-215ultraviolet, radiation, or temperatures >95°F, they are therefore not susceptible tohardening and loss of strength and therefore no aging management is required.Consistent with the above discussion, Monticello only included elastomers in anaging management program that are subject to elevated temperature, ultraviolet, or ionizing radiation. Elastomers are included in the One-Time Inspection Program to confirm that unacceptable degradation has not occurred such that they will perform their intended function during the period of extended operation.If inspections of these more severe applications identify unacceptable degradation, the inspection scope would be expanded as required by the One-Time Inspection Program. The expanded scope would include less environmentally severe applications and could eventually include the elastomers that were excluded from aging management as described above. Therefore, elastomers not explicitly identified as requiring aging management, based on industry experience and technical research, are subject to the One-Time Inspection Program requirements concerning scope expansion and could be inspected if needed based on the examination results of more severe applications.By letter, dated November 17, 2005, the applicant described the following additional agingmanagement for elastomers in an air environment exposed to ozone:After further evaluation of this issue, NMC has taken the conservative approachof managing change in material properties due to ozone for elastomers in an air environment, specifically for natural rubber. This is a result of the fact that neither representative ozone concentrations nor technically substantiated thresholds could be adequately or consistently determined, even thoughplant-specific operating experience has indicated that there has been no changein material properties due to ozone for these elastomer components. Further evaluation also revealed the inability to confirm that none of these componentsare fabricated from natural rubber.As a result, elastomers in an external air environment in the following LRA tableswill utilize the System Condition Monitoring Program to manage the potentialaging effect of change in material properties due to ozone which shall be assigned to these components.

  • Table 3.3.2-5 piping and fittings in the Demineralized Water System
  • Table 3.3.2-7 ventilation seals in the Emergency Filtration Train System
  • Table 3.3.2-16 expansion joints in the Service and Seal Water System
  • Table 3.4.2-2 expansion joints in the Condensate and Feedwater System(those which were not previously managed externally) 3-216Elastomers in Table 3.2.2-8 (ventilation seals in the Secondary ContainmentSystem) are presently being managed utilizing the One-Time InspectionProgram for the internal surfaces and the System Condition Monitoring Program for the external surfaces. These Aging Management Programs (AMPs) were initially credited to manage change in material properties and cracking due to thermal exposure, since a temperature threshold of greater than 95 F wasassigned to these components. Consequently, these same AMPs will alsomanage change in material properties due to ozone which shall be assigned to these components.Elastomers (expansion joints) in Table 3.4.2-3 (Main Condenser System) do notrequire aging management since these components do not serve a pressure boundary intended function but provide for plate-out and holdup of radioactive material during design basis events. Condenser integrity is continuously demonstrated during normal plant operation thus validating that this intendedfunction is maintained as stated in the plant-specific notes for these components in Section 3.4 of the LRA.Elastomers in an internal air environment in Table 3.3.2-6 (piping and fittings inthe Emergency Diesel Generators System) and Table 3.3.2-7 (ventilation sealsin the Emergency Filtration Train System) will utilize the One-Time Inspection Program to manage the potential aging effect of change in material properties due to ozone which shall be assigned to these components.Elastomers in both an internal and external air environment in Table 3.3.2-11(ventilation seals in the Heating and Ventilation System) were inadvertentlyomitted from this table. These components shall be managed for the potentialaging effect of change in material properties due to ozone utilizing the One-TimeInspection Program for the internal surfaces and the System Condition Monitoring Program for the external surfaces which shall be assigned to these components.All the elastomers addressed are long-lived components. Any component that isnot long-lived and replaced at specified intervals is eliminated from AMR consideration during the screening process. Although the expansion joints are presently under review for replacement on a fixed periodicity, this change has not been effected and they remain as and have been analyzed as long-lived components.Any degradation of elastomer components in an air environment resulting fromchange in material properties due to ozone for the external surfaces of these components shall be evaluated as discussed in the response to RAI B2.1.32-2 which addresses the System Condition Monitoring AMP.This response also applies to the previous RAI responses concerning elastomersincluding RAI 3.3.2.3-3, RAI 3.3.2.3-4, RAI 3.3.2.3-5, RAI 3.3.2.3-6, andRAI 3.4-01.

3-217Based on its review, the staff found the applicant's response to RAI 3.3.2.3-3 acceptable,because it satisfactorily identified stressors and thresholds for which hardening and loss of strength are aging effects for elastomer components and applied aging management for these cases. Where the stressors and thresholds for which hardening and loss of strength are not exceeded, aging management is not required. Therefore, the staff's concern described inRAI 3.3.2.3-3 is resolved.In RAI 3.3.2.3-4, dated July 20, 2005, the staff noted that LRA Tables 3.3.2-3, 3.3.2-5, 3.3.2-6,3.3.2-7, and 3.3.2-16 identify no aging effects for rubber expansion joints, piping and fittings,and elastomer ventilation seals in a plant indoor air environment; therefore, the staff requested that the applicant identify an AMP to manage hardening and loss of strength for these rubberand elastomer components in a plant indoor air environment.In its response, by letter dated August 16, 2005, the applicant stated that its response toRAI 3.3.2.3-3 applies to this RAI as well.The staff found the applicant's response acceptable. Therefore, the staff's concern described inRAI 3.3.2.3-4 is resolved.In RAI 3.3.2.3-5, dated July 20, 2005, the staff noted that LRA Tables 3.3.2-5 and 3.3.2-17identify no aging effects for rubber accumulators, piping, and fittings in a treated water environment. Previously, the staff had identified hardening and loss of strength as aging effects for rubber and elastomer components in this environment and recommended a plant-specific program to manage these aging effects by periodic inspections of the components; therefore, the staff requested that the applicant identify an AMP to manage hardening and loss of strengthfor these rubber components in a treated water environment.In its response, by letter dated August 16, 2005, the applicant referred to its response toRAI 3.3.2.3-3.The staff found the applicant's response acceptable; therefore, the staff's concern described inRAI 3.3.2.3-5 is resolved.In RAI 3.3.2.3-6, dated July 20, 2005, the staff noted that LRA Tables 3.3.2-6 and 3.3.2-7identify no aging effects for rubber ventilation seals, piping, and fittings in a gas and air internal environment; therefore, the staff requested that the applicant identify an AMP to managehardening and loss of strength for these rubber components in a gas and air internal environment where the internal temperature exceeds 95 F.In its response, by letter dated August 16, 2005, the applicant referred to its response toRAI 3.3.2.3-3.The staff found the applicant's response acceptable; therefore, the staff's concern described inRAI 3.3.2.3-6 is resolved.In RAI 3.3.2.3-7, dated July 20, 2005, the staff noted that LRA Tables 3.3.2-6 and 3.3.2-9identify no aging effects for stainless steel fasteners/bolting and copper alloy flame arresters in an environment exposed to weather; therefore, the staff requested that the applicant identify an 3-218AMP to manage loss of material due to pitting and crevice corrosion for these stainless steeland copper alloy components exposed to weather.In its response, by letter dated August 16, 2005, the applicant stated the following:Table 3.3.2-6, Emergency Diesel Generators System (EDG) and Table 3.3.2-9,Fire System (FIR) identify stainless steel fasteners/bolting (EDG and FIR),

copper alloy flame arrestors (EDG and FIR) and hose house supply valves (FIR) exposed to weather for these Auxiliary Systems. The NMC materials science position, which is in accordance with EPRI 1003056 (Non-Class I Mechanical Implementation Guideline and Mechanical Tools, Revision 3), is that these components do not have a surface exposed to an aggressive chemical species, do not have the potential for concentrating contaminants and are not subject towetting other than their normal environment. Therefore, loss of material due to crevice or pitting corrosion is not a potential aging mechanism.Crevice corrosion is a potential aging mechanism for wetted stainless steel andhigh zinc copper alloys under certain conditions. Crevice corrosion is strongly dependent on the presence of dissolved oxygen. Although oxygen depletion in crevices may occur as a result of the corrosion process, oxygen is st ill requiredfor the onset of corrosion, and a bulk fluid oxygen content or the presence ofcontaminants such as chlorides is necessary for the continued dissolution of material in the crevice. For systems with extremely low oxygen content (<0.1ppm), crevice corrosion is considered insignificant. This form of corrosion requires a crevice where contaminants and corrosion products can concentrate.

In addition to oxygen, moisture is required for the mechanism to operate.

Alternate wetting and drying is particularly harmful as this leads to a concentration of atmospheric pollutants and contaminants if they are present.These conditions do not exist at the MNGP.Pitting corrosion is a potential aging mechanism for wetted stainless steel andhigh zinc copper alloys under certain conditions. Unless cupric, ferric or mercuric halides are present in the environment, oxygen is required for pitting initiation.

Areas where aggressive species can concentrate are particularly susceptible to pitting. Most pitting is the result of halide contamination, with chlorides, bromides, and hypochlorites being prevalent. Pitting is a significant aging effect for stainless steels and high zinc copper alloys when exposed to a corrosive environment. Any continuously wetted or alternately wetted and dried surfaces tend to concentrate aggressive species if they are present and are prone to pitting corrosion. These conditions also do not exist at the MNGP.For conservatism, the stainless steel fastener/bolting component was added as a'global' asset to assure no components, materials or environments were inadvertently omitted during the AMR process. Recent walk downs of both the EDG and FIR Systems revealed there were no stainless steel fasteners/bolting exposed to weather in either of these systems. Additionally, the FIR hose housesupply valves reside within the individual hose house metal enclosures. Although these copper alloy valves are subjected to an 'Outside Air Protected from Weather' environment, they were conservatively assigned to the 'Exposed to 3-219Weather' environment. Sheltered environments tend to preclude the presence ofsufficient moisture to promote significant corrosion. Lastly, the copper alloy flame arrestors, though painted (no credit is taken for coatings at MNGP with respect to the mechanical systems), were confirmed to be aluminum during these walkdowns. Since aluminum and copper alloys are analyzed essentially in the same manner for loss of material due to crevice and pitting corrosion in an 'exposed to weather' external environment, the difference in actual material is considered inconsequential. However, both the EDG and FIR Systems' stainless steel fasteners/bolting exposed to weather asset shall be removed from Table 3.3.2-6 and Table 3.3.2-9 and the material for the flame arrestors shall be changed from copper alloy to aluminum in Table 3.3.2-6.Since none of these components have a surface exposed to an aggressivechemical species (sulfur dioxide, chlorine gases, sulfur gases, ozone, etc.), do not have the potential for concentrating contaminants and are not subject towetting other than their normal environment, loss of material due to crevice or pitting corrosion is not a potential aging mechanism. This has been confirmed by system walk downs and substantiated by plant-specific operating experience.Based on its review, the staff found the applicant's response to RAI 3.3.2.3-7 acceptablebecause (1) no stainless steel fasteners/bolting in the DGN and FIR system are exposed toweather and (2) the aluminum flame arrestors in Table 3.3.2-6 and the copper alloy hose house supply valves in Table 3.3.2-9 are not subject to environments that promote pitting and crevicecorrosion. Therefore, aging management is not required for these components and the staff'sconcern described in RAI 3.3.2.3-7 is resolved.In LRA Tables 3.3.2-1 through 3.3.2-18, the applicant identified line items for which it did notidentify any aging effects as a result of the aging review process.Specifically, the applicant stated that no aging effects occur when components fabricated frombronze, CASS, copper alloy, and stainless steel materials are exposed to air/gas (internal and external), concrete (external), dry air (internal), gas-halon (internal), gas-instrument air (internal), gas-nitrogen (internal), gas-refrigerant (internal), lubricating oil (internal and external),plant indoor air (internal and external), and primary containment air (external) environments. In addition, components fabricated from carbon steel, galvanized steel, and cast iron exposed to these same environments, with the exception of indoor air and primary containment airenvironments, have no aging effects. The applicant stated that materials science evaluation ofthese materials in such environments found no aging effects for the components and materials.

No aging effects are considered applicable to components fabricated from the above list of materials exposed to the given environments.As shown in the Metals Handbook, Ninth Edition, Volume 13, comprehensive tests over a20-year period under ASTM supervision confirmed the suitability of copper alloys foratmospheric exposure. Additionally, because the gaseous internal environments to which components within the scope of license renewal may be subject include air, nitrogen, carbon dioxide, freon, and halon, industry experience shows that copper piping exposed to an internal gaseous environment will be resistant to any age-related degradation; therefore, the SC willremain capable of performing intended functions consistent with the CLB for the period of extended operation.

3-220As shown in the Metals Handbook, Ninth Edition, Volumes 1 and 13, both oxygen and moisturemust be present to corrode steel. Experience has shown that general corrosion of steel (including carbon steel, alloy steel, gray cast iron, and galvanized steel) will apply only if it wereexposed to outdoor or indoor environments that promote condensation of water on the externalsurfaces of components; therefore, the SC will remain capable of performing intended functionsconsistent with the CLB for the period of extended operation.As shown in Metals Handbook, Ninth Edition, Volumes 3 and 13, stainless steels are highlyresistant to corrosion in dry atmospheres in the absence of corrosive species (which will bereflective of indoor uncontrolled air or primary containment air inerted with nitrogen); therefore, the SC will remain capable of performing intended functions consistent with the CLB for theperiod of extended operation.As shown in the Metals Handbook, Ninth Edition, Volumes 1 and 13, both oxygen and moisturemust be present to corrode steel. Components are not subject to wetting if their surfaces remain oil-coated; therefore, steel (carbon or stainless) in a lubricating oil environment with nowater pooling exhibits no aging effect, and the SC will remain capable of performing intendedfunctions consistent with the CLB for the period of extended operation.For carbon steel embedded in concrete, loss of material due to general corrosion could occur inan aggressive environment. An aggressive environment has pH less than 5.5, chlorides greater than 500 ppm, or sulfates greater than 1500 ppm. Plant documents confirm that thebelow-grade environment is not aggressive. The applicant's data indicate that the pH exceeds 7, chlorides are less than 100 ppm, and sulfates are less than 100 ppm. To ensure that the below-grade environment remains nonaggressive, the Structures Monitoring Programincludes periodic monitoring of ground water chemistry for the above parameters; therefore, the SC will remain capable of performing intended functions consistent with the CLB for the periodof extended operation.The staff's review of current industry research and operating experience found that effects ofthe listed environments on the given materials will not result in aging effects of concern during the period of extended operation; therefore, the staff concluded that no AERMs apply for thecomponent, material, and environment combinations described in the preceding discussion.3.3.2.3.1Auxiliary Systems-Alternate Nitrogen System-Summary of Aging ManagementEvaluation-Table 3.3.2-1The staff reviewed LRA Table 3.3.2-1, which summarizes the results of AMR evaluations for thealternate nitrogen system component groups.All line items in this table are consistent with the GALL Report or are included in the discussionin Section 3.3.2.3 above.3.3.2.3.2Auxiliary Systems-Chemistry Sampling System-Summary of Aging ManagementEvaluation-Table 3.3.2-2The staff reviewed LRA Table 3.3.2-2, which summarizes the results of AMR evaluations for thechemistry sampling system component groups.

3-221All line items in this table are consistent with the GALL Report or are included in the discussionin Section 3.3.2.3 above.3.3.2.3.3Auxiliary Systems-Circulating Water System-Summary of Aging ManagementEvaluation-Table 3.3.2-3The staff reviewed LRA Table 3.3.2-3, which summarizes the results of AMR evaluations for theCWT system component groups.The applicant stated that it expects no aging effects for stainless steel and polyvinyl chloride(PVC) filters/housings exposed to a plant indoor air environment. The staff's review of plant-specific and industry operating experience found no aging effects expected for stainless steel and PVC filters/housings exposed to a plant indoor air environment in the CWT system.Likewise, the applicant stated that it expects no aging effects for rubber expansion jointsexposed to plant indoor air and treated water environments. RAIs 3.3.2.3-3 and 3.3.2.3-4 inSER Section 3.3.2.3 discuss the staff's evaluation.Based on the above evaluations, the staff found that the applicant has identified the appropriateAMP for the materials and environment associated with the above components in the CWTsystem.3.3.2.3.4Auxiliary Systems-Control Rod Drive System-Summary of Aging ManagementEvaluation-Table 3.3.2-4The staff reviewed LRA Table 3.3.2-4, which summarizes the results of AMR evaluations for theCRD system component groups.The applicant proposed to manage the CRD system aging effects with the System ConditionMonitoring Program. SER Section 3.0.3.3.2 documents the staff's review of the applicant'sSystem Condition Monitoring Program.The staff's review of LRA Table 3.3.2-4 identified an area for which it needed additionalinformation to complete its evaluation of the applicant's results. The applicant responded to the staff's RAI as discussed below.In RAI 3.3.2.3-1, dated July 20, 2005, the staff noted that LRA Table 3.3.2-4 identifies SCC asan AERM for stainless steel piping and fittings in a primary containment air environment. To manage this aging effect, the applicant credited the System Conditioning Monitoring Program, which uses visual inspections of component external surfaces for detection of aging effects; therefore, the staff requested that the applicant provide operating experience or other bases fordetermining that SCC is an aging effect in this environment. In addition, since methods like VT-1, liquid penetrant, or volumetric inspections are used to detect SCC, the staff asked the applicant to identify the methods and acceptance criteria of the System Conditioning MonitoringProgram to detect SCC for these components.In its response, by letter dated August 16, 2005, the applicant stated the following:

3-222Data suggests that temperature is an important factor in stress corrosioncracking (SCC) and that SCC is seldom found at temperatures below 140 degrees F. However, a review of plant operating experience revealed two locations where cracking was observed on the exterior of the Control Rod Drive System (CRD) withdrawal lines, prompting NMC to manage cracking on theexterior of the stainless steel CRD lines located inside containment.In 1998, during performance of the visual walkdown portion of the reactorcoolant pressure boundary leakage test, a crack was identified on a CRD withdrawal line within the drywell. The specific CRD is CRD 34-27. Failure analysis performed by a metallurgical laboratory revealed the cause to be transgranular stress corrosion cracking (TGSCC) due to chloride attack of the external surface. This evaluation showed the cracking to originate from the outside diameter inwards. Also, the metallurgical laboratory found chloride in the through wall flaw. The source of the chloride contamination was not positively identified. The leaking pipe was in an area located directly under catwalks.

These open areas are more vulnerable to contamination due to personnel traffic and potential for sp ills.As a result of the leak, the following inspections were made during the 1998refueling outage:

  • All elbows (where the vertical run turns horizontal for penetration of thebiological shield) were visually inspected. There were no indications.
  • Dye penetrant testing on the elbows of 14 withdraw lines in the samebundle as CRD 34-27 (outside of the biological shield, with the exceptionof an elbow on CRD 38-27 which was inside the biological shield.) was conducted. No indications were found.During the 2000 outage, the accessible CRD piping had been wiped down andforeign material, including tape, was removed. After the piping was cleaned, an inspection of 504 one-foot long sections of all accessible CRD insert andwithdrawal lines from the hydraulic accumulator units (HCUs) to the reactor pedestal was implemented. A crack indication was found on CRD withdrawalline 14-27 inside the drywell. The drywell pipe section contained a defect greater than 10% through wall. The apparent cause of the indication appears to have been chloride induced SCC. The indication was identified as being under a piece of tape on a vertical section of the withdraw line. The laborer removing the tape from the area with the relevant indication noted that that particular piece of tapewas different from the others removed in that it was both discolored and difficult to remove. It is possible, although unlikely, that the chlorides necessary for TGSCC leached from this tape. However, a more plausible explanation is that chloride contaminated water from another source dripped down the pipe and the tape acted as a crevice, providing a spot for the aqueous chlorides to begin their 3-223attack. A source of aqueous chlorides leaking from above would be consistentwith the relevant conditions found during the 1998 refueling outage.In view of this plant specific operating experience, NMC conservatively assumedcracking on the external surface of the CRD pipes inside the drywell despite the extensive testing already conducted. The cracking will be managed using theSystem Condition Monitoring Program. The System Condition Monitoring Program is an existing plant-specific program. This program manages aging effects for normally accessible, external surfaces of piping, tanks, and other components and equipment within the scope of license renewal. The aging effects are to be managed through visual inspection to look for degradation conditions such as crack-like indications and corrosion. Crack-like indications willbe entered into the corrective action process for evaluation. The evaluation will include appropriate acceptance criteria based on applicable code specifications and industry practices such as EPRI. The evaluation will consider the need forfurther surface examinations such as liquid penetrant or volumetric inspection to determine the extent of condition.The staff reviewed the applicant's response and found it acceptable. The applicant satisfactorilyexplained its management of SCC as an aging effect in this environment and identified the methods and acceptance criteria used by System Conditioning Monitoring Program to detect SCC for these components. The staff's concern described in RAI 3.3.2.3-1 is resolved.The staff's review of plant-specific and industry operating experience found that the SystemCondition Monitoring Program effectively manages cracking due to SCC of stainless steel material for component types in the CRD system; therefore, the staff found that the applicanthas identified the appropriate AMP for the materials and environment associated with the aboveCRD system components.3.3.2.3.5Auxiliary Systems-Demineralized Water System-Summary of Aging ManagementEvaluation-Table 3.3.2-5The staff reviewed LRA Table 3.3.2-5, which summarizes the results of AMR evaluations for theDWS component groups.The applicant stated that it expects no aging effects for PVC and fiberglass piping, fittings,pump casings, tanks, thermowells, and valve bodies exposed to plant indoor air and treated water environments in the DWS. On the basis of its review of plant-specific and industry operating experience, the staff agreed with this statement.RAIs 3.3.2.3-4 and 3.3.2.3-5 in SER Section 3.3.2.3 discusses the staff's evaluation withrespect to the lack of aging effects for rubber piping and fittings exposed to a plant indoor air and treated water environments.Based on the above evaluations, the staff found that the applicant has identified the appropriateAMP for the materials and environment associated with the above components in the DWS.In LRA Table 3.3.2-5, the applicant proposed to manage loss of material due to pitting andcrevice corrosion and MIC of copper alloy materials for the component types of flow elements, 3-224piping and fittings, and valve bodies exposed to a treated water environment with the PlantChemistry Program combined with the One-Time Inspection Program.The staff reviewed and evaluated the applicant's Plant Chemistry Program and the One-TimeInspection Program, as documented in SER Sections 3.0.3.2.19 and 3.0.3.1.4, respectively.The Plant Chemistry Program mitigates the aging effects on component surfaces exposed to water as the process fluid; chemistry programs control water chemistry for impurities (e.g.,

chloride and sulfate) that accelerate corrosion or crack initiation and growth, or that cause heat transfer degradation due to fouling in select heat exchangers. This program relies on monitoring and control of water chemistry to keep peak levels of various contaminants below system-specific limits. The new One-Time Inspection Program is consistent with therecommendations of GALL AMP XI.M32, and includes measures to verify the effectiveness of the Plant Chemistry Program. The One-Time Inspection Program addresses concerns and provides confirmation of the potential long incubation period for certain aging effects on SCs. If system contaminants are maintained within the limits specified by the Plant Chemistry Program,the corrosion exhibited by the copper alloy in a closed system is adequately managed. Theapplicant has chosen a different combination of AMPs to manage the AERM. The staff found this combination adequate and acceptable for managing this material, environment, and aging effect because contaminants are maintained within limits to inhibit corrosion of the copper alloy.In LRA Table 3.3.2-5, the applicant proposed to manage loss of material due to selectiveleaching of copper alloy materials for the component types of flow elements, piping and fittings, and valve bodies exposed to a treated water (internal) environment with the Selective Leaching of Materials Program.The staff reviewed and evaluated the applicant's Selective Leaching of Materials Program, asdocumented in SER Section 3.0.3.2.22. This new program includes a one-time visual inspection and hardness measurement of certain susceptible components to determine if selective leaching occurs. The staff determined that this AMP is adequate for managing this material, environment, and aging effect.the aging effect of loss of material due to MIC and selective leaching ofcopper alloy material exposed internally to treated water environment given in LRA Table 3.3.2-5.3.3.2.3.6Auxiliary Systems-Emergency Diesel Generators System-Summary of AgingManagement Evaluation-Table 3.3.2-6The staff reviewed LRA Table 3.3.2-6, which summarizes the results of AMR evaluations for theDGN component groups.The staff reviewed AMR line items for the DGN, which experiences cracking due to SCC ofcopper alloy, carbon steel, and cast iron; fouling of copper alloy; and loss of material for copper alloy for the following component types:

  • piping and fittings 3-225
  • fasteners and bolting
  • flame arrestors
  • gauges (flow, sight and level)
  • heat exchangers
  • pump casings
  • tanks
  • valve bodies
  • heaters/coolersFor those components requiring staff review, the following environments apply:
  • exposed to weather (external)
  • treated water (internal)
  • lubricating oil (external)
  • fuel oil (internal)
  • treated water (external)RAI 3.3.2.3-7 in SER Section 3.3.2.3 discusses the staff's evaluation with respect to agingeffects for stainless steel fasteners and bolting exposed to weather environment as well as for copper alloy flame arrestors exposed to weather environment is discussed in RAI 3.3.2.3-7 in SER Section 3.3.2.3. RAIs 3.3.2.3-4 and 3.3.2.3-6 in SER Section 3.3.2.3 discuss the staff'sevaluation with respect to aging effects for rubber piping and fittings exposed to a plant indoor air and gas instrument air environments. RAI 3.3.2.3-2 in SER Section 3.3.2.3 discusses thestaff's review of the management of fouling of heat exchangers in a lubricating oil environments using the One-Time Inspection Program.The applicant proposed to manage DGN aging effects with the CCCW System Program,One-Time Inspection Program, and Fuel Oil Chemistry Program. SER Sections 3.0.3.2.12, 3.0.3.1.4, and 3.0.3.2.17, respectively, document the staff's evaluation of these programs.The staff's review of plant-specific and industry operating experience found that the Closed-Cycle Cooling Water System Program, One-Time Inspection Program, Fuel Oil Chemistry Program effectively manage cracking due to SCC of copper alloy, carbon steel, and cast iron, fouling of copper alloy, and loss of material for copper alloy for DGN component types.Based on the above evaluations, the staff found that applicant has identified the appropriateAMPs for the materials and environment associated with the above components of the DGNcomponents.In LRA Table 3.3.2-6, the applicant proposed to manage heat transfer degradation due tofouling of copper alloy materials for component types of heat exchangers exposed to a treated water environment with the Closed-Cycle Cooling Water System Program.In LRA Table 3.3.2-6, the applicant proposed to manage loss of material due to pitting andcrevice corrosion, and MIC of copper alloy materials for component types including gauges (flow, level, and sight), heat exchangers, and valve bodies exposed to a treated water environment with the Closed-Cycle Cooling Water System Program.

3-226SER Section 3.0.3.2.12 documents the staff's review and evaluation of the applicant's CCCWProgram. The CCCW Program includes (1) preventive measures to minimize corrosion and (2)periodic system and component performance testing and inspection to monitor the effects ofcorrosion and confirm performance of intended functions. Preventive measures include the monitoring and control of corrosion inhibitors and other chemical parameters like pH, in accordance with the guidelines of EPRI TR-1007820, vendor recommendations, and plant operating experience.As the applicant made only minor changes to its CCCW System Program to implement EPRITR-1007820, the program is also still in accordance with the guidelines identified in GALL AMPXI.M21 (i.e., EPRI TR-107396). The applicant also performs periodic inspection and testing to confirm function and monitor corrosion in accordance with EPRI TR-1007820, vendor recommendations, and industry and plant operating experience. If system corrosion inhibitorconcentrations are maintained within the limits specified by the Plant Chemistry Program, corrosion of the copper alloy in a closed system is adequately managed. The staff found thisAMP adequate for managing this material, environment, and aging effect.In LRA Table 3.3.2-6, the applicant proposed to manage loss of material due to selectiveleaching of copper alloy materials for the component types of gauges (flow, level, and sight),

heat exchangers, and valve bodies exposed to treated water environment with the Selective Leaching of Materials Program.The staff reviewed and evaluated the applicant's Selective Leaching of Materials Program, asdocumented in SER Section 3.0.3.2.22. This new program includes a one-time visual inspection and hardness measurement of certain components susceptible to selective leaching. The program will determine if selective leaching occurs for certain components. The staff found thisAMP adequate for managing this material, environment, and aging effect.In LRA Table 3.3.2-6, the applicant proposed to manage loss of material due to pitting andcrevice corrosion and MIC of copper alloy materials for the component types of valve bodies exposed to a fuel oil environment with the Fuel Oil Chemistry Program, combined with the One-Time Inspection Program.In LRA Table 3.3.2-6, the applicant proposed to manage loss of material due to pitting andcrevice corrosion and MIC of stainless steel materials for component types of manifolds, piping and fittings, and valve bodies exposed to a fuel oil environment with the Fuel Oil Chemistry Program, combined with the One-Time Inspection Program.The staff reviewed and evaluated the applicant's Fuel Oil Chemistry Program, as documentedin Section 3.0.3.2.17, and the One-Time Inspection Program, as documented in SERSection 3.0.3.1.4. The Fuel Oil Chemistry Program is an existing program using existing diesel fuel oil system procedures that encompass the GALL Report program recommendations inmitigating and managing aging effects on the internal surfaces of diesel fuel oil storage tanks and associated components in systems that contain diesel fuel oil. The program includes (1)surveillance and monitoring procedures for maintaining diesel fuel oil quality by controllingcontaminants in accordance with applicable ASTM standards, (2) periodic draining of water, if present, from diesel fuel oil tanks, (3) periodic or conditional visual inspection of internal surfaces or wall thickness measurements (e.g., by UT) from external surfaces of diesel fuel oil 3-227tanks, and (4) one-time inspections of a representative sample of components in systems thatcontain diesel fuel oil.The applicant's new One-Time Inspection Program is consistent with the recommendations ofGALL AMP XI.M32. This program will include measures to verify the effectiveness of the PlantChemistry Program and the Fuel Oil Chemistry Program and also confirm the absence of age degradation in selected components (e.g., flow restrictors, venturis, and small bore piping) within the scope of license renewal. The One-Time Inspection Program addresses concerns and provides confirmation of the potential long incubation period for certain aging effects on SCs. The staff review found the Fuel Oil Chemistry Program supplemented by the One-Time Inspection Program adequate for managing these material, environment, and aging effects combinations.On the basis of its review of the applicant's programs, aging effects, and plant-specific andindustry operating experience, the staff determined that the Closed-Cycle Cooling WaterSystem Program, Selective Leaching of Materials Program, or Fuel Oil Chemistry Program combined with the One-Time Inspection Program effectively manage the aging effects of heat transfer degradation due to fouling, loss of material due to pitting and crevice corrosion, and MIC, and loss of material due to selective leaching of copper alloy or stainless steel materials exposed to a treated water (internal or external) or fuel oil environments in LRA Table 3.3.2-6.3.3.2.3.7Auxiliary Systems-Emergency Filtration Train System-Summary of AgingManagement Evaluation-Table 3.3.2-7The staff reviewed LRA Table 3.3.2-7, which summarizes the results of AMR evaluations for theemergency filtration train system component groups.RAIs 3.3.2.3-4 and 3.3.2.3-6 discuss the staff evaluation with respect to aging effects forelastomer ventilation seals exposed to air, gas, and plant indoor air environments.Based on the above evaluation, the staff found that the applicant has identified the appropriateAMPs for the materials and environments associated with the above components in the emergency filtration train system.The staff reviewed and evaluated the Selective Leaching of Materials Program, as documented in SER Section 3.0.3.2.22. This new program includes a one-time visual inspection and hardness measurement of certain components susceptible to selective leaching to determine if selective leaching occurs.the aging effect of loss of material due to selective leaching ofcopper alloy material exposed externally to a wet air/gas environment. On this basis, the staff found the applicant's program to manage loss of material due to selective leaching in LRA Table 3.3.2-7 acceptable.

3-2283.3.2.3.8Auxiliary Systems-Emergency Service Water System-Summary of AgingManagement Evaluation-Table 3.3.2-8The staff reviewed LRA Table 3.3.2-8, which summarizes the results of AMR evaluations for theESW system component groups.The staff reviewed AMR line items for the ESW system. This system experiences fouling of thecopper alloy component of heat exchangers.For those components requiring staff review, the lubricating oil (external) environment applies.

The applicant proposed to manage the ESW system aging effects with the One-TimeInspection Program. SER Section 3.0.3.1.4 documents the staff's evaluation of this program.RAI 3.3.2.3-2 discusses the staff evaluation with respect to managing fouling of heatexchangers in a lubricating oil environment using the One-Time Inspection Program.The staff's review of the plant-specific and industry operating experience found that the One-Time Inspection Program effectively manages fouling of copper alloy components in the ESW system.Based on the above evaluation, the staff found that the applicant has identified the appropriateAMP for the material and environment associated with the above components in the ESW system.3.3.2.3.9Auxiliary Systems-Fire System-Summary of Aging ManagementEvaluation-Table 3.3.2-9The staff reviewed LRA Table 3.3.2-9, which summarizes the results of AMR evaluations for theFIR component groups.In LRA Section 3.3.2.1.9 and Table 3.3.2-9, the applicant identified the materials, environments,and AERMs. The materials identified include bronze, carbon steel, cast iron, copper alloy, ductile iron, galvanized steel, gray cast iron, and stainless steel.The applicant identified the inside, outside, and buried environments to which these materialscould be exposed as air and gas (wetted, ambient and dry), atmosphere/weather, halon, rawwater, and treated water. The applicant identified loss of material (from corrosion or leaching) and heat transfer degradation due to fouling as the aging effects associated with the FIR.The applicant proposed to manage the FIR aging effects with the Bolting Integrity Program,Buried Piping & Tanks Inspection Program, Fire Protection Program, Fire Water System Program, and System Condition Monitoring Program. SER Sections 3.

0.3.2.4, 3.0.3.2.5, 3.0.3.2.15, 3.0.3.2.16, and 3.0.3.3.2, respectively, document the staff's evaluations of theseprograms.

3-229The staff reviewed LRA Section 3.3.2.1.9 and LRA Table 3.3.2-9 to determine whether theapplicant demonstrated that it will adequately manage the aging effects for the FIR during theperiod of extended operation, as required by 10 CFR 54.21(a)(3). The staff conducted its review, described below, in accordance with SRP-LR Section 3.3 and the GALL Report.The staff's review of LRA Table 3.3.2-9 identified areas for which it needed additionalinformation to complete its evaluation of the applicant's results. The applicant responded to the staff's RAIs as discussed below.In RAI 3.3.2.1.9-1, dated August 18, 2005, the staff noted that LRA Table 3.3.2-9 refers toNotes J and 319, which describe the AMRs for copper alloy in heat exchangers; therefore, the staff requested that the applicant justify the conclusion in Note 319 that "the AMP referenced isappropriate for the aging effects/mechanisms identified and provides assurance that the aging effects/mechanisms are effectively managed through the period of extended operation."In its response, by letter dated September 16, 2005, the applicant stated that the Fire WaterSystem Program manages aging of water-based FIR piping and components in accordance with applicable NFPA recommendations. The FP AMP manages aging of fire barriers, the diesel-driven fire pump, and the halon fire suppression system consistent with the GALLReport, since GALL AMP XI.M26 states for FP that, "For operating plants, the fire protection AMP includes a fire barrier inspection program and a diesel-driven fire pump inspection program." As a result, both the Fire Water System and Fire Protection Programs are credited for line items such as filter/strainers, manifolds, pump casings, and valve bodies because these line items apply to both the diesel-driven fire pump (Fire Protection Program) as well as the remainder of the water-based components (Fire Water System Program). In this specific case, the Fire Protection Program, not the Fire Water System Program, manages the copper alloy heat exchanger (radiator) for the diesel-driven fire pump addressed in the Fire Protection Program. Consequently, Note J, which states, "Neither the component nor the material and environment combination is evaluated in NUREG-1801," applies to this line item because theGALL Report,Section VII.G, addresses the diesel-driven fire pump copper heat exchanger in neither a treated water nor raw water environment. Additionally, Note 319, which states the following, further defines this issue: NUREG-1801, Volume 2, Chapter VII (Auxiliary Systems), Section G.6 (FireProtection) does not address this environment for the mechanical portion of the Fire Protection AMP (XI.M26). The AMP referenced is appropriate for the aging effects/mechanisms identified and provides assurance that the aging effects/mechanisms are effectively managed through the period of extended operation to further define this issue. Consequently, the Fire Protection Program, as defined in LRA Section B2.1.17, is appropriateto manage the aging effects of heat transfer degradation and loss of material for the copper alloy diesel-driven fire pump heat exchanger addressed in LRA Table 3.3.2-9 and assures effective management of the aging effects/mechanisms through the period of extended operation.Based on its review, the staff found the applicant's response to RAI 3.3.2.1.9-1 acceptablebecause it adequately explains that the GALL Report does not evaluate the copper alloydiesel-driven fire pump heat exchanger, in both treated water and raw water environments. The 3-230applicant stated that the Fire Protection Program manages the aging effects of heat transferdegradation and loss of material for the copper alloy diesel-driven fire pump heat exchanger.

The staff reviewed the applicant's Fire Protection Program and found acceptable the management of heat transfer degradation due to fouling and loss of material due to general, galvanic, crevice, and pitting corrosion and MIC, as given in LRA Table 3.3.2-9; therefore, the staff's concern described in RAI 3.3.2.1.9-1 is resolved.In RAI 3.3.2.1.9-2, dated August 18, 2005, the staff noted that LRA Table 3.3.2-9 shows noAMP for stainless steel fasteners/bolting; therefore, the staff requested that the applicantexplain why these fasteners/bolting do not require an AMP as recommended by GALL AMP XI.M18.In its response, by letter dated September 16, 2005, the applicant stated that Table 3.3.2-9identifies stainless steel fasteners/bolting in exposed to weather and plant indoor air external environments. The applicant's materials science position, which is consistent with EPRI 1003056, is that these components have no surface exposed to an aggressive chemical species, have no potential for concentrating contaminants, and are not subject to wetting otherthan their normal environment; therefore, loss of material is not a potential aging effect asidentified by LRA Note 327. Additionally, the FIR has no bolts with a specified minimum yield strength >150 ksi.Crevice corrosion is a potential aging mechanism for wetted stainless steel under certainconditions. Crevice corrosion depends strongly on the presence of dissolved oxygen. Although oxygen depletion in crevices may occur as a result of corrosion, oxygen is st ill required for theonset of corrosion and bulk fluid oxygen content or the presence of contaminants like chloridesis necessary for the continued dissolution of material in the crevice. In systems with extremelylow oxygen content (< 0.1 ppm), crevice corrosion is considered insignificant. This form of corrosion requires a crevice where contaminants and corrosion products can concentrate. In addition to oxygen, moisture is required for the mechanism to operate. Alternate wetting and drying is particularly harmful as this leads to a concentration of atmospheric pollutants and contaminants, if present. These conditions do not exist for stainless steel fasteners/bolting at MNGP.Pitting corrosion is a potential aging mechanism for wetted stainless steel under certainconditions. Unless cupric, ferric, or mercuric halides are present in the environment, oxygen is required for pitting initiation. Areas where aggressive species can concentrate are particularly susceptible to pitting. Most pitting is the result of halide contamination with prevalent chlorides, bromides, and hypochlorites. Pitting is a significant aging effect for stainless steels when exposed to a corrosive environment. Any continuously wetted or alternately wetted and dried surfaces tend to concentrate any aggressive species, if they are present, and are prone to pitting corrosion. These conditions also do not exist for stainless steel fasteners/bolting at MNGP.For conservatism during the integrated plant assessment process, both the exposed to weatherand plant indoor air environments include the stainless steel fastener/bolting component to ensure that the evaluations have not inadvertently omitted any components, materials, orenvironments from the evaluations; however, recent walkdowns of the FIR revealed no stainless steel fasteners/bolting exposed to weather.

3-231Consequently, the applicant will remove the FIR stainless steel fasteners/bolting exposed toweather asset from LRA Table 3.3.2-9. Stainless steel fasteners/bolting in a plant indoor air environment have no aging effects for the same reasons as stated above.Based on its review, the staff found the applicant's response to RAI 3.3.2.1.9-2 acceptable,because the applicant stated that stainless steel fasteners/bolting in the FIR have no potentialfor concentrating contaminants and are not subject to wetting other than their normalenvironment. The applicant also stated that recent walkdowns of the FIR revealed no stainless steel fasteners/bolting exposed to weather, so it will remove this asset from LRA Table 3.3.2-9;therefore, the staff's concern described in RAI 3.3.2.1.9-2 is resolved.On the basis of its review of the applicant's programs, aging effects, and plant-specific andindustry operating experience, the staff determined that the aging effects from exposure of thefire water system components to the environments described in LRA Table 3.3.2.6 areconsistent with the GALL Report and with industry experience for these material-environment combinations; therefore, the staff found that the applicant identified the applicable aging effectsand associated AMPs and that they are appropriate for the combination of materials and environments listed.In LRA Table 3.3.2-9, the applicant proposed to manage heat transfer degradation due tofouling, loss of material due to crevice and pitting corrosion, MIC, and loss of material due to selective leaching of copper alloy materials for the component types of heat exchangers exposed to a raw water environment with the Fire Protection Program.The staff reviewed and evaluated the Fire Protection Program, as documented in SER Section 3.0.3.2.15. The Fire Protection Program includes a fire barrier inspection program, a diesel-driven fire pump inspection program, and a halon fire suppression system inspection.The program requires periodic visual inspection of fire barriers, seals, walls, ceilings, floors, andassociated fire-rated doors. The diesel-driven fire pump inspection program periodically tests the pump and inspects the diesel engine to ensure that the fuel supply line can perform the intended function. The halon fire-suppression system inspection includes periodic inspectionand testing of the cable spreading room halon fire-suppression system. The applicant willenhance the existing Fire Protection Program under the Parameters Monitored or Inspected element to be consistent, with certain exceptions, with GALL AMP XI.M26, as modified by ISG-04. The exception to the GALL Report concerns the periodic visual inspection and function test of halon systems at least once every 6 months. The applicant functionally tests and visuallyinspects the cable spreading room halon system every 18 months instead of every 6 months asrecommended in the GALL Report. The staff found this exception acceptable, as documented in SER Section 3.0.3.2.15.

3-232With respect to copper alloy in raw water, the staff has accepted that these AERMs exist inother systems, such as CWT and diesel generator support systems. The fire water and FPsystems also have instances of copper alloy in raw water. The applicant credits the FireProtection Program with managing loss of material due to crevice and pitting corrosion, MIC, and selective leaching. The staff review found this AMP adequate for managing this material, environment, and aging effect. With respect to copper alloy in glycol corrosion-inhibited treated water (external), the staff has accepted that these AERMs exist in other systems, such as the CWT and diesel generator support systems. With respect to gray cast iron in glycolcorrosion-inhibited treated water (external), the applicant credited the Fire Protection Programwith managing loss of material due to general, galvanic, crevice, and pitting corrosion, MIC, and selective leaching. The staff's review found this AMP adequate for managing the AERMs of heat transfer degradation due to fouling, loss of material due to crevice and pitting corrosion, and MIC for the materials identified.In RAI 3.3.2.2.5-1, dated October 31, 2005, the staff requested that the applicant demonstratehow the Fire Water System and the Fire Protection Programs will manage loss of material dueto selective leaching for these materials.In its response, dated November 22, 2005, the applicant stated that it inadvertently omitted theFIR from the applicable systems table in LRA Section B2.1.30 (under "Scope of Program") forthe Selective Leaching of Materials Program. The applicant agreed to revise LRA Section B2.1.30 to include the FIR within the scope of the program. In its letter dated February 28, 2006, the applicant revised LRA Section B2.1.30 to include the FIR within the scope of the program.Additionally, in its response, the applicant stated that under "Scope of Program," the FireProtection, Fire Water System, and Buried Piping & Tanks Programs credit the Selective Leaching of Materials Program for managing loss of material due to selective leaching. The applicant inadvertently omitted such credits not specifically stated from these programdescriptions in the LRA for the respective AMPs.It was not clear to the staff how the applicant intended to credit the Selective Leaching ofMaterial Program, as the Parameters Monitored or Inspected element and the Detection of Aging Effects element for the AMPs do not specify any components that could have an agingeffect of loss of material due to selective leaching. The applicant agreed to revise these AMPs to describe how they will credit the Selective Leaching of Materials Program. In its letter, datedFebruary 28, 2006, the applicant revised the Scope of Program element for the Fire Protection,Fire Water System, and Buried Piping & Tanks Programs to include loss of material due to selective leaching by crediting the Selective Leaching of Materials Program.The staff found this response acceptable; therefore, the staff's concern described inRAI 3.3.2.2.5-1 is resolved.In LRA Table 3.3.2-9, the applicant proposed to manage loss of material due to galvanic andgeneral corrosion of carbon steel materials for the component types of valve bodies exposed to air/gas (internal) environment with the Fire Water System Program.The staff reviewed and evaluated the Fire Water System Program, as documented in SERSection 3.0.3.2.16. The Fire Water System Program relies on testing of water-based FP system 3-233piping and components in accordance with applicable NFPA recommendations. In addition, theapplicant will modify this program to include (1) portions of the FP sprinkler system subject tofull-flow tests before the period of extended operation and (2) portions of the FP systemexposed to water that are visually inspected internally. Periodic full-flow fl ush test s and systemperformance tests ensure that the aging mechanisms of corrosion and biofouling/fouling are properly managed in the fire water system. With respect to carbon steel in an air/gas (internal)environment, the applicant has chosen, for conservatism, to manage the AERM as though the environment were water. The staff review found this AMP adequate for managing this material, environment, and aging effect.On the basis of its review of the applicant's programs, aging effects and plant-specific andindustry operating experience, the staff determined that the Fire Protection and Fire WaterSystem Programs effectively manage the aging effect of heat transfer degradation due to fouling, loss of material due to general, galvanic, crevice, and pitting corrosion and MIC, and loss of material due to selective leaching of copper alloy, gray cast iron, and carbon steel materials exposed to raw water, glycol corrosion-inhibited treated water (internal and external),

and air/gas (internal) environments. On this basis, the staff found acceptable the management of heat transfer degradation due to fouling, loss of material due to general, galvanic, crevice, and pitting corrosion and MIC, and loss of material due to selective leaching in LRA Table 3.3.2-9.3.3.2.3.10Auxiliary Systems-Fuel Pool Cooling and Cleanup-Summary of AgingManagement Evaluation-Table 3.3.2-10The staff reviewed LRA Table 3.3.2-10, which summarizes the results of AMR evaluations forthe FPC component groups.In LRA Table 3.3.2-10, the applicant proposed to manage loss of material due to crevice andpitting corrosion and MIC of copper alloy materials for the component types of piping and fittings, and valve bodies exposed internally to a treated water environment with the Plant Chemistry Program combined with the One-Time Inspection Program.The staff reviewed and evaluated the applicant's Plant Chemistry Program and the One-TimeInspection Program, as documented in SER Sections 3.0.3.2.19 and 3.0.3.1.4, respectively.The Plant Chemistry Program mitigates the aging effects on component surfaces that are exposed to water as the process fluid; chemistry programs are used to control water chemistry for impurities (e.g., chloride and sulfate) that accelerate corrosion or crack initiation and growth and that cause heat transfer degradation due to fouling in select heat exchangers. This program relies on monitoring and control of water chemistry to keep peak levels of various contaminants below system-specific limits. The new One-Time Inspection Program is consistentwith the recommendations of GALL AMP XI.M32 and will verify the effectiveness of the PlantChemistry Program. The One-Time Inspection Program addresses concerns and provides confirmation for the potential long incubation period for certain aging effects on SCs. The staff review determined that the Plant Chemistry Program supplemented by the One-Time InspectionProgram is adequate for managing this material, environment, and aging effect combination.In LRA Table 3.3.2-10, the applicant proposed to manage loss of material due to selectiveleaching of copper alloy materials for the component types of piping and fittings, and valve 3-234bodies exposed internally to a treated water environment with the Selective Leaching ofMaterials Program.The staff reviewed and evaluated the Selective Leaching of Materials Program, as documentedin SER Section 3.0.3.2.22. This new program includes a one-time visual inspection and hardness measurement to determine if selective leaching occurs for certain susceptible components. The staff's program review found management of loss of material due to selective leaching in LRA Table 3.3.2-7 acceptable.the aging effects of loss of material due to crevice and pitting corrosion,MIC, and selective leaching of copper alloy material exposed to a treated water (internal) environment. On this basis, the staff found management of loss of material due to crevice and pitting corrosion, MIC, and selective leaching, as given in LRA Table 3.3.2-10, acceptable.3.3.2.3.11Auxiliary Systems-Heating and Ventilation-Summary of Aging ManagementEvaluation-Table 3.3.2-11The staff reviewed LRA Table 3.3.2-11, which summarizes the results of AMR evaluations forthe HTV component groups.In LRA Table 3.3.2-11, the applicant proposed to manage loss of material due to pitting andcrevice corrosion of copper alloy materials for the component types of heaters/coolers, heating, ventilation, and air conditioning (HVAC) units, piping and fittings, and valve bodies exposed to a treated water or steam environment with the Closed-Cycle Cooling Water System Program.Section 3.0.3.2.12. The CCCW System Program includes (1) preventive measures to minimizecorrosion and (2) periodic system and component performance testing and inspection tomonitor the effects of corrosion and confirm performance of intended functions. Preventive measures monitor and control corrosion inhibitors and other chemical parameters like pH, in accordance with the guidelines of EPRI TR-1007820, vendor recommendations, and plant operating experience. As only minor changes were made to the CCCW System Program toimplement EPRI TR-1007820, the program is also still consistent with the guidelines identifiedin GALL AMP XI.M21 (i.e., EPRI TR-107396). Periodic inspection and testing to confirm function and monitor corrosion are also performed in accordance with EPRI TR-1007820, vendor recommendations, and industry and plant-operating experience. The staff's review found this AMP adequate for managing this material, environment, and aging effect.In LRA Table 3.3.2-11, the applicant proposed to manage loss of material due to pitting andcrevice corrosion and MIC of copper alloy materials for the component types of gauges (flow, level, and sight), chillers, piping and fittings, and valve bodies exposed to a treated waterenvironment with the One-Time Inspection Program.

3-235In LRA Table 3.3.2-11, the applicant proposed to manage loss of material due to selectiveleaching of copper alloy materials for the component types of chillers, gauges (flow, level, andsight), heaters/coolers, HVAC units, piping and fittings, and valve bodies exposed to treated water, treated water or steam (internal), and wet air/gas (external) environments with the Selective Leaching of Materials Program. Section 3.0.3.2.22. This new program includes a one-time visual inspection andhardness measurement to determine if selective leaching occurs for certain susceptible components. The staff's review found this AMP adequate for managing this material, environment, and aging effect.On the basis of its review of the applicant's programs, aging effects, and plant-specific andindustry operating experience, the staff determined that the Closed-Cycle Cooling WaterSystem Program, One-Time Inspection Program, and Selective Leaching of Materials Program effectively manage the aging effect of loss of material due to pitting and crevice corrosion, MIC, and selective leaching of copper alloy material exposed to treated water (internal), treated water or steam (internal), and wet air/gas (external) environments. On this basis, the staff found that management of inTable 3.3.2-11 is acceptable.3.3.2.3.12Auxiliary Systems-Instrument and Service Air System-Summary of AgingManagement Evaluation-Table 3.3.2-12The staff reviewed LRA Table 3.3.2-12, which summarizes the results of AMR evaluations forthe AIR system component groups.In LRA Table 3.3.2-12, the applicant proposed to manage loss of material due to crevice andpitting corrosion and MIC of copper alloy materials for the component types of gauges (flow, level, and sight) and valve bodies exposed to a treated water environment with the CCCWSystem Program.The staff reviewed and evaluated the CCCW System Program, as documented in SERSection 3.0.3.2.12. The CCCW System Program includes (1) preventive measures to minimizecorrosion and (2) periodic system and component performance testing and inspection tomonitor the effects of corrosion and confirm performance of intended functions. Preventive measures monitor and control corrosion inhibitors and other chemical parameters like pH in 3-236accordance with the guidelines of EPRI TR-1007820, vendor recommendations, and plantoperating experience. As only minor changes were made to the CCCW System Program toimplement EPRI TR-1007820, the program is also still consistent with the guidelines identifiedin GALL AMP XI.M21 (i.e., EPRI TR-107396). Periodic inspection and testing to confirm function and monitor corrosion are also performed in accordance with EPRI TR-1007820, vendor recommendations, and industry and plant operating experience. The staff's review found this AMP adequate for managing this material, environment, and aging effect. a gas-compressed air environment with the Compressed Air Monitoring Program. Section 3.0.3.2.13. The Compressed Air Monitoring Program consists of inspection,monitoring, and testing of the AIR system for reasonable assurance that the components willperform their intended functions for the period of extended operation. With respect to copper alloy in a gas-compressed air environment, MNGP has chosen, for conservatism, to manage the AERM as though it were an environment with condensation. The staff's review found this AMP adequate for managing this material, environment, and aging effect.environments with theSelective Leaching of Materials Program.The staff reviewed and evaluated the Selective Leaching of Materials Program, as documentedin SER Section 3.0.3.2.22. This new program includes a one-time visual inspection and hardness measurement to determine if selective leaching occurs for certain susceptible components. The staff's review found this AMP adequate for managing this material, environment, and aging effect.On the basis of its review of the applicant's programs, aging effects, and plant-specific andindustry operating experience, the staff determined that the Closed-Cycle Cooling WaterSystem Program, Compressed Air Monitoring Program, and Selective Leaching of Materials Program effectively manage the aging effect of loss of material due to crevice and pitting corrosion, MIC, and selective leaching of copper alloy material exposed to treated water (internal) and gas-compressed air (internal) environments. On this basis, the staff found management of loss of material due to crevice and pitting corrosion, MIC, and selective leaching in LRA Table 3.3.2-12 acceptable.3.3.2.3.13Auxiliary Systems-Radwaste Solid and Liquid System-Summary of AgingManagement Evaluation-Table 3.3.2-13The staff reviewed LRA Table 3.3.2-13, which summarizes the results of AMR evaluations forthe radwaste solid and liquid system component groups.All line items in this table are consistent with the GALL Report or are included in the discussionin Section 3.3.2.3 above.

3-2373.3.2.3.14Auxiliary Systems-Reactor Building Closed Cooling Water System-Summary ofAging Management Evaluation-Table 3.3.2-14The staff reviewed LRA Table 3.3.2-14, which summarizes the results of AMR evaluations forthe RBC system component groups. a treated water environment with the CCCW System Program.The staff reviewed and evaluated the CCCW System Program, as documented in SERSection 3.0.3.2.12. The CCCW System Program includes (1) preventive measures to minimizecorrosion and (2) periodic system and component performance testing and inspection tomonitor the effects of corrosion and confirm performance of intended functions. Preventive measures monitor and control corrosion inhibitors and other chemical parameters like pH, in accordance with the guidelines of EPRI TR-1007820, vendor recommendations, and plant operating experience. As only minor changes were made to the CCCW System Program toimplement EPRI TR-1007820, the program is also still consistent with the guidelines identifiedin GALL AMP XI.M21 (i.e., EPRI TR-107396). Periodic inspection and testing to confirm function and monitor corrosion are also performed in accordance with EPRI TR-1007820, vendor recommendations, and industry and plant operating experience. The staff's review found this AMP adequate for managing this material, environment, and aging effect.environment with the Selective Leaching of MaterialsProgram.. The staff's review found this AMP adequate for managing this material,environment, and aging effect.Table 3.3.2-14, is acceptable.3.3.2.3.15Auxiliary Systems-Reactor Water Cleanup System-Summary of AgingManagement Evaluation-Table 3.3.2-15The staff reviewed LRA Table 3.3.2-15, which summarizes the results of AMR evaluations forthe RWCU system component groups.

3-238All line items in this table are consistent with the GALL Report or are included in the discussionin Section 3.3.2.3 above.3.3.2.3.16Auxiliary Systems-Service and Seal Water System-Summary of AgingManagement Evaluation-Table 3.3.2-16The staff reviewed LRA Table 3.3.2-16, which summarizes the results of AMR evaluations forthe service and seal water system component groups.RAIs 3.3.2.3-3 and 3.3.2.3-4 discuss the staff evaluation with respect to aging effects for rubberexpansion joints exposed to plant indoor air and raw water environments in the service and seal water system.Based on the RAI evaluations, the staff found that the applicant has identified the appropriateAMP for the materials and environments associated with the above components in the serviceand seal water system. All other line items in this table are consistent with the GALL Report orare included in the discussion in Section 3.3.2.3 above.3.3.2.3.17Auxiliary Systems-Standby Liquid Control System-Summary of AgingManagement Evaluation-Table 3.3.2-17The staff reviewed LRA Table 3.3.2-17, which summarizes the results of AMR evaluations forthe SLC system component groups.RAI 3.3.2.3-5 discusses the staff evaluation with respect to aging effects for rubberaccumulators exposed to nitrogen gas and plant indoor air environments in the SLC system.Based on the evaluation of the response to the above RAI, the staff found that applicant hasidentified the appropriate AMP for the materials and environments associated with the abovecomponents in the SLC system. All other line items in this table are consistent with the GALLReport or are included in the discussion in Section 3.3.2.3 above.3.3.2.3.18Auxiliary Systems-Wells and Domestic Water System-Summary of AgingManagement Evaluation-Table 3.3.2-18The staff reviewed LRA Table 3.3.2-18, which summarizes the results of AMR evaluations forthe wells and domestic water system component groups.In LRA Table 3.3.2-18, the applicant proposed to manage loss of material due to crevice andpitting corrosion, MIC, and erosion of copper alloy materials for the component types of piping and fittings and valve bodies exposed to a raw water environment with the One-Time Inspection Program.The staff reviewed and evaluated the One-Time Inspection Program, as documented in SERSection 3.0.3.1.4. The new One-Time Inspection Program is consistent with therecommendations of GALL AMP XI.M32 and will confirm the absence of age degradation inselected components (e.g., flow restrictors, venturis, and small bore piping) within the scope of license renewal. The One-Time Inspection Program addresses concerns and provides confirmation for the potential long incubation period for certain aging effects on SCs. The 3-239applicant has noted in the LRA that in some cases in which aging effects/mechanisms are notexpected to be significant, the One-Time Inspection Program alone is credited with managing aging effects. The staff determined that the use of the One-Time Inspection Program alone isacceptable where the use of the Plant Chemistry Program is not a viable option. This AMP isappropriate for the aging effects/mechanisms identified and assures effective management of them through the period of extended operation.In LRA Table 3.3.2-18, the applicant proposed to manage loss of material due to crevicecorrosion, pitting corrosion, and MIC of Hastelloy (C-276) material for the component types of piping and fittings exposed to a raw water environment using the One-Time Inspection Program. In addition, the applicant stated that Hastelloy (C-276) in a concrete or plant indoor airenvironment has no AERM and therefore requires no AMP.The staff determined that Hastelloy (C-276) is a highly corrosion-resistant material, anddegradation is not expected in typical domestic water applications. Hastelloy (C-276) piping and fitting material exposed to concrete or an air environment in the absence of moisture with contaminants has no aging effects and requires no aging management. Similarly, degradation of Hastelloy (C-267) in a raw water internal environment is not expected. It is conservative to assume loss of material due to crevice and pitting corrosion and MIC in this environment with the potential for unknown contaminants. The staff's review found the One-Time InspectionProgram adequate to manage the aging effects of this corrosion-resistant material in this environment to confirm that degradation is not occurring.In LRA Table 3.3.2-18, the applicant proposed to manage loss of material due to selectiveleaching of copper alloy materials for the component types of piping and fittings and valve bodies exposed to a raw water environment with the Selective Leaching of Materials Program.The staff reviewed and evaluated the Selective Leaching of Materials Program, as documentedin SER Section 3.0.3.2.22. This new program includes a one-time visual inspection and hardness measurement to determine if selective leaching occurs for certain susceptible components. The staff's review found this AMP adequate for managing this material, environment, and aging effect.On the basis of its review of the applicant's programs, aging effects, and plant-specific andindustry operating experience, the staff determined that the One-Time Inspection Program andSelective Leaching of Materials Program effectively manage the aging effect of loss of material due to crevice and pitting corrosion, MIC, erosion, and selective leaching of copper alloy material exposed to a raw water (internal) environment. On this basis, the staff found management of loss of material due to crevice and pitting corrosion, MIC, erosion, and selective leaching, as given in LRA Table 3.3.2-18, acceptable.Conclusion. On the basis of its review, the staff found that the applicant appropriately evaluatedAMR results involving material, environment, AERM, and AMP combinations that are not evaluated in the GALL Report. The staff found that the applicant has demonstrated that theaging effects will be adequately managed so that intended functions will be maintainedconsistent with the CLB for the period of extended operation, as required by10 CFR 54.21(a)(3).

3-2403.3.3 ConclusionThe staff concluded that the applicant provided sufficient information to demonstrate that theaging effects for the auxiliary systems components that are within the scope of license renewaland subject to an AMR will be adequately managed so that intended functions will bemaintained consistent with the CLB for the period of extended operation, as required by10 CFR 54.21(a)(3).The staff also reviewed the applicable USAR supplement program summaries and concludedthat they adequately describe the AMPs credited with managing aging of the auxiliary systems,as required by 10 CFR 54.21(d).3.4 Aging Management of Steam and Power Conversion SystemThis section of the SER documents the staff's review of the applicant's AMR results for the SPCsystem components and component groups associated with the following systems:

  • condensat e stor age syst em
  • turbine generator system3.4.1 Summary of Technical Information in the Application In LRA Section 3.4, the applicant provided AMR results for the SPC system components andcomponent groups. In LRA Table 3.4.1, the applicant provided a summary comparison of its AMRs with the AMRs evaluated in the GALL Report for the SPC system components andcomponent groups.The applicant's AMRs incorporated applicable operating experience in the determination ofAERMs. These reviews included evaluation of plant-specific and industry operating experience.

The plant-specific evaluation included reviews of CRs and discussions with appropriate site personnel to identify AERMs. The applicant's review of industry operating experience included a review of the GALL Report and operating experience issues identified since the issuance of the GALL Report.3.4.2 Staff Evaluation The staff reviewed LRA Section 3.4 to determine if the applicant provided sufficient informationto demonstrate that the effects of aging for the SPC system components that are within thescope of license renewal and subject to an AMR will be adequately managed so that theintended functions will be maintained consistent with the CLB for the period of extendedoperation, as required by 10 CFR 54.21(a)(3).In addition, the staff performed an onsite audit of AMRs to confirm the applicant's claim thatcertain identified AMRs are consistent with the GALL Report. The staff did not repeat its reviewof the matters described in the GALL Report; however, the staff did verify that the material 3-241presented in the LRA is applicable and that the applicant identified the appropriate GALLReport AMRs. SER Section 3.0.3 documents the staff's evaluations of the AMPs. The MNGP audit and review report details the staff's audit evaluation, which are summarized in SER Section 3.4.2.1.The staff also performed an onsite audit of those selected AMRs that are consistent with theGALL Report and for which further evaluation is recommended. The staff confirmed that the applicant's further evaluations are consistent with the acceptance criteria in SRP-LR Section 3.4.2.2. The MNGP audit and review report documents the staff's audit evaluations,which are summarized in SER Section 3.4.2.2.The staff performed an onsite audit and conducted a technical review of the remaining AMRsthat are not consistent with, or not addressed in, the GALL Report. The audit and technicalreview included evaluating whether the applicant identified all plausible aging effects and whether the aging effects listed are appropriate for the combination of materials and environments specified. The MNGP audit and review report documents the staff's audit evaluations. SER Section 3.4.2.3 summarizes these audit evaluations and documents thestaff's evaluation of its technical review.Finally, the staff reviewed the AMP summary descriptions in the USAR supplement to ensurethat they adequately describe the programs credited with managing or monitoring aging for theSPC system components.Table 3.4-1 below summarizes the staff's evaluation of components, aging effects/mechanisms,and AMPs listed in LRA Section 3.4 that are addressed in the GALL Report.Table 3.4-1 Staff Evaluation for Steam and Power Conversion System Components inthe GALL ReportComponent GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff EvaluationPiping and fittings inmain feedwater line,steamline and AFWpiping (PWR only)(Item Number3.4.1-01)Cumulative fatiguedamageTLAA, evaluated inaccordance with10 CFR 54.21(c)TLAAThis TLAA isevaluated in Section4.3, Metal Fatigueof the RPV andInternals, andReactor CoolantPressure BoundaryPiping andComponents (seeSection 3.4.2.2.1)Piping and fittings,valve bodies andbonnets, pumpcasings, tanks,tubes, tubesheets,channel head andshell (except mainsteam system)(Item Number3.4.1-02)Loss of materialdue to general(carbon steel only),pitting, and crevicecorrosionWater chemistry,one-time inspectionOne-TimeInspection Program(B2.1.23), PlantChemistry Program(B2.1.25) Consistent withGALL Report, whichrecommends furtherevaluation (seeSection 3.4.2.2.2)

Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation3-242Auxiliary feedwater(AFW) piping(Item Number3.4.1-03)Loss of materialdue to general,pitting, and crevicecorrosion, MIC, andbiofoulingPlant specificNot applicable,PWR only (seeSection 3.4.2.2.3)Oil coolers in AFWsystem (lubricatingoil side possiblycontaminated withwater)(Item Number3.4.1-04)Loss of materialdue to general(carbon steel only),pitting, and crevicecorrosion and MICPlant specificNot applicable,PWR only (seeSection 3.4.2.2.3)External surface ofcarbon steelcomponents(Item Number3.4.1-05)Loss of materialdue to generalcorrosionPlant specificSystem ConditionMonitoring Program(B2.1.32)Consistent withGALL Report, whichrecommends furtherevaluation (seeSection 3.4.2.2.4)Carbon steel pipingand valve bodies(Item Number3.4.1-06)Wall thinning due toflow-acceleratedcorrosionFlow-acceleratedcorrosionFlow-AcceleratedCorrosion Program(B2.1.19)Consistent withGALL Report, whichrecommends nofurther evaluationCarbon steel pipingand valve bodies inmain steam system(Item Number3.4.1-07)Loss of materialdue to pitting andcrevice corrosionWater chemistryThis line item wasnot used at MNGP.See Item Number3.4.1-02Closure bolting inhigh-pressure orhigh-temperaturesystems(Item Number3.4.1-08)Loss of materialdue to generalcorrosion; crackinitiation and growthdue to cyclicloading and/or SCCBolting integrityBolting IntegrityProgram (B2.1.4)Consistent withGALL Report, whichrecommends nofurther evaluationHeat exchangersandcoolers/condensersserviced byopen-cycle coolingwater(Item Number3.4.1-09)Loss of materialdue to general(carbon steel only),pitting, and crevicecorrosion, MIC, andbiofouling; buildupof deposit due tobiofoulingOpen-cycle coolingwater systemNot applicable (seeSection 3.4.2.1.1)Heat exchangersandcoolers/condensersserviced byclosed-cycle coolingwater(Item Number3.4.1-10)Loss of materialdue to general(carbon steel only),pitting, and crevicecorrosionClosed-cyclecooling watersystemNot applicable.No heat exchangersserviced byclosed-cycle coolingwater Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation3-243External surface ofabovegroundcondensate storagetank(Item Number3.4.1-11)Loss of materialdue to general(carbon steel only),pitting, and crevicecorrosionAbove groundcarbon steel tanksNot applicable.MNGP condensatestorage tanks arenot within the scopeof license renewalExternal surface ofburied condensatestorage tank andAFW piping(Item Number3.4.1-12)Loss of materialdue to general,pitting, and crevicecorrosion and MICBuried piping andtanks surveillance or Buried piping andtanks inspectionBuried Piping &Tanks InspectionProgram (B2.1.5)Emergency dieselgenerators systemoil storage tankexternal surface ismanaged by theBuried Piping &Tanks InspectionProgramExternal surface ofcarbon steelcomponents(Item Number3.4.1-13)Loss of materialdue to boric acidcorrosionBoric acid corrosionNot applicable,PWR onlyThe staff's review of the MNGP component groups followed one of several approaches. Oneapproach, documented in SER Section 3.4.2.1, involves the staff's review of the AMR resultsfor components in the SPC system that the applicant indicated are consistent with the GALLReport and do not require further evaluation. Another approach, documented in SERSection 3.4.2.2, involves the staff's review of the AMR results for components in the SPCsystem that the applicant indicated are consistent with the GALL Report and for which furtherevaluation is recommended. A third approach, documented in SER Section 3.4.2.3, involves thestaff's review of the AMR results for components in the SPC system that the applicant indicatedare not consistent with, or not addressed in, the GALL Report. SER Section 3.0.3 documentsthe staff's review of AMPs that are credited to manage or monitor aging effects of the SPC system components.3.4.2.1 AMR Results That Are Consistent with the GALL Report Summary of Technical Information in the Application. In LRA Section 3.4.2.1, the applicantidentified the materials, environments, and AERMs. The applicant identified the following programs that manage the aging effects related to the SPC system components:

  • Bolting Integrity Program (B2.1.4)
  • Flow-Accelerated Corrosion Program (B2.1.19)
  • One-Time Inspection Program (B2.1.23)
  • Open-Cycle Cooling Water System Program (B2.1.24)
  • Plant Chemistry Program (B2.1.25)
  • Selective Leaching of Materials Program (B2.1.30)
  • System Condition Monitoring Program (B2.1.32) 3-244Staff Evaluation. In LRA Tables 3.4.2-1 through 3.4.2-5, the applicant summarized the AMRsfor the SPC system components, and identified which AMRs it considered to be consistent withthe GALL Report.For component groups evaluated in the GALL Report for which the applicant has claimedconsistency with the GALL Report, and for which the GALL Report does not recommend further evaluation, the staff performed an audit and review to determine whether the GALL Reportevaluation bounds the plant-specific components contained in these GALL Report componentgroups.The applicant provided a note for each AMR line item. The notes described how the informationin the tables aligns with the information in the GALL Report. The staff audited those AMRs with Notes A through E, which indicate that 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 AMP identified in the GALL Report. The staff audited these line items to verify consistency with the GALL Report and the validity of the AMR for the site-specific conditions.Note B 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 AMP identified in the GALL Report. The staff audited these line items to verify consistency with the GALL Report. The staff verified that it had reviewed and accepted the identified exceptionsto the GALL Report AMPs. The staff also determined whether the AMP identified by the applicant is consistent with the AMP identified in the GALL Report and whether the AMR is validfor the site-specific conditions.Note C indicates that the component for the AMR line item, although different, is consistent withthe GALL Report for material, environment, and aging effect. In addition, the AMP is consistent with the AMP identified by the GALL Report. This note indicates that the applicant could not finda listing of some system components in the GALL Report. However, the applicant identified adifferent component in the GALL Report that has 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 determined whether the AMR line item of the different component applies to the component under review and whether the AMR is valid for the site-specific conditions.Note D indicates that the component for the AMR line item, although different, is consistent withthe GALL Report for material, environment, and aging effect. In addition, the AMP takes some exceptions to the AMP identified in the GALL Report. The staff audited these line items to verify consistency with the GALL Report. The staff verified whether the AMR line item of the different component applies to the component under review. The staff verified that it had reviewed and accepted the identified exceptions to the GALL Report AMPs. The staff also determined whether the AMP identified by the applicant is consistent with the AMP identified in the GALLReport and whether the AMR is 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 the applicant credited a different AMP. The staff audited these line items to verify consistency with the GALL Report. The staff also determined whether 3-245the identified AMP will manage the aging effect consistent with the AMP identified by the GALLReport and whether the AMR is valid for the site-specific conditions.The staff conducted an audit and review of the information provided in the LRA, as documentedin the MNGP audit and review report. The staff did not repeat its review of the matters described in the GALL Report; however the staff did verify that the material presented in the LRA is applicable and that the applicant identified the appropriate GALL Report AMRs. The following sections discuss the staff's evaluation.3.4.2.1.1Loss of Material Due to General, Pitting, and Crevice Corrosion, MIC, andBiofouling; Buildup of Deposit Due to BiofoulingIn LRA Table 3.4.1, Item 3.4.1-09, the applicant addressed the loss of material due to general,pitting, and crevice corrosion, MIC, and biofouling, and buildup of deposit due to biofouling for heat exchangers and coolers/condensers serviced by OCCW. The applicant stated that Item3.4.1-09 does not apply. The applicant stated that the management of aging effects of certaincomponents of the CDR with the intended function of plateout and holdup of radioactivematerial is not applicable because the CDR structural integrity is demonstrated continuouslyduring normal plant operation.During the audit and review, the staff noted that in LRA Table 3.4.2-3 the applicant presentedits AMR results for the CDR system. In the table, the applicant claimed consistency with theGALL Report for aging management of the internal and external surfaces of the carbon steel condenser shell. The table cited generic Note E (i.e., the component, material, and environment are consistent with the GALL Report recommendation but the applicant applied a differentAMP). However, the applicant claimed that an AMP is not required and referenced plant-specific Note 410. The staff questioned the applicant's use of Note E for these AMR entries as no AMP is credited.In response, the applicant stated that the structural integrity of the CDR required to perform itspost-accident intended function is demonstrated continuously during normal plant operation; therefore, no traditional AMP is required. The post-accident intended function of the CDR is toprovide a holdup volume and plateout surface for MSIV leakage. This intended function does not require the CDRs to be leak tight because the post-accident conditions in the CDRs areessentially atmospheric and there will be no challenge to their pressure boundary integrity.Normal plant operation assures adequate CDR pressure boundary integrity and thepost-accident intended function to provide pressure boundary and holdup volume and plateout surface.The staff noted that SRP-LR Section A.1.2.3.4 states that a program based solely on detectingSC failures is not considered an effective AMP. The staff then reviewed the applicant's justification and asked it to clarify why it had described no AMP for these components.The applicant stated that radioactive iodine is assumed to plate out on the interior surfaces ofthe CDR for both loss of coolant and control rod drop accidents. Aging management is notrequired for the CDR components that have only a plateout and holdup of radioactive materialintended function. For these components, the aging effects do not require aging managementas the condenser surface condition does not affect the deposition of iodine in the CDR. Tomaintain the intended function, the CDR and the components which make up the CDR complex 3-246simply have to remain intact. Condenser structural integrity is demonstrated continuously duringnormal operation when the condenser is required to maintain vacuum. When the condenser is required to perform its intended function following a DBA, the MSIVs will be closed andcondenser vacuum will be lost. The condenser will not be required to perform a pressureboundary function because essentially atmospheric conditions will exist inside the condenser.Since normal performance considerations, such as fouling and in-leakage (e.g., CWT or air leaks), place greater requirements on condenser operation than the post-accident plateout,then, as long as the condenser is intact and operational, the post-accident plateout and holdupof radioactive material will be maintained and no aging management is required.Additionally, as documented in its August 31, 2005, letter, the applicant revised plant-specificNote 410 to clarify the discussion of the intended function of the CDR:No traditional aging management of the main condenser for plateout and holdupis required. The main condenser is required to perform a post-accident intended function of plateout and holdup. This post-accident intended function does not require the main condenser to be leak tight and post-accident conditions in the main condenser would be essentially atmospheric. During normal plant operation, the main condenser continuously verifies its structural integrity by maintaining condenser vacuum that is constantly monitored and provides assurance that it will perform its post-accident intended function of iodineplateout and holdup.The staff's review of the applicant's response found that the CDR need not be leak-tight, aspost-accident conditions in the CDR are essentially atmospheric. During normal plantoperations, the applicant continuously monitors condenser vacuum to verify the integrity of the CDR. Degradation of its integrity to a loss of vacuum will require placement of the plant in amode that will obviate the post-accident intended function; therefore, acceptable performanceduring normal plant operation is adequate assurance that the CDR can perform the hol dup andplateout post-accident function.On this basis, the staff found that the applicant appropriately addressed the aging effect andmechanism as identified in the GALL Report.Conclusion. The staff evaluated the applicant's claim of consistency with the GALL Report. Thestaff also reviewed information pertaining to the applicant's consideration of recent operating experience and proposals for managing associated aging effects. The staff's review concluded that the AMR results, which the applicant claimed to be consistent with the GALL Report, areconsistent with the AMRs in the GALL Report; therefore, the staff concluded that the applicanthas demonstrated that the aging effects for these components will be adequately managed sothat their intended function(s) will be maintained consistent with the CLB for the period ofextended operation, as required by 10 CFR 54.21(a)(3).3.4.2.2AMR Results That Are Consistent with the GALL Report, for Which Further EvaluationIs RecommendedSummary of Technical Information in the Application. In LRA Section 3.4.2.2 the applicantprovided further evaluation of aging management as recommended by the GALL Report for the 3-247SPC system components. The applicant provided information concerning how it will m anage thefollowing aging effects:
  • cumulative fatigue damage
  • loss of material due to general, pitting, and crevice corrosion
  • loss of material due to general, pitting, and crevice corrosion, microbiologicallyinfluenced corrosion, and biofouling
  • general corrosion
  • loss of material due to general, pitting, crevice, and microbiologically influencedcorrosionStaff Evaluation. For component groups evaluated in the GALL Report for which the applicanthas claimed consistency with the GALL Report, and for which the GALL Report recommends further evaluation, the staff audited and reviewed the applicant's evaluation to determinewhether it adequately addressed the issues that were further evaluated. In addition, the staffreviewed the applicant's further evaluations against the criteria contained in SRP-LR Section 3.4.2.2. The staff's audit and review report details the staff's audit. The following sections discuss the staff's evaluation of the aging effects.3.4.2.2.1 Cumulative Fatigue Damage In LRA Section 3.4.2.2.1, the applicant stated that fatigue is a TLAA, as defined in10 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 criteria in SRP-LR Section 3.4.2.2.2.In LRA Section 3.4.2.2.2 the applicant addressed loss of material due to general, pitting, andcrevice corrosion of carbon steel and cast iron piping and fittings, valve bodies and bonnets, pump casings, pump suction and discharge lines, tanks, tubesheets, channel heads, and shells except for MST system components in the SPC system. This section also addresses loss ofmaterial due to pitting and crevice corrosion of stainless steel components in the SPC system.SRP-LR Section 3.4.2.2.2 states the following:The management of loss of material due to general, pitting, and crevicecorrosion should be evaluated further for carbon steel piping and fittings, valve bodies and bonnets, pump casings, pump suction and discharge lines, tanks, tubesheets, channel heads, and shells except for main steam systemcomponents and for loss of material due to pitting and crevice corrosion for stainless steel tanks and heat exchanger/cooler tubes. The water chemistry program relies on monitoring and control of water chemistry based on the guidelines in BWRVIP-29 (EPRI guideline TR-103515) for water chemistry to manage the effects of loss of material due to general, pitting, or crevice corrosion. However, corrosion may occur at locations of stagnant flow conditions.

Therefore, the effectiveness of the chemistry control program should be verified to ensure that corrosion is not occurring. The GALL Report recommends further 3-248evaluation of programs to manage loss of material due to general, pitting, andcrevice corrosion to verify the effectiveness of the water chemistry program. A one-time inspection of select components and susceptible locations is an acceptable method to ensure that corrosion is not occurring and that thecomponent's intended function will be maintained during the period of extendedoperation.In LRA Section 3.4.2.2.2, the applicant stated that the One-Time Inspection Program and PlantChemistry Program manage the aging effect. Exceptions apply to GALL Report recommendations for the Plant Chemistry Program implementation (refer to LRA Section B2.1.25). The One-Time Inspection Program is a new AMP. The scope of this new AMP will incorporate activities to verify the effectiveness of the Plant Chemistry Program,including a sample of components where the flow of water is low or stagnant conditions exist (refer to LRA Section B2.1.23). Implementation of the One-Time Inspection Program, in conjunction with the Plant Chemistry Program, to manage the aging effect provides added assurance that the aging effect is not occurring at locations of stagnant or low flow; or that theaging effect is progressing very slowly such that the component's intended function will bemaintained during the period of extended operation.The applicant stated in the LRA that the Plant Chemistry Program manages the loss of materialfor carbon and stainless steel components in SPC systems, and that a one-time inspection ofselected components and susceptible locations will verify the efficacy of that program. SERSections 3.0.3.2.19 and 3.0.3.1.4 document the staff's evaluations of the Plant ChemistryProgram and One-Time Inspection Program, respectively.On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LRSection 3.4.2.2.2. For those line items that apply to LRA Secti on 3.4.2.2.2, the staff determinedthat the applicant's AMRs are consistent with the GALL Report and the applicant hasdemonstrated that the effects of aging will be adequately managed so that the intendedfunction(s) will be maintained consistent with the CLB during the period of extended operation,as required by 10 CFR 54.21(a)(3).3.4.2.2.3Loss of Material Due to General, Pitting, and Crevice Corrosion, MicrobiologicallyInfluenced Corrosion, and BiofoulingThe staff reviewed LRA Section 3.4.2.2.3 against the criteria in SRP-LR Section 3.4.2.2.3.In LRA Section 3.4.2.2.3, the applicant stated that this aging effect applies to PWRs only.SRP-LR Section 3.4.2.2.3 states that loss of material due to general, pitting, and crevicecorrosion, MIC, and biofouling could occur in carbon steel piping and fittings for untreated water from the backup water supply in the PWR auxiliary FW (AFW) system. SRP-LR Table 3.3-1states that further evaluation for this aging effect is for PWR plants only.The staff found that this aging effect is not applicable at MNGP.

3-2493.4.2.2.4 General CorrosionThe staff reviewed LRA Section 3.4.2.2.4 against the criteria in SRP-LR Section 3.4.2.2.4.In LRA Section 3.4.2.2.4 the applicant addressed loss of material due to general corrosion onthe external surfaces of carbon steel and cast iron components of the SPC system in air/gasenvironments.SRP-LR Section 3.4.2.2.4 states the following:Loss of material due to general corrosion could occur on the external surfaces ofall carbon steel structures and components, including closure bolting, exposed to operating temperature less that 212 F. The GALL Report recommends furtherevaluation to ensure that this aging effect is adequately managed.In LRA Section 3.4.2.2.4, the applicant stated that the System Condition Monitoring Programmanages the loss of material for carbon steel and cast iron components in SPC systems. TheSystem Condition Monitoring Program manages the aging effect on the external surfaces of carbon steel and cast iron components in air/gas environments. Management of the aging effect associated with certain components of the CDR with the plateout and holdup ofradioactive material intended function is not applicable, as the CDR structural integrity isdemonstrated continuously during normal plant operation. As documented in its August 31,2005, letter, the applicant stated that it will revise the LRA to eliminate reference to the pressureboundary function of the CDRs as this function is inappropriate for these components. TheSystem Condition Monitoring Program is an existing plant-specific program that manages aging effects for normally accessible external surfaces of piping, tanks, and other components and equipment within the scope of license renewal through visual inspection and monitoring of external surfaces for leakage and evidence of material degradation. Implementation of the System Condition Monitoring Program to manage corrosion adds assurance that corrosion does not occur and that the aging effect progresses so slowly that the component's intendedfunction will be maintained during the period of extended operation. SER Section 3.0.3.3.2documents the staff's review of the applicant's System Condition Monitoring Program.On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LRSection 3.4.2.2.4. For those line items that apply to LRA Secti on 3.4.2.2.4, the staff determinedthat the applicant's AMRs are consistent with the GALL Report and the applicant hasdemonstrated that the effects of aging will be adequately managed so that the intendedfunctions will be maintained consistent with the CLB during the period of extended operation, asrequired by 10 CFR 54.21(a)(3).3.4.2.2.5Loss of Material Due to General, Pitting, Crevice, and Microbiologically InfluencedCorrosionThe staff reviewed LRA Section 3.4.2.2.5 against the criteria in SRP-LR Section 3.4.2.2.5.The applicant stated in LRA Section 3.4.2.2.5.2 that MNGP CSTs are not SR and therefore notwithin the scope of licensing renewal. The applicant also stated in LRA Section 3.4.2.2.5.2 thatMNGP has no underground CSTs.

3-250Because the applicant has no components from this group, the staff concurred with theapplicant's determination that this aging effect is not applicable.Conclusion. On the basis of its review, for component groups evaluated in the GALL Report forwhich the applicant has claimed consistency with the GALL Report, and for which the GALL Report recommends further evaluation, the staff determined that the applicant adequatelyaddressed the issues that were further evaluated. The staff found that the applicant hasdemonstrated that the aging effects will be adequately managed so that the intended functionswill be maintained consistent with the CLB for the period of extended operation, as required by10 CFR 54.21(a)(3).3.4.2.3 AMR Results That Are Not Consistent with or Not Addressed in the GALL ReportSummary of Technical Information in the Application. In LRA Tables 3.4.2-1 through 3.4.2-5,the staff reviewed additional details of the results of the AMRs for material, environment, AERM, and AMP combinations that are not consistent with the GALL Report, or that are notaddressed in the GALL Report.In LRA Tables 3.4.2-1 through 3.4.2-5, the applicant indicated, via Notes F through J, that thecombination of component type, material, environment, and AERM does not correspond to a line item in the GALL Report and provided information concerning how it will manage the agingeffect. Specifically, Note F indicates that the GALL Report does not evaluate the material for the AMR line item component. Note G indicates that the GALL Report does not evaluate the environment for the AMR line item component and material. Note H indicates that the GALL Report does not evaluate the aging effect for the AMR line item component, material, and environment combination. Note I indicates that the aging effect identified in the GALL Report forthe line item component, material, and environment combination is not applicable. Note J indicates that the GALL Report does not evaluate either the component or the material andenvironment combination for the line item.Staff Evaluation. For component type, material, and environment combinations that the GALLReport does not evaluate, the staff reviewed the applicant's evaluation to determine whether theapplicant demonstrated that the effects of aging will be adequately managed so that theintended functions will be maintained consistent with the CLB during the period of extendedoperation. This section addresses AMR results for which LRA Tables 3.4.2-1 through 3.4.2-5 identified no aging effects. The discussion on each table addresses the other line items that arenot consistent with the GALL Report or not addressed in the GALL Report. The following sections discuss the staff's evaluation.In LRA Tables 3.4.2-1 through 3.4.2-5, the applicant identified AMR line items for which theaging review process identified no aging effects. Specifically, the applicant identified no aging effects for components fabricated from stainless steel and rubber materials that are exposed to a primary containment air, plant indoor air, instrument air, or gas environment or for components fabricated from carbon steel or stainless steel that are exposed to a lubricating oil environment. The applicant stated that a materials science evaluation for these materials inthese environments discovered no aging effects.Because stainless steels are highly resistant to corrosion in dry atmospheres in the absence ofcorrosive species, as cited in the Metals Handbook, Ninth Edition, the staff agreed that stainless 3-251steel in an indoor, uncontrolled air environment (e.g., plant indoor air) or in a gas environment(e.g., primary containment air inerted with nitrogen) exhibits no aging effect and that the SC will,therefore, remain capable of performing its intended functions consistent with the CLB for the period of extended operation. In addition, because both oxygen and moisture must be present to corrode steel, as cited in the Metals Handbook, the staff agreed that carbon steel or stainlesssteel in a lubricating oil internal environment with no water pooling exhibits no aging effect and that the SC will, therefore, remain capable of performing its intended functions consistent withthe CLB for the period of extended operation.As listed in the GALL Report, rubber that is not in an environment of elevated temperature (i.e.,above 95 F (35 C)) with additional factors such as exposure to ozone, oxidation, and radiationwill remain capable of performing intended functions consistent with the CLB for the period ofextended operation. Because specific ozone concentrations could not be determined, by letterdated November 17, 2005, the applicant stated that it will manage change in material propertiesdue to ozone for elastomers in an external air environment using the System Condition Monitoring Program. SER Section 3.4.2.3.3 documents the staff's evaluation.The staff's review of current industry research and operating experience found that plant indoorair, primary containment air, instrument air on stainless steel, or lubricating oil on stainless steel or carbon steel will not result in aging of concern during the period of extended operation;therefore, the staff concluded that the component, material, and environment combinationsdescribed in the preceding discussion have no applicable AERMs.The staff's review of current industry research and operating experience found that theapplicant demonstrated that no aging effects are predicted for the material and environmentalcombinations reported and that the SPC system components fabricated from these materials inthe environments listed above will maintain their intended functions consistent with the CLBduring the period of extended operation, as required by 10 CFR 54.21(a)(3).3.4.2.3.1Steam and Power Conversion System-Condensate Storage System-Summary ofAging Management Evaluation-Table 3.4.2-1The staff reviewed LRA Table 3.4.2-1, which summarizes the results of AMR evaluations for the condensate stor age system component groups.All line items in this table are consistent with the GALL Report or are included in the discussionin Section 3.4.2.3 above.3.4.2.3.2Steam and Power Conversion System-Condensate and FeedwaterSystem-Summary of Aging Management Evaluation-Table 3.4.2-2The staff reviewed LRA Table 3.4.2-2, which summarizes the results of AMR evaluations for thecondensate and FW system component groups.In LRA Table 3.4.2-2, the applicant proposed to manage cracking and change in materialproperties due to thermal exposure of rubber materials for the component types of expansion joints exposed to a treated water (internal) environment using the One-Time Inspection Program.

3-252SER Section 3.0.3.1.4 documents the staff's review of the One-Time Inspection Program. TheOne-Time Inspection Program is a new program consistent with the recommendations of GALL AMP XI.M32". This program will include measures to verify the effectiveness of the PlantChemistry Program and the Fuel Oil Chemistry Program and also will confirm the absence ofage degradation in selected components (e.g., flow restrictors, venturis, and small bore piping) within scope of license renewal. The One-Time Inspection Program addresses concerns and provides confirmation for the potential long incubation period for certain aging effects on SCs.

The applicant has noted in the LRA that in some cases in which aging effects/mechanisms are not expected to be significant, the One-Time Inspection Program alone is credited with managing aging effects. The staff's review determined that the use of the One-Time InspectionProgram alone is acceptable in certain cases in which the use of the Plant Chemistry Program is not a viable option. This AMP is appropriate for the aging effects/mechanisms identified and assures effective management of the aging effects through the period of extended operation.that the One-Time Inspection Program effectivelymanages the aging effects of cracking and change in material properties due to thermal exposure of rubber material exposed to a treated water (internal) environment. On this basis, the staff found that management of cracking due to thermal exposure, as given in LRA Table 3.4.2-2, is acceptable.3.4.2.3.3Steam and Power Conversion System-Main Condenser System-Summary ofAging Management Evaluation-Table 3.4.2-3The staff reviewed LRA Table 3.4.2-3, which summarizes the results of AMR evaluations for theCDR system component groups.In Table 3.4.2-2, the applicant identified no AERMs for rubber expansion joints intended tomaintain the pressure boundary function in a plant indoor air environment. The applicant stated that the GALL Report does not evaluate either the components or the material and environmentcombination. The applicant further stated that these elastomer components (e.g., neoprene,rubber) are indoors and not subject to UV rays or ozone, nor are they in locations subject to radiation exposure or to temperatures at which changes in material properties or cracking could occur (>95 F); therefore, the applicant contended that no aging management is required. Inindustry experience, however, elastomeric expansion joints degrade due to oxidation in environments that are not necessarily harsh, as discussed in EPRI Report 1008035 and EPRI Report 1007933.The staff's review of LRA Section 3.4 identified areas for which it needed additional informationto complete its evaluation of the applicant's results. The applicant responded to the staff's RAIs as discussed below.In RAI 3.4-1, dated July 20, 2005, the staff requested that the applicant discuss its inspectionprocedures for the rubber expansion joints related to preventive maintenance, for both externaland internal surfaces of the elastomer.

3-253In its response, by letter dated August 16, 2005, the applicant stated the following:EPRI Report 1008035, 'Expansion Joint Maintenance Guide,' Revision 1,May 2003, Table 5-4, rates elastomers against oxidation, tensile strength, andradiation. Elastomers, such as Neoprene, Natural Rubber, Chlorobutyl, Buna-N, Viton, and EPDM, are rated as good or better in the categories of oxidation, tensile strength, and radiation.EPRI Report 1007933, 'Aging Assessment Field Guide,' December 2003,pages 60 through 65, lists oxidation as a degradation mechanism brought on by the stressors: Thermal, Radiation, and Ultraviolet. As stated in the first paragraph of the question, these elastomers are not exposed to these stressors.Since these elastomers are not exposed to ultraviolet, radiation, or temperatures>95 degrees F, they are therefore not susceptible to oxidation and no aging management is required.In addition, the applicant referred to a related response to RAI 3.3.2.3-3, which addresses theoxidation effects and degradation of elastomers due to thermal, irradiation, and UV exposure.The staff also noted that the applicant's response to RAI 3.3.2.3-4, dated August 16, 2005, hadnot addressed degradation of rubber by oxidation resulting from exposure to ozone in air. The staff asked the applicant to provide the specific designation of the types of elastomers installed at the plant and the data related to exposure to ozone in air for each type, if available. Inaddition, the staff asked the applicant to explain its method for evaluating degradation causedby oxidation from exposure to ozone.The staff was concerned that some of the elastomers in question may not be long-livedcomponents designed for 60 years. The applicant's response had not clearly stated that thesecomponents are not long-lived and are replaced at specified intervals. The staff asked the applicant to confirm this and provide supporting data.In its response, by letter dated November 17, 2005, the applicant stated the following:After further evaluation of this issue, NMC has taken the conservative approachof managing change in material properties due to ozone for elastomers in an air environment, specifically for natural rubber. This is a result of the fact that neither representative ozone concentrations nor technically substantiated thresholds could be adequately or consistently determined, even though plantspecific operating experience has indicated that there has been no change in material properties due to ozone for these elastomer components. Further evaluation also revealed the inability to confirm that none of these componentsare fabricated from natural rubber.As a result, elastomers in an external air environment in the following LRA tableswill utilize the System Condition Monitoring Program to manage the potentialaging effect of changes in material properties due to ozone which shall be assigned to these components.

3-254

  • Table 3.3.2-5 piping and fittings in the Demineralized Water System
  • Table 3.3.2-7 ventilation seals in the Emergency Filtration Train System
  • Table 3.3.2-16 expansion joints in the Service and Seal Water System
  • Table 3.4.2-2 expansion joints in the Condensate and Feedwater System(those which were not previously managed externally)Elastomers in Table 3.2.2-8 (ventilation seals in the Secondary ContainmentSystem) are presently being managed utilizing the One-Time InspectionProgram for the internal surfaces and the System Condition Monitoring Program for the external surfaces. These Aging Management Programs (AMPs) were initially credited to manage change in material properties and cracking due to thermal exposure, since a temperature threshold of greater than 95 F wasassigned to these components. Consequently, these same AMPs will alsomanage change in material properties due to ozone which shall be assigned to these components.Elastomers (expansion joints) in Table 3.4.2-3 (Main Condenser System) do notrequire aging management since these components do not serve a pressure boundary intended function but provide for plate-out and holdup of radioactive material during design basis events. Condenser integrity is continuously demonstrated during normal plant operation thus validating that this intendedfunction is maintained as stated in the plant-specific notes for these components in Section 3.4 of the LRA.Elastomers in an internal air environment in Table 3.3.2-6 (piping and fittings inthe Emergency Diesel Generators System) and Table 3.3.2-7 (ventilation sealsin the Emergency Filtration Train System) will utilize the One-Time Inspection Program to manage the potential aging effect of change in material properties due to ozone which shall be assigned to these components.Elastomers in both an internal and external air environment in Table 3.3.2-11(ventilation seals in the Heating and Ventilation System) were inadvertentlyomitted from this table. These components shall be managed for the potentialaging effect of change in material properties due to ozone utilizing the One-TimeInspection Program for the internal surfaces and the System Condition Monitoring Program for the external surfaces which shall be assigned to these components.All the elastomers addressed are long-lived components. Any component that isnot long-lived and replaced at specified intervals is eliminated from AMR consideration during the screening process. Although the expansion joints are presently under review for replacement on a fixed periodicity, this change has 3-255not been effected and they remain as and have been analyzed as long-livedcomponents.Any degradation of elastomer components in an air environment resulting fromchange in material properties due to ozone for the external surfaces of these components shall be evaluated as discussed in the response to RAI B2.1.32-02 which addresses the System Condition Monitoring AMP.The staff's review found the applicant's response acceptable, because the applicant added theSystem Condition Monitoring and One-Time Inspection Programs for the management of aging effects in elastomers. The applicant also satisfactorily addressed the staff's concern related to long-lived components. SER Sections 3.0.3.3.2 and 3.0.3.1.4 document the staff reviews of theSystem Condition Monitoring and One-Time Inspection Programs, respectively; therefore, the staff's concern described in RAI 3.3.2.3-4 is resolved.In RAI 3.4-2, dated July 20, 2005, the staff noted that in LRA Table 3.4.2-3 the applicantidentified the aging effects of changes in material properties and cracking due to irradiation and thermal exposure for rubber expansion joints in an internal steam environment. The intended function of the expansion joints is to maintain holdup of radioactive material. The applicant stated that the GALL Report does not evaluate either the components or the material andenvironment combination. The applicant further stated that the aging effect/mechanism isapplicable but requires no management as the intended function for this component is post-accident iodine plateout and holdup. According to the applicant, CDR structural integrity iscontinuously demonstrated during normal plant operation, thus maintaining the intendedfunction; however, the staff position is that this component type (rubber expansion joint) is within the scope of license renewal and its aging effects should be managed. The staff requested that the applicant provide the appropriate AMP to manage the aging effects ofchanges in material properties and cracking due to irradiation and thermal expansion of the rubber expansion joints in a steam environment.In its response, by letter dated August 16, 2005, the applicant further demonstrated that thepost-accident plateout and holdup of radioactive material intended function will be maintainedand no aging management is required. The applicant stated the following:For both a Loss of Coolant Accident (LOCA) and a Control Rod DropAccident (CRDA), radioactive iodine is assumed to be held up and plate-out onthe interior surfaces of the main condenser. 'Plate-out and holdup of radioactive material' is the only intended function assigned to the main condenser expansion joints.Aging management is not required for the main condenser components thathave only a plate-out and holdup of radioactive material intended function. For these components, the aging effects do not require aging management because the deposition of iodine in the main condenser is unaffected by the condenser surface condition. To maintain the intended function, the main condenser and the components, which make up the main condenser complex, simply have to remain intact.

3-256Condenser structural integrity is continuously demonstrated during normaloperation when the condenser is required to maintain vacuum. Following a design basis accident, when the condenser is required to perform its intended function, the main steam isolation valves will be closed and vacuum will be lost.The condenser will not be required to perform a pressure boundary functionbecause atmospheric conditions will exist inside the condenser.Since normal performance considerations such as fouling and in-leakage (e.g.,circulating water or air leaks) place greater requirements on condenser operation than the post-accident plate-out, then as long as the condenser is intact and operational, the post-accident plate-out and holdup of radioactive material intended function will be maintained and no aging management is required.The staff's review found the applicant's response to RAI 3.4-2 acceptable because thecondenser is likely to remain operational following a DBA as well as during normal operation, and no aging management is required; therefore, the staff's concern described in RAI 3.4-2 isresolved.3.4.2.3.4Steam and Power Conversion System-Main Steam System-Summary of AgingManagement Evaluation-Table 3.4.2-4The staff reviewed LRA Table 3.4.2-4, which summarizes the results of AMR evaluations for theMST system component groups.All line items in this table are consistent with the GALL Report or are included in the discussionin Section 3.4.2.3 above.3.4.2.3.5Steam and Power Conversion System-Turbine Generator System-Summary ofAging Management Evaluation-Table 3.4.2-5The staff reviewed LRA Table 3.4.2-5, which summarizes the results of AMR evaluations for theturbine generator system component groups.In LRA Table 3.4.2-5, the applicant proposed to manage the loss of material due to selectiveleaching of cast iron materials for the component types of steam traps exposed to a treated water or steam (internal) environment, or for copper alloy component types of heat exchangers exposed to a wet air or gas environment, or for component types of piping and fittings exposed to a raw water environment, using the Selective Leaching of Materials Program.SER Section 3.0.3.2.22 documents the staff's review and evaluation of the applicant's SelectiveLeaching of Materials Program. The Selective Leaching of Materials Program includes a one-time visual inspection and hardness measurement of certain components susceptible to selective leaching. In situations in which hardness testing is not practical, the applicant will use a qualitative approach by other NDE or metallurgical methods to determine the presence and extent of selective leaching. The program will determine if selective leaching occurs for certain components and ensure the integrity of components made of gray cast iron, bronze, brass, andother alloys exposed to a raw water, treated water, or ground-water environment that may cause selective leaching of one of the metal components.

3-257In LRA Table 3.4.2-5, the applicant proposed to manage the loss of material due to MIC, pitting,and crevice corrosion of copper alloy materials for the component types of gauges, piping and fittings, and valve bodies exposed to a treated water (internal) environment using the One-Time Inspection Program and the Plant Chemistry Program.SER Sections 3.0.3.2.19 and 3.0.3.1.4 document the staff's reviews of the applicant's PlantChemistry Program and the One-Time Inspection Program, respectively. The Plant Chemistry Program mitigates the aging effects on component surfaces that are exposed to water as the process fluid; chemistry programs are used to control water chemistry for impurities (e.g.,

chloride and sulfate) that accelerate corrosion or crack initiation and growth and that cause heat transfer degradation due to fouling in select heat exchangers. This program relies on monitoring and control of water chemistry to keep peak levels of various contaminants below system-specific limits. The One-Time Inspection Program is a new program consistent with therecommendations of GALL AMP XI.M32 and verifies the effectiveness of the Plant Chemistry Program. The One-Time Inspection Program addresses concerns and provides confirmation for the potential long incubation period for certain aging effects on SCs. The staff review determined that the Plant Chemistry Program supplemented by the One-Time InspectionProgram is adequate for managing these combinations of material, environment, and aging effects.In LRA Table 3.4.2-5, the applicant proposed to manage loss of material due to MIC, pitting,and crevice corrosion of copper alloy materials for the component types of heat exchangers exposed to a wet air or gas (external) environment using the System Condition Monitoring Program.SER Section 3.0.3.3.2 documents the staff's review and evaluation of the applicant's SystemCondition Monitoring Program.that the Plant Chemistry Program, One-Time Inspection Program, and System Condition Monitoring Program effectively manage the aging effect of loss of material due to MIC, pitting, and crevice corrosion of copper alloy material exposed to wet air or gas, or treated water environment. The Selective Leaching of Materials Program effectively manages the loss of material due to selective leaching of cast iron material exposed to treated water environment, and copper alloy exposed to wet air or gas and raw water environments. The staff found that the applicant's program to manage loss of material due to MIC, pitting, crevice corrosion, and selective leaching, as given in LRA Table 3.4.2-5, is acceptable.Conclusion. On the basis of its review, the staff found that the applicant appropriately evaluatedAMR results involving material, environment, AERMs, and AMP combinations that the GALL Report does not evaluate. The staff found that the applicant has demonstrated that the effectsof aging will be adequately managed so that the intended functions will be maintainedconsistent with the CLB for the period of extended operation, as required by10 CFR 54.21(a)(3).

3-2583.4.3 ConclusionThe staff concluded that the applicant provided sufficient information to demonstrate that theeffects of aging for the SPC system components that are within the scope of license renewaland subject to an AMR will be adequately managed so that the intended functions will bemaintained consistent with the CLB for the period of extended operation, as required by10 CFR 54.21(a)(3).The staff also reviewed the applicable USAR supplement program summaries and concludedthat they adequately describe the AMPs credited for managing aging of the SPC system, asrequired by 10 CFR 54.21(d).3.5 Aging Management of Containments, Structures, and Component SupportsThis section of the SER documents the staff's review of the applicant's AMR results for thecontainments, structures, and component supports components and component groups associated with the following systems:

  • cranes, heavy loads, rigging
  • diesel fuel oil transfer house
  • emergency filtration train building
  • fire protection barriers commodity group
  • hangers and supports commodity group
  • intake structure
  • miscellaneous SBO yard structures
  • offgas stack
  • offgas storage and compressor building
  • plant control and cable spreading structure
  • radioactive waste building
  • reactor building
  • structures affecting safety
  • turbine building
  • underground duct bank3.5.1 Summary of Technical Information in the Application In LRA Section 3.5, the applicant provided AMR results for the containments, structures, andcomponent supports components and component groups. In LRA Table 3.5.1, the applicantprovided a summary comparison of its AMRs with the AMRs evaluated in the GALL Report for the containments, structures, and component supports components and component groups.The applicant's AMRs incorporated applicable operating experience in the determination ofAERMs. These reviews included evaluation of plant-specific and industry operating experience.

The plant-specific evaluation included reviews of CRs and discussions with appropriate site personnel to identify AERMs. The applicant's review of industry operating experience included a 3-259review of the GALL Report and operating experience issues identified since the issuance of theGALL Report.3.5.2 Staff Evaluation The staff reviewed LRA Section 3.5 to determine if the applicant provided sufficient informationto demonstrate that the aging effects for the containments, structures, and component supportssystem components that are within the scope of license renewal and subject to an AMR will beadequately managed so that the intended functions will be maintained consistent with the CLBfor the period of extended operation, as required by 10 CFR 54.21(a)(3).In addition, the staff performed an onsite audit of AMRs to confirm the applicant's claim thatcertain identified AMRs are consistent with the GALL Report. The staff did not repeat its reviewof the matters described in the GALL Report; however, the staff did verify that the material presented in the LRA is applicable and that the applicant had identified the appropriate GALLReport AMRs. SER Section 3.0.3 documents the staff's evaluations of the AMPs. The MNGP audit and review report details the staff's audit evaluation, as summarized in SER Section 3.5.2.1.The staff also performed an onsite audit of those selected AMRs that are consistent with theGALL Report and for which further evaluation is recommended. The staff confirmed that the applicant's further evaluations are consistent with the acceptance criteria in SRP-LR Section 3.5.2.2. The MNGP audit and review report documents the staff's audit evaluations,which and are summarized in SER Section 3.5.2.2.The staff performed an onsite audit and conducted a technical review of the remaining AMRsthat are not consistent with, or not addressed in, the GALL Report. The audit and technicalreview included evaluating whether the applicant identified all plausible aging effects and whether the aging effects listed are appropriate for the combination of materials and environments specified. The MNGP audit and review report documents the staff's audit evaluations. SER Section 3.5.2.3 summarizes these audit evaluations and documents thestaff's technical review.Finally, the staff reviewed the AMP summary descriptions in the USAR supplement to ensurethat they adequately describe the programs credited with managing or monitoring aging for thecontainments, structures, and component supports system components.Table 3.5-1 below summarizes the staff's evaluation of components, aging effects/mechanisms,and AMPs listed in LRA Section 3.5 that are addressed in the GALL Report.

3-260Table 3.5-1 Staff Evaluation for Containments, Structures, and Component Supports inthe GALL ReportComponent GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff EvaluationCommon Components of All Types of PWR and BWR ContainmentPenetrationsleeves, penetrationbellows, anddissimilar metalwelds(Item Number3.5.1-01)Cumulative fatiguedamage (CLBfatigue analysisexists)TLAA, evaluated inaccordance with10 CFR 54.21(c)TLAAThis TLAA isevaluated in Section4.3, Metal Fatigueof the RPV andInternals, andReactor CoolantPressure BoundaryPiping andComponents andSection 4.6, FatigueAnalysis of thePrimaryContainment,Attached Piping,and ComponentsPenetrationsleeves, bellows,and dissimilar metalwelds(Item Number3.5.1-02)Cracking due tocyclic loading, orcrack initiation andgrowth due to SCCContainment ISI,containment leak-rate test 10 CFR 50,Appendix JProgram (B2.1.1),PrimaryContainmentIn-ServiceInspection Program(B2.1.26) Consistent withGALL Report, whichrecommends furtherevaluation (seeSection 3.5.2.2.1)Penetrationsleeves, penetrationbellows, anddissimilar metalwelds(Item Number3.5.1-03)Loss of materialdue to corrosionContainment ISI,containment leak-rate test 10 CFR 50,Appendix JProgram (B2.1.1),PrimaryContainmentIn-ServiceInspection Program(B2.1.26)Consistent withGALL Report, whichrecommends nofurther evaluationPersonnel airlockand equipmenthatch(Item Number3.5.1-04)Loss of materialdue to corrosionContainment ISI,containment leak-rate test 10 CFR 50,Appendix JProgram (B2.1.1),PrimaryContainmentIn-ServiceInspection Program (B2.1.26) Consistent withGALL Report, whichrecommends nofurther evaluationPersonnel airlockand equipmenthatch(Item Number3.5.1-05)Loss of leaktightness in closedposition due tomechanical wear oflocks, hinges, andclosure mechanismContainment leak-rate test, plantTechnicalSpecifications 10 CFR 50,Appendix JProgram (B2.1.1)Consistent withGALL Report, whichrecommends nofurther evaluation Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation3-261Seals, gaskets, andmoisture barriers(Item Number3.5.1-06)Loss of sealant andleakage throughcontainment due todeterioration of jointseals, gaskets, andmoisture barriersContainment ISI,containment leak-rate test 10 CFR 50,Appendix JProgram (B2.1.1),PrimaryContainmentIn-ServiceInspection Program(B2.1.26)Consistent withGALL Report, whichrecommends nofurther evaluationPWR Concrete (Reinforced and Prestressed) and Steel ContainmentBWR Concrete (Mark II and III) and Steel (Mark I, II, and III) ContainmentConcrete elements-foundation, walls,dome(Item Number3.5.1-07)Aging of accessibleand inaccessibleconcrete areas dueto leaching ofcalcium hydroxide,aggressivechemical attack,and corrosion ofembedded steelContainment ISINot applicable toMNGP Mark IcontainmentConcrete elements-foundation(Item Number3.5.1-08)Cracks, distortion,and increases incomponent stresslevel due tosettlementStructuresMonitoringNot applicable toMNGP Mark IcontainmentConcrete elements-foundation(Item Number3.5.1-09)Reduction infoundation strengthdue to erosion ofporous concretesubfoundationStructuresMonitoringNot applicable toMNGP Mark IcontainmentConcrete elements-foundation, dome,and wall(Item Number3.5.1-10)Reduction ofstrength andmodulus due toelevatedtemperaturePlant specificNot applicable toMNGP Mark IcontainmentPrestressedcontainment-tendons andanchoragecomponents(Item Number3.5.1-11)Loss of prestressdue to relaxation,shrinkage, creep,and elevatedtemperatureTLAA, evaluated inaccordance with10 CFR 54.21(c)Not applicable toMNGP Mark IcontainmentSteel elements-liner plate,containment shell(Item Number3.5.1-12)Loss of materialdue to corrosion inaccessible andinaccessible areasContainment ISI,containment leak-rate test 10 CFR 50,Appendix JProgram (B2.1.1),PrimaryContainmentIn-ServiceInspection Program(B2.1.26)Consistent withGALL Report, whichrecommends furtherevaluation(seeSection 3.5.2.2.1)

Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation3-262Steel elements-vent header,drywell head, torus,downcomers, poolshell(Item Number3.5.1-13)Cumulative fatiguedamage (CLBfatigue analysisexists)TLAA, evaluated inaccordance with10 CFR 54.21(c)TLAAThis TLAA isevaluated in Section4.3, Metal Fatigueof the RPV andInternals, andReactor CoolantPressure BoundaryPiping andComponents andSection 4.6,Fatigue Analysis ofthe PrimaryContainment,Attached Piping,and ComponentsSteel elements-protected by coating(Item Number3.5.1-14)Loss of materialdue to corrosion inaccessible areasonlyProtective coatingmonitoring andmaintenance 10 CFR 50,Appendix JProgram (B2.1.1),PrimaryContainmentIn-ServiceInspection Program(B2.1.26),Protective CoatingMonitoring &MaintenanceProgram (B2.1.27)Consistent withGALL Report.Protective CoatingMonitoring &MaintenanceProgram is notrelied upon formanaging loss ofmaterial due tocorrosion, but iscredited forpreventingdegradation ofcoatings that couldlead to clogging ofECCS suppressionpool suctionstrainersPrestressedcontainment-tendons andanchoragecomponents(Item Number3.5.1-15)Loss of materialdue to corrosion ofprestressingtendons andanchoragecomponentsContainment ISINot applicable toMNGP Mark Icontainment. Thereare no prestressedcontainmenttendons andanchoragecomponentsConcrete elements-foundation, dome,and wall(Item Number3.5.1-16)Scaling, cracking,and spalling due tofreeze-thaw;expansion andcracking due toreaction with aggregateContainment ISINot applicable toMNGP Mark Icontainment Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation3-263Steel elements-vent line bellows,vent headers,downcomers(Item Number3.5.1-17)Cracking due tocyclic loads or crackinitiation and growthdue to SCCContainment ISI,containment leak-rate test 10 CFR 50,Appendix JProgram (B2.1.1),PrimaryContainmentIn-ServiceInspection Program(B2.1.26) Consistent withGALL Report, whichrecommends furtherevaluation (seeSection 3.5.2.2.1)Steel elements-suppressionchamber liner(Item Number3.5.1-18)Crack initiation andgrowth due to SCCContainment ISI,containment leak-rate testNot applicable toMNGP Mark IcontainmentSteel elements-drywell head anddowncomer pipes(Item Number3.5.1-19)Fretting and lockupdue to wearContainment ISINot applicable to MNGP.Components notsubject to relativemotionClass I StructuresAll groups exceptGroup 6-accessibleinterior/exteriorconcrete and steelcomponents(Item Number3.5.1-20)All types of agingeffectsStructuresMonitoringStructuresMonitoring Program(B2.1.31)Consistent withGALL Report, whichrecommends furtherevaluation(seeSection 3.5.2.2.2)Groups 1-3, 5, 7-9-inaccessibleconcretecomponents, suchas exterior wallsbelow grade andfoundation(Item Number3.5.1-21)Aging ofinaccessibleconcrete areas dueto aggressivechemical attack,and corrosion ofembedded steelPlant specificNoneMNGP meets thecriteria specified inthe GALL ReportConsistent withGALL Report, whichrecommends furtherevaluation (seeSection 3.5.2.2.2)Group 6-allaccessible/inaccessibleconcrete, steel, and earthencomponents(Item Number3.5.1-22)All types of agingeffects, includingloss of material dueto abrasion,cavitation, andcorrosionInspection ofwater-controlstructures orFERC/U.S. ArmyCorp of Engineersdam inspection andmaintenanceStructuresMonitoring Program(B2.1.31)Consistent withGALL Report, withenhancements inthe StructuresMonitoring Programto includeRG 1.127,Inspection of Water-Control StructuresAssociated withNuclear PowerPlants.

Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation3-264Group 5-liners(Item Number3.5.1-23)Crack initiation andgrowth from SCCand loss of materialdue to crevicecorrosionWater chemistryand monitoring ofspent fuel poolwater levelPlant ChemistryProgram (B2.1.25),PrimaryContainmentIn-ServiceInspection Program(B2.1.26), andSystem ConditionMonitoring Program(B2.1.32)Consistent withGALL Report, whichrecommends nofurther evaluationGroups 1-3, 5, 6-all masonry blockwalls(Item Number3.5.1-24)Cracking due torestraint, shrinkage,creep, andaggressiveenvironmentMasonry wallFire ProtectionProgram (B2.1.17),StructuresMonitoring Program(B2.1.31)Consistent withGALL Report, withenhancements inthe StructuresMonitoring Programto include masonrywallsGroups 1-3, 5, 7-9-foundation(Item Number3.5.1-25)Cracks, distortion,and increases incomponent stresslevel due tosettlementStructuresmonitoringStructuresMonitoring Program(B2.1.31) only forthe fuel oil transferhouseConsistent withGALL Report(seeSection 3.5.2.2.1)Groups 1-3, 5-9-foundation(Item Number3.5.1-26)Reduction infoundation strengthdue to erosion ofporous concretesubfoundationStructuresmonitoring NoneMNGP meets thecriteria specified inthe GALL ReportConsistent withGALL Report(seeSection 3.5.2.2.1)Groups 1-5-concrete(Item Number3.5.1-27)Reduction ofstrength andmodulus due toelevatedtemperaturePlant specificNoneConcretetemperatures do notexceed GALLReportrecommended limitsConsistent withGALL Report, whichrecommends furtherevaluation(seeSection 3.5.2.2.1)Groups 7, 8-liners(Item Number3.5.1-28)Crack initiation andgrowth due to SCC;loss of material dueto crevice corrosionPlant specificNot applicable.MNGP has noGroup 7 (concretetanks) or Group 8(steel tanks) withlinersComponent Supports Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation3-265All groups-supportmembers-anchorbolts, concretesurrounding anchorbolts, welds, groutpad, boltedconnections, etc.(Item Number3.5.1-29)Aging of componentsupportsStructuresMonitoringBuried Piping &Tanks InspectionProgram (B2.1.5),PrimaryContainmentIn-ServiceInspection Program(B2.1.26),StructuresMonitoring Program(B2.1.31), SystemConditionMonitoring Program(B2.1.32) Consistent withGALL Report, whichrecommends furtherevaluation(seeSection 3.5.2.2.3)Groups B1.1, B1.2,and B1.3-supportmembers-anchorbolts, welds(Item Number3.5.1-30)Cumulative fatiguedamage (CLBfatigue analysisexists)TLAA, evaluated inaccordance with10 CFR 54.21(c)This TLAA isevaluated in Section4.3, Metal Fatigueof the RPV andInternals, andReactor CoolantPressure BoundaryPiping andComponentsAll groups-supportmembers-anchorbolts, welds(Item Number3.5.1-31)Loss of materialdue to boric acidcorrosionBoric acid corrosionNot applicable,PWR onlyGroups B1.1, B1.2,and B1.3-supportmembers-anchorbolts, welds, springhangers, guides,stops, and vibrationisolators(Item Number3.5.1-32)Loss of materialdue toenvironmentalcorrosion; loss ofmechanical functiondue to corrosion,distortion, dirt,overload, etc.ISIASME Section XI,Subsection IWFProgram (B2.1.3)Consistent withGALL Report, whichrecommends nofurther evaluationGroup B1.1-high-strength low-alloybolts(Item Number3.5.1-33)Crack initiation andgrowth due to SCCBolting integrityNot applicable toMNGP. There areno high-strengthlow-alloy bolts inuse at MNGP forstructural applications The staff's review of the MNGP component groups followed one of several approaches. Oneapproach, documented in SER Section 3.5.2.1, involves the staff's review of the AMR resultsfor components in the containments, structures, and component supports that the applicantindicated are consistent with the GALL Report and do not require further evaluation. Anotherapproach, documented in SER Section 3.5.2.2, involves the staff's review of the AMR resultsfor components in the containments, structures, and component supports that the applicant 3-266indicated are consistent with the GALL Report and for which further evaluation isrecommended. A third approach, documented in SER Section 3.5.2.3, involves the staff'sreview of the AMR results for components in the containments, structures, and component supports that the applicant indicated are not consistent with, or not addressed in, the GALLReport. Section 3.0.3 documents the staff's review of AMPs that are credited to manage ormonitor aging effects of the containments, structures, and component supports components.3.5.2.1 AMR Results That Are Consistent with the GALL Report Summary of Technical Information in the Application. In LRA Section 3.5.2.1, the applicantidentified the materials, environments, and AERMs. The applicant identified the following programs that manage the aging effects related to the containments, structures, andcomponent supports system components:

  • Buried Piping & Tanks Inspection Program (B2.1.5)
  • Inspection of Overhead Heavy Load and Light Load (Related to Refueling) HandlingSystems Program (B2.1.22)
  • One-Time Inspection Program (B2.1.23)
  • Plant Chemistry Program (B2.1.25)
  • Protective Coating Monitoring & Maintenance Program (B2.1.27)
  • Structures Monitoring Program (B2.1.31)
  • System Condition Monitoring Program (B2.1.32)Staff Evaluation. In LRA Tables 3.5.2-1 through 3.5.2-18, the applicant summarized the AMRsfor the containments, structures, and component supports components and identified which AMRs it considered to be consistent with the GALL Report.For component groups evaluated in the GALL Report for which the applicant has claimedconsistency with the GALL Report, and for which the GALL Report does not recommend further evaluation the staff performed an audit and review to determine whether the GALL Report evaluation bounds the plant-specific components contained in these GALL Report componentgroups.The applicant provided a note for each AMR line item. The notes describe how the informationin the tables aligns with the information in the GALL Report. The staff audited those AMRs with Notes A through E, which indicate that 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 AMP 3-267identified in the GALL Report. The staff audited these line items to verify consistency with theGALL Report and the 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 AMP identified in the GALL Report. The staff audited these line items to verify consistency with the GALL Report. The staff verified that it had reviewed and accepted the identified exceptionsto the GALL Report AMPs. The staff also determined whether the AMP identified by the applicant is consistent with the AMP identified in the GALL Report and whether the AMR is validfor the site-specific conditions.Note C indicates that the component for the AMR line item, although different, is consistent withthe GALL Report for material, environment, and aging effect. In addition, the AMP is consistent with the AMP identified by the GALL Report. This note indicates that the applicant could not finda listing of some system components in the GALL Report; however, the applicant identified adifferent component in the GALL Report that has 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 determined whether the AMR line item of the different component applies to the component under review and whether the AMR is valid for the site-specific conditions.Note D indicates that the component for the AMR line item, although different, is consistent withthe GALL Report for material, environment, and aging effect. In addition, the AMP takes some exceptions to the AMP identified in the GALL Report. The staff audited these line items to verify consistency with the GALL Report. The staff verified whether the AMR line item of the different component applies to the component under review. The staff verified that it had reviewed and accepted the identified exceptions to the GALL Report AMPs. The staff also determined whether the AMP identified by the applicant is consistent with the AMP identified in the GALLReport and whether the AMR is 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 the applicant credited a different AMP. The staff audited these line items to verify consistency with the GALL Report. The staff also determined whether the identified AMP will manage the aging effect consistent with the AMP identified by the GALLReport and whether the AMR is valid for the site-specific conditions.The staff conducted an audit and review of the information provided in the LRA, as documentedin the MNGP audit and review report. The staff did not repeat its review of the matters described in the GALL Report; however, the staff did verify that the material presented in the LRA is applicable and that the applicant identified the appropriate GALL Report AMRs. The following sections discuss the staff's evaluation.3.5.2.1.1 Loss of Material Due to Corrosion in Accessible Areas In reviewing entries in LRA Table 3.5.2-13 for carbon steel and low-alloy steel in treated waterand air/gas environments, the staff identified some discrepancies in notes for AMR line items that reference GALL Report line item II.B.1.1.1-a. The discrepancies resulted because theapplicant credited different AMPs from those recommended by the GALL Report and used 3-268exceptions where none existed. The staff asked the applicant to resolve these discrepancies. Inits response, by letter dated August 11, 2005, the applicant stated the following:LRA line II.B.1.1.1-a for the component structural steel in a treated waterenvironment for the AMP Primary Containment Inservice Inspection program, the note should have been

'C' and not 'D.'LRA line II.B.1.1.1-a for the component structural steel in a treated waterenvironment for the AMP Plant Chemistry program, the note should have been

'E' and not 'D.'LRA line II.B.1.1.1-a for the component support members, welds, boltedconnections, torus internal catwalk support columns in a treated water environment for the AMP Primary Containment Inservice Inspection program, the note should have been

'C' and not 'D.'LRA line II.B.1.1.1-a for the component support members, welds, boltedconnections, torus internal catwalk support columns in a treated water environment for the AMP Plant Chemistry Program, the note should have been

'E' and not 'D.'LRA line II.B.1.1.1-a for the component structural steel inside torus, torus internalcatwalk in an air/gas environment, for the AMP Primary Containment Inservice Inspection Program, the note should have been

'C' and not 'D.'Because the components, material, and AMP identified in the LRA are consistent with the GALLReport, the staff concluded that the applicant appropriately addressed aging management forthe above components.The staff's review found that the applicant appropriately addressed the agingeffects/mechanisms, as recommended by the GALL Report.Conclusion. The staff evaluated the applicant's claim of consistency with the GALL Report. Thestaff also reviewed information pertaining to the applicant's consideration of recent operating experience and proposals for managing associated aging effects. The staff's review concluded that the AMR results, which the applicant claimed to be consistent with the GALL Report, areconsistent with the AMRs in the GALL Report; therefore, the staff concluded that the applicanthas demonstrated that the aging effects for these components will be adequately managed sothat their intended functions will be maintained consistent with the CLB for the period ofextended operation, as required by 10 CFR 54.21(a)(3).3.5.2.2AMR Results That Are Consistent with the GALL Report, for Which Further EvaluationIs RecommendedSummary of Technical Information in the Application. In LRA Section 3.5.2.2, the applicantprovided further evaluation of aging management as recommended by the GALL Report for the containments, structures, and component supports components. The applicant provided information concerning how it will manage the following aging effects for PWR and BWRcontainments:

3-269

  • aging of inaccessible concrete areas
  • cracking, distortion, and increase in component stress level due to settlement; reductionof foundation strength 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 corrosion in inaccessible areas of steel containment shell or linerplate
  • loss of prestress due to relaxation, shrinkage, creep, and elevated temperature
  • cumulative fatigue damage
  • cracking due to cyclic loading and SCCThe applicant also provided information on its management of the following aging effects forClass 1 structures:
  • aging of structures not covered by the Structures Monitoring Program
  • aging management of inaccessible areasFinally, the applicant provided information on its management of aging effects for componentsupports:
  • aging of supports not covered by the Structures Monitoring Program
  • cumulative fatigue damage due to cyclic loadingStaff Evaluation. For component groups evaluated in the GALL Report for which the applicanthas claimed consistency with the GALL Report, and for which the GALL Report recommends further evaluation, the staff audited and reviewed the applicant's evaluation to determinewhether it adequately addresses the issues that were further evaluated. In addition, the staffreviewed the applicant's further evaluations against the criteria contained in SRP-LR Section 3.5.2.2. The staff's audit and review report details the staff's audit. The following sections discuss the staff's evaluation of the aging effects.3.5.2.2.1 PWR and BWR Containments The staff reviewed LRA Section 3.5.2.2.1 against the criteria in SRP-LR Section 3.5.2.2.1,which addresses several areas discussed below.Aging of Inaccessible Concrete Areas. The staff reviewed LRA Section 3.5.2.2.1.1 against thecriteria in SRP-LR Section 3.5.2.2.1.1.In LRA Section 3.5.2.2.1.1, the applicant addressed aging of inaccessible concrete areas.SRP-LR Section 3.5.2.2.1.1 states the following:Cracking, spalling, and increases in porosity and permeability due to leaching ofcalcium hydroxide and aggressive chemical attack; and cracking, spalling, loss 3-270of bond, and loss of material due to corrosion of embedded steel could occur ininaccessible areas of PWR concrete and steel containments; BWR Mark II concrete containments; and Mark III concrete and steel containments. The GALLReport recommends further evaluation of plant-specific programs to manage the aging effects for inaccessible areas if specific criteria defined in the GALL Report cannot be satisfied.In LRA Section 3.5.2.2.1.1, the applicant stated that these aging effects/mechanisms do notapply to the MNGP containment because it is a BWR Mark I design, which does not include concrete as part of the containment structure. The staff found that these agingeffects/mechanisms do not apply for the MNGP containment.Cracking, Distortion, and Increase in Component Stress Level Due to Settlement; Reduction ofFoundation Strength Due to Erosion of Porous Concrete Subfoundations, If Not Covered by theStructures Monitoring Program. The staff reviewed LRA Section 3.5.2.2.1.2 against the criteriain SRP-LR Section 3.5.2.2.1.2.In LRA Section 3.5.2.2.1.2, the applicant addressed cracking, distortion, and increase incomponent stress level due to settlement as well as reduction of foundation strength due to erosion of porous concrete subfoundations.SRP-LR Section 3.5.2.2.1.2 states the following:Cracking, distortion, and increase in component stress level due to settlementcould occur in PWR concrete and steel containments and BWR Mark II concrete containments and Mark III concrete and steel containments. Also, reduction offoundation strength due to erosion of porous concrete subfoundations could occur in all types of PWR and BWR containments. Some plants may rely on a de-watering system to lower the site ground-water level. If the plant's CLB creditsa de-watering system, the GALL Report recommends verification of thecontinued functionality of the de-wateri ng system during the period of extendedoperation. The GALL Report recommends no further evaluation if this activity is included in the scope of the applicant's structures monitoring program.In LRA Section 3.5.2.2.1.2, the applicant addressed aging effects due to settlement, specificallywhether it needs to manage the aging effects/mechanisms based on a plant-specific review of the conditional requirements outlined in the GALL Report.This subsection mainly concerns PWR and BWR Mark II and III concrete containments;however, the settlement criteria presented apply to all concrete foundations. The plant initial licensing basis did not include a program to monitor settlement. With the exception of the diesel fuel oil transfer house, no significant settlement has been observed on any major structure, and de-watering systems are not used. These circumstances satisfy the GALL Reportrecommendations on concrete settlement and, therefore, with the exception of the diesel fuel oiltransfer house, cracks, distortion, and increase in component stress levels due to settlementrequire no aging management.The diesel fuel oil transfer house is a moderate-weight structure exerting a mean bearingpressure of about 1100 pounds per square foot (lb/ft
2) on the underlying foundation material.

3-271The foundation material of compacted granular backf ill underlain by stiff clay lenses andsandstone bedrock should not be susceptible to settlement under the load imposed. However, the diesel fuel oil transfer house has undergone significant differential settlement. According to plant records and settlement data, the diesel fuel oil transfer house settled rapidly following construction, which the applicant stated probably resulted from washout after a rainstorm and was long ago effectively complete. Data recorded annually since 1992 show no significant continued settlement of the structure.The Structures Monitoring Program manages the aging effects for the diesel fuel oil transferhouse. As part of the Structures Monitoring Program, the applicant performs an annual inspection of the diesel fuel oil transfer house for settlement to manage the aging effects of cracks, distortion, and increase in component stress level due to settlement. The inspectionadds assurance that the aging effects do not occur or progress so slowly that the component'sintended function will be maintained during the period of extended operation.SER Section 3.0.3.2.23 documents the staff's evaluation of the Structures Monitoring Program.The staff found this program acceptable for managing the aging effects of cracks, distortion,and increase in component stress level due to settlement as it inspects for settlement.The applicant also addressed the aging effects of all types of PWR and BWR containments dueto erosion of porous concrete subfoundations, specifically whether it needs to manage the aging effects/mechanisms based on a plant-specific review of the conditional requirements outlined in the GALL Report. The applicant's response to erosion of cement from porous concrete subfoundations, as described in IN 97-11, "Cement Erosion from Containment Subfoundations at Nuclear Power Plants," dated March 21, 1997, and IN 98-26, "SettlementMonitoring and Inspection of Plant Structures Affected by Degradation of Porous Concrete Subfoundations," dated July 24, 1998, concluded that foundation materials contain no porouslayers. The concrete base or lean concrete fill material beneath major building foundationscontains no high-alumina cement. The applicant does not rely on a de-wateri ng system to lowersite ground water.The applicant concluded that the GALL Report recommendations are satisfied for porousconcrete subfoundations and therefore the aging effects due to erosion of porous concrete subfoundations necessitate no aging management.during inspections under theStructures Monitoring Program, (2) the applicant has no porous concrete subfoundations, and (3) the applicant does not employ a de-watering system.On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LRSection 3.5.2.2.1.2. For those line items that apply to LRA Section 3.5.2.2.1.2, the staffdetermined that the applicant's AMRs are consistent with the GALL Report and the applicanthas demonstrated that the effects of aging will be adequately managed so that the intendedfunctions will be maintained consistent with the CLB during the period of extended operation, asrequired by 10 CFR 54.21(a)(3).

3-272Reduction of Strength and Modulus of Concrete Structures Due to Elevated Temperature. Thestaff reviewed LRA Section 3.5.2.2.1.3 against the criteria in SRP-LR Section 3.5.2.2.1.3.In LRA Section 3.5.2.2.1.3, the applicant addressed reduction of strength and modulus ofconcrete structures due to elevated temperature.SRP-LR Section 3.5.2.2.1.3 states the following:Reduction of strength and modulus of elasticity due to elevated temperaturescould occur in PWR concrete and steel containments and BWR Mark II concrete containments and Mark III concrete and steel containments. The GALL Reportrecommends further evaluation if any portion of the concrete containment components exceeds specified temperature limits (i.e., general area temperature

66 C [150F] and local area temperature 93 C [200 F]).The applicant stated that this aging effect mainly concerns PWR and BWR Mark II and IIIconcrete containments; however, the temperature criteria presented in this section apply to all concrete. Plant documents confirm that concrete elements are not subject to elevatedtemperatures in excess of 150 F generally and 200 F locally. Plant areas that bound high-temperature considerations are the drywell general area and biological shield wall piping penetration local area, which experience temperatures of 135 F and 179 F, respectively.The staff's review determined that the applicant has evaluated the temperatures of hot pipingpenetrations considering the presence of insulation, which is credited with maintaining the penetration temperatures below the local limits of 200 F. Insulation is included within the scopeof license renewal and is subject to an AMR.The staff found the applicant's AMRs consistent with the GALL Report in demonstrating that thetemperatures do not exceed the temperatures recommended in the GALL Report for which evaluation is required.On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LRSection 3.5.2.2.1.3. For those line items that apply to LRA Section 3.5.2.2.1.3, the staffdetermined that the applicant's AMRs are consistent with the GALL Report and the applicanthas demonstrated that the effects of aging will be adequately managed so that the intendedfunctions will be maintained consistent with the CLB during the period of extended operation, asrequired by 10 CFR 54.21(a)(3).Loss of Material Due to Corrosion in Inaccessible Areas of Steel Containment Shell or LinerPlate. The staff reviewed LRA Section 3.5.2.2.1.4 against the criteria in SRP-LRSection 3.5.2.2.1.4.In LRA Section 3.5.2.2.1.4, the applicant addressed loss of material due to corrosion for thedrywell shell and the drywell support skirt in inaccessible areas (i.e., embedded in concrete).SRP-LR Section 3.5.2.2.1.4 states the following:Loss of material due to corrosion could occur in inaccessible areas of the steelcontainment shell or the steel liner plate for all types of PWR and BWR 3-273containments. The GALL Report recommends further evaluation of plant-specificprograms to manage this aging effect for inaccessible areas if specific criteria defined in the GALL Report cannot be satisfied.In LRA Section 3.5.2.2.1.4, the applicant stated that MNGP satisfies t; therefore, aplant-specific AMP for loss of material due to corrosion of steel elements in inaccessible areas is not required.The applicant also stated that the Protective Coating Monitoring & Maintenance Program is notcredited with managing loss of material due to corrosion but with preventing degradation of coatings that could lead to clogging of ECCS suppression pool suction strainers.

Implementation of this program to manage the aging effect adds assurance that the agingeffect does not occur or progresses so slowly that the component's intended function will bemaintained during the period of extended operation.The staff reviewed LRA Section 3.5.2.2.1.4 and determined that the applicant satisfied thespecific criteria defined in the GALL Report for preventing loss of material due to corrosion for the drywell shell and the drywell support skirt in inaccessible areas (i.e., embedded in concrete).

The staff's review of applicant documents specifying that (1) plant concrete meets ACI 318 or 349 criteria, (2) the Structures Monitoring Program inspects the concrete around the inside of the drywell adjacent to the moisture barrier, (3) the scope of the Primary Containment In-Service Inspection Program includes the moisture barrier, and (4) borated water leaks do not apply for BWR plants. Therefore, the staff determined that further evaluation is not necessary.The staff found that the applicant is consistent with the GALL Report, and a plant-specific AMPfor loss of material is not required. SER Section 3.5.2.3.6 documents further discussion of thestaff's review of loss of material due to corrosion for the drywell shell in inaccessible areas.On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LRSection 3.5.2.2.1.4. For those line items that apply to LRA Section 3.5.2.2.1.4, the staffdetermined that the applicant's AMRs are consistent with the GALL Report and the applicanthas demonstrated that the effects of aging will be adequately managed so that the intendedfunctions will be maintained consistent with the CLB during the period of extended operation, asrequired by 10 CFR 54.21(a)(3).Loss of Prestress Due to Relaxation, Shrinkage, Creep, and Elevated Temperature. The staffreviewed LRA Section 3.5.2.2.1.5 against the criteria in SRP-LR Section 3.5.2.2.1.5.In LRA Section 3.5.2.2.1.5, the applicant addressed loss of prestress due to relaxation,shrinkage, creep, and elevated temperature.SRP-LR Section 3.5.2.2.1.5 states the following:Loss of prestress forces due to relaxation, shrinkage, creep, and elevatedtemperature for PWR prestressed concrete containments and BWR Mark II prestressed concrete containments is a TLAA as defined in 10 CFR 54.3. TLAAs are required to be evaluated in accordance with 10 CFR 54.21(c).

3-274In LRA Section 3.5.2.2.1.5, the applicant stated that this aging effect applies to Mark II BWRcontainments only.Because MNGP is not a PWR and has no BWR Mark II containment, the staff found this agingeffect not applicable.Cumulative Fatigue Damage. In LRA Section 3.5.2.2.1.6, the applicant stated that fatigue is aTLAA as defined in 10 CFR 54.3. Applicants must evaluate TLAAs in accordance with 10 CFR 54.21(c)(1). SER Sections 4.3 and 4.6 document the staff's review of the applicant'sevaluation of this TLAA.Cracking Due to Cyclic Loading and SCC. The staff reviewed LRA Section 3.5.2.2.1.7 againstthe criteria in SRP-LR Section 3.5.2.2.1.7.In LRA Section 3.5.2.2.1.7, the applicant addressed cracking due to cyclic loading and SCC.SRP-LR Section 3.5.2.2.1.7 states the following:Cracking of containment penetrations (including penetration sleeves, penetrationbellows, and dissimilar metal welds) due to cyclic loading or SCC could occur in all types of PWR and BWR containments. Cracking could also occur in vent line bellows, vent headers, and downcomers due to SCC for BWR containments. A visual VT-3 examination would not detect such cracks. The GALL Reportrecommends further evaluation of the inspection methods implemented to detect these aging effects.In LRA Section 3.5.2.2.1.7, the applicant listed components associated with primarycontainment that require aging management for cracking due to cyclic loading because theiroriginal design bases did not include CLB fatigue analyses. Specifically, components requiring aging management for cracking due to cyclic loading include drywell penetrations, drywell penetration sleeves, and associated dissimilar metal welds. These components are designed to stress levels without requiring fatigue analyses and thus fine cr acks are unlikely to occur;therefore, existing requirements for leak-rate testing pursuant to the 10 CFR 50, Appendix JProgram and surface inspections pursuant to the Primary Containment In-Service Inspection Program are adequate to detect cracking due to cyclic loading.The applicant also listed components associated with primary containment that require agingmanagement for crack initiation and growth due to SCC, specifically the stainless steel vent line bellows and drywell penetration bellows. The GALL Report states that weld Examination Categories E-B (pressure retaining welds, VT-1 examination method) and E-F (dissimilar pressure retaining welds, surface examination method) for vent line and other penetration bellows assemblies are warranted for the extended period of operations.The applicant stated that its operating history on bellows replacements is limited to bellowsX-16B. Leakage was identified during local leak-rate testing and not from cracks observedduring a visual examination. The leakage was identified at the outer-most bellows from a smallfailure underneath the outer-most collar of the expansion joint. The applicant did not identify anycracks in the weld metal. Industry operating history has identified cracks of the bellows but nonein the weld metal. Welds for bellows assemblies are in a sheltered, noncorrosive environment.

3-275Additionally, bellows assemblies are located outside primary containment in an air/gasenvironment with temperatures not expected to exceed threshold limits for SCC. Because of the nonaggressive environmental exposures and plant-specific and industry operating histories, the applicant stated that weld examinations using optional Examination Categories E-B and E-F arenot warranted. The applicant stated that existing requirements for visual examinations, inaccordance with ASME Code,Section XI (Subsection IWE), Examination Category E-A, and Appendix J leak-rate testing, Examination Category E-P, should be sufficient to detect cracking of the bellows assemblies.The applicant concluded that implementation of these programs to manage aging effects addsassurance that the aging effects do not occur or progress so slowly that the component'sintended function will be maintained during the period of extended operation.SER Sections 3.0.3.1.6 and 3.0.3.2.1 document the staff's reviews of the applicant's PrimaryContainment In-Service Inspection Program and the 10 CFR 50, Appendix J Program, respectively. The NRC staff found these programs acceptable for managing cracking due tocyclic loading and SCC in accessible areas.The staff reviewed industry operating experience on cracking of containment penetrations(including penetration sleeves, penetration bellows, and dissimilar metal welds) due to cyclicloading and SCC and found it to be similar to the applicant's operating experience. The staff concluded that the applicant appropriately addressed further evaluation of this aging effect.On the basis of its review, the staff concluded that, based on the programs identified above, theapplicant has met the criteria of SRP-LR Section 3.5.2.2.1.7. For those line items that apply toLRA Section 3.5.2.2.1.7, the staff determined that the applicant's AMRs are consistent with theGALL Report and the applicant has demonstrated that the effects of aging will be adequatelymanaged so that the intended functions will be maintained consistent with the CLB during theperiod of extended operation, as required by 10 CFR 54.21(a)(3).3.5.2.2.2 Class 1 Structures The staff reviewed LRA Section 3.5.2.2.2 against the criteria in SRP-LR Section 3.5.2.2.2,which addresses several areas discussed below.Aging of Structures Not Covered by Structures Monitoring Program. The staff reviewed LRASection 3.5.2.2.2.1 against the criteria in SRP-LR Section 3.5.2.2.2.1.In LRA Section 3.5.2.2.2.1, the applicant addressed various aging effects for concrete andcarbon steel components. The applicant specifically addressed whether it needs to manage the aging effects/mechanisms based on plant-specific review of the conditional requirements outlined in the GALL Report.SRP-LR Section 3.5.2.2.2.1 states the following:The GALL Report recommends further evaluation of certain structure/agingeffect combinations if they are not covered by the Structures Monitoring Program. This includes (1) scaling, cracking, and spalling due to repeatedfreeze-thaw for Groups 1-3, 5, 7-9 structures; (2) scaling, cracking, spalling and 3-276increase in porosity and permeability due to leaching of calcium hydroxide andaggressive chemical attack for Groups 1-5, 7-9 structures; (3) expansion and cracking due to reaction with aggregates for Groups 1-5, 7-9 structures; (4) cracking, spalling, loss of bond, and loss of material due to corrosion of embedded steel for Groups 1-5, 7-9 structures; (5) cracks, distortion, andincrease in component stress level due to settlement for Groups 1-3, 5, 7-9 structures; (6) reduction of foundation strength due to erosion of porous concrete subfoundation for Groups 1-3, 5-9 structures; (7) loss of material due to corrosion of structural steel components for Groups 1-5, 7-8 structures; (8) loss of strength and modulus of concrete structures due to elevated temperatures for Groups 1-5; and (9) crack initiation and growth due to SCC and loss of material due to crevice corrosion of stainless steel liner for Groups 7 and 8 structures.

Further evaluation is necessary only for structure/aging effect combinations not covered by the structures monitoring program. Technical details of the aging management issue are presented in SRP-LR Subsection 3.5.2.2.1.2 for items (5)and (6) and Subsection 3.5.2.2.1.3 for item (8).The applicant stated that, in accordance with the GALL Report for carbon steel in accessibleareas, loss of material due to corrosion requires aging management. It performs aging management of carbon steel in accessible areas within the Structures Monitoring Program through general visual inspections. Protective coatings, including galvanization, are not relied upon to manage the aging effects.The applicant also stated that the underground duct bank and intake structures includebelow-grade steel components. As the below-grade sides of the carbon steel components are not accessible, the condition of the accessible sides of the carbon steel components located inan atmosphere/weather, air/gas, or raw water environment, will be used to evaluate thecondition of the inaccessible sides of the carbon steel components.The applicant stated that, in accordance with the GALL Report and ISG-03, concrete inaccessible areas requires aging management for the aging mechanisms of freeze-thaw, leaching of calcium hydroxide, reaction with aggregates, corrosion of embedded steel, and aggressive chemical attack. The applicant performs aging management of concrete in accessible areas through general visual inspections within the Structures Monitoring Program.The applicant stated that concrete in inaccessible areas requires no aging management andprovided justification in the following paragraphs from LRA Section 3.5.2.2.2.1:MNGP is located in a severe weathering region according to Figure 1 of ASTMC33-90, and therefore a freeze-thaw evaluation is required. Plant documentsconfirm that the concrete has an air content between 3 and 6%, and subsequentinspections performed on concrete in accessible areas did not exhibit degradation related to freeze-thaw. This evaluation satisfies GALL Report and ISG-03 condition requirements for concrete in inaccessible areas, and therefore loss of material and cracking due to freeze-thaw do not require aging management.Plant documents confirm that the concrete was constructed in accordance withthe recommendations in ACI 201.2R-77 for durability. Additionally, there is no 3-277flowing water acting on any below-grade concrete basemat or concrete wall.Building foundations may or may not fall below the ground-water table. For those below the ground-water table, evaluation shows that ground-water flow velocity is well below the threshold at which any significant erosion or leaching of calcium hydroxide is possible. This evaluation satisfies the GALL Report and ISG-03 condition requirements for concrete in inaccessible areas, and therefore increase in porosity and permeability and loss of strength due to leaching of calciumhydroxide do not require aging management.Tests and petrographic examinations performed according to ASTM C289-64and ASTM C295 verified that aggregates used are not reactive. This satisfies the GALL Report and ISG-03 condition requirements for concrete in inaccessible areas, and therefore expansion and cracking due to reaction with aggregates do not require aging management.The GALL Report and ISG-03's description of an aggressive environment is pH< 5.5, chlorides >500 ppm, or sulfates > 1500 ppm. Plant documents confirm that the below-grade environment is not aggressive (MNGP data indicates thatthe pH is > 7.0, the chlorides are < 100 ppm and the sulfates are < 100 ppm).The Structures Monitoring Program includes examinations of below-grade concrete when excavated for any reason. To ensure the below-grade environment remains non-aggressive, ground-water chemistry is monitored periodically for the above parameters as part of the Structures Monitoring Program. This satisfies the GALL Report and ISG-03 condition requirements for concrete in inaccessible areas, and therefore cracking, loss of bond, and loss of material due to corrosion of embedded steel do not require aging management.

Based on the above rationale, increase in porosity and permeability, cracking,and loss of material due to aggressive chemical attack do not require aging management.Finally, the applicant stated in LRA Section 3.5.2.2.2.1 that implementation of the StructuresMonitoring Program to manage aging effects/mechanisms adds assurance that the aging effects do not occur or progress so slowly that the component's intended function will bemaintained during the period of extended operation.SER Section 3.0.3.2.23 documents the staff's evaluation of the Structures Monitoring Program.The staff reviewed component/aging effect combinations and the need to manage the agingeffects/mechanisms based on plant-specific review of the conditional requirements outlined in the GALL Report and determined that the applicant appropriately addressed these conditions.The staff's review of the applicant's evaluations found them acceptable.On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LRSection 3.5.2.2.2.1. For those line items that apply to LRA Section 3.5.2.2.2.1, the staffdetermined that the applicant's AMRs are consistent with the GALL Report and the applicanthas demonstrated that the effects of aging will be adequately managed so that the intendedfunctions will be maintained consistent with the CLB during the period of extended operation, asrequired by 10 CFR 54.21(a)(3).

3-278Aging Management of Inaccessible Areas. The staff reviewed LRA Section 3.5.2.2.2.2 againstthe criteria in SRP-LR Section 3.5.2.2.2.2.In LRA Section 3.5.2.2.2.2, the applicant addressed aging management of inaccessible areasfor Class 1 structures.SRP-LR Section 3.5.2.2.2.2 states the following:Cracking, spalling, and increases in porosity and permeability due to aggressivechemical attack, and cracking, spalling, loss of bond, and loss of material due tocorrosion of embedded steel could occur in below-grade inaccessible concrete areas. The GALL Report recommends further evaluation to manage these aging effects in inaccessible areas of Groups 1-3, 5, 7-9 structures, if specific criteria defined in the GALL Report cannot be satisfied.In LRA Section 3.5.2.2.2.2 the applicant stated that it has no Group 7 or 8 structures; therefore,discussion of the aging effects for these structures is not required. For other structures, the applicant concluded that concrete in inaccessible areas requires no aging management for corrosion of embedded steel and aggressive chemical attack and provided justification in LRA Section 3.5.2.2.2.1.The staff reviewed LRA Section 3.5.2.2.2.1 and found the specific criteria defined in the GALLReport satisfied; therefore, further evaluation is not necessary.On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LRSection 3.5.2.2.2.2. For those line items that apply to LRA Section 3.5.2.2.2.2, the staffdetermined that the applicant's AMRs are consistent with the GALL Report and the applicanthas demonstrated that the effects of aging will be adequately managed so that the intendedfunctions will be maintained consistent with the CLB during the period of extended operation, asrequired by 10 CFR 54.21(a)(3).3.5.2.2.3 Component Supports The staff reviewed LRA Section 3.5.2.2.3 against the criteria in SRP-LR Section 3.5.2.2.3,which addresses several areas discussed below.Aging of Supports Not Covered by the Structures Monitoring Program. The staff reviewed LRASection 3.5.2.2.3.1 against the criteria in SRP-LR Section 3.5.2.2.3.1.In LRA Section 3.5.2.2.3.1, the applicant discussed aging of component supports, specificallywhether it needs to manage the aging effects/mechanisms based on a plant-specific review of the conditional requirements outlined in the GALL Report.SRP-LR Section 3.5.2.2.3.1 states the following:The GALL Report recommends further evaluation of certain componentsupport/aging effect combinations if they are not covered by the Structures Monitoring Program. This includes (1) reduction in concrete anchor capacity due to degradation of the surrounding concrete, for Groups B1-B5 supports; (2) loss 3-279of material due to environmental corrosion, for Groups B2-B5 supports; and (3)reduction/loss of isolation function due to degradation of vibration isolation elements, for Group B4 supports. Further evaluation is necessary only for structure/aging effect combinations not covered by the Structures Monitoring Program.The applicant stated that component supports include structural elements connected to thebuilding or its structures and extending to a system or system component for support orrestraint. Component supports include support members, anchor bolts, welds, bolted connections, grout pads, and building concrete at locations of expansion and at grouted anchors. This boundary definition includes any vibration isolation elements. Spray or drip shields for equipment are included with component supports. In addition, electrical and instrumentation racks, electrical panels, cabinets and enclosures, lighting fixtures, tube track,conduit, and cable trays provide support and, thus, are included with component supports.

Miscellaneous steel structures such as platforms, stairs, whip restraints, and masonry wall supports are parts of the structures in which they are located.The applicant stated in the LRA that the AERM for carbon steel components is loss of material.In accordance with EPRI 1002950 guidelines, only general corrosion is an aging mechanism applicable to loss of material for carbon steel in air/gas or atmosphere/weather environments.

The EPRI guidelines also indicate that general, crevice, and pitting corrosion and MIC are aging mechanisms applicable to loss of material for carbon steel in treated water and below-grade environments. Therefore, as the applicant stated in the LRA, management of this aging effect isrequired:The aging effect requiring management for reinforced concrete and groutcomponents is reduction in concrete anchor capacity due to local concrete degradation. The only mechanism applicable to this aging effect is service-induced cracking or other concrete aging mechanism. Operating experience has shown that service-induced cracking can occur in concrete and grouted foundations. Concrete expansion bolts (anchors) can lose anchor capacity due to concrete or grout degradation. Therefore, management of this aging effect is required.The aging effect requiring management for elastomers (rubber, neoprene, silicone, etc.) is reduction or loss of isolation function. The aging mechanismsapplicable to this aging effect are radiation hardening, temperature, humidity, and sustained vibratory loading. Operating experience has also shown that elastomer materials can degrade over time. Therefore, management of this aging effect is required.Concerning AMPs used in addressing aging management, the applicant stated the following inthe LRA:The System Condition Monitoring Program is used to identify and correct agingconcerns for component supports in an air/gas or atmosphere/weather environment. Through general visual inspections, the System Condition Monitoring Program identifies and evaluates general corrosion of carbon steel components, service-induced cracking of grout and concrete local to support 3-280anchorage as well as degradation due to radiation hardening, temperature,humidity, and sustained vibratory loading of vibration isolation elements.The Structures Monitoring Program is used to identify and correct agingconcerns with miscellaneous steel components in an air/gas environment.

Through general visual inspections, the Structures Monitoring Program identifies and evaluates general corrosion of carbon steel components as well as service-induced cracking and degradation of grout and concrete local to the anchorage.The Buried Piping & Tanks Inspection Program is used to identify loss ofmaterial for carbon steel conduit and the Diesel Fuel Oil Storage Tank flood tie-downs in a below-grade environment through internal inspections of buried tanks, system functional testing, and periodic inspections of buried pipe. Acondition assessment evaluation is made of the buried conduit and the Diesel Fuel Oil Storage Tank flood tie-downs such that repairs can be made, if necessary, prior to loss of intended function.Access to the components inside the torus is limited. Since the PrimaryContainment In-Service Inspection Program inspects components inside the torus when available, it is relied upon to manage the aging effects of the miscellaneous steel components, support members, welds, and bolted connections located inside the torus. Through general visual inspections, the Primary Containment In-Service Inspection Program identifies and evaluates general (environmental), crevice, galvanic, MIC, and pitting corrosion of carbon steel components in treated water and general corrosion in air/gas.Finally, the applicant stated that implementation of these programs to manage agingeffects/mechanisms provides added assurance that the aging effects do not occur or progress so slowly that the component's intended function will be maintained during the period ofextended operation.The staff reviewed component support/aging effect combinations not addressed by theStructures Monitoring Program and determined that other AMPs address them. The staff concluded that the applicant used the appropriate AMPs.SER Section 3.0.3.2.23 documents the staff's evaluation of the Structures Monitoring Program.SER Section 3.0.3.3.2 documents the staff's evaluation of the System Condition MonitoringProgram. SER Section 3.0.3.2.5 documents the staff's evaluation of the Buried Piping & TanksInspection Program. Finally, SER Section 3.0.3.1.6 documents the staff's evaluation of thePrimary Containment In-Service Inspection Program.On the basis of its review, the staff concluded that the applicant has met the criteria of SRP-LRSection 3.5.2.2.3.1. For those line items that apply to LRA Section 3.5.2.2.3.1, the staffdetermined that the applicant's AMRs are consistent with the GALL Report and the applicanthas demonstrated that the effects of aging will be adequately managed so that the intendedfunctions will be maintained consistent with the CLB during the period of extended operation, asrequired by 10 CFR 54.21(a)(3).

3-281Cumulative Fatigue Damage Due to Cyclic Loading. Cumulative fatigue is a TLAA, as defined in10 CFR 54.3. TLAAs are required to be evaluated in accordance with 10 CFR 54.21(c)(1). SER Section 4.3 documents the evaluation of this TLAA.Conclusion. On the basis of its review, for component groups evaluated in the GALL Report forwhich the applicant has claimed consistency with the GALL Report, and for which the GALL Report recommends further evaluation, the staff determined that the applicant adequatelyaddressed the issues that were further evaluated. The staff found that the applicant hasdemonstrated that the aging effects will be adequately managed so that the intended functionswill be maintained consistent with the CLB for the period of extended operation, as required by10 CFR 54.21(a)(3).3.5.2.3 AMR Results That Are Not Consistent with or Not Addressed in the GALL ReportSummary of Technical Information in the Application. In LRA Tables 3.5.2-1 through 3.5.2-18,the staff reviewed additional details of the results of the AMRs for material, environment, AERM, and AMP combinations that are not consistent with the GALL Report, or that are notaddressed in the GALL Report.In LRA Tables 3.5.2-1 through 3.5.2-18, the applicant indicated, via Notes F through J, that thecombination of component type, material, environment, and AERM does not correspond to a line item in the GALL Report and provided information concerning how it will manage the agingeffect. Specifically, Note F indicates that the GALL Report does not evaluate the material for the AMR line item component. Note G indicates that the GALL Report does not evaluate the environment for the AMR line item component and material. Note H indicates that the GALL Report does not evaluate the aging effect for the AMR line item component, material, and environment combination. Note I indicates that the aging effect identified in the GALL Report forthe line item component, material, and environment combination is not applicable. Note J indicates that the GALL Report does not evaluate either the component or the material andenvironment combination for the line item.Staff Evaluation. For component type, material, and environment combinations that are notevaluated in the GALL Report, the staff reviewed the applicant's evaluation to determinewhether the applicant demonstrated that the aging effects will be adequately managed so thatintended functions will be maintained consistent with the CLB during the period of extendedoperation. The following sections discuss the staff's evaluation.In LRA Tables 3.5.2-1 through 3.5.2-18, the applicant identified AMR result line items for whichthe aging review process identified no aging effects. The applicant stated that it identified noaging effects for components fabricated from the materials and exposed to the environments described below.No aging effects were considered applicable to components fabricated from stainless steelmaterial exposed to air/gas environments. On the basis of the staff's review of current industry research and operating experience, stainless steel in dry air or gas (such as nitrogen, carbon dioxide, freon, and halon) exhibits no aging effect and the SC will therefore remain capable ofperforming its intended functions consistent with the CLB for the period of extended operation.Based on the Metals Handbook, Ninth Edition, Volumes 3 and 13, stainless steels are highlyresistant to corrosion in dry atmospheres in the absence of corrosive species, as will be the 3-282case for the gases referenced; therefore, the staff found that stainless steel in an air/gasenvironment will not result in aging that will be of concern during the period of ext endedoperation. The staff concluded that no AERMs apply for stainless steel components exposed to air or gas environments.In RAI 3.5.2-1, dated September 28, 2005, the staff noted that the applicant listed below-gradeconcrete (foundation, walls) as requiring no AMP in Tables 3.5.2-2, 3.5.2-3, 3.5.2-4, 3.5.2-6,3.5.2-7, 3.5.2-9, 3.5.2-11, 3.5.2-12, 3.5.2-13, 3.5.2-15, 3.5.2-16, and 3.5.2-17. The applicantstated that an AMP is not required to manage aging because, as described in Note 501, plant documents confirm that the concrete had an air content between 3 and 6 percent andinspections performed on concrete in accessible areas did not exhibit degradation related to freeze-thaw. The staff noted that the GALL Report recommends that concrete have awater-to-cement ratio of 0.35:0.45 to ensure no aging degradation related to freeze-thaw;therefore, the staff requested that the applicant verify the water-to-cement ratio or provide anappropriate AMP if the ratio does not meet the GALL Report recommendation. The staff raised the same question for below-grade concrete (foundations, walls, lean concrete) listed in Table 3.5.2-8.In its response, by letter dated October 28, 2005, the applicant stated the following:Note: This response applies to Tables 3.5.2-2, 3.5.2-3, 3.5.2-4, 3.5.2-6, 3.5.2-7,3.5.2-8, 3.5.2-9, 3.5.2-10, 3.5.2-11, 3.5.2-12, 3.5.2-14, 3.5.2-15, 3.5.2-16,3.5.2-17 and 3.5.2-18 but is not applicable to Table 3.5.2-13 (i.e. not applicablesince there is no below grade concrete inside drywell).The criteria used to evaluate concrete located below grade were consistent withNRC Staff final position issued for Interim Staff Guidance (ISG)-03 (see LRASection 2.1.4.3). ISG-03 provided the following criteria for the aging effects loss of material (spalling, scaling) and cracking due to freeze-thaw for concrete in inaccessible areas (i.e. exterior locations below grade and foundations).'Inaccessible Areas:

Evaluation is needed for plants that are located in moderate to severeweathering conditions (weathering index>100 day-inch/yr) (NUREG-1557).Documented evidence to confirm that the in-place concrete had the air content between 3 percent to 6 percent and the subsequent inspectionsperformed did not exhibit degradations related to freeze-thaw should be considered a part of the evaluation.'LRA Note 501 and Table 1, item 3.5.1-20, and further evaluation for 3.5.2.2.2.1included the following statement.'MNGP is located in a severe weathering region according to Figure 1 ofASTM C33-90, and therefore freeze-thaw evaluation is required. Plant documents confirm that the concrete had an air content between 3 percentand 6 percent, and subsequent inspections performed on concrete in accessible areas did not exhibit degradation related to freeze-thaw. This evaluation satisfies NUREG-1801 and ISG-03 condition requirements for 3-283concrete in inaccessible areas, and therefore loss of material and crackingdue to freeze-thaw do not require aging management.'All criteria of ISG-03 have been satisfied including an aging effect evaluation dueto severe weather location, documentation confirming that the concrete had anair content between 3 percent and 6 percent, and plant inspection findings thatdid not exhibit degradation related to freeze-thaw.Additionally, ISG-03 was one of five ISG guidance documents issued forimplementation by the NRC prior to the LRA submittal. Under this guidance, theStaff removed the water-to-cement ratio and replaced it with the statement,

'subsequent inspections performed did not exhibit degradations related to freeze-thaw'. This substitution is consistent with ACI 318, DurabilityRequirements that state, 'Since it is difficult to accurately determine the water-cementitious materials ratio of concrete during production, the f'c specified should be reasonably consistent with the water-cementitious materials ratio required for durability. Selection of an f'c that is consistent with thewater-cementitious ratio selected for durability will help ensure that the requiredwater-cementitious materials ratio is actually obtained in the field.' ACI 318 also states that the quality and production of concrete must be considered. At MNGP, all in place concrete met or exceeded the design required strength (f'c).

Concrete inspections continue to show no evidence of degradation due to freeze-thaw. Plant concrete design specifications (Specification for Purchase of Off-Site Concrete for the MNGP, Specification for Forming, Placing, Finishing and Curing of Concrete, and Specification for Materials Testing Services, etc.)

include requirements that satisfy ACI 318 standards for materials, durability,concrete quality, mixing, and placing. Plant documents confirm that the concretewas constructed in accordance with the recommendations in ACI 201.2R for durability and therefore able to resist freeze-thaw and other age relateddegradation. Materials used in the concrete mix design conformed to ASTM specifications (C-94, C-150, etc.) that ensured consistent, proportional,non-porous concrete of quality materials. Aggregates conformed to the requirements of ASTM C-33 and were accepted based on ASTM C-295 (petrographic) C-289 (reactivity) and other tests. Mixing and delivering of concrete was in accordance with ACI standards for hot and cold weather conditions (ACI 305, ACI 306) and appropriate air entrainment, adequate curing, and special attention to construction practices were maintained with reference to ASTM C-260, C-494 and C-618. Utilizing industry construction standardsensured good workmanship and quality control practices (i.e., the requirements of ACI 304, 308, 309, ASTM C-94, etc.).Compliance with the above industry code requirements and guidelines ensuresthat freeze-thaw is not significant as proven by the absence of freeze-thawdegradation.The staff's review found the applicant's response to RAI 3.5.2-1 acceptable. The staff foundthat the applicant provided sufficient information to conclude that its below-grade concrete willnot require an AMP for loss of material due to the freeze-thaw aging mechanism; therefore, the staff's concern described in RAI 3.5.2-1 is resolved.

3-284In RAI 3.5.2-2, dated September 28, 2005, the staff noted that the applicant listed below-gradeconcrete (foundation, walls) as requiring no AMP in Tables 3.5.2-3, 3.5.2-4, 3.5.2-6, 3.5.2-7,3.5.2-9, 3.5.2-11, 3.5.2-12, 3.5.2-13, 3.5.2-15, 3.5.2-16, and 3.5.2-17. The applicant stated thatno AMP is required to manage aging because, as described in Note 506, (1) the plant initial licensing basis did not include a program to monitor settlement, (2) no significant settlement has been observed, and (3) de-watering systems are not used. The applicant's statement isinconsistent with ISG-03, which requires a "Structural Monitoring Program" based on the requirement of 10 CFR 50.65 (Maintenance Rule) for accessible areas and a "plant-specific program for inaccessible areas." Therefore, the staff requested that the applicant provide anappropriate AMP for this component group and below-grade concrete (foundation, walls, lean concrete) listed in Table 3.5.2-8.In its response, by letter dated October 28, 2005, the applicant stated the following:Note: This response applies to Tables 3.5.2-3, 3.5.2-4, 3.5.2-6, 3.5.2-7, 3.5.2-8,3.5.2-9, 3.5.2-10, 3.5.2-11, 3.5.2-12, 3.5.2-14, 3.5.2-15, 3.5.2-16, 3.5.2-17 and3.5.2-18 but is not applicable to Table 3.5.2-13 (i.e. not applicable since there isno below grade concrete inside drywell).ISG-03 did not include an evaluation for the aging effects cracks, distortion, andincrease in component stress level due to settlement and therefore NUREG-1801 (2001) was used to evaluate the plant specific applicability of thisaging effect. Settlement is a condition that directly affects the concrete foundation components (see NUREG-1557 page B-154 and Electric PowerResearch Institute (EPRI) 103842 page 4-88), and thus applicable to inaccessible concrete. NUREG-1801 (2001) states that,'The initial Licensing Basis for some plants included a program to monitorsettlement. If no settlement was evident during the first decade or so, the NRC may have given the licensee approval to discontinue the program.However, if a de-wateri ng system is relied upon for control of settlement,then the licensee is to ensure proper functioning of the de-watering systemthrough the period of extended operation.'LRA Note 506, Table 3.5.1 item number 3.5.1-25, and further evaluation3.5.2.2.1.2 included the following statement.'The plant initial Licensing Basis did not include a program to monitorsettlement. No significant settlement has been observed on any major structure and de-watering systems are not used. This satisfies NUREG-1801condition requirements on concrete settlement, and therefore cracks,distortion, and increase in component stress levels due to settlement do not require aging management.'The NUREG-1801 criteria used to evaluate concrete for settlement consists ofan initial Licensing Basis program to monitoring settlement, evident of settlement during the first decade, and a de-watering system relied upon for settlementcontrol. All are not applicable to the MNGP. The initial licensing basis did not include a settlement monitoring program, no significant settlement has ever been 3-285observed on any major structure, and de-watering systems were not used (seediscussion on the Diesel Fuel Oil Transfer House that follows).Additionally, the MNGP USAR, Section 12.2.1.11 includes a discussion onfoundation design and construction. The USAR provides conclusions on foundation designs based on soil bearing values. Major building structures were constructed on bedrock, compacted granular fill, or stiff clay. No unusual orunforeseen foundation construction problems were encountered. A survey traverse of points on the buildings was established to monitor foundation settlement. This survey determined that settlement was uniform and within the predicted values. The reactor building, the turbine building and other structures are supported on mat foundations. The stack and control and cable spreading building are also on mat foundations, and the emergency diesel generator building is constructed on a continuous footing foundation. The emergency filtration train building rests on a combination of mat and caisson foundations.The MNGP review is consistent with NUREG-1801 condition requirements forsettlement, similar to the review performed in the Dresden and Quad Cities Safety Evaluation Report (SER), NUREG-1796. NUREG-1796 stated that, 'noaging management is required' and the Staff responded with, 'The Staff finds the applicant's explanation to be acceptable because there has been no requirement to monitor settlement as part of the licensing basis for all four units, and there are no de-watering systems in place.'Although not managed for cracks, distortion, and increase in component stresslevel due to settlement (except for the Diesel Fuel Oil Transfer House, see below), all accessible concrete is managed for aging effects including cracks,loss of material, etc. Additionally, whenever an inaccessible area is excavated, exposed or modified, an inspection is performed.As stated above, settlement has not been observed at any major structures. TheDiesel Fuel Oil Transfer House, a small structure north of the Emergency Diesel Generator Building has experienced settlement. The structure is rectangular with external dimensions of 11'-6" (N-S) x 14' (E-W) x 13'-6" high. Walls are 1'-6" thick. It is a moderate weight structure exerting a mean bearing pressure of about 1,100 lb. / ft.

2 on the underlying foundation material. The foundationmaterial is compacted granular backf ill underlain by stiff clay lenses andsandstone bedrock, and should not be susceptible to settlement under the load imposed. However the Diesel Fuel Oil Transfer House has undergone significant differential settlement. Based on plant records and settlement data, settlement of the Diesel Fuel Oil Transfer House occurred rather rapidly following construction and was probably due to washout after a rainstorm and was long ago effectively complete. Settlement data recorded annually since 1992 continues to show no significant settlement of the structure. A Nonconformance Report root cause analysis concluded there was insufficient foundation support to prevent settling.

Measurements taken in 1976, 1979 and 1991 show settlement has continued over the years since construction but at an extremely low rate. Surveys determined that the entire building has settled about 3/4" to 1" on the east sideand about 5 1/4" to 5 1/2" on the west side. No evidence of cracks or distortion has 3-286been observed by the Structures Monitoring Program inspections performed in1996 and 2002. The Diesel Fuel Oil Transfer House is monitored for the aging effects of cracks, distortion, and increase in component stress level due tosettlement now on an annual basis as part of the Structures Monitoring Program

and will be managed throughout the period of extended operation.In conclusion, cracks, distortion, and increase in component stress level due tosettlement is not an applicable aging mechanism for any in scope structure with the exception of the Diesel Fuel Oil Transfer House which is managed for aging effects due to settlement.The staff's review found the applicant's response to RAI 3.5.2-2 acceptable. The applicantprovided sufficient information to justify that, except for the diesel fuel oil transfer house, which is managed for aging effects due to settlement, other building structures need no management for aging effects due to settlement. The staff found the applicant's statement reasonable and acceptable regarding its management of all accessible concrete for aging effects, including cracks and loss of material, and its inspection of inaccessible areas whenever they areexcavated, exposed, or modified; therefore, the staff's concern described in RAI 3.5.2-2 isresolved.The staff's audit and review of the applicant's program found that the applicant demonstratedthat the aging effects will be adequately managed so that the intended functions will bemaintained during the period of extended operation as required by 10 CFR 54.21(a)(3).3.5.2.3.1Structures and Component Supports-Cranes, Heavy Loads, Rigging-Summary ofAging Management Evaluation-Table 3.5.2-1The staff reviewed LRA Table 3.5.2-1, which summarizes the results of AMR evaluations for thecranes, heavy loads, and rigging component groups.All line items in this table are consistent with the GALL Report or are included in the discussionin Section 3.5.2.3 above.3.5.2.3.2Structures and Component Supports-Diesel Fuel Oil Transfer House-Summary ofAging Management Evaluation-Table 3.5.2-2The staff reviewed LRA Table 3.5.2-2, which summarizes the results of AMR evaluations for thediesel fuel oil transfer house component groups.All line items in this table are consistent with the GALL Report or are included in the discussionin Section 3.5.2.3 above.3.5.2.3.3Structures and Component Supports-Emergency Diesel GeneratorBuilding-Summary of Aging Management Evaluation-Table 3.5.2-3The staff reviewed LRA Table 3.5.2-3, which summarizes the results of AMR evaluations for theEDG building component groups.

3-287All line items in this table are consistent with the GALL Report or are included in the discussionin Section 3.5.2.3 above.3.5.2.3.4Structures and Component Supports-Emergency Filtration TrainBuilding-Summary of Aging Management Evaluation-Table 3.5.2-4The staff reviewed LRA Table 3.5.2-4, which summarizes the results of AMR evaluations for theemergency filtration train building component groups.All line items in this table are consistent with the GALL Report or are included in the discussionin Section 3.5.2.3 above.3.5.2.3.5Structures and Component Supports-Fire Protection Barrier-Summary of AgingManagement Evaluation-Table 3.5.2-5The staff reviewed LRA Table 3.5.2-5, which summarizes the results of AMR evaluations for theFP barrier commodity groups.The staff also reviewed LRA Section 3.5.2.1.5, which identified the materials, environments,AERMs, and AMPs for the FP barrier commodity group. The staff conducted its review, described below, in accordance with SRP-LR Section 3.5 and the GALL Report.The staff's review of LRA Table 3.5.2-5 identified areas for which it needed additionalinformation to complete its evaluation of the applicant's results. The applicant responded to the staff's RAIs as discussed below.In RAI 3.5.2.1.5-1, dated August 18, 2005, the staff noted that LRA Table 3.5.2-5 refers to theFire Protection Program as the AMP to manage loss of material for carbon steel in air/gas.

Therefore, the staff requested that the applicant justify this conclusion.In its response, by letter dated September 16, 2005, the applicant stated that LRA Table 3.5.2-5refers to the Fire Protection Program as the AMP for carbon steel with a fire barrier intended function in an air/gas environment. The scope of the program described in Fire Protection Program PBD/AMP-013, Table 7.1, includes fire barriers with specific reference to carbon steel with an aging effect of loss of material in a plant indoor air environment (i.e., air/gas environment). This description is consistent with LRA Table 3.5.2-5.The staff's review found the applicant's response to RAI 3.5.2.1.5-1 acceptable because thescope of the Fire Protection Program includes fire barriers with specific reference to carbon steel with an aging effect of loss of material in a plant indoor air environment, as described in Fire Protection Program PBD/AMP-013, Table 7.1. The staff's review of the applicant's Fire Protection Program, including Table 7.1 of PBD/AMP-013, found that it provides reasonable assurance that carbon steel components in an air/gas environment in the FP system will bemanaged for aging effects during the period of extended operation. Therefore, the staff'sconcern described in RAI 3.5.2.1.5-1 is resolved.In RAI 3.5.2.1.5-2, dated August 18, 2005, the staff noted that LRA Tables 3.5.2-5, 3.5.2-15,and 3.5.2-17 refer to the Fire Protection Program as the AMP for fibrous fire wraps (thermal insulating wool/fiber), cementitious fireproofing (thermal insulating mastic), and rigid board 3-288(thermal insulating board) in air/gas; therefore, the staff requested that the applicant justify thisconclusion.In its response, by letter dated September 16, 2005, the applicant stated that LRATables 3.5.2-5, 3.5.2-15, and 3.5.2-17 refer to the Fire Protection Program as the AMP formanaging aging effects for fibrous fire wraps, cementitious fireproofing, and rigid board with a fire barrier intended function in an air/gas environment. The scope of the Fire Protection Program, as described in Fire Protection Program PBD/AMP-013, Table 7.1, includes fire barriers with specific reference to fibrous fire wraps, cementitious fireproofing, and rigid board with the aging effects of cracking, delamination, and loss of material in an air/gas environment.

This description is consistent with LRA Tables 3.5.2-5, 3.5.2-15, and 3.5.2-17.The staff's review found the applicant's response to RAI 3.5.2.1.5-2 acceptable because thescope of the Fire Protection Program includes fire barriers with specific reference to fibrous fire wraps, cementitious fireproofing, and rigid board with the aging effects of cracking, delamination, and loss of material in an air/gas environment, as described in Fire Protection Program PBD/AMP-013, Table 7.1. The staff's review of the applicant's Fire Protection Program, including PBD/AMP-013, Table 7.1, found that it provides reasonable assurance thatfibrous fire wraps, cementitious fireproofing, and rigid board in an air/gas environment in the FP system will be managed for aging effects during the period of extended operation. Therefore,the staff's concern described in RAI 3.5.2.1.5-2 is resolved.The staff's review of the applicant's programs, the aging effects, and the plant-specific andindustry operating experience determined that the applicant adequately identified applicableaging effects and the AMPs credited with managing them for the fire barrier commodity group not addressed by the GALL Report. The staff found the applicant's AMR results for the fire barrier commodity group acceptable.3.5.2.3.6Structures and Component Supports-Hangers and Supports-Summary of AgingManagement Evaluation-Table 3.5.2-6The staff reviewed LRA Table 3.5.2-6, which summarizes the results of AMR evaluations for thehangers and supports commodity groups.The applicant proposed to manage loss of material due to MIC, pitting, and crevice corrosion ofstainless steel materials for supports for ASME Code Class MC components (i.e., vent header column support pins exposed to treated water environment) using the ASME Section XI, Subsection IWF Program.SER Section 3.0.3.2.3 documents the staff's review of the ASME Section XI, Subsection IWFProgram. The ASME Section XI, Subsection IWF Program is part of the ASME Section XI In-Service Inspection Program. It provides for condition monitoring of Class 1, 2, 3, and MC component supports. The applicant will enhance it to inspect Class MC component supportsconsistent with the GALL Report, Chapter III, Section B1.3. The parameters monitored orinspected are loss of material and loss of mechanical function. The NDE technique used is the VT-3 method to detect unacceptable conditions such as loss of material and loss of mechanical function.

3-289In RAI 3.5.2-3, dated September 28, 2005, the staff noted that the Table 3.5.2-6 lists below-grade concrete (diesel fuel oil storage tank deadmen) as requiring no AMP. The applicant stated that no AMP is required to manage aging because, as described in Note 552, "NUREG-1801 lists inside or outside containment as the environment. Consider that thisenvironment includes atmosphere/weather and below grade." The applicant's statement isinconsistent with ISG-03, which requires a "Structural Monitoring Program" based on the requirement of 10 CFR 50.65 (Maintenance Rule) for accessible areas and a "plant-specific program for inaccessible areas." Therefore, the staff requested that the applicant provide anappropriate AMP for this component group.In its response, by letter dated October 28, 2005, the applicant stated the following:The buried Diesel Fuel Oil Storage Tank is anchored to a concrete foundation.To account for this condition, NUREG-1801 line item III.B4.3-a, 'buildingconcrete at locations of expansion and grouted anchors' was used. Although probably not the best usage of line III.B4.3-a, it was chosen to address thisunique condition. Note 552 was provided to clarify the different environment used than that specified in NUREG-1801 (i.e., below grade rather than theNUREG-1801 environment, inside or outside containment). The LRA AMP alsodiffered from that specified in NUREG-1801. Generic Note 'I' was used todescribe these differences since it was considered the 'best' note available to describe this unique condition. The aging effect, 'reduction in concrete anchor capacity due to local degradation' for the inaccessible location was evaluated by considering all possible concrete degradation mechanisms including freeze-thaw (III.A3.1-a), leaching of calcium hydroxide (III.A3.1-b), reaction with aggregate (III.A3.1-c), corrosion of embedded steel (III.A3.1-e), aggressivechemical attack (III.A3.1-g), settlement (III.A3.1-h), and erosion of porousconcrete sub-foundations (III.A3.1-h). The evaluation concluded that thesemechanisms did not require aging management (see page 3-686 of the LRA).

Service induced cracking was also not applicable since vibration/movement of the tank is not expected and the fact that the tank is surrounded by soil/fillmaterial. Therefore reduction in concrete anchor capacity due to local degradation was determined insignificant and aging management not required.The staff's review found the applicant's response to RAI 3.5.2-3 acceptable. The applicant'sresponse stated that it had evaluated all the possible aging mechanisms/effects and concluded that they did not require an AMP. The staff found the applicant's conclusion reasonable andacceptable; therefore, the staff's concern described in RAI 3.5.2-3 is resolved.In RAI 3.5.2-7, dated September 28, 2005, the staff noted that Table 3.5.2-6 identifies two lineitems related to carbon steel and low-alloy steel embedded in concrete as not requiring aging management. Note 549 states, "Requirements specified in NUREG-1801 for concrete quality,inspections, and housekeeping are satisfied for steel elements in inaccessible areas." Based on the industry-wide experience related to corrosion of the drywell shell in the sand pocket region, the staff requested that the applicant provide information regarding its inspections andhousekeeping related to carbon steel and low-alloy steel embedded in concrete and explain why these activities should not be a part of an existing AMP. The embedded items are included in an existing program to look for evidence of environment change (e.g., sand drains not 3-290working properly) in accessible areas that will indicate potential degradation in inaccessibleareas.The same question applied to carbon steel and low-alloy steel embedded in concrete listed inTable 3.5.2-13.In its response, by letter dated October 28, 2005, the applicant stated the following:Components in Table 3.5.2-6 refer to the embedded anchorage of the drywellsupport skirt, the embedded components of the female stabilizers, andembedded conduit. The evaluation of the embedded portions of the drywell shell and drywell support skirt is provided in Table 3.5.2-13.The applicant deliberated how these components meet the following four recommendations inGALL Report line item II.B1.1.1-a: (224)Concrete meeting the requirements of ACI 318 or 349 and theguidance of ACI 201.2R was used for the containment concrete in contact with the embedded containment shell or liner. (225)The concrete is monitored to ensure that it is free of penetratingcracks that provide a path for water seepage to the surface of thecontainment shell or liner. (226)The moisture barrier, at the junction where the shell or linerbecomes embedded, is subject to aging management activities in accordance with IWE requirements. (227)Borated water spills and water ponding on the containmentconcrete floor are not common and when detected are cleaned up in a timely manner.The applicant provided the following plant-specific evaluation: (228)Concrete meeting the following requirements was used for thecontainment concrete in contact with the embedded containment shell and skirt. The MNGP concrete design specifications for Purchase of Off-Site Concrete for the MNGP, Specification for Forming, Placing, Finishing and Curing of Concrete, Specification for Materials Testing Services and others specifications include requirements that satisfy ACI 318 standards for materials, durability, concrete quality, mixing and placing. Plant documentsconfirm that the concrete was constructed in accordance with the recommendations in ACI 201.2R for durability and therefore ableto resist weathering action, chemical attack, abrasion, leaching of calcium hydroxide, corrosion of reinforcement, and chemical reactions of aggregates. Materials used in the concrete mix design conformed to ASTM specifications (C-94, C-150, etc.) that ensure consistent, proportional, non-porous concrete of quality materials. Aggregates conformed to the requirements of ASTM C-33 and were accepted based on ASTM C-295 (petrographic)

C-289 (reactivity) and other tests. Mixing and delivering of 3-291concrete was in accordance with ACI standards for hot and coldweather conditions (ACI 305, ACI 306) and appropriate air entrainment, adequate curing, and special attention to construction practices were maintained (ASTM C-260, C-494 and C-618). MNGP construction specifications ensure good workmanship and quality control practices (ACI 304, 308, 309, ASTM C-94, etc.). (229)For accessible concrete inside drywell, the Structures MonitoringProgram inspects for cracking adjacent to the moisture barrier, at the concrete floor, and RPV Pedestal. Inspections ensure that the concrete is free of penetrating cra cks that provide a path for waterseepage to the containment shell. The bioshield wall is completely encased in steel and therefore inaccessible for inspection.AMPs will be used to manage the drywell to reactor building refueling sealbellows assembly located between the drywell outer shell and the reactor building concrete (See Table 3.5.2-15). By managing this assembly for aging degradation and water leakage (during refueling activities), any water seepage past the assembly to the drywell shell, sand pocket, embedded shell, and embedded skirt will be prevented, or detected and corrected. Therefore, loss ofmaterial due to corrosion for these components will be insignificant. Agingmanaged for the drywell to reactor building refueling seal bellows assembly willbe provided by the Primary Containment In-Service Inspection Program and the Structures Monitoring Program. These Programs ensure that degradation of the assembly or any water leakage past the assembly will be detected andcorrected before loss of intended function. These programs ensure that, - the drywell air gap drain outlets and sand pocket drain outlets are notobstructed prior to refueling - the drain lines that are incorporated into the refueling bellows assemblyare monitored for leaks - the drywell air gap drain outlets and drywell sand pocket drain outletsare inspected for signs of leakage during refueling, and - aging effects including loss of material are detected.The Plant Chemistry Program is also used to manage the assembly byensuring that the water chemistry remains within design parameters.MNGP operating history showed no evidence of refueling seal leakage, nowater observed in air gap during construction, and no water used to extinguish a fire in the air gap or for any other reason. Plant engineering and maintenance personnel confirmed the absence of leakage at the drywell air gap drains, and the sand pocket drains. Plant specific operating history has proven that inspection and monitoring activities adequately manage aging effects to ensure no loss of intended function.The applicant further asserted that the Primary Containment In-Service Inspection Programmanages aging effects associated with the moisture barrier and that borated water inside the 3-292drywell is not a concern for BWR plants. With these assertions, the applicant pointed out thatloss of material due to corrosion is not significant.The staff evaluated the information provided above, and the information provided to the NRC'saging management inspection team on the status of the drywell shell, and made the followingfindings:

  • The operating history confirmed that there is no indication of water in the air gapbetween the shell and the shield concrete.
  • The UT measurements taken, in mid-1986 and at the end of 1987, indicate that themetal thickness in the sand pocket region varies from 1.065 inches to 1.13 inches, and the design thickness in this area of the drywell shell is 1.0 inch.
  • In response to NRC GL 87-05, "Request for Additional Information Assessment ofLicensee Measures to Mitigate and/or Identify Potential Degradation of Mark I Drywells,"

the applicant made sure that the three drain paths (i.e., the drain that would preventpotential leakages from refueling seal areas, the drains at the sand pocket areas above the sealed sand pocket area, and the drains at the bottom of the sand pocket area) are clear of any obstruction. The applicant has been monitoring these drains and plans to continue the practice during the period of extended operation.

  • During the 1987 visual examination, some surface corrosion was noted where theconcrete floor meets the inside surface of the drywell shell. This was attributed to the joint sealant used during initial construction. The sealant was removed and replaced with nonshrink grout and a new type of sealant that would prevent corrosion. The applicant will periodically examine this area as required by Subsection IWE of Section XIof the ASME Code.Based on the above findings, the staff concluded that MNGP will adequately manage theinaccessible areas of the drywell shell during the period of extended operation, and the concernexpressed in RAI 3.5.2-7 is resolved.In RAI 3.5.2-8, dated September 28, 2005, the staff noted that recent experience with toruscracking at Fitzpatrick indicates HPC discharge configuration in the torus as a cause of cracking; therefore, the staff requested that the applicant describe its HPC configuration thatcould affect torus integrity during the period of extended operation.In its response, by letter dated October 28, 2005, the applicant stated the following:The HPCI turbine exhaust discharge pipe configuration at MNGP is significantlydifferent than that at Fitzpatrick. - The HPCI turbine exhaust at Fitzpatrick is located near the torus ringgirder (end bay) while the MNGP HPCI turbine exhaust is located approximately mid-bay between torus ring girders - The Fitzpatrick HPCI exhaust pipe incorporates a 90 degree elbow, isrelatively short with no holes, and discharges vertically in the vicinity of the torus ring girder and stiffener plates that are part of the torus external 3-293column support system. The Fitzpatrick torus crack was observedadjacent to these stiffener plates. The MNGP exhaust pipe is considerably longer with a submerged sparger that consist of a pipe, capped at one end, with a large number of holes in the lower portion which increases the area available for steam condensation compared to a straight pipe discharge. The MNGP pipe is not a vertical run, but instead, incorporates a 60 degree elbow.Based on the above comparison, the HPCI Turbine Exhaust configuration andlocation at MNGP is unlike that at Fitzpatrick. The MNGP pipe configuration and location are believed to be less susceptible to cracking and therefore less likely to affect torus integrity during the period of extended operation.The staff's review found the applicant's response to RAI 3.5.2-8 acceptable. Based on thereview of the root cause analysis of the through-wall crack at Fitzpatrick, the configuration ofHPC steam discharge (using spargers), and the location of HPC exhaust pipe, the staff found the applicant's torus is not prone to such cracking. Therefore, the staff's concern described in RAI 3.5.2-8 is resolved.In RAI 3.5.2-9, dated September 28, 2005, the staff noted that three line items in Table 3.5.2-6indicate that lubrite plates have been used at several locations in hangers and supports. The staff's position is that an inspection of the accessible portion of the lubrite bearing is needed to ensure proper functioning during postulated environmental conditions; therefore, the staff requested that the applicant incorporate an examination of the accessible portion of the lubritebearings in an appropriate AMP.In its response, by letter dated October 28, 2005, the applicant stated the following:Industry guidance provided in EPRI-1002950, Aging Effects for Structures andStructural Components, Revision 1 dated August 2003 for lubrite or similar material states that, 'An extensive search of industry operating experience did not identify any instances of lubrite plate degradation or failure to perform its intended function.' Additionally EPRI states that, 'Lubrite material resists deformation, has a low coefficient of friction, resists softening at elevated temperatures, absorbs grit and abrasive particles, is not susceptible to corrosion, withstands high intensities of radiation, and will not score or mar. Lubriteproducts are solid, permanent, completely self lubricating, and require no maintenance for the design life of the product. The lubrite lubricants used in nuclear applications are designed specifically for the environments to which they are exposed.'Review of the MNGP pipe support and MC component support drawings whereLubrite or similar material was used reveals that the sliding surfaces are sandwiched between plates, and therefore, inaccessible for inspection. Plant specific operating experience found no evidence of age-related degradation for Lubrite or similar material during support overhaul activities, and no pipe or pipe support failures attributed to the inability of sliding surface material to function asdesigned.

3-294However, the applicant stated that aging effects for lubrite or similar materials are notsignificant, and although no aging management is required, the ASME Section XI, Subsection IWF Program inspects the supports in LRA Table 3.5.2-6 incorporating the use of lubrite or similar materials.The staff's review found the applicant's response to RAI 3.5.2-9 acceptable. The staffrecognized the operating experience with the use of lubrite bearings and found the applicant's approach to inspect them under its ASME Section XI, Subsection IWF program acceptable.

Therefore, the staff's concern described in RAI 3.5.2-9 is resolved.On the basis of its review of the applicant's programs, aging effects, and plant-specific andindustry operating experience, the staff determined that the ASME Section XI, Subsection IWFProgram effectively manages the loss of material due to MIC, pitting, and crevice corrosion of stainless steel materials for supports for ASME Code Class MC components (i.e., vent header column support pins exposed to treated water environment), as given in LRA Table 3.5.2-6.3.5.2.3.7Structures and Component Supports-HPC Building-Summary of AgingManagement Evaluation-Table 3.5.2-7The staff reviewed LRA Table 3.5.2-7, which summarizes the results of AMR evaluations for theHPC building component groups.All line items in this table are consistent with the GALL Report or are included in the discussionin Section 3.5.2.3 above.3.5.2.3.8Structures and Component Supports-Intake Structure-Summary of AgingManagement Evaluation-Table 3.5.2-8The staff reviewed LRA Table 3.5.2-8, which summarizes the results of AMR evaluations for theintake structure component groups.All line items in this table are consistent with the GALL Report or are included in the discussionin Section 3.5.2.3 above.3.5.2.3.9Structures and Component Supports-Miscellaneous Station Blackout YardStructures-Summary of Aging Management Evaluation-Table 3.5.2-9The staff reviewed LRA Table 3.5.2-9, which summarizes the results of AMR evaluations for themiscellaneous SBO yard structures component groups.All line items in this table are consistent with the GALL Report or are included in the discussionin Section 3.5.2.3 above.3.5.2.3.10Structures and Component Supports-Offgas Stack-Summary of AgingManagement Evaluation-Table 3.5.2-10The staff reviewed LRA Table 3.5.2-10, which summarizes the results of AMR evaluations forthe offgas stack component groups.

3-295In RAI 3.5.2-4, dated September 28, 2005, the staff noted that Table 3.5.2-10 lists below-gradeconcrete (Pedestal) as requiring no AMP. The applicant stated that no AMP is required to manage aging because, as described in Notes 501 and 506, (1) the plant initial licensing basis did not include a program to monitor settlement, (2) no significant settlement has been observed, (3) de-watering systems are not used, and (4) plant documents confirm that theconcrete had an air content between 3 and 6 percent and inspection of concrete in accessible areas found no degradation related to freeze-thaw. The GALL Report recommends that concrete should have a water-to-cement ratio of 0.35-0.45 to ensure no aging degradation related to freeze-thaw; therefore, the staff requested that the applicant verify thewater-to-cement ratio as 0.35-0.45. The staff noted that the applicant's statement isinconsistent with ISG-03, which requires a "Structural Monitoring Program" based on the requirement of 10 CFR 50.65 (Maintenance Rule) for accessible areas and a "plant-specific program for inaccessible areas." The staff raised the same question for below-grade concrete (foundation, walls, slabs, grout) listed in Table 3.5.2-18.In its response, by letter dated October 28, 2005, the applicant stated that the responses toRAIs 3.5.2-1 and 3.5.2-2 are applicable to this question. The staff's review found the applicant'sresponse to RAI 3.5.2-4 acceptable. The staff's evaluation of these responses is described inSER Section 3.5.2.3. Therefore, the staff's concern described in RAI 3.5.2-4 is resolved.3.5.2.3.11Structures and Component Supports-Offgas Storage and CompressorBuilding-Summary of Aging Management Evaluation-Table 3.5.2-11The staff reviewed LRA Table 3.5.2-11, which summarizes the results of AMR evaluations forthe offgas storage and compressor building component groups.All line items in this table are consistent with the GALL Report or are included in the discussionin Section 3.5.2.3 above.3.5.2.3.12Structures and Component Supports-Plant Control and Cable SpreadingStructure-Summary of Aging Management Evaluation-Table 3.5.2-12The staff reviewed LRA Table 3.5.2-12, which summarizes the results of AMR evaluations forthe plant control and cable spreading structure component groups.All line items in this table are consistent with the GALL Report or are included in the discussionin Section 3.5.2.3 above.3.5.2.3.13Structures and Component Supports-Primary Containment-Summary of AgingManagement Evaluation-Table 3.5.2-13The staff reviewed LRA Table 3.5.2-13, which summarizes the results of AMR evaluations forthe primary containment component groups.The applicant proposed to manage loss of material due to MIC, pitting, and crevice corrosion ofstainless steel materials for thermowells exposed to a treated water environment using the Plant Chemistry, Primary Containment In-Service Inspection, and 10 CFR Part 50, Appendix J Programs.

3-296The SER documents the staff's reviews and evaluations of the Plant Chemistry Program, thePrimary Containment In-Service Inspection Program, and the 10 CFR 50, Appendix J Program in Sections 3.0.3.2.19, 3.0.3.1.6, and 3.0.3.2.1, respectively.Pitting of stainless steel components relates primarily to the presence of detrimental ionicspecies like chlorides, fluorides, and sulfates. Crevice corrosion of stainless steel components relates primarily to the presence of significant levels of dissolved oxygen. The Plant Chemistry Program manages these aging effects by ensuring that corrosive ion concentrations do not exceed acceptance limits and that pH remains within an acceptable range. In addition, this program controls the growth of organic substances, thus eliminating MIC.The Primary Containment In-Service Inspection Program specifies visual examination ofaccessible surfaces on the containment pressure-retaining boundary, internal vent system , andsteel components within the torus to detect indications of damage or deterioration that could adversely affect the intended functions of the containment system.The 10 CFR 50, Appendix J Program specifies pneumatic pressure tests and visualexaminations to verify the structural and leak integrity of the primary containment.In RAI 3.5.2-5, dated September 28, 2005, the staff noted that, in describing the intendedfunctions of the three items in Table 3.5.2-13 related to concrete in air/gas, the applicant statedthat one of the intended functions is "non-safety support." Therefore, the staff requested thatthe applicant clarify this characterization in terms of the CLB safety classification as well as in terms of the criteria in 10 CFR 54.4, "Scope," and provide examples of how the components provide nonsafety support.In its response, by letter dated October 28, 2005, the applicant explained:The primary containment in scope concrete components subject to an AMR withthe intended function, 'non-safety support' were identified in Table 2.4.13-1 with AMR results provided in Table 3.5.2-13. Table 2.1-1 of the LRA included the definition as,'Provide structural support to non-safety related components whose failurecould prevent satisfactory accomplishment of any of the required safety related functions.'This component-level intended function was the specific function of thecomponent that suppor ted system-level functions that formed the basis forincluding the primary containment structure within the scope of license renewal.

The scoping methodology utilized by the NMC for the MNGP was consistent withthe guidance provided by the NRC in NUREG-1800 and by the industry inNuclear Energy Institute (NEI) 95-10.In terms of the MNGP CLB, this function was characterized in a license renewaltechnical report as,'The MNGP CLB includes a number of topics that identify NSR SSCscredited for preventive or mitigative functions in support of safe shutdown for 3-297special events (e.g., external floods) or whose failure could preventsatisfactory accomplishment of a Scoping Criterion 1 function (e.g.,

Seismic II/I considerations). Based on a review of the CLB, those topics that meet Scoping Criterion 2 are, High Energy Line Break (HELB)...Flooding Events...Missile Hazards...Overhead Handling Systems...Seismic Interaction.'In terms of 10 CFR 54.4, this function was characterized in a technical report forlicense renewal as,'[Non-safety related] NSR SSCs directly connected to Scoping Criterion 1SSCs: The in-scope boundary for license renewal extends into the NSR portion of the piping and supports up to and including the first equivalent anchor beyond the safety/nonsafety interface. For Monticello, the first equivalent anchor is that point beyond which failure of the piping system willnot prevent the satisfactory accomplishment of the Scoping Criterion 1 function of the connected SSCs.NSR structures attached to, or next to, Scoping Criterion 1 structures are inscope for license renewal if their failure could prevent a Scoping Criterion 1 SSC from performing its intended function.NSR SSCs that are not directly connected to Scoping Criterion 1 SSCs: TheNSR SSCs may be in-scope if their failure could prevent the performance of a Scoping Criterion 1 function.'The license renewal technical report included further discussion on NSR SSCsthat are not directly connected to Scoping Criterion 1 SSCs with detailed information on the identification process of spatial interactions, a process to determine which NSR conduits, trays, junction boxes, and lighting fixtures to consider in scope for license renewal, and the process for determining in scope NSR HVAC ducts and supports.An example of how concrete components provide nonsafety support would be anattachment to the concrete of NSR light fixtures or NSR HVAC duct routed near/above scoping Criteria 1 components.The staff's review found the applicant's response to RAI 3.5.2-5 acceptable. The applicantdescribed the scoping process for NSR components (including the components that function assupports). This description is sufficient to explain the nonsafety characterization of the components, and the staff found the scoping process used in this context acceptable.

Therefore, the staff's concern described in RAI 3.5.2-5 is resolved.In RAI 3.5.2-6, dated September 28, 2005, the staff noted that Table 3.5.2-13 lists severalstructural components (e.g., drywell equipment foundation, bioshield wall, RPV pedestal) under the component type concrete in air/gas. LRA Section 3.5.2.2.1.3 and Note 508 describe andjustify the elevated temperatures around the reactor vessel based on the estimated temperatures in the drywell; therefore, the staff requested that the applicant provide (1) asummary description of the cooling system installed to control the temperatures inside the 3-298drywell and (2) the operating experience related to the effectiveness of the cooling system.Relevant to this request, the staff inquired whether the shield wall temperatures or any other parameter monitored will detect malfunctioning of the cooling system.Furthermore, following the discussion of the elevated temperatures in and around the bioshieldwall in LRA Section 3.5.2.2.1.3, the staff agreed that the concrete properties will not be affectedsignificantly if the actual temperatures around the shield wall remain within the estimated limits;however, additional shrinkage and loss of moisture due to radiation could degrade the concrete in the long term. In this context the staff requested that the applicant summarize the results ofthe last two inspections performed for (1) the bioshield wall, (2) RPV pedestal, (3) anchorages of seismic stabilizer frame, and (4) masonry walls (if any) inside the drywell.In its response, by letter dated October 28, 2005, the applicant provided the followingdiscussion:gggggggggg)Drywell fan coolers are used to control temperatures inside thedrywell. USAR Section 5.2 states that, 'The primary containment ventilating and cooling system consists of four air coolers whichcool the atmosphere to below a 135 F bulk average drywelltemperature during normal plant operation. The drywell atmosphere is circulated through the drywell and the air coolers by fans, and the reactor building closed cooling water system isemployed to remove heat from the air coolers.'hhhhhhhhhh)Plant daily operating data confirms that the general areamaximum normal operating temperature inside drywell is below the NUREG-1801 limit of 150 F. Therefore the drywell fan coolershave proven their effectiveness in controlling the drywell air temperature. Plant calculations determined that the biologicalshield wall pipe penetrations were sufficiently designed in size, insulation characteristics, and air gap to limit the local area maximum normal operating temperatures to 179 F, less than theNUREG-1801 threshold local area temperature of 200 F. iiiiiiiiii)Results of the 1996, 1998 and 2002 Periodic Structural InspectionReports found all concrete at the RPV Pedestal to be acceptable with no deficiencies observed. The bioshield wall is complete encased in steel and therefore cannot be inspected. Drywell structural steel components were found acceptable with no deficiencies observed including stabilizerattachment welds to the plated bioshield wall. USAR Section 12 states that the primary function of the bioshield wall is, 'to protect equipment inside the drywell against radiation and thermal effects. The structure is capable of transmitting loads due to seismic and jet forces acting on it.

The biological shield is composed of two steel cylinders interconnected with 27 WF (177 lb/ft) columns and is filled with concrete. Because of theradiation and temperature effects on the concrete only the lower 12 feet of concrete, up to the 959 foot elevation, has been designed as structural concrete capable of resisting forces and shears. Above the 959 foot elevation the two steel cylinders and 27 WF columns are structurally 3-299adequate and the concrete fill has not been considered as adding to thesupport.'The staff's review found the applicant's response to RAI 3.5.2-6 acceptable. The responseadequately describes the temperatures in the drywell and the effectiveness of the coolingsystem in keeping temperatures within the threshold limits. The response also describes thecondition of the vital concrete and structural components in the drywell. The staff found the applicant's method of cooling the drywell atmosphere and monitoring the structural componentsin the drywell acceptable; therefore, the staff's concern described in RAI 3.5.2-6 is resolved.In RAI 3.5.2-10, dated September 28, 2005, the staff noted that a recent breakage ofT-quencher support bolts at the Edwin I. Hatch plant indicated that the Plant ChemistryProgram that controls the chemistry of treated water may not be adequate for managing theaging of submerged support components; therefore, the staff requested that the applicantaddress the adequacy of the Plant Chemistry Program alone to manage the aging degradation of the submerged supports. The staff further noted that this RAI applies to all line items in Table 3.5.2-13 identifying the Plant Chemistry Program as the sole AMP.In its response, by letter dated October 28, 2005, the applicant confirmed the following:All line items in Table 3.5.2-13 in a treated water environment (submerged) aremanaged by the Plant Chemistry Program, in addition to the MNGP Primary Containment In-Service Inspection Program, and in many cases, are also managed by a third program, 10 CFR 50, Appendix J. Therefore, the applicant asserted this RAI is not applicable to MNGP.Additionally, the MNGP Primary Containment In-Service Inspection Programincludes activities that perform periodic visual inspections by divers (when the torus is not drained) and by engineers (when drained) for submerged components, including their support members, bolted connections, and welds.

Components inspected include such items as T-quenchers, SRV piping and supports, ECCS strainers, vent header supports, catwalk supports, and other submerged piping and supports not included in the IWE, VT-3 inspection.

Inspections are conducted periodically at intervals not to exceed five (5) years.

The MNGP Primary Containment In-Service Inspection Program manages aging effects for visible degradation such as deformation, cracks, corrosion, loosebolts, etc.The staff's review found the applicant's response to RAI 3.5.2-10 acceptable. The responseindicates that the applicant plans to use the Primary Containment In-Service InspectionProgram and the 10 CFR Part 50, Appendix J Program, as appropriate, for managing aging of components in these line items. The staff found the applicant's approach to managing the aging of these components acceptable; therefore, the staff's concern described in RAI 3.5.2-10 isresolved.In RAI 3.5.2-11, dated September 28, 2005, the staff noted that for a number of items inTable 3.5.2-13, the applicant identified the 10 CFR Part 50, Appendix J Program as the AMP tomanage aging. Option B of Appendix J will permit the applicant to conduct Type B leakage ratetests of penetrations at 10-year intervals; therefore, the staff requested that the applicant 3-300address the plant-specific process (e.g., test frequency and operating experience) credited withmanaging degradation and leak tightness of the pressure boundary penetrations, including vent bellows.In its response, by letter dated October 28, 2005, the applicant stated the following:Type B tests, which are conducted at performance-based intervals not exceeding120 months (plus an extension of 15 months if required by the refueling schedule), are performed to assess leakage through individual penetration isolation barriers other than valves. Pursuant to NEI 94-01, air lock tests must be performed at intervals not exceeding 30 months and at other times as determined by air lock use. Also, bolted access-way cover seals are always tested following end-of-outage closures of the access-ways. The default interval between Type B tests is 30 months. The interval may be extended to 60 months following two (2) consecutive tests with results that meet performance leakage acceptance criteria and to 120 months following three (3) consecutive tests that meet these criteria. The interval reverts to the default interval following a test failure.The MNGP operating history on bellow leakage/replacement is limited to one,2-ply bellow. Leakage was identified during LLRT and not a result of cracks observed during a visual examination. Leakage was identified at the outer-mostbellows from a small failure underneath the outer collar of the expansion joint and consequently the bellow was replaced. No cracks in the weld metal wereidentified. Industry operating history has also identified cracked bellows, but no cracks in the weld metal.The staff's review found the applicant's response to RAI 3.5.2-11 acceptable. The operatinghistory of the penetrations and vent bellows demonstrates that the applicant applies CLBrequirements for leak-rate testing of these pressure-retaining components; therefore, the stafffound the approach used by the applicant in ensuring the leak tightness of these componentsacceptable, and the staff's concern described in RAI 3.5.2-11 is resolved.In RAI 3.5.2-12, dated September 28, 2005, the staff noted that three line items inTable 3.5.2-13 indicate that lubrite plates had been used at several locations in the primarycontainment. In Note 556, the applicant stated that graphite plate material is not used fordrywell head and downcomers; therefore, the staff requested that the applicant clarify howlubrite plates were used for drywell head and downcomers. In Note 559, the applicant stated that beam seats in the drywell consist of carbon steel plate over a bronze plate lubricated withgraphite packed into trepanned depressions. The steel plate covers the graphite packing and protects it from particulate contaminants. The staff believes that if the lubrite bearing is qualified generally for use in the sustained temperatures and radiation existing in the drywell, the accessible part of the bearing should be inspected to ensure proper functioning during postulated environmental conditions. The staff requested the applicant to incorporate anexamination of the accessible portion of the lubrite bearings in an appropriate AMP.In its response, by letter dated October 28, 2005, the applicant stated the following:

3-301Lubrite type material is not used for the drywell head or downcomers.Table 3.5.2-13 line entry was necessary to demonstrate that aging effects in NUREG-1801 line item II.B1.1.1-e were evaluated. The evaluation provided inTable 3.5.2-13, note 556 stated that, 'The drywell head and downcomer pipesare carbon steel material. Graphite plate material is not used for these components and therefore the aging effect is not applicable.'NUREG-1801 line item II.B1.1.1-e also includes fretting due to mechanical wearof carbon steel. EPRI-1002950, Structural Tools, evaluated fretting as loss of material occurring as a result of the relative motion between two components.

EPRI concluded that thermal cycling during plant heat-up, cool down (refuelingoperations) and normal operation have insufficient relative motion and frequency to result in significant wear. EPRI concluded that wear of carbon steel is a design issue that incorporates sliding surfaces into the design. In accordance with the EPRI evaluation, the drywell head and downcomers do not require aging management for fretting. Note that the drywell head and downcomers are managed for loss of material due to corrosion consistent with NUREG-1801line II.B1.1.1-a. See Table 3.5.2-13 for this evaluation.On the subject of lubrite plates, the applicant explained the following:Lubrite material incorporated into radial beam seat connections is used insidedrywell to connect platform steel to the drywell shell. The beam seat Lubrite plate is sandwiched between larger steel plates which overhang it, and therefore, inspection is not possible. These beam seats are well over 20 feet from the reactor pressure vessel and outside the bioshield wall. This is the only application of Lubrite type material in use inside the drywell where the higher gamma radiation levels are expected. According to EPRI-1002950 the only aging effect for Lubrite is change in material properties, and only if Lubrite is exposed to at least 10 4 Rads. Radiation levels outside the bioshield wall at the perimeterof the drywell would be significantly less that the EPRI threshold limit. All other Lubrite type material applications are outside the drywell where radiation levels would typically be significantly less than inside the drywell.The staff's review found the applicant's response to RAI 3.5.1-12 acceptable. The applicantclarified its intention and approach in managing the line item components. The staff found the applicant's aging management of lubrite materials acceptable; therefore, the staff's concerndescribed in RAI 3.5.2-12 is resolved.The staff's review of the applicant's programs, the aging effects, and plant-specific and industryoperating experience determined that the Plant Chemistry Program, the Primary ContainmentIn-Service Inspection Program, and the 10 CFR Part 50, Appendix J Program effectively manage the aging effect of loss of material due to MIC, pitting, and crevice corrosion of stainless steel material exposed to a treated water environment. On this basis, the staff found the applicant's management of loss of material due to MIC, pitting, and crevice corrosion in primary containment acceptable.

3-3023.5.2.3.14Structures and Component Supports-Radioactive Waste Building-Summary ofAging Management Evaluation-Table 3.5.2-14The staff reviewed LRA Table 3.5.2-14, which summarizes the results of AMR evaluations forthe radioactive waste building component groups.All line items in this table are consistent with the GALL Report or are included in the discussionin Section 3.5.2.3 above.3.5.2.3.15Structures and Component Supports-Reactor Building-Summary of AgingManagement Evaluation-Table 3.5.2-15The staff reviewed LRA Table 3.5.2-15, which summarizes the results of AMR evaluations forthe reactor building component groups.The staff also reviewed LRA Section 3.5.2.1.15, which identifies the materials, environments,AERMs, and AMPs for the reactor building component group. The staff conducted its review, described below, in accordance with SRP-LR Section 3.5 and the GALL Report.The applicant has proposed to manage the reduction of neutron absorbing capacity and loss ofmaterial due to corrosion of boral with the Plant Chemistry Program in conjunction with a one-time inspection.The applicant stated that the Plant Chemistry Program manages the aging effects of boral in atreated water environment due to crevice, galvanic, and pitting corrosion and MIC, and the aging effect of cracking due to SCC, by ensuring that corrosive ion concentrations do not exceed acceptable limits and by limiting the amount of impurities in the water. The applicant further stated that plant test results and industry experience indicate that use of the PlantChemistry Program during the period of extended operation will continue to manage the loss ofneutron absorption capacity aging effect effectively. The applicant will apply the One-TimeInspection Program for added assurance that aging effects do not occur.The staff's review of LRA Table 3.5.2-15 and LRA Section 3.5.2.1.15 identified areas in whichthe staff needed additional information to complete its evaluation of the applicant's results. The applicant responded to the staff's RAIs as discussed below.In RAI 3.5.2.1.15-1, dated August 18, 2005, the staff requested that the applicant providedetails of the plant's Boral Coupon Surveillance Program.In its response, by letter dated September 16, 2005, the applicant stated the following:...The program placed seven sets of coupons in the fuel pool to be removed on aperiodic basis and tested for degradation. To date, six of the seven coupon sets have been removed and tested and no degradation has been found (see response to RAI 3.5.2.1.15-3 for test results). Testing methods include physical observations; neutron attenuation tests; weight, specific gravity, dimensional checks; and analysis for boron content. The final (seventh) coupon set will beremoved and tested before the period of extended operation to satisfy the requirement for a one-time inspection. No further testing is proposed during the 3-303period of extended operation pending acceptable results from the finalinspection.The applicant based its election not to continue coupon testing into the period of extendedoperation partly on the results of the six previously tested coupons, which represent over 20 years of operating experience.In response to staff RAI 3.5.2.1.15-3, dated September 16, 2005, the applicant provided testresults for the past coupon inspections indicating that all coupons have retained the required level of neutron absorption capability with no discernable degradation.The staff needed additional information to complete its evaluation for the aging management ofboral. The applicant will not test boral coupons into the period of extended operation. For thisreason, the staff requested that the applicant provide details on its ability to identify a potentialaging effect in the plant's boral. Because the applicant will not test actual boral samples, it must provide assurance that it will be able to identify and mitigate any degradation of boral over theperiod of extended operation.In a supplemental response, dated November 17, 2005, the applicant stated that it will removethe unclad coupon in the final (seventh) coupon set from the pool and visually examine it before the period of extended operation to satisfy the requirement for a one-time inspection. The applicant will return the unclad coupon to the spent fuel pool immediately following the visualexamination, and the entire set of coupons will remain in the spent fuel pool until they areremoved for surveillance testing sometime during the period of extended operation.The applicant's operating experience indicates that it is unlikely that the final boral coupon setwill exhibit degradation if tested before the period of extended operation. The applicantmaintains that the final coupon set will provide greater assurance of boral performance if it istested during the period of extended operation. The applicant's visual inspection of the uncladcoupon will satisfy the requirement for a one-time inspection and will provide additionalassurance that the boral has not experienced significant degradation since the examination ofthe last coupon set.The staff found the applicant's response to RAI 3.5.2.1.15-3 acceptable based on the conductof a one-time inspection of the remaining coupon to determine if there is any unacceptable degradation of the neutron absorption capability. Therefore, the staff's concern described inRAI 3.5.2.1.15-3 is resolved.In RAI 3.5.2.1.5-3, dated August 18, 2005, the staff noted that LRA Tables 3.5.2-15 and3.5.2-17 refer to the Structures Monitoring Program as the AMP to manage aging effects for rigid board (thermal insulating board) in an air/gas environment; therefore, the staff requested that the applicant justify this conclusion.In its response, by letter, dated September 16, 2005, the applicant stated the following:LRA Tables 3.5.2-15 and 3.5.2-17 refer to the Structures Monitoring Program asthe AMP for managing the aging effects for gypsum board walls (rigid board) with fire barrier and HELB barrier intended functions in an air/gas environment.

The scope of the Structures Monitoring Program described in the Structures 3-304Monitoring Program PBD/AMP-027, Table 7.1 includes rigid board with the agingeffect loss of material in an air/gas environment. This is consistent with LRA Tables 3.5.2-15 and 3.5.2-17.Since gypsum board walls perform fire barrier and HELB intended functions,both the Structures Monitoring Program and the Fire Protection Program willmanage the aging effects, ensuring the intended functions will be maintainedconsistent with the CLB for the period of extended operation.The staff's review found the applicant's response to RAI 3.5.2.1.5-3 acceptable because thescope of the Fire Protection Program in PBD/AMP-013, Table 7.1, includes gypsum board walls (rigid board) with fire barrier and HELB barrier intended functions in an air/gas environment.

The staff's review of the applicant's Fire Protection Program, including PBD/AMP-013, Table 7.1, found that components of the FP system will be managed for aging effects duringthe period of extended operation. The applicant also stated that both the Structures MonitoringProgram and the Fire Protection Program will manage the aging effect of gypsum board walls;therefore, the staff's concern described in RAI 3.5.2.1.5-3 is resolved.The staff's review of the applicant's programs, the aging effects, and the plant-specific andindustry operating experience determined that the applicant adequately identified applicableaging effects and the AMPs credited with managing them for the reactor building component group not addressed by the GALL Report. The staff found the applicant's AMR results for the reactor building component group acceptable.3.5.2.3.16Structures and Component Supports-Structures Affecting Safety-Summary ofAging Management Evaluation-Table 3.5.2-16The staff reviewed LRA Table 3.5.2-16, which summarizes the results of AMR evaluations forthe structures affecting safety component groups.All line items in this table are consistent with the GALL Report or are included in the discussionin Section 3.5.2.3 above.3.5.2.3.17Structures and Component Supports-Turbine Building-Summary of AgingManagement Evaluation-Table 3.5.2-17The staff reviewed LRA Table 3.5.2-17, which summarizes the results of AMR evaluations forthe turbine building component groups.The staff also reviewed LRA Section 3.5.2.1.17, which identifies the materials, environments,AERMs, and AMPs for the turbine building component group. The staff conducted its review, described below, in accordance with SRP-LR Section 3.5 and the GALL Report.As discussed in the resolution to RAI 3.5.2.1.5-3, the staff found that the Structures MonitoringProgram will properly manage the aging effects for gypsum board walls (rigid board) in anair/gas environment.The staff's review of the applicant's programs, the aging effects, and the plant-specific andindustry operating experience determined that the applicant adequately identified applicable 3-305aging effects and the AMPs credited with managing them for the turbine building componentgroup not addressed by the GALL Report. The staff found the applicant's AMR results for the turbine building component group acceptable.3.5.2.3.18Structures and Component Supports-Underground Duct Bank-Summary of AgingManagement Evaluation-Table 3.5.2-18The staff reviewed LRA Table 3.5.2-18, which summarizes the results of AMR evaluations forthe underground duct bank component groups.All line items in this table are consistent with the GALL Report or are included in the discussionin Section 3.5.2.3 above.Conclusion. On the basis of its review, the staff found that the applicant appropriately evaluatedAMR results involving material, environment, AERMs, and AMP combinations that are not evaluated in the GALL Report. The staff found that the applicant has demonstrated that theeffects of aging will be adequately managed so that the intended functions will be maintainedconsistent with the CLB for the period of extended operation, as required by10 CFR 54.21(a)(3).3.5.3 Conclusion The staff concluded that the applicant provided sufficient information to demonstrate that theeffects of aging for the containments, structures, and component supports system componentsthat are within the scope of license renewal and subject to an AMR will be adequately managedso that the intended functions will be maintained consistent with the CLB for the period ofextended operation, as required by 10 CFR 54.21(a)(3).The staff also reviewed the applicable USAR supplement program summaries and concludedthat they adequately describe the AMPs credited with managing aging of the containments,structures, and component supports, as required by 10 CFR 54.21(d).3.6 Aging Management of Electrical and Instrumentation and ControlsThis section of the SER documents the staff's review of the applicant's AMR results for theelectrical and instrumentation and controls (I&C) components associated with the following:

  • fuse holders commodity group
  • non-environmental qualification (EQ) cables and connections commodity group
  • offsite power/SBO recovery path commodity group3.6.1 Summary of Technical Information in the Application In LRA Section 3.6, the applicant provided AMR results for the electrical and I&C components.In LRA Table 3.6.1, the applicant provided a summary comparison of its AMRs with the AMRs evaluated in the GALL Report for the electrical and I&C components.

3-306The applicant's AMRs incorporated applicable operating experience in the determination ofAERMs. These reviews included evaluation of plant-specific and industry operating experience.

The plant-specific evaluation included reviews of CRs and discussions with appropriate site personnel to identify AERMs. The applicant's review of industry operating experience included a review of the GALL Report and operating experience issues identified since the issuance of the GALL Report.3.6.2 Staff Evaluation The staff reviewed LRA Section 3.6 to determine if the applicant provided sufficient informationto demonstrate that the effects of aging for the electrical and I&C components that are withinthe scope of license renewal and subject to an AMR will be adequately managed so that theintended functions will be maintained consistent with the CLB for the period of extendedoperation, as required by 10 CFR 54.21(a)(3).In addition, the staff performed an onsite audit of AMRs to confirm the applicant's claim thatcertain identified AMRs are consistent with the GALL Report. The staff did not repeat its reviewof the matters described in the GALL Report; however, the staff did verify that the material presented in the LRA is applicable and that the applicant identified the appropriate GALLReport AMRs. SER Section 3.0.3 documents the staff's evaluations of the AMPs. The MNGP audit and review report details the staff's audit evaluation, summarized in SER Section 3.6.2.1.The staff also performed an onsite audit of those selected AMRs that are consistent with theGALL Report and for which further evaluation is recommended. The staff confirmed that the applicant's further evaluations are consistent with the acceptance criteria in SRP-LR Section 3.6.2.2. The MNGP audit and review report documents the staff's audit evaluations,summarized in SER Section 3.6.2.2.The staff performed an onsite audit and conducted a technical review of the remaining AMRsthat are not consistent with, or not addressed in, the GALL Report. The audit and technicalreview included evaluating whether the applicant identified all plausible aging effects and whether the aging effects listed are appropriate for the combination of materials and environments specified. The MNGP audit and review report documents the staff's audit evaluations. SER Section 3.6.2.3 summarizes the staff's audit evaluations and documents thestaff's technical review.Finally, the staff reviewed the AMP summary descriptions in the USAR supplement to ensurethat they adequately describe the programs credited with managing or monitoring aging for theelectrical and I&C components.Table 3.6-1 below summarizes the staff's evaluation of components, aging effects/mechanisms,and AMPs listed in LRA Section 3.6 that are addressed in the GALL Report.

3-307Table 3.6-1 Staff Evaluation for Electrical and Instrumentation and Controls Componentsin the GALL ReportComponent GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff EvaluationElectricalequipment subjectto 10 CFR 50.49environmentalqualification (EQ)requirements(Item Number3.6.1-01)Degradation due tovarious agingmechanismsEnvironmentalqualification ofelectric componentsTLAAThis TLAA isevaluated in Section4.7, EnvironmentalQualification ofElectricalEquipment (EQ)Electrical cablesand connections notsubject to10 CFR 50.49 EQrequirements(Item Number3.6.1-02)Embrittlement,cracking, melting,discoloration,swelling, or loss ofdielectric strengthleading to reducedinsulationresistance (IR);electrical failurecaused by thermal/thermoxidativedegradation oforganics; radiolysisand photolysis[ultraviolet (UV)sensitive materialsonly] of organics;radiation-inducedoxidation; moistureintrusionAging managementprogram forelectrical cablesand connections notsubject to10 CFR 50.49 EQrequirementsElectrical Cables &Connections NotSubject to10 CFR 50.49EnvironmentalQualificationRequirementsProgram (B2.1.15)Consistent withGALL Report, whichrecommends nofurther evaluationElectrical cablesused ininstrumentationcircuits not subjectto 10 CFR 50.49EQ requirementsthat are sensitive toreduction inconductor insulationresistance (IR)(Item Number3.6.1-03)Embrittlement,cracking, melting,discoloration,swelling, or loss ofdielectric strengthleading to reducedIR; electrical failurecaused by thermal/thermoxidativedegradation oforganics;radiation-inducedoxidation; moistureintrusionAging managementprogram forelectrical cablesused ininstrumentation circuits not subjectto 10 CFR 50.49EQ requirementsElectrical CablesNot Subject to10 CFR 50.49EnvironmentalQualificationRequirements Usedin InstrumentationCircuits Program(B2.1.16) Consistent withGALL Report, whichrecommends nofurther evaluation Component GroupAging Effect/MechanismAMP in GALLReportAMP in LRAStaff Evaluation3-308Inaccessiblemedium-voltage(2 kV to 15 kV)cables (e.g.,installed in conduitor direct buried) notsubject to10 CFR 50.49 EQrequirements(Item Number3.6.1-04)Formation of watertrees, localizeddamage leading toelectrical failure(breakdown ofinsulation), watertress caused bymoisture intrusionAging managementprogram forinaccessiblemedium-voltagecables not subjectto 10 CFR 50.49EQ requirementsInaccessibleMedium Voltage(2kV to 34.5kV)Cables Not Subjectto 10 CFR 50.49EQ RequirementsProgram (B2.1.21 ) Consistent withGALL Report, whichrecommends nofurther evaluationElectricalconnectors notsubject to10 CFR 50.49 EQrequirements thatare exposed toborated waterleakage(Item Number3.6.1-05)Corrosion ofconnector contactsurfaces caused byintrusion of boratedwaterBoric acid corrosionNot applicable,PWR onlyThe staff's review of the MNGP component groups followed one of several approaches. Oneapproach, documented in SER Section 3.6.2.1, involves the staff's review of the AMR resultsfor electrical and I&C components that the applicant indicated are consistent with the GALLReport and do not require further evaluation. Another approach, documented in SERSection 3.6.2.2, involves the staff's review of the AMR results for electrical and I&C componentsthat the applicant indicated are consistent with the GALL Report and for which furtherevaluation is recommended. A third approach, documented in SER Section 3.6.2.3, involves thestaff's review of the AMR results for electrical and I&C components that the applicant indicated are not consistent with, or not addressed in, the GALL Report. SER Section 3.0.3 documentsthe staff's review of AMPs that are credited to manage or monitor aging effects of the electrical and I&C components.3.6.2.1 AMR Results That Are Consistent with the GALL Report Summary of Technical Information in the Application. In LRA Section 3.6.2.1, the applicantidentified the materials, environments, and AERMs. The applicant identified the following programs that manage the aging effects related to the electrical and I&C components:

  • Bus Duct Inspection Program (B2.1.6)
  • Electrical Cables & Connections Not Subject to 10 CFR 50.49 EnvironmentalQualification Requirements Program (B2.1.15)
  • Electrical Cables Not Subject to 10 CFR 50.49 Environmental QualificationRequirements Used in Instrumentation Circuits Program (B2.1.16)
  • Inaccessible Medium Voltage (2kV to 34.5kV) Cables Not Subject to 10 CFR 50.49 EQRequirements Program (B2.1.21 )

3-309Staff Evaluation. In LRA Tables 3.6.2-1 through 3.6.2-4, the applicant summarized the AMRsfor the electrical and I&C components and identified which AMRs it considered to be consistent with the GALL Report.For component groups evaluated in the GALL Report for which the applicant has claimedconsistency with the GALL Report, and for which the GALL Report does not recommend further evaluation, the staff performed an audit and review to determine whether the GALL Reportevaluation bounds the plant-specific components contained in these GALL Report componentgroups.The applicant provided a note for each AMR line item. The notes describe how the informationin the tables aligns with the information in the GALL Report. The staff audited those AMRs with Notes A through E, which indicate that 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 AMP identified in the GALL Report. The staff audited these line items to verify consistency with the GALL Report and the validity of the AMR for the site-specific conditions.Note B 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 AMP identified in the GALL Report. The staff audited these line items to verify consistency with the GALL Report. The staff verified that it had reviewed and accepted the identified exceptionsto the GALL Report AMPs. The staff also determined whether the AMP identified by the applicant is consistent with the AMP identified in the GALL Report and whether the AMR is validfor the site-specific conditions.Note C indicates that the component for the AMR line item, although different, is consistent withthe GALL Report for material, environment, and aging effect. In addition, the AMP is consistent with the AMP identified by the GALL Report. This note indicates that the applicant could not finda listing of some system components in the GALL Report; however, the applicant identified adifferent component in the GALL Report that has 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 determined whether the AMR line item of the different component applies to the component under review and whether the AMR is valid for the site-specific conditions.Note D indicates that the component for the AMR line item, although different, is consistent withthe GALL Report for material, environment, and aging effect. In addition, the AMP takes some exceptions to the AMP identified in the GALL Report. The staff audited these line items to verify consistency with the GALL Report. The staff verified whether the AMR line item of the different component applies to the component under review. The staff verified whether it had reviewed and accepted the identified exceptions to the GALL Report AMPs. The staff also determinedwhether the AMP identified by the applicant is consistent with the AMP identified in the GALLReport and whether the AMR is 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 the applicant credited a different AMP. The staff audited 3-310these line items to verify consistency with the GALL Report. The staff also determined whetherthe identified AMP will manage the aging effect consistent with the AMP identified by the GALLReport and whether the AMR is valid for the site-specific conditions.The staff conducted an audit and review of the information provided in the LRA, as documentedin the MNGP audit and review report. The staff did not repeat its review of the matters described in the GALL Report; however, the staff did verify that the material presented in the LRA is applicable and that the applicant identified the appropriate GALL Report AMRs.The staff reviewed the LRA to confirm that the applicant (1) provided a brief description of thesystem, components, materials, and environment; (2) stated that the GALL Report reviewed theapplicable aging effects, and (3) identified those aging effects for the electrical and I&C components that are subject to an AMR. On the basis of its audit and review the staff determined that, for AMRs not requiring further evaluation, as identified in LRA Table 3.6.1, theapplicant's references to the GALL Report are acceptable and no further staff review is required.Conclusion. The staff evaluated the applicant's claim of consistency with the GALL Report. Thestaff also reviewed information pertaining to the applicant's consideration of recent operating experience and proposals for managing associated aging effects. The staff's review concluded that the AMR results, which the applicant claimed to be consistent with the GALL Report, areconsistent with the AMRs in the GALL Report. Therefore, the staff concluded that the applicanthas demonstrated that the effects of aging for these components will be adequately managedso that their intended functions will be maintained consistent with the CLB for the period ofextended operation, as required by 10 CFR 54.21(a)(3).3.6.2.2AMR Results That Are Consistent with the GALL Report, for Which Further EvaluationIs RecommendedSummary of Technical Information in the Application. In LRA Section 3.6.2.2, the applicantprovided further evaluation of aging management as recommended by the GALL Report for the electrical and I&C components. The applicant provided information concerning how it willmanage the aging effects in electrical equipment subject to EQ.Staff Evaluation. For component groups evaluated in the GALL Report for which the applicanthas claimed consistency with the GALL Report, and for which the GALL Report recommends further evaluation, the staff audited and reviewed the applicant's evaluation to determinewhether it adequately addresses the issues that were further evaluated. In addition, the staffreviewed the applicant's further evaluations against the criteria contained in SRP-LR Section 3.6.2.2. The staff's audit and review report details the staff's audit. The following sections discuss the staff's evaluation of the aging effects.3.6.2.2.1 Electrical Equipment Subject to Environmental QualificationIn LRA Section 3.6.2.2.1, the applicant stated that EQ 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 4.7 documents the staff's review of the applicant's evaluation of this TLAA.

3-311Conclusion. On the basis of its review, for component groups evaluated in the GALL Report forwhich the applicant has claimed consistency with the GALL Report, and for which the GALL Report recommends further evaluation, the staff determined that the applicant adequatelyaddressed the issues that were further evaluated. The staff found that the applicant hasdemonstrated that the effects of aging will be adequately managed so that the intendedfunctions will be maintained consistent with the CLB for the period of extended operation, asrequired by 10 CFR 54.21(a)(3).3.6.2.3 AMR Results That Are Not Consistent with or Not Addressed in the GALL ReportSummary of Technical Information in the Application. In LRA Tables 3.6.2-1 through 3.6.2-4,the staff reviewed additional details of the results of the AMRs for material, environment, AERM, and AMP combinations that are not consistent with the GALL Report, or that are notaddressed in the GALL Report.In LRA Tables 3.6.2-1 through 3.6.2-4, the applicant indicated, via Notes F through J, that thecombination of component type, material, environment, and AERM does not correspond to a line item in the GALL Report and provided information concerning how it will manage the agingeffect. Specifically, Note F indicates that the GALL Report does not evaluate the material for the AMR line item component. Note G indicates that the GALL Report does not evaluate the environment for the AMR line item component and material. Note H indicates that the GALL Report does not evaluate the aging effect for the AMR line item component, material, and environment combination. Note I indicates that the aging effect identified in the GALL Report forthe line item component, material, and environment combination is not applicable. Note J indicates that the GALL Report does not evaluate either the component or the material andenvironment combination for the line item.Staff Evaluation. For component type, material, and environment combinations that are notevaluated in the GALL Report, the staff reviewed the applicant's evaluation to determinewhether the applicant demonstrated that the effects of aging will be adequately managed sothat the intended functions will be maintained consistent with the CLB during the period ofextended operation. The following sections discuss the staff's evaluation.In LRA Tables 3.6.2-1 through 3.6.2-4, the applicant identified AMR line items for which theaging review process identified no aging effects. The applicant stated that it identified no agingeffects for components fabricated from the materials and exposed to the environments described below.3.6.2.3.1Electrical Components-Electrical Penetrations Commodity Group-Summary ofAging Management Evaluation-Table 3.6.2-1The staff reviewed LRA Table 3.6.2-1, which summarizes the results of AMR evaluations for theelectrical penetrations commodity group component groups.In LRA Table 3.6.2-1, the applicant stated that no aging effects occur when componentsfabricated from epoxy, fiberglass, and hypalon paint material are exposed to heat, radiation, and moisture environment. The applicant further stated that GE supplied the non-EQ penetrations and that they are manufactured and tested to the same specifications as the GE-supplied EQ penetrations.

3-312The materials subject to aging that are installed in the penetrations are epoxy, fiberglass, andhypalon paint. The applicant evaluated these materials as part of the EQ calculation associatedwith GE penetrations. Fiberglass is a spun glass inert material not susceptible to significant thermal degradation. Of the two organic materials, epoxy and hypalon paint, epoxy is considered more susceptible to radiation effects. In accordance with the applicant's EQ calculation, the lifetime of these two materials exceeds the required 60-year service life.Because the evaluated temperature and radiation levels of the organic materials exceed thoseto which the materials are actually exposed (service conditions for the drywell are 135 F and1.58x10 7 Rads), the materials are shown to have an expected lifetime in excess of 60 years.When a component's expected lifetime exceeds its intended service life, there are no agingeffects which require management because the component remains capable of performing its intended function; therefore, no aging effects are considered applicable to components fabricated from epoxy, fiberglass, and hypalon paint material exposed to heat, radiation, and moisture environments.The staff's review of the applicant's programs, the aging effects, and the plant-specific andindustry operating experience determined that heat, radiation, or moisture on epoxy, fiberglass, and hypalon paint will not result in aging that will be of concern during the period of ext endedoperation. Therefore, the staff concluded that epoxy, fiberglass, and hypalon paint componentsexposed to a heat, radiation, and moisture environment have no applicable AERMs and that the applicant has demonstrated that the effects of aging will be adequately managed so that theintended functions will be maintained during the period of extended operation, as required by10 CFR 54.21(a)(3).3.6.2.3.2Electrical Components-Fuse Holders Commodity Group-Summary of AgingManagement Evaluation-Table 3.6.2-2The staff reviewed LRA Table 3.6.2-2, which summarizes the results of AMR evaluations for thefuse holders commodity group component groups.In LRA Table 3.6.2-2, the applicant identified AMR line items for which the aging review processidentified no aging effects. Specifically, the applicant stated that it identified no aging effects for(1) components fabricated from various insulating materials (e.g., Phenolic or Melamine) exposed to heat and radiation environments and (2) components fabricated from copper, brass, and steel material exposed to thermal cycling, vibration, electrical transients, mechanicalstresses, corrosion, chemical contamination, and oxidation environments.Components Fabricated from Various Insulating Materials such as Phenolic or MelamineExposed to Heat or Radiation. The average temperature where fuse holders are located is 85 F and the radiation exposure is 1.11x10 5 Rads. These temperature and radiation levels areless than the insulating material 60-year service-limiting temperature of 205 F and radiationdose of 5x10 7 Rads. Operating experience demonstrates no aging effect when insulatingmaterials such as Phenolic or Melamine are exposed for 60 years at a service-limiting temperature of 205 F and radiation dose of 5x10 7 Rads. No aging effects are consideredapplicable for components fabricated from various insulating materials (e.g., Phenolic or Melamine) exposed to heat and radiation environments.On the basis of its review of current industry research and operating experience, the staff foundthat heat and radiation on various insulating materials like Phenolic or Melamine will not result 3-313in aging that will be of concern during the period of extended operation. The applicant's fuseholders are not exposed to temperatures at which operating experience demonstrates aging effects of embrittlement, cracking, melting, or discoloration; therefore, the staff concluded thatinsulating materials such as Phenolic or Melamine exposed to heat and radiation environments have no applicable AERMs.Components Fabricated from Copper, Brass, and/or Steel Exposed to Thermal Cycling,Vibration, Electrical Transients, Mechanical Stress, Corrosion, Chemical Contamination, orOxidation.Effect of thermal cycling-Thermal cycling is an aging effect associated with power circuitoperations. Operating low-current fuse holders below the design-current rating will eliminate theaging effect of thermal cycling. Typically, control fuse holders are rated far in excess of the fuse rating. The fuse will limit the current to values well below the rating of the fuse holder. The low current values experienced by control circuits typically do not create thermal cycling effects. No aging effects are considered to apply to components fabricated from copper, brass, and/or steel material exposed to a thermal cycling environment.On the basis of its review of current industry research and operating experience, the staff foundthat thermal cycling on copper, brass, and/or steel will not result in aging that will be of concernduring the period of extended operation. Fuse holders at MNGP are low current, and operatingexperience shows that low currents do not create thermal cycling effects; therefore, the staffconcluded that copper, brass, and/or steel components exposed to a thermal cyclingenvironment have no applicable AERMs.Effect of vibration-Vibration is a result of rapid mechanical movement about a specific point atan elevated frequency. Fuse holders at MNGP are mounted on rigid walls and are not subject to vibration. No aging effects are considered applicable to components fabricated from copper, brass, and/or steel material exposed to a vibration environment.On the basis of its review of current industry research and operating experience, the staff foundthat vibration on the fuse holder's metallic clamp fabricated from copper, brass, and/or steel willnot result in aging that will be of concern during the period of extended operation. Fuse holdersat MNGP are mounted on rigid walls and not subject to vibration; therefore, the staff concludedthat copper, brass, and/or steel components exposed to a vibration environment have noAERMs.Effect of electrical transients-Electrical transients of power applications (i.e., large-surgecurrent transformers and power cables) create aging effects. These transients affect the insulation of the device and if sufficiently frequent may weaken the insulation over time. Fuse holders subject to an AMR at MNGP provide electrical power to fire detection components.

These components are low-voltage and low-current applications. No aging effects are considered applicable to components fabricated from copper, brass, and/or steel material exposed to electrical transients.On the basis of its review of current industry research and operating experience, the staff foundthat electrical transients on copper, brass, and/or steel will not result in aging that will be ofconcern during the period of extended operation. Electrical transients in the low-currentapplication of fuse holders at MNGP are not sufficient to cause aging effects; therefore, the 3-314staff concluded that copper, brass, and/or steel components exposed to an electrical transientenvironment have no applicable AERMs.Effect of mechanical stress-Frequent manipulation is a result of removing and reinstalling thefuse from the fuse holder in a frequent time period. Aging effects resulting from frequent manipulation have a correlation to fatigue. Fuse holders at MNGP have no fuses removed and reinstalled on a frequent basis. No aging effects are considered applicable to components fabricated from copper, brass, and/or steel material exposed to a mechanically stressful environment.On the basis of its review of current industry research and operating experience, the staff foundthat mechanical stress on copper, brass, and/or steel will not result in aging that will be ofconcern during the period of extended operation. Fuses at MNGP are not frequently removedand installed; therefore, the staff concluded that copper, brass, and/or steel componentsexposed to a mechanically stressful environment have no applicable AERMs.Effect of corrosion, chemical contamination, and oxidation-The aging stressors chemicalcontamination, corrosion, and oxidation are related to environments in which chemical watervapors create adverse localized environments. The indoor air environment is a controlled, mild environment with no significant concentrations of chemical vapors and moisture to create an adverse environment. Fuse holders at MNGP operate in an indoor air environment. No aging effects are considered applicable to components fabricated from copper, brass, and/or steel material exposed to chemical contamination, corrosion, and oxidation environments.On the basis of its review of current industry research and operating experience, the staff foundthat chemical contamination, corrosion, and oxidation on copper, brass, and/or steel will notresult in aging that will be of concern during the period of extended operation. Fuse holders atMNGP are protected from moisture and chemical contamination. Therefore, the staff concludedthat copper, brass, and/or steel components exposed to chemical contamination, corrosion, andoxidation environments have no applicable AERMs.The staff's review of the applicant's programs, the aging effects, and the plant-specific andindustry operating experience determined that the applicant demonstrated that the effects ofaging for fuse holders will be adequately managed so that the intended functions will bemaintained during the period of extended operation, as required by 10 CFR 54.21(a)(3).3.6.2.3.3Electrical Components-Non-EQ Cables and Connections CommodityGroup-Summary of Aging Management Evaluation-Table 3.6.2-3The staff reviewed LRA Table 3.6.2-3, which summarizes the results of AMR evaluations for thenon-EQ cables and connections commodity group component groups.In LRA Table 3.6.2-3, the applicant stated that it identified no aging effects for componentsfabricated from various metal materials exposed to thermal cycling, ohmic heating, electrical transients, vibration, chemical contamination, corrosion, and oxidation environments. Assupported by SAND96-0344, "Aging Management Guideline for Commercial Nuclear Power Plants-Electrical Cable and Terminations," issued September 1996, and the applicant'soperating experience, the likelihood of substantially increased effects or failure rates is considered low from thermal cycling, ohmic heating, electrical transients, mechanical stress 3-315(vibration), chemical contamination, corrosion, and oxidation. No aging effects are consideredapplicable to components fabricated from various metal materials exposed to thermal cycling,ohmic heating, electrical transients, vibration, chemical contamination, corrosion, and oxidationenvironments.The staff noted that operating experience shows loosening of metallic parts of cableconnections. Review of several licensee event reports revealed loose connections due to corrosion, vibration, thermal cycling, and other factors. In RAI 3.6-2, dated November 7, 2005,the staff requested that the applicant provide technical justification for not providing an AMP forcable connections.In its response, by letter dated December 7, 2005, the applicant stated that SAND96-0344categorizes aging mechanisms as either "significant" or "significant and observed." According to SAND96-0344, the aging mechanism listed is "significant."Section 4.2 of SAND96-0344 emphasizes that "the applicability of some aging mechanisms toactual cable systems (cable and connections) may be very limited or the frequency of theiroccurrence may be extremely low." After a consideration of all stressors and the reported incidence of their effects in the industry, SAND96-0344 concluded the following:...the likelihood of substantially increased effects or failure rate resulting fromaging mechanisms currently categorized only as 'significant' is considered low.This assessment, which is based on industry-wide observations, provides reasonableassurance that these aging mechanisms will cause no loss of intended function if leftunmanaged during the period of extended operation. Based on the above, the applicant statedthat industry and plant-specific operating experience does not support the presence of agingeffects from thermal cycling, ohmic heating, electric transients, vibration, chemical contamination, corrosion, and oxidation on the metallic parts of cable connections.In a January 12, 2006, teleconference, the staff informed the applicant that its justification fornot having an AMP for cable connections was inadequate because the operating experience shows loosening of metallic parts of cable connections. The staff recommended that theapplicant implement an AMP for the metallic parts of cable connections in accordance withGALL AMP XI.E6, "Electrical Cable Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements." The applicant stated that it had implemented a plant-specificthermography program for equipment that presents a significant risk to core protection, isnecessary to maintain full power production, or has the potential to reduce power. This equipment, monitored at least semiannually, includes but is not limited to substation equipment, 4-kV breakers, load centers, motor control centers, control centers, control panels, direct current equipment, motors, or generators. The licensee stated that it will consider expandingthe current thermography program to include cable connectors and switchyard bus connections as well as transmission conductor connections that are within the scope of license renewal.In its letter dated February 28, 2006, the applicant committed to implementing a new programconsistent with GALL AMP XI.E6, documented as commitment 55 in Table A.5. The staff foundthis response acceptable, as it will provide assurance that the effects of aging on electricalconnections will be adequately managed. Therefore, the staff's concern described in RAI 3.6-2is resolved.

3-316On the basis of the staff's review of the applicant's programs, the aging effects, and theplant-specific and industry operating experience, the staff determined that the applicantdemonstrated that the effects of aging for non-EQ cables and connections will be adequatelymanaged so that the intended functions will be maintained during the period of extendedoperation, as required by 10 CFR 54.21(a)(3).3.6.2.3.4Electrical Components-Offsite Power/Station Blackout Recovery Path CommodityGroup-Summary of Aging Management Evaluation-Table 3.6.2-4The staff reviewed LRA Table 3.6.2-4, which summarizes the results of AMR evaluations for theoffsite power/SBO recovery path commodity group component groups.The applicant proposed to manage embrittlement, cracking, discoloration, oxidation, andloosening of bolted connections for nonsegregated phase bus made from various metals and organic polymers, porcelain, fiberglass, and silicon rubber in an indoor and outdoor airenvironment using the Bus Duct Inspection Program. SER Section 3.0.3.3.1 documents thestaff evaluation of the Bus Duct Inspection Program.Nonsegregated Phase BusA nonsegregated phase bus connects two or more elements of an electrical power circuit and isnormally used to connect active electrical components such as generators, breakers, and transformers. The intended function of a nonsegregated phase bus is to provide electrical connections to specified sections of an electrical circuit to deliver voltage, current, or signals.The applicant has identified the Bus Duct Inspection Program to manage aging effects in thenonsegregated phase bus. SER Section 3.0.3.3.1 documents the staff evaluation of the BusDuct Inspection Program.High-Voltage InsulatorsIn LRA Table 3.6.2-4, the applicant stated that it identified no aging effects for high-voltageinsulators fabricated from porcelain, cement, and metal material exposed to an outdoor air environment.Effect of surface contamination on porcelain-The applicant stated that MNGP is located in arural area not close to saltwater environments. The nearest industrial facility discharging anysignificant amount of airborne particulates is about 5 miles northwest of the plant. Since the plant began operation in 1971, plant personnel have not conducted regularly scheduledmaintenance to remove surface contamination from the switchyard or transmission line insulators. Additionally, operating experience indicates no age-related degradation of the high-voltage insulators from surface contamination. No aging effects are considered applicable to components fabricated from porcelain material exposed to an outdoor air environment.On the basis of its review of current industry research and operating experience, the staff foundthat porcelain in an outdoor air environment will not result in aging that will be of concern duringthe period of extended operation. The applicant's high-voltage insulators are not located in anarea subject to airborne contaminants. Therefore, the staff concluded that porcelaincomponents exposed to an outdoor air environment have no AERMs.

3-317Effect of cracking on porcelain-Cracks have also been known to occur in insulators used instrain applications when the cement that binds the parts together expands enough to crack theporcelain. This phenomenon, known as cement growth, is caused by improper manufacturing process or materials that increase the cement's susceptibility to moisture penetration. Porcelaincracking caused by cement growth has occurred only in isolated bad batches of insulators used in strain applications. The dates of manufacture and brands of these problem insulators are known and they have been removed from service. Cracking is not considered applicable to components fabricated from porcelain and cement material exposed to an outdoor air environment.On the basis of its review of current industry research and operating experience, the staff foundthat porcelain and cement in an outdoor air environment will not result in aging that will be ofconcern during the period of extended operation. Operating experience using properlymanufactured cement shows no aging effects. Therefore, the staff concluded that porcelain and cement components exposed to an outdoor air environment have no applicable AERMs.Effect of loss of material due to wear-Loss of material due to mechanical wear is an agingeffect for strain and suspension insulators if they are subject to significant movement. Although this mechanism is possible, experience shows that transmission conductors do not normally swing, and when they do, because of strong winds, they dampen quickly once the wind subsides. Routine inspections of high-voltage insulators have not identified wear, and loss of material due to wear is not considered applicable for components fabricated from metal material exposed to an outdoor air environment.On the basis of its review of current industry research and operating experience, the staff foundthat metal in an outdoor air environment will not result in loss of material due to wear that will beof concern during the period of extended operation. Transmission conductors and high-voltage insulators are not subject to significant movement; therefore, the staff concluded that metalcomponents exposed to an outdoor air environment have no applicable AERMs.The staff's review of the applicant's programs, the aging effects, and the plant-specific andindustry operating experience determined that the applicant had demonstrated that the effectsof aging for high-voltage insulators will be adequately managed so that the intended functionswill be maintained during the period of extended operation, as required by 10 CFR 54.21(a)(3).High-Voltage Switchyard BusIn LRA Table 3.6.2-4, the applicant stated that it identified no aging effects for high-voltageswitchyard buses fabricated from aluminum and steel material exposed to an outdoor air environment.Effect of vibration on switchyard bus-Switchyard buses connected to flexible conductors thatnormally do not vibrate are supported by insulators and ultimately by static, structural components like concrete footings and structural steel. With no connections to moving or vibrating equipment, vibration is not an applicable stressor. No aging effects are considered to be applicable to components fabricated from aluminum and steel exposed to outdoor air and vibration environments.

3-318On the basis of its review of current industry research and operating experience, the staff foundthat outdoor air and vibration of aluminum and steel will not result in aging that will be ofconcern during the period of extended operation. Switchyard bus is not subject to vibration.Therefore, the staff concluded that for aluminum and steel components exposed to outdoor airdue to vibration have no applicable AERMs.Effect of oxidation on switchyard bus and connections-All switchyard bus connections withinthe offsite power/SBO recovery path boundaries are bolted, welded, or, for jumper cables,crimped aluminum connections. Aluminum bus, solid and flexible connectors, and ground straps are highly conductive but do not make good contact surfaces as aluminum exposed to air forms nonconductive aluminum oxide on the surface. To prevent formation of aluminum oxide, the connections are cleaned with a wire brush (to remove existing aluminum oxide) and covered with No-Ox grease to prevent air from contacting the aluminum surface. After the connection is completed, additional compound is applied and forced into every irregularity and opening to seal the joint completely against moisture and corrosion. The grease prevents oxidation of the aluminum surface, thereby maintaining good conductivity at the bus connections. The grease is a consumable that is replaced during bus routine maintenance.

Routine maintenance thermography inspections monitor substation connections, which include the SBO recovery path equipment connections, on a semiannual basis. These inspections identify connections where conditions exist that have resulted in increased resistance and a subsequent rise in temperature. The applicant schedules the inspections in the work controlprocess and performs them on a repetitive basis as part of routine maintenance. The inspections have been effective in identifying conditions before any loss of the component intended function. Oxidation is not considered applicable to components fabricated from aluminum and steel exposed to outdoor air.On the basis of its review of current industry research and operating experience, the staff foundthat aluminum and steel in an outdoor air environment will not result in aging that will be ofconcern during the period of extended operation. The application of grease and its periodic replacement eliminates the effects from air on switchyard bus connections. In addition, the applicant periodically inspects connections using thermography. Therefore, the staff concluded that aluminum and steel components exposed to an outside air environment have no applicable AERMs.High-Voltage Transmission ConductorsIn LRA Table 3.6.2-4, the applicant stated that it identified no aging effects for high-voltagetransmission conductors fabricated from aluminum and steel material exposed to an outdoor air environment.Effect of loss of conductor strength due to corrosion-For transmission conductors, degradationbegins as a loss of zinc from the galvanized steel core wires. Corrosion rates depend largely on air quality, which includes suspended particles chemistry, sulfur dioxide concentration in air, precipitation, fog chemistry, and meteorological conditions. Corrosion of transmission conductors is a very slow process that is even slower in rural areas with generally fewer suspended particles and sulfur dioxide concentrations in the air than urban areas. MNGP is located in a rural area with low airborne particle and sulfur dioxide concentrations. No aging effects are considered applicable to components fabricated from aluminum and steel exposed to outdoor air.

3-319On the basis of its review of current industry research and operating experience, the staff foundthat aluminum and steel in an outdoor air environment will not result in aging that will be ofconcern during the period of extended operation. Corrosion is a slow process and is slower in rural areas, where MNGP is located. Therefore, the staff concluded that loss of conductor strength due to corrosion is not an applicable AERM for aluminum and steel components exposed to an outside air environment.Effect of vibration-Wind loading can cause transmission conductor vibration. Wind loading isconsidered in the initial design and field installation of transmission conductors and high-voltage insulators throughout the transmission and distribution network. Loss of material due to wear and fatigue that could be caused by transmission conductor vibration or sway is not considered an applicable aging effect because experience throughout the industry shows no significant failures of this type. No aging effects are considered applicable to components fabricated from aluminum and steel material exposed to an outdoor air environment.On the basis of its review of current industry research and operating experience, the staff foundthat aluminum and steel in an outdoor air environment will not result in aging that will be ofconcern during the period of extended operation. There is no operating experience for failure of transmission conductors due to vibration. Therefore, the staff concluded that vibration will notresult in any applicable AERMs for aluminum and steel components exposed to an outside air environment.Electrical Cables and Connections Not Subject to 10 CFR 50.49 EQ RequirementsSER Section 3.6.2.3.3 documents the staff evaluation for this area.The staff's review of the applicant's programs, the aging effects, and the plant-specific andindustry operating experience determined that the applicant had demonstrated that the effectsof aging will be adequately managed so that the intended functions will be maintained duringthe period of extended operation, as required by 10 CFR 54.21(a)(3).Conclusion. On the basis of its review, the staff found that the applicant appropriately evaluatedAMR results involving material, environment, AERMs, and AMP combinations that are not evaluated in the GALL Report. The staff found that the applicant has demonstrated that theeffects of aging will be adequately managed so that the intended functions will be maintainedconsistent with the CLB for the period of extended operation, as required by10 CFR 54.21(a)(3).3.6.3 Conclusion The staff concluded that the applicant provided sufficient information to demonstrate that theeffects of aging for the electrical and I&C components that are within the scope of license renewal and subject to an AMR will be adequately managed so that the intended functions willbe maintained consistent with the CLB for the period of extended operation, as required by10 CFR 54.21(a)(3).

3-320The staff also reviewed the applicable USAR supplement program summaries and concludedthat they adequately describe the AMPs credited for managing aging of the electrical and I&Ccomponents, as required by 10 CFR 54.21(d).3.7 Conclusion for Aging Management Review ResultsThe staff reviewed the information in LRA Section 3 and Appendix B to the LRA. On the basisof its review of the AMR results and AMPs, the staff concluded that the applicant has demonstrated that the aging effects will be adequately managed so that the intended functionswill be maintained consistent with the CLB for the period of extended operation, as required by10 CFR 54.21(a)(3). The staff also reviewed the applicable USAR supplement program summaries and concluded that the USAR supplement adequately describes the AMPs credited for managing aging, as required by 10 CFR 54.21(d).

4-1SECTION 4TIME-LIMITED AGING ANALYSES4.1 Identification of Time-Limited Aging AnalysesThis section discusses the identification of time-limited aging analyses (TLAAs). NuclearManagement Company, LLC (NMC or the applicant), discusses the TLAAs in Sections 4.2 through 4.10 of its license renewal application (LRA). Sections 4.2 through 4.11 of this safety evaluation report (SER) document the review of the TLAAs conducted by the staff of the U.S.Nuclear Regulatory Commission (NRC or the staff).TLAAs are certain plant-specific safety analyses that involve time-limited assumptions definedby the current operating term. Pursuant to Title 10, Section 54.21(c)(1), of the Code of FederalRegulations (10 CFR 54.21(c)(1)), the applicant for license renewal must provide a list ofTLAAs, as defined in 10 CFR 54.3(a), and demonstrate that (i) the analyses will remain valid forthe period of extended operation, (ii) the analyses have been projected to the end of the periodof extended operation, or (iii) the effects of aging on the intended functions will be adequatelymanaged for the period of extended operation. In accordance with 10 CFR 54.3(a), TLAAs are those licensee calculations and analyses that meet the following six criteria: (252)involve systems, structures, and components (SSCs) within the scope of licenserenewal, as delineated in 10 CFR 54.4(a) (253)consider the effects of aging (254)involve time-limited assumptions defined by the current operating term, for example,40 years (255)were considered to be relevant by the licensee in making a safety determination (256)involve conclusions or provide the basis for conclusions related to the capability of theSSC to perform its intended functions, as delineated in 10 CFR 54.4(b) (257)are contained or incorporated by reference in the current licensing basis (CLB)In addition, pursuant to 10 CFR 54.21(c)(2), an applicant must provide a list of plant-specificexemptions granted under 10 CFR 50.12, "Specific Exemptions," that are based on TLAAs. Forany such exemptions, the applicant must provide an evaluation that justifies the continuation ofthe exemptions for the period of extended operation.4.1.1 Summary of Technical Information in the ApplicationTo identify the TLAAs, the applicant evaluated calculations for the Monticello NuclearGenerating Plant (MNGP) against the six criteria specified in 10 CFR 54.3, "Definitions." The applicant indicated that it had identified the calculations that met the six criteria by searching theCLB, which includes the Updated Safety Analysis Report (USAR), engineering calculations, technical reports, engineering work requests, licensing correspondence, and applicable vendor 4-2reports. In LRA Table 4.1-1, "List of MNGP Time-Limited Aging Analyses (TLAAs)," theapplicant listed the applicable TLAAs in the following categories:

  • neutron embrittlement of the reactor vessel and internals
  • metal fatigue-RPV, internals and pressure boundary
  • neutron embrittlement
  • environmental fatigue
  • environmental qualification
  • loss of preload
  • plant-specific TLAAsPursuant to 10 CFR 54.21(c)(2), the applicant stated that it did not identify any exemptionsgranted under 10 CFR 50.12 that were based on a TLAA, as defined in 10 CFR 54.3.4.1.2 Staff Evaluation In LRA Section 4.1, the applicant identified the TLAAs applicable to MNGP; the applicant alsodiscussed exemptions based on these TLAAs. The staff reviewed the information to determine whether the applicant had provided adequate information to meet the requirements of10 CFR 54.21(c)(1) and 10 CFR 54.21(c)(2).The applicant provided a list of common TLAAs from NUREG-1800, "Standard Review Plan forReview of License Renewal Applications for Nuclear Power Plants," dated July 2001. The applicant listed those TLAAs that are applicable to MNGP in LRA Table 4.1-1.As required by 10 CFR 54.21(c)(2), an applicant must provide a list of all the exemptionsgranted under 10 CFR 50.12 that are based on a TLAA and evaluated and justified for continuation through the period of extended operation. In its LRA, the applicant stated that itreviewed each active exemption to determine whether the exemption was based on a TLAA.

The applicant did not identify any TLAA-based exemptions. On the basis of the information provided by the applicant with regard to the process used to identify TLAA-based exemptions, as well as the results of the applicant's search, the staff concluded that the applicant did notidentify any TLAA-based exemptions that are justified for continuation through the period ofextended operation, in accordance with 10 CFR 54.21(c)(2).4.1.3 Conclusion On the basis of its review, the staff concluded that the applicant provided an acceptable list ofTLAAs, as required by 10 CFR 54.21(c)(1). The staff also confirmed that no exemptions under 10 CFR 50.12 have been granted on the basis of a TLAA, as required by 10 CFR 54.21(c)(2).4.2 Neutron Embrittlement of the Reactor Vessel and InternalsThe materials of the reactor pressure vessel (RPV) and internals are subject to embrittlementresulting from high energy (E > 1 million electron volts (MeV)) neutron exposure. Embrittlementmeans the material has lower toughness (i.e., will absorb less strain energy during a crack orrupture), thus allowing a crack to propagate more easily under thermal and/or pressure loading.

4-3Toughness (indirectly measured in foot-pounds (ft-lb) of absorbed energy in a Charpy impacttest) is temperature dependent in ferritic materials. An initial nil-ductility reference temperature (RTNDT), the temperature associated with the transition from ductile to brittle behavior, isdetermined for vessel materials through a combination of Charpy and drop weight testing.

Toughness increases with temperature up to a maximum value called the "upper-shelf energy" (USE). Neutron embrittlement causes an increase in the RTNDT and a decrease in the USE ofRPV steels. The increase or shift in the initial nil ductility reference temperature (RTNDT) meanshigher temperatures are required for the material to continue to act in a ductile manner. To reduce the potential for brittle fracture during RPV operation by accounting for the changes inmaterial toughness as a function of neutron radiation exposure (fluence), operating pressure-temperature (P-T) limit curves are included in plant technical specifications (TSs). The P-T curves account for the decrease in material toughness associated with a given fluence, which is used to predict the loss in toughness of the RPV materials. Based on the projected drop in toughness for a given fluence, the P-T curves are generated to provide a minimum temperature limit associated with the vessel pressure. The P-T curves are determined by the

RTNDT and RTNDT values for the licensed operating period, along with appropriate margins.4.2.1 RPV Materials USE Reduction Due to Neutron Embrittlement 4.2.1.1 Summary of Technical Information in the ApplicationIn LRA Section 4.2.1, the applicant summarized the evaluation of the RPV materials USEreduction from neutron embrittlement for the period of extended operation. USE is the standardindustry parameter used to indicate the maximum toughness of a material at high temperature.

Appendix G, "Fracture Toughness Requirements," to 10 CFR Part 50, "Domestic Licensing of Production and Utilization Facilities," requires the predicted end-of-life Charpy impact test USEfor RPV materials to be at least 50 ft-lb (absorbed energy), unless an approved analysis supports a lower value. Initial unirradiated test data are available for only one plate heat for the MNGP RPV to demonstrate a minimum 50 ft-lb USE by standard methods. End-of-life fracture energy was evaluated by using an equivalent margin analysis (EMA) methodology approved by the NRC in NEDO-32205-A, Revision 1, "10 CFR 50 Appendix G Equivalent Margin Analysis forLow Upper Shelf Energy in BWR/2-6 Vessels," February 1994. This analysis confirmed that an adequate margin of safety against fracture, equivalent to the requirements of Appendix G to 10 CFR Part 50, does exist. The end-of-life USE calculations satisfy the criteria of 10 CFR 54.3(a), as described in SER Section 4.1. As such, these calculations are a TLAA.Fluence was calculated for the MNGP RPV for the extended 60-year (54 effective full-poweryears (EFPY)) licensed operating period using the methodology of NEDC-32983P, "General Electric (GE) Methodology for Reactor Pressure Vessel Fast Neutron Flux Evaluation,"

approved by the NRC in a letter dated September 14, 2001, from S.A. Richards, NRC, to J.F.Klapproth, GE. The NRC found that, in general, this methodology adheres to the guidance inRegulatory Guide (RG) 1.190, "Calculational and Dosimetry Methods for Determining Pressure Vessel Neutron Fluence," March 2001, for neutron flux evaluation. For MNGP, 54 EFPY is equivalent to 3.90x10 8 megawatt hours (MWh) through the end of Cycle 22 at 1775 megawattsthermal (MWt) plus 4.76x10 8 MWh at 1880 MWt. Peak fluence was calculated at the RPV innersurface (inner diameter) to evaluate USE. The value of neutron fluence was also calculated for the 1/4-thickness (1/4T) location into the RPV wall measured radially from the inside diameter (ID), using Equation 3 from Paragraph 1.1 of RG 1.99, Revision 2, "Radiation 4-4Embrittlement of Reactor Vessel Materials." This 1/4T depth is recommended in the AmericanSociety of Mechanical Engineers (ASME) Boiler and Pressure Vessel Code Section XI, Appendix G, Subarticle G-2120 as the maximum postulated defect depth for calculating P-T curves.4.2.1.2 Staff Evaluation The staff reviewed LRA Section 4.2.1, pursuant to 10 CFR 54.21(c)(1)(ii), to verify that theanalyses have been projected to the end of the period of extended operation.Neutron Fluence EvaluationLRA Section 4.2.1 indicates that the applicant calculated neutron fluence for the MNGP RPV forthe extended 60-year (54 EFPY) licensed operating period based on 3.90x10 8 MWh throughCycle 22 at 1775 MWt plus 4.76x10 8 MWh at 1880 MWt. This calculation results in a peakneutron fluence of 5.17x10 18 neutrons per square centimeter (n/cm

2) (E>1.0 MeV), a peak 1/4Tfluence of 3.82x10 18 n/cm 2 (E>1.0 MeV) for the RPV, and a neutron fluence at the inside of theshroud of 3.84x10 21 n/cm 2 (E>1.0 MeV) at the end of the extended operating period. Originally,MNGP was licensed for 1670 MWt and uprated to 1775 MWt in October 1998 during fuel cycle 19.The staff's review of LRA Section 4.2.1 identified areas for which it needed additionalinformation to complete its evaluation of the applicant's neutron fluence evaluation. The applicant responded to the staff's requests for additional information (RAIs) as discussed below.In RAI 4.2-1, dated September 28, 2005, the staff requested that the applicant provide the basisfor the neutron flux estimates in the TLAA.In its response, by letter dated October 28, 2005, the applicant explained the following:Flux estimates for the MNGP were performed in accordance with the GeneralElectric methodology for neutron flux calculation documented in Licensing Topical Report (LTR) NEDC-32983P-A which has been approved by the NRC. Ingeneral, this methodology adheres to the guidance in Regulatory Guide 1.190 for neutron flux evaluation. A key input to this calculation was the total integratedpower (MWDth) through the first 22 cycles of operation. In addition, Cycle 22core data was used as a basis for the calculation. Flux profiles were generated from this data and, using the maximum flux, the integrated fluence at 54 EFPYwas determined. Fluence estimates at 54 EFPY were conservatively determined using 1775 MWt for Cycles 1 through 22 (previous to rerate implementation in the fall of 1998 the rated power was 1670 MWt) and 1880 MWt for the remainder of the license renewal period of extended operation (54 EFPY). This resulted in EFPYs of 25.09 and 28.91 respectively.In addition to the conservative methodology described above, a bias adjustmentderived from extensive benchmarking of the methodology against measured data as well as an uncertainty related to the flux calculation was incorporated. To account for variations in operation (e.g. capacity factor, core design, etc.), a 4-5multiplier of 1.3 was applied to the reactor pressure vessel to obtain a boundingfluence...In addition, in a letter dated June 10, 2005, the applicant confirmed that the 54 EFPY used inthe TLAA bounds plant-specific operation:NMC has determined that the 54 Effective Full Power Years (EFPY) used forTime-Limited Aging Analyses bounds the plant-specific EFPY for MNGP based on a conservative evaluation of plant history and projected capacity factors. This evaluation results in an expectation of less than 49.5 EFPY at the end of the license renewal period of extended operation. Assuming a 100 percent capacity factor over the same operating period also results in a projected less than 54 EFPY for MNGP.Based on its review, the staff found the applicant's response to RAI 4.2-1 acceptable. Becausethe applicant projected neutron fluence at the expiration of the extended period of operation byan NRC-approved methodology using conservative inputs, the staff considered the neutronfluence projection adequate for TLAA use for the RPV and shroud. Therefore, the staff's concern described in RAI 4.2-1 is resolved.USE EvaluationAppendix G to 10 CFR Part 50, provides the staff's criteria for maintaining acceptable levels ofCharpy USE for the RPV beltline materials throughout the licensed lives of operating facilities.The rule requires a minimum 75 ft-lb Charpy USE value for RPV beltline materials in the unirradiated condition and a 50 ft-lb minimum Charpy USE value throughout the life of the facility, unless analysis demonstrates that lower USE values will provide acceptable margins ofsafety against fracture equivalent to those required by ASME Code Section XI, Appendix G.

The rule also requires methods for calculating Charpy USE values to account for the effects of neutron irradiation on those values for the materials and to incorporate any relevant RPVsurveillance capsule data reported through a plant's RPV material surveillance program,created pursuant to Appendix H, "Reactor Vessel Material Surveillance ProgramRequirements," to 10 CFR Part 50.RG 1.99, Revision 2, expands the discussion regarding the calculation of Charpy USE valuesand describes two methods for calculating Charpy USE values for RPV beltline materials depending on whether a given RPV beltline material is included in the plant's RPV Material Surveillance Program (i.e., 10 CFR Part 50, Appendix H Program). If surveillance data are notavailable, Charpy USE is determined in accordance with regulatory position 1.2 in RG 1.99, Revision 2. If surveillance data are available, Charpy USE should be determined in accordance with regulatory position 2.2 in RG 1.99, Revision 2. These methods refer to RG 1.99,Revision 2, Figure 2, which indicates that the percentage drop in Charpy USE depends on the amount of copper in the material and the neutron fluence. Since the analyses performed inaccordance with Appendix G to 10 CFR Part 50 are based on a flaw with a depth equal to 1/4T, the neutron fluence used in the Charpy USE analysis is at the 1/4T depth location.By letter dated April 30, 1993, the Boiling Water Reactor Owners Group (BWROG) submittedNEDO-32205-A to demonstrate that boiling-water reactor (BWR) RPVs could meet margins ofsafety against fracture equivalent to those required by ASME Code Section XI, Appendix G, for 4-6Charpy USE values less than 50 ft-lb. In a letter dated December 8, 1993, the staff concludedthat the topical report demonstrated that the evaluated materials have margins of safety againstfracture equivalent to ASME Code Section XI, Appendix G, in accordance with Appendix G to 10 CFR Part 50. In that report, the BWROG derived through statistical analysis the unirradiatedCharpy USE values for materials that originally had no documented unirradiated Charpy USE values. Using these statistically derived Charpy USE values, the BWROG predicted the Charpy USE values through 40 years of operation, in accordance with RG 1.99, Revision 2. The BWROG analysis determined that the minimum allowable Charpy USE value in the transverse direction for base metal and along the weld for weld material was 35 ft-lb.Electric Power Research Institute (EPRI) Topical Report (TR)-113596, "BWR Vessel andInternals Project (BWRVIP) BWR Reactor Pressure Vessel Inspection and Flaw Evaluation Guidelines," BWRVIP-74, issued September 1999, documents the GE updated Charpy USEevaluation. An October 18, 2001, letter from Mr. C.I. Grimes to Mr. C. Terry documented staff review and approval of EPRI TR-113596. The analysis in EPRI TR-113596 used the methodology in RG 1.99, Revision 2, to determine the reduction in the unirradiated Charpy USEfrom neutron irradiation. Using this methodology and a correction factor of 65 percent for conversion of the longitudinal properties to transverse properties, the lowest Charpy USE at 54 EFPY for all BWR/3-6 plates was projected to be 45 ft-lb. The correction factor for specimen orientation in plates is based on NRC Branch Technical Position MTEB 5-2, "Fracture Toughness Requirements." EMA acceptance criteria specified in the staff-approved report BWRVIP-74 using the methodology in RG 1.99, Revision 2, are based on the percent reductionin the unirradiated Charpy USE values from neutron radiation. The acceptance criteria specifiedin the BWRVIP-74 report indicate that the maximum allowable percent reduction in USE value is 23.5 percent for the plates and 39 percent for the welds.In RAI 4.2-2, dated September 28, 2005, the staff noted that because the analysis inBWRVIP-74 is generic, the applicant submitted plant-specific information in LRA Tables 4.2.1-1 and 4.2.1-2 for the limiting MNGP plates and welds to demonstrate that the RPV limiting beltlinematerials meet the criteria in the BWRVIP-74 report for the end of the license renewal period.

These tables do not include an evaluation of surveillance plate and weld data. Surveillance datawere submitted to the NRC in a letter dated December 21, 1998, containing Report SIR-97-003,Revision 2, "Review of the Results of Two Surveillance Capsules, and Recommendations for the Materials Properties and P-T Curves to be Used for the Monticello Reactor Pressure Vessel," which indicates that unirradiated Charpy USE data were available for surveillance plates, but not for surveillance welds. Therefore, Charpy USE evaluations using surveillance data could be performed for the plates but not the welds. The staff requested that the applicantdetermine the impact of the surveillance plate data on the limiting beltline plate USE andevaluate what impact, if any, these data have on the validity of the plate EMA.In its response, by letter dated October 28, 2005, the applicant stated the following:Using the '1 st Capsule' data for plate C2220-2 identified in Table 2-1 ofSIR-97-003, Revision 2 results in a measured decrease of 18.3 percent as opposed to an 11.5 percent predicted decrease using RG 1.99 Figure 2 as noted in LRA Table 4.2.1-1 at a fluence of 2.93x10 17 n/cm 2. Correspondingly, at the54 EFPY 1/4T fluence of 3.82x10 18 with an 18.3 percent measured decrease theRG1.99 Position 2.2 adjusted decrease is 33.5 percent which exceeds the margin to safety requirement of 23.5 percent defined in BWRVIP-74-A.

4-7Based on its review, the staff found the applicant's response to RAI 4.2-2 acceptable; however,in this response, the applicant demonstrated that the adjusted percent reduction obtained usingRG 1.99, position 2.2, also results in a 54 EFPY USE greater than 50 ft-lb for plate C2220-2. Asdescribed above, using data from SIR-97-003 results in a position 2.2 Charpy USE reduction of 33.5 percent at the expiration of the extended period of operation. With a transverseunirradiated USE of 86.5 ft-lb (0.65 x 133 ft-lbs), a 33.5 percent reduction results in a 54 EFPY Charpy USE of 57.5 ft-lb, which exceeds the 50 ft-lb minimum identified in Appendix G to 10 CFR Part 50. Because the projected USE exceeds the minimum recommended by Appendix G to 10 CFR Part 50, the staff found the applicant's response acceptable. Therefore, the staff'sconcern described in RAI 4.2-2 is resolved.There are four plates in the MNGP RPV beltline, one with USE greater than 50 ft-lbs, asdiscussed in the previous paragraph. The other three plates have no surveillance data;however, the applicant has used the RG 1.99, Revision 2, methodology to demonstrate thatthese three plates will have less than a 23.5 percent reduction in Charpy USE value at theexpiration of the extended period of operation. Therefore, these plates satisfy BWRVIP-74-Acriteria and the margins of safety against fracture equivalent to ASME Code Section XI, Appendix G, in accordance with Appendix G to 10 CFR Part 50.In RAI 4.2-3, dated September 28, 2005, the staff noted that the weld materials used in theMNGP RPV beltline were fabricated using the shielded metal arc weld (SMAW) process. Such welds are low in copper because the weld electrodes used in this process are not copper coated; therefore, the staff requested that the applicant calculate the projected Charpy USE forthe limiting weld and plate in the reactor vessel beltline at the 1/4T depth using the neutronfluence at the end of the period of extended operation.In its response, by letter dated October 28, 2005, the applicant analyzed the impact of neutronradiation on the RPV beltline welds. In this analysis, the weld material was projected to have a Charpy USE at the expiration of the extended period of operation of 68 ft-lb. The applicantutilized an unirradiated Charpy USE of 84.5 ft-lb, which is the lower 95/95 confidence value forthe SMAW database reported in BWRVIP-74-A. The drop in Charpy USE was calculated by the RG 1.99, Revision 2, methodology and a 0.10 percent copper. As the RPV beltline welds areprojected to have a Charpy USE at the expiration of the extended period of operation greaterthan 50 ft-lb, the RPV beltline weld material meets the criteria of Appendix G to 10 CFR Part 50 criteria at that point.LRA Table 4.2.2-1 indicates that N2 nozzles are within the beltline of the RPV. The MNGP N2nozzles were fabricated as forgings. In a letter dated February 27, 2006, the applicant provided additional data to demonstrate that, at the end of the period of extended operation, the N2nozzles will have Charpy USE values greater than 50 ft-lb. The applicant indicated:Given the hot working normally associated with the fabrication of forgings(resulting in a more refined grain structure), it is expected that the fracture toughness properties of the A 508 Class 2 forging materials would be equivalent, if not better than, the corresponding A 533 Grade B plate materials typically used to fabricate beltline shell courses. 508 Class 2 forging materials (or equivalent) have been used throughout the industry for fabrication of reactor vessel components, including the MNGP recirculation inlet (N2) nozzles, and as such, a 4-8significant amount of data has been reported on the fracture toughness of thesematerials.The applicant performed a study using the NRC Reactor Vessel Integrity Database, Revision 2(RVID2), to determine a generic Charpy USE for A 508 Class 2 forgings. The study indicates that the mean of the USE data for the forgings is 108 ft-lb, with a minimum observed USE of70 ft-lb and a standard deviation of 24 ft-lb. As defined in NUREG-1475, "Applying Statistics,"for 95/95 confidence with a data set consisting of 67 data points, the value is 1.9996. Thisresults in a Mean- of 60 ft-lb. Using the RG 1.99 methodology for determining the impact ofneutron radiation on Charpy USE, the applicant determined that at the expiration of theextended license the Charpy USE will be 52 ft-lb. The staff has confirmed this value.The applicant compared the generic Charpy USE data from forgings with the generic CharpyUSE from plate material. The mean equivalent transverse Charpy USE was reported as 82.5 ft-lb for plate material in BWRVIP-74-A. The minimum observed Charpy USE was 59 ft-lb and the Mean- was 64.5 ft-lb for the plate material.The applicant also evaluated the RVID2 database surveillance capsule results for forgingmaterials with respect to plate materials. These results indicate that application of the RG 1.99 prediction to forgings adequately predicts the irradiated behavior of these materials.The applicant concluded the following:Therefore, it has been demonstrated that the forging materials meet or exceedthe requirements for plate materials, and that the MNGP N2 nozzle case is bounded by the [equivalent margins analysis] EMA plate requirements described in BWRVIP-74-A. Further, it has been demonstrated that, in general, irradiated forging materials behave in a manner consistent with the predictions of RG 1.99.

Based on the results of this evaluation, the USE of the N2 nozzle forgings will be adequate for the period of extended operation.The staff concluded that the analysis provided for the MNGP N2 nozzles demonstrates that thenozzles will have Charpy USE greater than 50 ft-lb and will meet the requirements of AppendixG to 10 CFR Part 50 at the expiration of the extended license. Therefore, the staff's concerndescribed in RAI 4.2-3 is resolved.Table 4.2.1-1 of this SER summarizes the staff's review of the calculated USE values.Table 4.2.1-1 Reactor Vessel Upper-Shelf Energy Analysis SummaryRV Beltline ComponentAcceptance Criterion for USEComponent Value for 54 EFPYC2220-2 Limiting Plate> 50 ft-lb57.5 ft-lbWelds-shielded metal arc> 50 ft-lb68 ft-lbN2 Nozzle-forging> 50 ft-lb52 ft-lb 4-94.2.1.3 USAR SupplementThe applicant provided a USAR supplement summary description of its TLAA evaluation of RPVmaterials USE reduction from neutron embrittlement in LRA Section A3.1. On the basis of its review of the USAR supplement, the staff concluded that the summary description of the applicant's actions to address the RPV materials USE reduction from neutron embrittlement is

adequate.4.2.1.4 Conclusion The staff concluded that the applicant provided an acceptable demonstration, pursuant to10 CFR 54.21(c)(1)(ii), that the analyses of the RPV materials Charpy USE reduction from neutron embrittlement have been projected to the end of the period of extended operation. Thestaff also concluded that the USAR supplement contains an appropriate summary description of this TLAA evaluation, sufficient to satisfy the requirements of 10 CFR 54.21(d).4.2.2Adjusted Reference Temperature for RPV Materials Due to Neutron Embrittlement 4.2.2.1 Summary of Technical Information in the ApplicationIn LRA Section 4.2.2, the applicant summarized the evaluation of the adjusted referencetemperature (ART) for RPV materials from neutron embrittlement for the period of extended operation. The initial RTNDT is the temperature at which a nonirradiated metal (ferritic steel)changes in fracture characteristics, going from ductile to brittle behavior. The applicant evaluated the RTNDT according to the procedures in ASME Code, Paragraph NB-2331. Neutronembrittlement raises the initial RTNDT. Appendix G to 10 CFR Part 50 defines the fracturetoughness requirements for the life of the vessel. The RTNDT is evaluated as the difference inthe 30 ft-lb index temperatures from the average Charpy curves measured before and after irradiation. This increase (RTNDT) means that higher temperatures are required for the materialto continue to act in a ductile manner. The ART is defined as RTNDT + RTNDT + margin. Themargin is defined in RG 1.99. The P-T curves are developed from the ART for the RPV materials. These are determined by the unirradiated RTNDT and by the RTNDT calculations forthe licensed operating period. RG 1.99 defines the calculation methods for RTNDT, ART, andend-of-life USE. The RTNDT and ART calculations meet the criteria of 10 CFR 54.3(a). As such,they are TLAAs.4.2.2.2 Staff Evaluation The staff reviewed LRA Section 4.2.2, pursuant to 10 CFR 54.21(c)(1)(ii), to verify that theanalyses have been projected to the end of the period of extended operation.LRA Table 4.2.2-1 provides the ART values for all beltline materials at the expiration of theextended operating period. The materials with the highest ART values are the C2220-1 and C2220-2 plates, which have 0.17 percent copper and 0.65 percent nickel. Using the RG 1.99,Revision 2, methodology and a neutron fluence of 3.82x10 18 n/cm 2 (E>1 MeV) at the 1/4Tlocation, the ART for these plates is 157 F at the expiration of the extended operating period.

4-10The weld material, which has 0.10 percent copper and 0.99 percent nickel, has an ART of 97 Fat the expiration of the extended operating period.The N2 nozzles have an ART of 117 F. The certified material test report includes nickelcontent and initial RTNDT data, but not copper content data. The copper value (0.18 percent) inthe analysis is generic, derived from data from nine nozzles in other BWR beltline nozzles. The value in the analysis is the mean plus one standard deviation value and is acceptable to the staff because it is consistent with the RG 1.99, Revision 2, criteria when copper is not reportedfor the material.The copper and nickel values for the plates and weld material are consistent with thosereported in RVID2. The staff confirmed the applicant's projected values of ART. These ART values are used in the P-T limits evaluation. P-T limits in the MNGP TSs are periodically updated (discussed in SER Section 4.2.5).4.2.2.3 USAR Supplement The applicant provided a USAR supplement summary description of its TLAA ART evaluationfor RPV materials from neutron embrittlement in LRA Section A3.1. On the basis of its review of the USAR supplement, the staff concluded that the summary description of the applicant'sactions to address the ART for RPV materials from neutron embrittlement is adequate.4.2.2.4 Conclusion The staff concluded that the applicant provided an acceptable demonstration, pursuant to10 CFR 54.21(c)(1)(ii), that the analyses of the ART for RPV materials from neutron embrittlement have been projected to the end of the period of extended operation. The staffalso concluded that the USAR supplement contains an appropriate summary description of this TLAA evaluation, sufficient to satisfy the requirements of 10 CFR 54.21(d).4.2.3 Reflood Thermal Shock Analysis of the RPV 4.2.3.1 Summary of Technical Information in the ApplicationIn LRA Section 4.2.3, the applicant summarized the evaluation of the reflood thermal shockanalysis of the RPV for the period of extended operation. The MNGP USAR includes an end-of-life thermal shock analysis performed on the RPV for a design-basis loss-of-coolant accident (LOCA) followed by a low-pressure coolant injection (LPCI). The effects of neutron embrittlement assumed by this thermal shock analysis will change with an increase in thelicensed operating period. This analysis satisfies the criteria of 10 CFR 54.3(a). As such, this analysis is a TLAA.4.2.3.2 Staff Evaluation The staff reviewed LRA Section 4.2.3, pursuant to 10 CFR 54.21(c)(1)(ii), to verify that theanalyses have been projected to the end of the period of extended operation.

4-11The peak fluence at the RPV wall is 5.17x10 18 n/cm 2 (E>1.0 MeV) for 54 EFPY of operation.Based on this fluence value, the previous reflood thermal shock analysis of the RPV is not bounding for the period of extended operation. The original analysis has been superseded by an analysis for BWR-6 RPVs that is applicable to the MNGP BWR-3 RPV.The BWR-6 RPV analysis applies to MNGP because it uses a bounding main steamline breakevent and an RPV thickness similar to that of the MNGP RPV. This analysis assumes end-of-license material toughness, which in turn depends on the end-of-license ART. The critical location for the fracture mechanics analysis is at 1/4T RPV thickness. For the main steamline break event, the peak stress intensity occurs approximately 300 seconds after initiation of the event. The analysis shows that at that point in the thermal shock event, thetemperature of the vessel wall at 1.5 inches deep (1/4T depth for the BWR-6 RPV) is approximately 400 F. For the MNGP vessel, the 1/4T depth is 1.26 inches.The staff's review of LRA Section 4.2.3 identified an area for which it needed additionalinformation to complete its evaluation of the applicant's neutron fluence evaluation. The applicant responded to the staff's RAI as discussed below.In RAI 4.2-4, dated September 28, 2005, the staff requested that the applicant provide thefracture toughness (peak stress intensity value) required to prevent fracture of the RPV resulting from reflood thermal shock.In its response, dated October 28, 2005, the applicant identified the maximum applied stressintensity for the thermal shock event as 103 kilopounds per square inch times the square root of inches (ksi-in1/2). Fracture toughness at approximately 300 seconds after initiation of the eventwas estimated to be 200 ksi-in1/2. In its response, the applicant stated the following:Paper G1/5, 'Fracture Mechanics Evaluation of a Boiling Water Reactor VesselFollowing a Postulated Loss of Coolant Accident,' Ranganath, S., Fifth International Conference on Structural Mechanics in Reactor Technology, Berlin, Germany, August 1979, defines the basis for this evaluation. As noted in the MNGP LRA submittal, the BWR/6 example in the paper referenced above bounds the conditions at the MNGP. This was demonstrated in the submittal by comparison of the parameters for the BWR/6 case versus the plant-specific MNGP case. As shown in the submittal, the plant-specific temperature at 1/4T depth into the vessel wall was determined to be 370 F at 300 seconds into thethermal shock event. It was also stated that using the highest 60 year Adjusted Reference Temperature (ART), the beltline material reaches upper shelf (200 ksi-in1/2) at 261 oF. Since this temperature is significantly lower than 370 oF, itis assured that the beltline material remains at upper shelf at 300 seconds into the thermal shock event. Figure 5 of 'Fracture Mechanics Evaluation of a BoilingWater Reactor Vessel Following a Postulated Loss of Coolant Accident,'

Ranganath, S., Fifth International Conference on Structural Mechanics in Reactor Technology, Berlin, Germany, August 1979, Paper GI/5, further demonstrates that at 300 seconds into the thermal shock event and at 1/4Tdepth into the vessel wall, the maximum applied stress intensity is 103 ksi-in1/2.Therefore, there is sufficient margin to prevent fracture due to reflood thermal shock.

4-12On the basis of its review, the staff found the applicant's response to RAI 4.2-4 acceptablebecause the applicant demonstrated that the beltline materials will have adequate fracturetoughness (applied stress intensity is less than upper-shelf fracture toughness) at 300 seconds into the event through the period of extended operation. The revised analysis demonstrates thatthe reflood thermal shock analysis of the RPV applies for the extended period of operation.Therefore, the staff's concern described in RAI 4.2-4 is resolved.4.2.3.3 USAR Supplement The applicant provided a USAR supplement summary description of its TLAA evaluation ofreflood thermal shock analysis of the RPV in LRA Section A3.1. On the basis of its review of the USAR supplement, the staff concluded that the summary description of the applicant's actions to address the reflood thermal shock analysis of the RPV is adequate.4.2.3.4 Conclusion The staff concluded that the applicant provided an acceptable demonstration, pursuant to10 CFR 54.21(c)(1)(ii), that the analyses of the reflood thermal shock analysis of the RPV havebeen projected to the end of the period of extended operation. The staff also concluded that theUSAR supplement contains an appropriate summary description of this TLAA evaluation, sufficient to satisfy the requirements of 10 CFR 54.21(d).4.2.4 Reflood Thermal Shock Analysis of the RPV Core Shroud 4.2.4.1 Summary of Technical Information in the ApplicationIn LRA Section 4.2.4, the applicant summarized the evaluation of the reflood thermal shockanalysis of the RPV core shroud for the period of extended operation. Radiation embrittlementmay affect the ability of RPV internals, particularly the core shroud, to withstand an LPCIthermal shock transient. The analysis of core shroud strain from reflood thermal shock is a TLAA because it is part of the CLB, supports a safety determination, and is based on the calculated lifetime neutron fluence.4.2.4.2 Staff Evaluation The staff reviewed LRA Section 4.2.4, pursuant to 10 CFR 54.21(c)(1)(ii), to verify that theanalyses have been projected to the end of the period of extended operation.Before license renewal, the RPV core shroud was evaluated for an LPCI reflood thermal shocktransient considering embrittlement effects of a 40-year radiation exposure (32 EFPY). The core shroud receives the maximum irradiation on the inside surface opposite the midpoint of the fuel centerline. The total integrated neutron flux at the end of 40 years of operation was2.7x10 20 n/cm 2 (greater than 1 MeV). The maximum thermal shock stress in this region is155,700 pounds per square inch (psi), equivalent to 0.57-percent strain. This strain range of 0.57 percent was calculated at the midpoint of the shroud, the zone of highest neutronirradiation.

4-13However, using the approved fluence methodology discussed in SER Section 4.2.1.2, theapplicant revised the analysis for the period of extended operation by calculating the 54 EFPYfluence at the most irradiated point on the core shroud to be 3.84x10 21 n/cm 2. The applicantindicated that the measured value of percent elongation for stainless steel weld metal is4 percent for a temperature of 297 C (567 F) with a neutron fluence of 8x10 21 n/cm 2 (greaterthan 1 MeV), while the average value for base metal at 290 C (554 F) is 20 percent. Thecalculated strain range of 0.57 percent represents a considerable margin of safety relative to measured values of percent elongation for annealed Type 304 stainless steel irradiated to 8x10 21 n/cm 2 (greater than 1 MeV). Because the measured value of elongation bounds thecalculated thermal shock strain amplitude of 0.57 percent, the calculated thermal shock strainat the most irradiated location is acceptable, considering the embrittlement effects for a 60-yearoperating period.The revised analysis demonstrates that the reflood thermal shock analysis of the RPV coreshroud applies for the extended period of operation and satisfies 10 CFR 54.21(c)(1)(ii) because the applicant provided additional data to justify operation to a higher neutron fluence to the end of the period of extended operation.4.2.4.3 USAR Supplement The applicant provided a USAR supplement summary description of its TLAA evaluation ofreflood thermal shock analysis of the RPV core shroud in LRA Section A3.1. On the basis of its review of the USAR supplement, the staff concluded that the summary description of the applicant's actions to address the reflood thermal shock analysis of the RPV core shroud is

adequate.4.2.4.4 Conclusion The staff concluded that the applicant provided an acceptable demonstration, pursuant to10 CFR 54.21(c)(1)(ii), that the reflood thermal shock analyses of the RPV core shroud have been projected to the end of the period of extended operation. The staff also concluded that theUSAR supplement contains an appropriate summary description of this TLAA evaluation, sufficient to satisfy the requirements of 10 CFR 54.21(d).4.2.5 RPV Thermal Limit Analysis: Operating Pressure-Temperature Limits 4.2.5.1 Summary of Technical Information in the ApplicationIn LRA Section 4.2.5, the applicant summarized the evaluation of the RPV thermal limitanalysis: operating P-T limits for the period of extended operation. The RPV thermal limitanalysis provides operating P-T limits for the period of extended operation and is dependent on the ART. The ART is the value of initial RTNDT + RTNDT + margins (for uncertainties) at aspecific location. Neutron embrittlement increases the ART. Thus, the minimum metal temperature at which an RPV is allowed to be pressurized increases. The ART of the limiting beltline material is used to correct the beltline P-T limits to account for irradiation effects.

Appendix G to 10 CFR Part 50 requires RPV thermal limit analyses to determine operating P-T limits for boltup, hydrotest, pressure tests, and normal operating and anticipated operationaloccurrences. Operating limits for pressure and temperature are required for three categories of 4-14operation-(1) hydrostatic pressure tests and leak tests, referred to as Curve A, (2) nonnuclearheatup/cooldown and low-level physics tests, referred to as Curve B, and (3) core-critical operation, referred to as Curve C. P-T limits are developed for three vessel regions, the upper vessel region, the core beltline region, and the lower vessel bottom head region. The calculations associated with generation of the P-T curves satisfy the criteria of 10 CFR 54.3(a).

As such, this topic is a TLAA.4.2.5.2 Staff Evaluation The staff reviewed LRA Section 4.2.5, pursuant to 10 CFR 54.21(c)(1)(ii), to verify that theanalyses have been projected to the end of the period of extended operation.The MNGP TSs include P-T limit curves for core-critical operation, nonnuclearheatup/cooldown, inservice leakage, and hydrostatic testing. They also limit the maximum rate of change of reactor coolant temperature. The criticality curves provide limits for both heatup and criticality calculated for a 32-EFPY operating period. The current TSs contain P-T curves developed using the 1989 edition of the ASME Boiler and Pressure Vessel Code, incorporating the effects of the 1998 power uprate, and ASME Code Case N-640, "Alternative Reference Fracture Toughness for Development of P-T Limit CurvesSection XI, Division 1."P-T limit curves in the MNGP TS are updated periodically, most recently in a February 24, 2003, NRC letter. The staff's February 24, 2003, safety evaluation (SE) indicates that the staffperformed an independent assessment of the proposed curves. The assessment concluded that the irradiated P-T limit curves for 32 EFPY generated at the plant will be at least asconservative as those that will be generated with ASME Code Section XI, Appendix G, criteriaand methods, as modified by ASME Code Case N-640, and the limit curves met the minimum temperature requirements in Table 1 of Appendix G to 10 CFR Part 50. The assessment was performed for P-T limit curves in which the 1/4T ART value was 157 F. Because SERSection 4.2.2.2 indicates a 1/4T ART value of 157 F at the expiration of the extended operatingperiod, the TS P-T limit curves apply to the end of the period of extended operation. Thisconclusion will be reevaluated when surveillance data for the RPV are withdrawn and tested aspart of the BWRVIP Integrated Surveillance Program.4.2.5.3 USAR Supplement The applicant provided a USAR supplement summary description of its TLAA evaluation of RPVthermal limit analysis-operating P-T limits in LRA Section A3.1. On the basis of its review of the USAR supplement, the staff concluded that the summary description of the applicant'sactions to address the RPV thermal limit analysis-operating P-T limits is adequate.4.2.5.4 Conclusion The staff concluded that the applicant provided an acceptable demonstration, pursuant to10 CFR 54.21(c)(1)(ii), that the RPV thermal limit analysis-operating P-T limits analyses have been projected to the end of the period of extended operation. The staff also concluded that theUSAR supplement contains an appropriate summary description of this TLAA evaluation, sufficient to satisfy the requirements of 10 CFR 54.21(d).

4-154.2.6 RPV Circumferential Weld Examination Relief4.2.6.1 Summary of Technical Information in the ApplicationIn LRA Section 4.2.6, the applicant summarized the evaluation of the RPV circumferential weldexamination relief for the period of extended operation. Relief from RPV circumferential weldexamination requirements under Generic Letter 98-05, "Boiling Water Reactor Licensees Useof the BWRVIP-05 Report to Request Relief from Augmented Inspection," is based on probabilistic assessments that predict an acceptable pr obability of failure per reactor operatingyear. The analysis is based on RPV metallurgical conditions, as well as flaw indication sizes and frequencies of occurrence that are expected at the end of a licensed operating period.MNGP has received this relief for the remaining 40-year licensed operating period. The circumferential weld examination relief analysis meets the requirements of 10 CFR 54.3(a). Assuch, it is a TLAA.4.2.6.2 Staff Evaluation The staff reviewed LRA Section 4.2.6, pursuant to 10 CFR 54.21(c)(1)(ii), to verify that theanalyses have been projected to the end of the period of extended operation.The technical basis for relief is discussed in the staff's final SER concerning the BWRVIP-05report, "BWR Vessel and Internals Project (BWRVIP), BWR Reactor Pressure Vessel Weld Inspection Requirements," enclosed in the letter dated July 28, 1998, from Mr. G.C. Laines, NRC, to Mr. C. Terry, the BWRVIP Chairman. In this letter, the staff concluded that, becausethe 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, continued inspection of the RPV circumferential welds will result ina negligible decrease in an already acceptably low rate of RPV failure; therefore, elimination of the inservice inspection (ISI) for RPV circumferential welds is justified. The staff's letter indicated that BWR applicants may request relief from 10 CFR 50.55a(g) ISI requirements for volumetric examination of circumferential RPV welds by demonstrating that (1) through the expiration of the license period, the circumferential welds satisfy the limiting conditional failure probability for circumferential welds in the NRC staff's July 28, 1998, evaluation and(2) implementation of operator training and established procedures that limit the frequency ofcold overpressure events to the frequency specified in the staff's SER. The letter indicated that the requirements for inspection of circumferential RPV welds during an additional 20-year license renewal period will be reassessed, on a plant-specific basis, as part of any BWR LRA;therefore, the applicant must request relief from inspection of circumferential welds during the license renewal period, pursuant to 10 CFR 50.55a.Section A.4.5 of the BWRVIP-74 report indicates that the staff's SER of the BWRVIP-05 reportconservatively evaluated the BWR RPVs to 64 EFPY, which is 10 EFPY greater than realistically expected for the end of the license renewal period. In the July 28, 1998, SER, thestaff used the mean RTNDT value for materials to evaluate failure probability of BWRcircumferential welds at 32 and 64 EFPY. The neutron fluence at the clad-weld (inner) interface was used for this evaluation.

4-16Since the staff analysis discussed in the BWRVIP-74 report is generic, the applicant submittedplant-specific information to demonstrate that the MNGP RPV beltline materials meet the criteria specified in the report. To demonstrate that the MNGP RPV has not become embrittled beyond the basis for the relief, the applicant, in LRA Table 4.2.6.1, compared 54 EFPY materialdata for the limiting MNGP circumferential weld with that of the 64 EFPY reference case in Appendix E to the staff's SER on the BWRVIP-05 report. The MNGP material data included amounts of copper and nickel, chemistry factor, the neutron fluence, RTNDT, initial RTNDT , andmean RTNDT of the limiting circumferential weld at the end of the renewal period. The staff hasverified the data for the copper and nickel contents and the initial RTNDT values for the MNGPcircumferential beltline weld material by comparing them with the corresponding data in RVID.

The 54 EFPY mean RTNDT value for the MNGP circumferential beltline weld is 47.4 F. The staffchecked the applicant's calculations for the 54 EFPY mean RTNDT values for the limiting MNGPcircumferential welds using the data presented in LRA Table 4.2.6.1 and found them to beaccurate. This 54 EFPY mean RTNDT value for MNGP is bounded by the 64 EFPY mean RTNDTvalue of 70.6 F used by the NRC to determine conditional failure probability of a circumferentialweld in a Chicago Bridge and Iron (CB&I) fabricated RPV. The 64 EFPY mean RTNDT valuefrom the staff SER dated July 28, 1998, is for a CB&I weld because CB&I welded the circumferential welds in the RPV. Because the 54 EFPY mean RTNDT value is less than the64 EFPY value from the staff SER dated July 28, 1998, the staff concluded that the NRCanalysis bounds the MNGP RPV conditional failure probability.The applicant stated that the procedures and training used to limit cold overpressure events willbe the same as those approved by the NRC when MNGP requested relief for the currentlicense period. A request for relief during the period of extended operation will be submitted tothe NRC before the period of extended operation.SER Table 4.2.6-1 summarizes the results of the staff's evaluation regarding the RPVcircumferential weld examination relief.Table 4.2.6-1 Effects of Irradiation on RPV Circumferential Weld Properties for MNGPValueCB&I 64 EFPYMNGP 54 EFPYCu (%)0.100.10Ni (%)0.990.99CF134.9138.5Fluence x 10 19 (n/cm 2)1.020.52 DRT NDT (F)135.6113 RT NDT (F)-65-65.6Mean RT NDT (F)70.647.4Probability of a failure event (NRC)1.78x10

-5Note 1Note 1. If the plant-specific mean RTNDT is less than the mean RTNDT associated withthe limiting case study, the staff concludes that the probability of failure for theplant-specific circumferential weld under review will be less than the conditionalprobability of failure value for the limiting circumferential weld in the limiting case study.

4-174.2.6.3 USAR SupplementThe applicant provided a USAR supplement summary description of its TLAA evaluation of RPVcircumferential weld examination relief in LRA Section A3.1. On the basis of its review of the USAR supplement, the staff concluded that the summary description of the applicant's actions to address the RPV circumferential weld examination relief is adequate.4.2.6.4 Conclusion The staff concluded that the applicant provided an acceptable demonstration, pursuant to10 CFR 54.21(c)(1)(ii), that the analyses of the RPV circumferential weld examination reliefhave been projected to the end of the period of extended operation. The staff also concludedthat the USAR supplement contains an appropriate summary description of this TLAA evaluation, sufficient to satisfy the requirements of 10 CFR 54.21(d).4.2.7 RPV Axial Weld Failure Probability 4.2.7.1 Summary of Technical Information in the ApplicationIn LRA Section 4.2.7, the applicant summarized the evaluation of the RPV axial weld failureprobability for the period of extended operation. The BWRVIP recommendations for inspectionof RPV shell welds contain generic analyses supporting an NRC SER conclusion that thegeneric-plant axial weld failure rate is no more than 5x10

-6 per reactor year. BWRVIP-05showed that this axial weld failure rate of 5x10

-6 per reactor year is orders of magnitude greaterthan the 40-year end-of-life circumferential weld failure probability and this analysis justifiedrelief from inspection of the circumferential welds, as described in Section 4.2.6. MNGP received relief from the circumferential weld inspections for the remaining 40-year licensed operating period. The axial weld failure probability analysis meets the requirements of10 CFR 54.3(a). As such, it is a TLAA.4.2.7.2 Staff Evaluation The staff reviewed LRA Section 4.2.7, pursuant to 10 CFR 54.21(c)(1)(ii), to verify that theanalyses have been projected to the end of the period of extended operation.In its July 28, 1998, letter to Mr. C. Terry, the BWRVIP Chairman, the staff identified a concernabout the failure frequency of axially oriented welds in BWR RPVs. 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 SER on these analyses is enclosed in a March 7, 2000, letter from Mr. J. Strosnider (NRC) to Mr. C. Terry, BWRVIP Chairman. The staffperformed a generic analysis using Pilgrim as a model for BWR RPVs. The staff analysis identified as Mod 2 that the vessel failure frequency will be 5.02 x 10

-6 at a mean RTNDT at thevessel inside surface of 114 F.LRA Table 4.2.7-1 compared 54 EFPY material data for the limiting RPV axial weld with that ofMod 2 from the staff's SE in the March 7, 2000, letter. The MNGP material data included copper and nickel amounts, chemistry factor, neutron fluence, RTNDT, initial RTNDT, and mean RTNDT of the limiting axial weld at the end of the renewal period. The applicant calculated, and 4-18the staff confirmed, that the limiting axial weld mean RTNDT at the inside surface at theexpiration of the extended operating period is 47.4 F. Because the mean RTNDT at the vesselinside surface for the limiting axial weld is less than the value in the staff's Mod 2 analysis, the failure frequencies for the MNGP RPV will be less than 5 x 10

-6 per reactor year of operation atthe end of the period of extended operation; therefore, this analysis is acceptable.SER Table 4.2.7-1 summarizes the results of the staff's evaluation regarding the RPV axialweld failure probability.Table 4.2.7-1 Effects of Irradiation on RPV Axial Weld Properties for MNGPValueMod 2MNGP 54 EFPYCu (%)0.2190.10Ni (%)0.9960.99 CF138.5Fluence x 10 19 (n/cm 2)0.1480.52 DRT NDT (F)116113 RT NDT (F)-2-65.6Mean RT NDT (F)11447.4Probability of a failure event (NRC)5.02x10

-6Note 1Note 1. If the plant-specific mean RTNDT is less than the mean RTNDT associated withthe limiting case study, the staff concluded that probability of failure for the plant-specificaxial weld under review will be less than the conditional probability of failure value for thelimiting axial weld in the limiting case study.4.2.7.3 USAR Supplement The applicant provided a USAR supplement summary description of its TLAA evaluation of RPVaxial weld failure probability in LRA Section A3.1. On the basis of its review of the USARsupplement, the staff concluded that the summary description of the applicant's actions to address the RPV axial weld failure probability is adequate.4.2.7.4 Conclusion The staff concluded that the applicant has provided an acceptable demonstration, pursuant to10 CFR 54.21(c)(1)(ii), that the RPV axial weld failure probability analyses have been projectedto the end of the period of extended operation. The staff also concluded that the USARsupplement contains an appropriate summary description of this TLAA evaluation, sufficient to satisfy the requirements of 10 CFR 54.21(d).

4-194.3Metal Fatigue of the RPV and Internals, and Reactor Coolant Pressure BoundaryPiping and ComponentsA metal component subject to cyclic loads less than the static design load may fail from fatigue.Metal fatigue of components may have been evaluated based on an assumed number of transients or cycles for the current operating term. The validity of such metal fatigue analysis isreviewed for the period of extended operation.The specific criterion for fatigue analysis of ASME Code Section III components involvescalculating the cumulative usage factor (CUF). The fatigue damage in the component caused by each thermal or pressure transient depends on the magnitude of the stresses caused by the transient. The CUF sums the fatigue damage from each transient. The ASME Code Section III criterion requires that the CUF not exceed 1.0.4.3.1 RPV Fatigue Analyses 4.3.1.1 Summary of Technical Information in the ApplicationIn LRA Section 4.3.1, the applicant discussed that the RPV was designed to ASME Code,Section III. RPV fatigue analyses were performed for the vessel support skirt, shell, upper andlower heads, closure flanges, nozzles and penetrations, nozzle safe ends, and closure studs.

The end of the 40-year license fatigue usage was determined for the normal and upset pressure and thermal cycle events. After the original stress analyses, several hardwarechanges, operational changes (e.g., the 1998 power rerate), and/or stress analysis revisions have affected usage factors. Calculation of fatigue usage factors is part of the CLB and used to support safety determinations. The RPV fatigue analyses are TLAAs.The applicant stated that the 1998 MNGP power rerate included a reanalysis of the RPV. LRATable 4.3.1-1 lists the limiting design CUFs for the RPV components. The applicant stated thatthe fatigue usage factors in Table 4.3.1-1 were determined using the actual transient cyclesfrom its Fatigue Monitoring Program (FMP). On the basis of the actual transient accumulation rate, the applicant concluded that fatigue usage of the RPV components is not expected toexceed the allowable limit of 1.0 during the period of extended operation. The applicant alsostated that the Fatigue Monitoring Program will monitor transients contributing to fatigue usage,as described in Appendix B to the LRA.4.3.1.2 Staff Evaluation The staff reviewed LRA Section 4.3.1, pursuant to 10 CFR 54.21(c)(1)(iii), to verify that theeffects of aging on the intended functions will be adequately managed for the period ofextended operation, and, pursuant to 10 CFR 54.21(c)(1)(ii), that the analyses have beenprojected to the end of the period of extended operation.The RPV components were analyzed using the ASME Code fatigue requirements. LRATable 4.3.1-1 lists the design transients for the fatigue analysis of the RPV components. USARTable 4.2-1 lists the design transients for the RPV fatigue analysis. The staff confirmed that the transients in LRA Table 4.3.1-1 are the same as those in USAR Table 4.2-1.

4-20The staff's review of LRA Section 4.3.1 identified an area for which it needed additionalinformation to complete its evaluation of the RPV fatigue analysis. The applicant responded to the staff's RAI as discussed below.Table 4.3.1-1 also provides the estimated 60-year fatigue usage factors for the RPVcomponents, which are all less than the ASME Code Section III allowable limit of 1.0. Theapplicant indicated that these usage factors include the results of a reanalysis of RPVcomponents performed as part of the 1998 power rerate. The applicant also indicated that the fatigue usage factors were determined from the FMP.In RAI 4.3.1-1, dated June 21, 2005, the staff requested that the applicant describe how it hadcalculated the revised fatigue usage factors.In its response, dated July 21, 2005, the applicant stated that GE Document SASR 89-77,"Accumulated Fatigue Usage for the Monticello Nuclear Generating Station Reactor Pressure,"tabulates thermal transient (TT) cycles experienced by MNGP through July 1989. As discussedin SASR 89-77, the number of transient cycles through July 1989 was determined from a reviewof operator log books and plant records. The applicant stated that its FMP updates the numberof TT cycles once per refueling cycle. The applicant used t hese updated cycles to compute thefatigue usage factors in LRA Table 4.3.1-1.Based on its review, the staff found the applicant's response to RAI 4.3.1-1 acceptable becauseuse of the actual TT cycles to estimate the fatigue usage factors for the period of extendedoperation is reasonable; therefore, the staff's concern described in RAI 4.3.1-1 is resolved.The applicant will rely on its FMP to assure that the fatigue usage of the RPV components willremain within ASME Code Section III allowable limits during the period of extended operation.4.3.1.3 USAR Supplement The applicant provided a USAR supplement summary description of its TLAA evaluation of RPVfatigue analyses in LRA Section A3.2. On the basis of its review of the USAR supplement, the staff concluded that the summary description of the applicant's actions to address the RPV fatigue analyses is adequate.4.3.1.4 Conclusion The staff reviewed the applicant's TLAA regarding the RPV fatigue analyses, as summarized inLRA Section 4.3.1. The staff concluded that the applicant has demonstrated that, pursuant to10 CFR 54.21(c)(1)(iii), the effects of aging on the intended functions will be adequatelymanaged for the period of extended operation, and, pursuant to 10 CFR 54.21(c)(1)(ii), theanalyses have been projected to the end of the period of extended operation. The staff alsoconcluded that the USAR supplement contains an appropriate summary description of this TLAA evaluation sufficient to satisfy 10 CFR 54.21(d) requirements.

4-214.3.2 Fatigue Analysis of RPV Internals4.3.2.1 Summary of Technical Information in the ApplicationIn LRA Section 4.3.2, the applicant discussed the fatigue analysis of the reactor vesselinternals (RIT), indicating that the analysis was performed using ASME Code,Section III criteria. The applicant stated that the most significant fatigue loading occurs at the jet pumpdiffuser-to-baffle plate weld location. The original 40-year calculation showed a CUF of approximately 0.33. The applicant estimated the 60-year RIT fatigue usage by multiplying the 40-year fatigue usage by 1.5. The applicant concluded that the fatigue usage of the RIT willremain below the allowable limit of 1.0 through the period of extended operation.4.3.2.2 Staff Evaluation The staff reviewed LRA Section 4.3.2, pursuant to 10 CFR 54.21(c)(1)(ii), to verify that theanalyses have been projected to the end of the period of extended operation.The applicant stated that the RIT fatigue analysis was guided by ASME Code Section IIIcriteria. The applicant indicated that the most significant fatigue loading occurs at the jet pumpdiffuser-to-baffle plate weld location. The applicant's evaluation included three transients, (1) normal startup and shutdown, (2) improper start of a recirculation loop, and (3) design-basis accident (DBA).The applicant stated that the 60-year fatigue usage of the RIT was estimated by multiplying theoriginal fatigue usage by a factor of 1.5.The staff's review of LRA Section 4.3.2 identified an area for which it needed additionalinformation to complete its evaluation of the RIT fatigue analysis. The applicant responded to the staff's RAI as discussed below.In RAI 4.3.2-1, dated June 21, 2005, the staff requested that the applicant confirm that theextrapolation bounded the number of startup/shutdown design cycles listed in LRASection 4.3.1.In its response, dated July 21, 2005, the applicant reiterated that the most significant fatiguelocation for the RIT is at the jet pump diffuser-to-baffle plate weld. The applicant stated that thestartup/shutdown cycles had a negligible impact on fatigue usage at this location. The applicantstated that the only significant contributor to fatigue for the jet pump-to-baffle plate weld is thetransient that includes improper recirculation pump startup and post-DBA flooding. USAR Section 3.6.3.3 indicates that the RIT were originally evaluated for three improper recirculationpump starts. The applicant evaluated the impact of the updated number of design cycles listedin LRA Section 4.3.1 and found that the increase in the number of improper recirculation pumpstarts had no significant impact on fatigue usage. Therefore, the applicant concluded that theuse of the 1.5 factor to estimate the 60-year fatigue usage was conservative.Since the number of postulated DBA events does not increase for the period of extendedoperation and the increase in the number of improper recirculation pump starts has no 4-22significant impact on fatigue usage, the staff concluded that the applicant had adequatelyevaluated the RIT.Based on its review, the staff found the applicant's response to RAI 4.3.2-1 acceptable becausethe applicant performed an acceptable evaluation of the RIT for the period of extendedoperation, in accordance with the 10 CFR 54.21(c)(1)(ii) requirements; therefore, the staff'sconcern described in RAI 4.3.2-1 is resolved.4.3.2.3 USAR Supplement The applicant provided a USAR supplement summary description of its TLAA evaluation offatigue analysis of RPV internals in LRA Section A3.2. On the basis of its review of the USAR supplement, the staff concluded that the summary description of the applicant's actions to address the fatigue analyses of RPV internals is adequate.4.3.2.4 Conclusion The staff reviewed the applicant's TLAA regarding the fatigue analysis of RPV internalssummarized in LRA Section 4.3.2 and concluded that the applicant has provided an acceptabledemonstration, pursuant to 10 CFR 54.21(c)(1)(ii), that the analyses have been projected to theend of the period of extended operation. The staff also concluded that the USAR supplementcontains an appropriate summary description of this TLAA evaluation sufficient to satisfy 10 CFR 54.21(d) requirements.4.3.3ASME Section III Class 1 Reactor Coolant Pressure Boundary (RCPB) Piping andFatigue Analysis4.3.3.1 Summary of Technical Information in the ApplicationIn LRA Section 4.3.3, the applicant summarized the evaluation of the ASME Code Section IIIClass 1 reactor coolant pressure boundary (RCPB) piping and fatigue analysis for the period of extended operation. Piping systems were originally designed in accordance with AmericanStandards Association (ASA) B31.1 and United States of America Standard (USAS) B31.1.0which did not require an explicit fatigue analysis. The applicant concluded that the analyses demonstrate that the 40-year CUFs for the limiting components in all affected systems arebelow the ASME Code Section III allowable value of 1.0.4.3.3.2 Staff Evaluation The staff reviewed LRA Section 4.3.3, pursuant to 10 CFR 54.21(c)(1)(iii), to verify that theeffects of aging on the intended functions will be adequately managed for the period ofextended operation.The applicant indicated that RCPB piping was originally designed in accordance withASA B31.1 and USAS B31.1.0, which did not require explicit fatigue analyses of piping components. The applicant stated that portions of the RCPB required fatigue analysis, in accordance with ASME Code Section III for Nuclear Class 1 piping.

4-23The staff's review of LRA Section 4.3.3 identified an area for which it needed additionalinformation to complete its evaluation of the fatigue analysis. The applicant responded to the staff's RAI as discussed below.In RAI 4.3.3-1, dated June 21, 2005, the staff requested that the applicant provide the basis forthe requirement that RCPB portions be analyzed for fatigue, in accordance with the ASME Code Section III for Nuclear Class 1 piping. The staff also requested that the applicant indicatewhether the number of TT cycles used to estimate the 60-year fatigue usage of the core spray(CSP) valve joint is consistent with the number of TT cycles obtained from the FMP and used toestimate the 60-year fatigue usage of the CSP nozzle.In its response, dated July 21, 2005, the applicant indicated that replaced portions of the REC,CSP, and residual heat removal (RHR) systems were evaluated using ASME Code Section IIIfatigue analysis guidelines. Replacement of ASA B31.1 components with ASME Code Section III components is acceptable. Replaced components must then satisfy ASME Coderequirements, including those for fatigue.The applicant stated that the design fatigue usage at the limiting location for RCPB CSP pipingis less than 0.65 (CSP valve joint). The applicant estimated the 60-year fatigue usage by multiplying the design value by 1.5 to obtain a fatigue usage slightly below the allowable limit of 1.0; however, in LRA Table 4.3.1-1, the applicant indicated that the projected 60-year fatigueusage of the CSP nozzle is 0.65 based on the number of TT cycles counted by the FMP. Inresponding to RAI 4.3.3-1, the applicant stated that portions of the CSP piping were replaced in1986 and that, as discussed above, the replaced piping was evaluated using ASME Code Section III fatigue guidelines. The applicant indicated that the evaluation considered 100startup/shutdown cycles; therefore, extrapolation of the CSP piping usage factor by a factor of1.5 should represent 150 startup/shutdown cycles. LRA Section 4.3.1 projects 207startup/shutdown cycles for 60 years of plant operation. The staff reviewed data provided inSASR 89-77 indicating that the most significant TT affecting the CSP nozzle fatigue usage is startup/shutdown cycles. SASR 89-77 also indicated that 86 startup/shutdown cycles had accumulated before the CSP piping replacement. Therefore, the number of expected startup/shutdown cycles for the replaced CSP piping is 121 through the period of extendedoperation.Based on its review, the staff found the applicant's response to RAI 4.3.3-1 acceptable becausethe applicant's evaluation of the CSP valve joint represents a conservative estimate for the number of startup/shutdown cycles; therefore, the staff's concern described in RAI 4.3.3-1 isresolved.The applicant's FMP tra cks the number of design cycles for RPV com ponents. As discussed inAppendix B to the LRA, the FMP scope also includes RCPB piping. The staff concluded that the FMP provides an acceptable program to manage the fatigue usage of the RCPB components during the period of extended operation, in accordance with the requirements of10 CFR 54.21(c)(1)(iii).4.3.3.3 USAR Supplement The applicant provided a USAR supplement summary description of its TLAA evaluation ofASME Code Section III Class 1 RCPB piping and fatigue analysis in LRA Section A3.3. On the 4-24basis of its review of the USAR supplement, the staff concluded that the summary descriptionof the applicant's actions to address the fatigue analysis of ASME Code Section III Class 1RCPB piping is adequate.4.3.3.4 Conclusion The staff reviewed the applicant's TLAA regarding the fatigue analysis of ASME CodeSection III Class 1 RCPB piping, as summarized in LRA Section 4.3.3, and concluded that theapplicant has provided an acceptable demonstration that, pursuant to 10 CFR 54.21(c)(1)(iii),the effects of aging on the intended functions will be adequately managed for the period ofextended operation. The staff also concluded that the USAR supplement contains anappropriate summary description of this TLAA evaluation, sufficient to satisfy 10 CFR 54.21(d) requirements.4.3.4 RCPB Section III Class 2 and 3 Piping and Components4.3.4.1 Summary of Technical Information in the ApplicationIn LRA Section 4.3.4, the applicant summarized the evaluation of the RCPB ASME CodeSection III Class 2 and 3 piping and components for the period of extended operation. Thesecomponents were designed to ASA B31.1 and USAS B31.1.0 criteria, which did not require explicit fatigue analyses of the piping components, but did require application of a stress reduction factor to the allowable thermal bending stress range, if the number of full-range cycles exceeds 7000. The applicant stated that the number of thermal cycles experienced bythese systems is not expected to exceed 7000 during the period of extended operation;therefore, the applicant concluded that the analyses will remain valid for that period.4.3.4.2 Staff Evaluation The staff reviewed LRA Section 4.3.4, pursuant to 10 CFR 54.21(c)(1)(i), to verify that theanalyses will remain valid for the period of extended operation.The applicant indicated that the remaining piping and components were designed to codes thatdid not require explicit fatigue analyses. As discussed previously, the applicant performed fatigue analyses of the replaced portions of the RCPB piping. The design of the remaining piping systems is governed by the ASA B31.1 and USAS B31.1.0 criteria that limit the numberof full-range stress cycles from thermal bending to 7000. The applicant stated that the projectednumber of thermal bending cycles will not exceed 7000 for any non-ASME Code Section IIIClass 1 piping during the period of extended operation based on an assessment of the number of thermal cycles for the FW nozzle. The applicant selected the FW nozzle because it wassubject to the largest number of TT cycles in the RPV nozzle fatigue analyses. The applicantmultiplied the number of FW nozzle TT design cycles by 1.5 to provide a bounding estimate forthe non-ASME Class 1 piping.On the basis of its review, the staff concluded that the applicant's evaluation provides areasonable upper bound estimate of the number of full-range thermal bending cycles fornon-ASME Class 1 piping systems because the evaluation bounds the expected number ofTTs, including the number of expected startup/shutdown cycles for the facility. Therefore, the 4-25staff concluded that the applicant has adequately demonstrated that the analyses of thenon-ASME Class 1 piping and components will remain valid for the period of ext endedoperation, in accordance with the requirements of 10 CFR 54.21(c)(1)(i).4.3.4.3 USAR Supplement The applicant provided a USAR supplement summary description of its TLAA evaluation ofASME Code Section III Class 2 and 3 piping and components in LRA Section A3.4. On thebasis of its review of the USAR supplement, the staff concluded that the summary description of the applicant's actions to address the RCPB Section III Class 2 and 3 piping and componentsis adequate.4.3.4.4 Conclusion The staff reviewed the applicant's TLAA regarding the RCPB Section III Class 2 and 3 pipingand components, summarized in LRA Section 4.3.4, and concluded that the applicant providedan acceptable demonstration, pursuant to 10 CFR 54.21(c)(1)(i), that the analyses will remainvalid for the period of extended operation. The staff also concluded that the USAR supplementcontains an appropriate summary description of this TLAA evaluation, sufficient to satisfy 10 CFR 54.21(d) requirements.4.4 Irradiation-Assisted Stress-Corrosion Cracking (IASCC)4.4.1 Summary of Technical Information in the Application In LRA Section 4.4, the applicant summarized the evaluation of irradiation-assisted stresscorrosion cracking (IASCC) for the period of extended operation. Austenitic stainless steel RPV internal components exposed to a neutron fluence greater than 5x10 20 n/cm 2 (E > 1 MeV) aresusceptible to IASCC in the BWR environment. As described in the SER to BWRVIP-26, IASCC of RPV internals is a TLAA.4.4.2 Staff Evaluation The staff reviewed LRA Section 4.4, pursuant to 10 CFR 54.21(c)(1)(iii), to verify that the agingeffects from IASSC on the intended functions will be adequately managed for the period ofextended operation.The staff reviewed the information in the LRA and noted that the austenitic stainless steelcomponents exposed to a neutron fluence greater than 5x10 20 n/cm 2 (E >1 MeV) areconsidered susceptible to IASCC. These RPV internal components include the top guide, the shroud, and the incore instrumentation dry tubes and guide tubes. The staff reviewed thefluence calculations for the RPV and verified that other RPV internal components (e.g., the coreplate) are not expected to exceed a neutron fluence of 5x10 20 n/cm 2 and thus are considerednot to be susceptible to IASCC. In the LRA, the applicant stated that the aging effects fromIASCC of these RPV components are managed by three aging management programs (AMPs),

B2.1.2, ASME Section XI In-Service Inspection, Subsections IWB, IWC, and IWD; B2.1.12, BWR Vessel Internals; and B2.1.25, Plant Chemistry. The applicant stated that implementationof these three AMPs will manage the aging effects from IASCC such that the RPV internal 4-26components will continue to perform their intended functions consistently with the licensingbasis for the period of extended operation.The staff reviewed other applicant documents pertaining to the RPV, BWRVIP documents, andEPRI topical reports applying to generic RPVs. The staff observed that, while fluence level was the primary contributor to IASCC, additional factors also contributed or increased component susceptibility to IASCC. The staff observed that BWRVIP-41, "BWR Jet Pump Assembly lnspection and Flaw Evaluation Guidelines," states that materials like austenitic stainless steel used in jet pumps are not greatly susceptible to IASCC due to the low fluence levels in the annulus region." The staff also observed that the June 5, 2001, SER that acceptedBWRVIP-41 stated that materials in a nonoxygenated environment are also not greatlysusceptible to IASCC, which becomes a concern only when cr acks are already present in acomponent. Thus, the SER stated that, when an applicant can show that cra cks hav e notoccurred in components, loss of fracture toughness from IASCC will not be a significant agingeffect.The staff asked the applicant to clarify its actions regarding the above additional factors. As tothe aggressive oxygenated environment, the applicant responded that it had implementedhydrogen water chemistry (HWC) in 1989, which reduces the oxidizing environment of the reactor coolant system (RCS) by injecting excess hydrogen to combine with free oxygenproduced by radiolysis. The dissolved oxygen content of FW is regulated to 20-50 parts per billion (ppb) during power operation, which minimizes corrosion potential. The staff reviewedhistorical data from the Water Chemistry Program and verified the low dissolved oxygen content.In a letter, dated June 10, 2005, the applicant stated that, in addition to those examinationsrequired by the ISI Program, which includes all pertinent examinations required by the BWRVIP program, it will examine the top guide grid high-fluence locations using the EVT-1 visualexamination method. In the same letter, the applicant committed to inspections of 10 percent ofthese locations within 12 years. The staff reviewed the applicant's operational experience and observed that, to date, it has inspected 25 percent of the high-fluence locations of the top guidegrid and detected no evidence of cracking.The staff reviewed the fluence calculations for the RPV internals and observed that there was afactor of 30 percent that was added to the calculated fluence level results. The staff asked the applicant to clarify the purpose of this added factor. The applicant stated that this factor was added for conservatism.The staff reviewed the RPV components for IASCC, considering that (1) these componentswere composed of a material that was identified in BWRVIP-41 as not highly susceptible to IASCC, (2) these components are in a nonaggressive, low-dissolved-oxygen environment, so, as stated in the SER, the susceptibility of these components to IASCC is reduced, (3) noevidence of cra cks has been detected in the RPV inspections to date, so as stated in the SER,significant loss of fracture toughness will not result, and (4) the fluence calculations thatdetermined the three RPV components susceptible to IASCC add a factor of 30 percent, for conservatism. The staff concluded that the applicant's AMP B2.1.2, ASME Section XI In-Service Inspection, Subsections IWB, IWC, and IWD; B2.1.12, BWR Vessel Internals; and B2.1.25, Plant Chemistry, will adequately manage the aging effects from IASCC for the periodof extended operation.

4-27During the audit and review, the staff identified an additional issue that required furtherclarification by the applicant. The applicant has committed to perform additional top guide examinations within the first 12 years of the period of extended operation; however, there is nocommitment to perform examinations during the remaining period of extended operation, nor acommitment as to what the applicant will do if any RPV examination detects an indication. In RAI 4.1-1, the staff requested that the applicant describe its actions for the remainder of theperiod of extended operation.In its response, by letter dated November 22, 2005, the applicant stated that it will perform aninspection of a sampling of top guide high-fluence locations (i.e., where fluence exceeds 5.0x10 20 n/cm 2) consistent with the lower plenum inspection and flaw evaluation guidelinesdescribed in BWRVIP-47. Ten percent of the total high-fluence population will be inspectedwithin 12 years, with a minimum of 5 percent inspected within the first 6 years. If flaws are detected, inspection of an additional 5 percent of the total high-fluence population will becompleted. This process will be repeated until no new flaws are detected. Any flaw exceedinginspection limits will be evaluated and necessary corrective actions made that may include, butare not limited to, accept as-is, accept as-is with required periodic reinspection, or remove indication by metal removal. All corrective actions will be performed in accordance withapproved procedures. Indication mapping and sizing will be documented for use in industryresolution of any related concerns. Reinspection scope and frequency during the entire period of extended operation will depend on initial inspection results, as well as on related industryexperience. Therefore, the staff concluded this TLAA is acceptable and consistent with theGALL Report, and the staff's concern described in RAI 4.1-1 is resolved.4.4.3 USAR Supplement The applicant provided a USAR supplement summary description of its TLAA evaluation ofIASCC in LRA Section A3.5. On the basis of its review of the USAR supplement, the staff concluded that the summary description of the applicant's actions to address the IASCC is

adequate.4.4.4 Conclusion The staff concluded that the applicant provided an acceptable demonstration, pursuant to10 CFR 54.21(c)(1)(iii), that the aging effects from IASSC on the intended functions will beadequately managed for the period of extended operation. The staff also concluded that theUSAR supplement contains an appropriate summary description of this TLAA evaluation, sufficient to satisfy the requirements of 10 CFR 54.21(d).4.5 Effects of Reactor Coolant Environment4.5.1 Summary of Technical Information in the Application In LRA Section 4.5, the applicant summarized its evaluation of the effects of the reactor coolantenvironment for the period of extended operation. The applicant evaluated the impact of thereactor coolant environment on the fatigue life of the locations addressed in NUREG/CR-6260,"Application of NUREG/CR-5999 Interim Fatigue Curves for Selected Nuclear Power PlantComponents." The applicant's evaluation indicated that the environmental fatigue usage for all 4-28locations is less than the allowable limit of 1.0 for the period of extended operation. Theapplicant concluded that the effects of environmentally assisted fatigue were shown to be acceptable through the period of extended operation. The applicant further indicated that theFMP periodically reviews and updates fatigue analyses to ensure continued compliance with the fatigue acceptance criteria.4.5.2 Staff Evaluation The staff reviewed LRA Section 4.5, pursuant to 10 CFR 54.21(c)(1)(ii), to verify that theanalyses have been projected to the end of the period of extended operation.The applicant stated that the FMP will continue during the period of extended operation toassure that design cycle limits are not exceeded. The applicant's FMP tracks transients andcycles of RCS components with explicit design transient cycles to assure that thesecomponents remain within their design bases. Generic Safety Issue (GSI)-166, "Adequacy of the Fatigue Life of Metal Components," raised concerns about the conservatism of the fatigue curves used in the design of the RCS components. Although GSI-166 was resolved for the current 40-year design life of operating components, the staff identified GSI-190, "FatigueEvaluation of Metal Components for 60-Year Plant Life," to address license renewal. The NRC closed GSI-190 in December 1999, after concluding the following:The results of the probabilistic analyses, along with the sensitivity studiesperformed, the iterations with industry (NEI and EPRI), and the different approaches available to the licensees to manage the effects of aging, lead to the conclusion that no generic regulatory action is required, and that GSI-190 isclosed. This conclusion is based primarily on the negligible calculated increases in core damage frequency in going from 40 to 60-year lives. However, the calculations supporting resolution of this issue, which included consideration of environmental effects, and the nature of age-related degradation indicate the potential for an increase in the frequency of pipe leaks as plants continue to operate. Thus, the staff concluded that, consistent with existing requirements in10 CFR 54.21, licensees should address the effects of coolant environment on component fatigue life as aging management programs are formulated in support of license renewal.The staff compared the usage factors provided by the applicant with those in NUREG/CR-6260for the older vintage BWR. NUREG/CR-6260 identified several locations for which theenvironmental usage factor was projected to exceed 1.0, including the CSP nozzle safe end, the FW nozzle, the FW line reactor core isolation cooling (RCIC) tee connection, and the RHRreturn line tee.The staff's review of LRA Section 4.5 identified an area for which it needed additionalinformation to complete its evaluation of the effects of the reactor coolant environment. The applicant responded to the staff's RAI as discussed below.The environmental fatigue usage for the CSP nozzle (safe end) in LRA Section 4.5 is muchlower than the fatigue usage of the CSP nozzle (without environmental effects) in LRA Table 4.3.1-1. In RAI 4.5-1, dated June 21, 2005, the staff requested that the applicant provide 4-29the basis for the reported usage factors in LRA Section 4.5. In addition, the staff requested thatthe applicant discuss the calculation of the F en multipliers used for each of the NUREG/CR-6260locations.In its response, dated August 16, 2005, the applicant stated that the fatigue usage reported inLRA Table 4.3.1-1 for the CSP nozzle was based on cycle counting, whereas, theenvironmental usage factor in LRA Section 4.5 was based on a detailed stress analysis. During a followup discussion on September 1, 2005, the applicant stated that the fatigue usage inTable 4.3.1-1 resulted from considering all load cycles at the maximum stress, and the usagefactor in LRA Section 4.5 resulted from separating the individual load cycles by stress level. Thestaff found this explanation reasonable.The applicant indicated that MNGP used HWC. The NUREG/CR-6260 components wereevaluated for a high oxygen environment without HWC. Oxygen concentration has a significant impact on the fatigue life of carbon and low-alloy steel components. HWC lowers the oxygen concentration in BWRs to reduce the stress-corrosion cracking potential of stainless steel components. The reduced oxygen concentration significantly reduces the environmental impact on the fatigue life of carbon and low-alloy steel components compared to equivalent NUREG/CR-6260 carbon and low-alloy steel components.NUREG/CR-6260 identified high environmental fatigue usage at the stainless steel CSP nozzlesafe end. The applicant replaced the CSP safe ends in 1986. The applicant stated that thereplaced CSP safe ends are carbon steel. Because the applicant has implemented an HWC program, the environmental impact on the fatigue usage of the carbon steel safe ends is not significant; therefore, the staff concluded that the applicant's calculated environmental fatigueusage for the CSP nozzle safe ends is reasonable and acceptable.Because the applicant uses HWC, usage factors for the FW nozzle and the FW line RCIC teeconnection are not directly comparable to the NUREG/CR-6260 values. The applicant statedthat it had recently evaluated these locations in detail for environmental fatigue. The applicantalso stated that the environmental factors for the evaluations considered both the times HWChad and had not been in operation. Since the FW nozzle safe ends were replaced in the 1980s, the lower environmental factor reflects the greater operating exposure to HWC. Considering the applicant's use of HWC and replacement of the FW nozzle safe ends in the 1980s, the reported environmental factors are reasonable; therefore, the staff found the applicant's evaluation of theenvironmental fatigue usage of the FW nozzle and the FW line RCIC tee connection acceptable.The applicant also evaluated the RHR piping tapered transition and RHR return line tee in detailfor environmental fatigue. The RHR return line tee was the bounding fatigue usage location.Since the RHR return line tee was replaced in the 1980s, it will be subject to fewer years ofservice than the component evaluated in NUREG/CR-6260. In addition, the environmentalfatigue criteria for the stainless evaluations in NUREG/CR-6260 were independent oftemperature. Later criteria in NUREG/CR-5704 found that the environmental effect on fatigueusage is insignificant at temperatures less than 200 C. The staff noted that RHR shutdowncooling initiates at less than 200 C. Considering the items discussed above, the applicant'senvironmental fatigue usage of the RHR return line tee is reasonable. Therefore, the staff foundthe applicant's evaluation of the environmental fatigue usage of the RHR return line teeacceptable.

4-30Based on its review, the staff found the applicant's response to RAI 4.5-1 acceptable becausethe applicant reasonably evaluated the environmental impact on the fatigue life of RCPBcomponents for the period of extended operation; therefore, the staff's concern described inRAI 4.5-1 is resolved.4.5.3 USAR Supplement The applicant provided a USAR supplement summary description of its TLAA evaluation of theeffects of the reactor coolant environment in LRA Section A3.7. On the basis of its review of the USAR supplement, the staff concluded that the summary description of the applicant's actions to address the effects of the reactor coolant environment is adequate.4.5.4 Conclusion The staff reviewed the applicant's TLAA regarding the effects of reactor coolant environment,as summarized in LRA Section 4.5, and concluded that the applicant provided an acceptabledemonstration, pursuant to 10 CFR 54.21(c)(1)(ii), that the analyses have been projected to theend of the period of extended operation. The staff also concluded that the USAR supplementcontains an appropriate summary description of this TLAA evaluation, sufficient to satisfy the requirements of 10 CFR 54.21(d).4.6 Fatigue Analyses of the Primary Containment, Attached Piping, and ComponentsThe Mark I containment consists of a freestanding steel containment drywell, vent system , andsteel pressure suppression chamber (torus). Large-scale testing of the Mark III containmentand in-plant testing of Mark I primary containment systems identified additional hydrodynamicloads not considered in the original containment design. The Mark I Owners Group initiated the Mark I Containment Program to develop a generic load definition and structural analysis techniques. The staff evaluation of the generic load definition and structural assessment techniques is in NUREG-0661, "Safety Evaluation Report, Mark I Containment Long TermProgram, Resolution of Generic Technical Activity A-7," July 1980. The Mark I Containment Long-Term Program evaluation of hydrodynamic loads included fatigue analyses of the torus

and vent system and of the torus attached piping (TAP).The containment liner plates, penetration sleeves (including dissimilar metal welds), andpenetration bellows may be designed in accordance with the ASME Code,Section III,requirements. If a plant's code of record requires a fatigue analysis, it may be a TLAA and must be evaluated in accordance with 10 CFR 54.21(c)(1) to ensure adequate management of the effects of aging on the intended functions for the period of extended operation.The staff reviewed the adequacy for the period of extended operation of the fatigue analyses ofthe metal containment, containment liner plates (including welded joints), penetration sleeves, dissimilar metal welds, and penetration bellows. SER Section 4.3 reviews the fatigue analyses of the pressure boundary of process piping, following the guidance in SRP-LR Section 4.3.

4-314.6.1 Fatigue Analysis of the Suppression Chamber, Vents, and Downcomers4.6.1.1 Summary of Technical Information in the ApplicationIn LRA Section 4.6.1, the applicant discussed the suppression chamber and vent systemfatigue analysis. New hydrodynamic loads were identified subsequent to the original design of the containment suppression chamber vents. These loads result from blowdown into the suppression chamber during a postulated LOCA and during safety relief valve (SRV) operation for plant transients. The applicant identified the vent header-downcomer intersection and the torus shell as the limiting locations in terms of fatigue usage. The applicant stated that the onlycontribution to fatigue usage during normal operation is from SRV operation and that the number of SRV actuations is not expected to exceed the design number through the period ofextended operation.4.6.1.2 Staff Evaluation The staff reviewed LRA Section 4.6.1, pursuant to 10 CFR 54.21(c)(1)(i), to verify that theanalyses will remain valid for the period of extended operation, and, pursuant to10 CFR 54.21(c)(1)(iii), to verify that the effects of aging on the intended functions will beadequately managed for the period of extended operation.The applicant stated that the Mark I Containment Program evaluated the suppression chamberand vent header system, including fatigue analyses of the torus shell and vent header system.The applicant's Mark I Containment Program Plant Unique Analysis Report summarized these analyses. The applicant subsequently reevaluated these locations for the increased number of SRV actuations postulated as a result of the 1998 power rerate. The resulting fatigue usage, considering the increase in SRV cycles, was less than the 1.0 allowable limit. The applicantestimated that the number of SRV cycles will not exceed the number used for the evaluation ofthe suppression chamber and vent header system during the period of extended operation. Inaddition, the applicant indicated that the Fatigue Monitoring Program monitors the number ofSRV lifts to assure that the usage factor remains below 1.0 for the limiting components.The staff found that the applicant's FMP will ensure that fatigue usage of the suppressionchamber vents and downcomers will remain below 1.0 for the period of extended operation, inaccordance with the requirements of 10 CFR 54.21(c)(1)(iii).4.6.1.3 USAR Supplement The applicant provided a USAR supplement summary description of its TLAA evaluation offatigue analysis of the suppression chamber, vents, and downcomers in LRA Section A3.8. On the basis of its review of the USAR supplement, the staff concluded that the summary description of the applicant's actions to address the fatigue analysis of the suppression chamber, vents, and downcomers is adequate.4.6.1.4 Conclusion The staff reviewed the applicant's TLAA regarding the fatigue analysis of the suppressionchamber, vents, and downcomers, as summarized in LRA Section 4.6.1, and concluded that 4-32the applicant has provided an acceptable demonstration, pursuant to 10 CFR 54.21(c)(1)(i), thatthe analyses will remain valid for the period of extended operation. In addition, the staffconcluded that, pursuant to 10 CFR 54.21(c)(1)(iii), the effects of aging on the int endedfunctions will be adequately managed for the period of extended operation. The staff alsoconcluded that the USAR supplement contains an appropriate summary description of this TLAA evaluation, sufficient to satisfy 10 CFR 54.21(d) requirements.4.6.2Fatigue Analysis of the SRV Piping Inside the Suppression Chamber and InternalStructures4.6.2.1 Summary of Technical Information in the ApplicationIn LRA Section 4.6.2, the applicant discussed the suppression chamber piping and internalsstructure fatigue evaluations. The reactor pressure relief system includes SRVs located on themain steamlines within the drywell between the reactor vessel and the first isolation valve. Theapplicant stated that it had not performed fatigue analyses for torus internal structures (i.e.,

catwalk and monorail). The applicant indicated that it had performed fatigue analyses for the SRV piping inside the torus. The applicant also stated that the SRV piping analyses will remainvalid for the period of extended operation.4.6.2.2 Staff Evaluation The staff reviewed LRA Section 4.6.2, pursuant to 10 CFR 54.21(c)(1)(ii), to verify that theanalyses have been projected to the end of the period of extended operation.The applicant stated that the fatigue analyses of the torus internal SRV piping had been part ofthe Mark I Containment Program. The applicant also indicated that the piping had beenevaluated for the 26-percent increase in the number of SRV cycles resulting from the 1998power rerate. The resulting 40-year fatigue usage was well below the allowable limit of 1.0. The applicant multiplied the resulting 40-year fatigue usage by 1.5 to estimate the fatigue usage for 60 years of plant operation.Because the applicant indicated that the number of SRV cycles used in the power rerateevaluation is conservative for 40 years of plant operation, the 1.5 factor provides a conservative estimate for the period of extended operation; therefore, the staff found that the applicantadequately demonstrated that the fatigue usage of the torus SRV piping will remain withinacceptable limits for the period of extended operation, in accordance with the requirements of10 CFR 54.21(c)(1)(ii).4.6.2.3 USAR Supplement The applicant provided a USAR supplement summary description of its TLAA evaluation offatigue analysis of the SRV piping inside the suppression chamber and internal structures in LRA Section A3.8. On the basis of its review of the USAR supplement, the staff concluded that the summary description of the applicant's actions to address the fatigue analysis of the SRV piping inside the suppression chamber and internal structures is adequate.

4-334.6.2.4 ConclusionThe staff reviewed the applicant's TLAA regarding the fatigue analysis of the SRV piping insidethe suppression chamber and internal structures, as summarized in LRA Section 4.6.2, and concluded that the applicant provided an acceptable demonstration, pursuant to10 CFR 54.21(c)(1)(ii), that the analyses have been projected to the end of the period ofextended operation. The staff also concluded that the USAR supplement contains anappropriate summary description of this TLAA evaluation, sufficient to satisfy 10 CFR 54.21(d) requirements.4.6.3 Fatigue Analysis of Suppression Chamber External Piping and Penetrations 4.6.3.1 Summary of Technical Information in the ApplicationIn LRA Section 4.6.3, the applicant discussed the fatigue analysis of suppression chamberexternal piping and penetrations. These analyses included the large- and small-bore TAP, suppression chamber penetrations, and the emergency core cooling system (ECCS) suctionheader and were based on cycles postulated to occur within the 40-year operating life of theplant. The applicant stated that these analyses will remain valid for the period of ext endedoperation.4.6.3.2 Staff Evaluation The staff reviewed LRA Section 4.6.3, pursuant to 10 CFR 54.21(c)(1)(ii), to verify that theanalyses have been projected to the end of the period of extended operation and, pursuant to10 CFR 54.21(c)(1)(iii), that the effects of aging on the intended functions will be adequatelymanaged for the period of extended operation.The applicant stated that fatigue effects were specifically addressed for the suppressionchamber TAP penetrations and the suction header in the Mark I Containment Program. The applicant indicated that it evaluated the TAP penetration fatigue analyses for the 26-percentincrease in SRV cycles resulting from the 1998 power uprate. The resulting 40-year fatigueusage was less than the allowable limit of 1.0. The applicant indicated that the FatigueMonitoring Program monitors the number of SRV lifts to assure that the usage factor remains below 1.0 for the limiting components.Because the number of SRV lifts is monitored, the staff found that the applicant's FMP willassure that the TAP penetrations fatigue usage will remain below 1.0 for the period of ext endedoperation, in accordance with the requirements of 10 CFR 54.21(c)(1)(iii).The applicant also stated that the Mark I Owner's Group had generically addressed TAP pipingfor all Mark I plants. The applicant identified the SRV piping as the limiting location and evaluated it for a 26-percent increase in the number of SRV cycles as a result of the 1998power rerate. The resulting 40-year fatigue usage was well below the 1.0 allowable limit. The applicant multiplied the resulting 40-year fatigue usage by 1.5 to estimate fatigue usage for 60 years of plant operation.

4-34Because the applicant indicated that the number of SRV cycles used in the power rerateevaluation is conservative for 40 years of plant operation, the 1.5 factor provides a conservative estimate for the period of extended operation; therefore, the staff found that the applicantadequately demonstrated that the fatigue usage of the torus SRV piping will remain withinacceptable limits for the period of extended operation, in accordance with the requirements of10 CFR 54.21(c)(1)(ii).4.6.3.3 USAR Supplement The applicant provided a USAR supplement summary description of its TLAA evaluation of thefatigue analysis of suppression chamber external piping and penetrations in LRA Section A3.8.

On the basis of its review of the USAR supplement, the staff concluded that the summary description of the applicant's actions to address the fatigue analysis of the suppression chamber external piping and penetrations is adequate.4.6.3.4 Conclusion The staff reviewed the applicant's TLAA regarding the fatigue analysis of the suppressionchamber external piping and penetrations, as summarized in LRA Section 4.6.3, and concluded that the applicant provided an acceptable demonstration, pursuant to 10 CFR 54.21(c)(1)(ii),that the analyses have been projected to the end of the period of extended operation. Inaddition, pursuant to 10 CFR 54.21(c)(1)(iii), the staff concluded that the effects of aging on theintended functions will be adequately managed for the period of extended operation. The staffalso concluded that the USAR supplement contains an appropriate summary description of this TLAA evaluation, sufficient to satisfy 10 CFR 54.21(d) requirements.4.6.4 Drywell-to-Suppression Chamber Vent Line Bellows Fatigue Analysis 4.6.4.1 Summary of Technical Information in the ApplicationIn LRA Section 4.6.4, the applicant discussed the fatigue analysis of the drywell-to-suppressionchamber vent line bellows. The applicant stated that the vent line bellows stresses are primarilycaused by differential thermal expansion during startup/shutdown and accident conditions. Theapplicant projected that the number of startup/shutdown cycles in the design will not be exceeded during the period of extended operation; therefore, the applicant concluded that theanalysis remains valid for that period.4.6.4.2 Staff Evaluation The staff reviewed LRA Section 4.6.4, pursuant to 10 CFR 54.21(c)(1)(i), to verify that theanalyses will remain valid for the period of extended operation.The applicant stated that the drywell-to-suppression chamber vent line bellows stresses areprimarily caused by differential thermal expansion of the reactor suppression chamber and drywell during normal startup and shutdown operations. The applicant stated that the designassumes 300 startup/shutdown cycles. As indicated in LRA Section 4.3, the applicant projectedfewer than 300 startup/shutdown cycles through the period of extended operation.

4-354.6.4.3 USAR SupplementThe applicant provided a USAR supplement summary description of its TLAA evaluation ofdrywell-to-suppression chamber vent line bellows fatigue analysis in LRA Section A3.8. On the basis of its review of the USAR supplement, the staff concluded that the summary description of the applicant's actions to address the drywell-to-suppression chamber vent line bellows fatigue analysis is adequate.4.6.4.4 Conclusion The staff reviewed the applicant's TLAA regarding the drywell-to-suppression chamber vent linebellows fatigue analysis, as summarized in LRA Section 4.6.4, and concluded that the applicant provided an acceptable demonstration, pursuant to 10 CFR 54.21(c)(1)(i), that the analyses willremain valid for the period of extended operation. The staff also concluded that the USARsupplement contains an appropriate summary description of this TLAA evaluation, sufficient to satisfy the requirements of 10 CFR 54.21(d).4.6.5 Primary Containment Process Penetration Bellows Fatigue Analysis 4.6.5.1 Summary of Technical Information in the ApplicationIn LRA Section 4.6.5, the applicant discussed the primary containment process bellows fatigueanalysis. Containment pipe penetrations required to accommodate thermal movement have expansion bellows. The applicant stated that these containment process bellows involve pipingsystems that penetrate the drywell shell and that these bellows were designed for a minimum of7000 operating cycles. The applicant indicated that the number of expected operati ng cycl esthrough the period of extended operation is much fewer than 7000; therefore, the applicantconcluded that the analysis of the containment process bellows will remain valid for the periodof extended operation.4.6.5.2 Staff Evaluation The staff reviewed LRA Section 4.6.5, pursuant to 10 CFR 54.21(c)(1)(i), to verify that theanalyses will remain valid for the period of extended operation.The applicant stated that the containment process piping penetration bellows were designed toASME Code Section III, Class B requirements, which do not require a formal fatigue analysis;however, the criteria for the attached process piping limit the number of full-range bending cycles. As discussed in SER Section 4.3, the applicant indicated that the number of expectedoperating cycles for the process piping is much fewer than 7000; therefore, the applicantconcluded that the analyses of the containment process piping bellows will remain valid for theperiod of extended operation.The staff found that the applicant's evaluation of the process piping provides a reasonableupper-bound estimate of the number of full-range thermal bending cycles for the process pipingpenetration bellows because the evaluation bounds the expected number of TTs, including the number of expected startup/shutdown cycles, for the facility.

4-364.6.5.3 USAR SupplementThe applicant provided a USAR supplement summary description of its TLAA evaluation ofprimary containment process penetration bellows fatigue analysis in LRA Section A3.8. On the basis of its review of the USAR supplement, the staff concluded that the summary description of the applicant's actions to address the primary containment process penetration bellows fatigue analysis is adequate.4.6.5.4 Conclusion The staff reviewed the applicant's TLAA of the primary containment process penetrationbellows fatigue analysis summarized in LRA Section 4.6.5 and concluded that the applicant provided an acceptable demonstration, pursuant to 10 CFR 54.21(c)(1)(i), that the analyses willremain valid for the period of extended operation. The staff also concluded that the USARsupplement contains an appropriate summary description of this TLAA evaluation, sufficient to satisfy the requirements of 10 CFR 54.21(d).4.7 Environmental Qualification of Electrical Equipment (EQ)4.7.1 Summary of Technical Information in the Application The 10 CFR 50.49, "Environmental Qualification of Electric Equipment Important to Safety forNuclear Power Plants," environmental qualification (EQ) program has been identified as a TLAA for the purposes of license renewal. The TLAA of EQ electrical components includes all long-lived, passive electrical components and instrumentation and controls (I&C) components that are important to safety and located in a harsh environment. The harsh environments of the plant are those areas that are subject to environmental effects by a LOCA or a high-energy line break (HELB). The EQ equipment comprises safety-related (SR) and Q-list equipment, nonsafety-related (NSR) equipment whose failure could prevent satisfactory accomplishment of any SR function, and necessary post-accident monitoring equipment.The applicant's EQ Program manages component thermal, radiation, and cyclic aging throughaging evaluations based on 10 CFR 50.49(f) qualification methods. Environmentally qualified equipment must be refurbished, replaced, or have its qualification extended before reaching the aging limits established in the aging evaluation. Aging evaluations for environmentally qualifiedequipment that specify the qualified life of at least 40 years are considered TLAAs for license renewal.4.7.2 Staff Evaluation The staff reviewed LRA Section 4.7, pursuant to 10 CFR 54.21(c)(1)(iii), to verify that theeffects of aging on the intended functions will be adequately managed for the period ofextended operation.The results of the electrical equipment EQ in LRA Section 4.7 indicate that the aging effects ofelectrical equipment EQ identified in the TLAA will be managed during the extended period ofoperation under 10 CFR 54.21(c)(1)(iii); however, the applicant did not submit information onthe attribute of a reanalysis of an aging evaluation to extend the qualification life of such 4-37electrical equipment identified in the TLAA. The important attributes of a reanalysis are theanalytical methods, the data collection and reduction methods, the underlying assumptions, the acceptance criteria, and the corrective actions. In RAI 4.7-1, dated November 7, 2005, the staffrequested that the applicant provide information about the important attributes of reanalysis ofan aging evaluation of electrical equipment identified in the TLAA to extend the qualificationunder 10 CFR 50.49(e).In its response, by letter dated December 7, 2005, the applicant stated that the reanalysis of anaging evaluation normally extends the qualification by reducing excess conservatism incorporated in the prior evaluation. The staff reviewed this information and found the applicant's response satisfactory; therefore, the staff's concern described in RAI 4.7-1 is resolved.The staff also reviewed the EQ Program to determine whether it will assure that the electricalcomponents covered under this program will continue to perform their intended functionconsistently with the CLB for the period of extended operation. The staff's evaluation of thecomponent qualification focused on how the program manages the aging effects through effective incorporation of the following 10 elements-program scope, preventive action, parameters monitored or inspected, detection of aging effects, monitoring and trending, acceptance criteria, corrective actions, confirmation process, administrative controls, and operating experience.Program Scope Pursuant to 10 CFR 50.49, the EQ Program evaluates harsh environments in which electricalequipment important to safety may be required to operate. The applicant stated that anequipment master list, maintained at MNGP, includes SR electrical equipment, NSR equipment whose failure could prevent accomplishment of safety functions, and certain post-accident monitoring equipment. The staff considered the scope of the program acceptable.Preventive Actions The ongoing EQ Program ensures that electrical equipment important to safety is capable ofperforming its intended function in a harsh environment, in accordance with 10 CFR 50.49.

Although 10 CFR 50.49 does not require actions that prevent aging effects, EQ Programactions that could be viewed as preventive actions include (1) establishing the component service condition tolerance and aging limits (e.g., qualified life or condition limit) and (2) where applicable, requiring specific installation, inspection, monitoring, or periodic maintenance actions to manage equipment aging effects within the qualification. The staff considered these actions acceptable because 10 CFR 50.49 does not require actions that prevent aging effects.Parameters Monitored or Inspected The applicant stated that qualified life is not based on condition or performance monitoring.Pursuant to 10 CFR 50.49(e), the qualification must include and be based on temperature and pressure, humidity, chemical effects, radiation, aging, submergence, synergistic effects, and margins. Pursuant to RG 1.89, Revision 1, "Environmental Qualification of Certain Electric Equipment Important to Safety for Nuclear Power Plants," issued June 1984, monitoring or inspection of certain environmental conditions or component parameters may be used to ensure that the component is within the bounds of its qualification basis or as a means to modify the qualified life. The applicant's EQ Coordinator is responsible for reviewing program 4-38data and industry information. Deviations are documented in the Corrective Action Program(CAP) and actions to correct identified issues may include monitoring, inspection, reanalysis, or testing. For example, the EQ Coordinator monitors radiation protection surveys for changes inradiation levels and has initiated a temperature monitoring program in areas containing EQ equipment. The staff considered this monitoring approach appropriate because the program objective is to ensure that the established qualified life of devices is not exceeded.Detection of Aging Effects 10 CFR 50.49 does not require the detection of aging effects for inservice components. Theapplicant stated that the CAP, the Preventive Maintenance Program, and the Quality ControlProgram will identify any aging effects of EQ equipment and initiate corrective action required tomaintain equipment qualification. In addition, monitoring and inspection of certain environmental conditions or component parameters may be used to ensure that the component is within the bounds of its qualification basis, or as a means to modify the qualified life. The staff considered the applicant's above programs to detect aging effects acceptable.Monitoring and Trending 10 CFR 50.49 does not require monitoring and trending of component condition or performanceparameters of inservice components to manage the effects of aging. The EQ Program actions that could be viewed as monitoring include monitoring how long qualified components have been installed. Monitoring or inspecting certain environmental, condition, or component parameters may be used to ensure that a component is within its qualification or as a means to modify the qualification. The staff considered this program acceptable because 10 CFR 50.49 does not require monitoring and trending of component condition or performance parameters of inservice components to manage the effects of aging.Acceptance Criteria 10 CFR 50.49 acceptance criteria require that an inservice EQ component is maintained withinits qualification including its (a) established aging limits and (b) continued qualification for the projected accident conditions. 10 CFR 50.49 requires refurbishment, replacement, or requalification before exceeding the aging limits of each installed device. The applicant stated that its program has identified all components subject to the 10 CFR 50.49 acceptance criteriaon an SR equipment master list. The EQ Coordinator maintains calculations supporting equipment qualification, which include such information as location, environmental conditions, qualification methods, and acceptance criteria. Before reaching the end of qualified life, affected components are refurbished, requalified, or replaced to ensure continued functionality of the installed components. The staff considered this program acceptable since it is consistent with 10 CFR 50.49 requirements of refurbishment, replacement, or requalification before exceeding the qualified life of each installed device.Corrective Actions, Confirmation Process, and Administrative Controls The applicant stated that if an EQ component is found to be outside the bounds of itsqualification basis, it implements corrective actions in accordance with the station's CAP. When operational or maintenance activities identify unexpected adverse conditions affecting the environment of a qualified component, it is evaluated and the applicant takes appropriate corrective actions, which may include changes to the qualification bases and conclusions.

When an emerging industry aging issue is identified that affects the qualification of an EQ 4-39component, it is evaluated and the applicant takes appropriate corrective actions, which mayinclude changes to the qualification bases and conclusions. The staff considered this acceptable because the corrective actions are implemented in accordance with the requirements of Appendix B to 10 CFR Part 50, which ensures the adequacy of corrective actions. SER Section 3.0.4 addresses the evaluations of these program elements.Operating Experience The EQ Program includes monitoring and assessment of industry information to assess itsimpact on EQ components. The applicant stated that the EQ Coordinator is responsible forreviewing the disposition of such information, as well as subsequent assignment of actions to be taken on such information and confirmation that the completion of the actions satisfactorily address potential EQ aging issues. The staff found that the applicant adequately addressedoperating experience.4.7.3 USAR Supplement The applicant provided a USAR supplement summary description of its TLAA evaluation ofelectrical equipment EQ in LRA Section A3.9. On the basis of its review of the USAR supplement, the staff concluded that the summary description of the applicant's actions to address electrical equipment EQ is adequate.4.7.4 Conclusion The staff concluded that the applicant provided an acceptable demonstration regardingelectrical equipment EQ, pursuant to 10 CFR 54.21(c)(1)(iii), that the effects of aging on theintended functions will be adequately managed for the period of extended operation. The staffalso concluded that the USAR supplement contains an appropriate summary description of this TLAA evaluation, sufficient to satisfy the requirements of 10 CFR 54.21(d).4.8 Stress Relaxation of Rim Holddown Bolts4.8.1 Summary of Technical Information in the ApplicationIn LRA Section 4.8, the applicant summarized the evaluation of the stress relaxation of rimholddown bolts for the period of extended operation. As described in the SER to BWRVIP-25, plants must consider relaxation of the rim holddown bolts as a TLAA issue. Because MNGP has not installed core plate wedges, the loss of preload must be considered in the TLAA evaluation.4.8.2 Staff Evaluation The staff reviewed LRA Section 4.8, pursuant to 10 CFR 54.21(c)(1)(ii), to verify that theanalyses have been projected to the end of the period of extended operation.The LRA states that, for the period of extended operation, the expected preload loss for the rimholddown bolts was assumed to be 19 percent, which bounds the original BWRVIP analysis.

With a 19-percent preload loss, the core plate will maintain sufficient preload to prevent slidingunder both normal and accident conditions.In a letter dated June 10, 2005, the applicant provided additional details of the analysis for therim holddown bolts:

4-40To more accurately address MNGP for License Renewal, a plant-specificcalculation was performed that incorporated the MNGP core plate geometry, anoperating temperature of 288 C (550 F) and a MNGP fluence calculation thatwas performed specifically for License Renewal in accordance with guidance provided in Regulatory Guide 1.190, 'Calculational and Dosimetry Methods for Determining Pressure Vessel Neutron Fluence,' March 2001, (LRA Section 4.2.1). The maximum fluence applicable to the bolts in the highest fluence region of the core plate was determined to be 2.2x10 19 n/cm 2 at the endof the 60-year plant life. The resultant relaxation was determined to be 8 percent based on GE Design Documents. The analysis assumed that all of the bolts were at this fluence even though many bolts experience a lower fluence depending on their specific location...In RAI 4.8-2, dated September 28, 2005, the staff requested that the applicant provide thestress relaxation curves, information regarding the material type, the loads used to develop the stress relaxation curves, and show that the axial and bending stresses for the mean and highest loaded holddown bolts will not exceed the ASME allowable stresses.In its response, dated October 28, 2005, the applicant provided, "The Relaxation of IrradiatedAustenitic Steels and Ni-GE Mean Design Curve," based on a model that assumed a stress-linear, primary plus secondary creep law form and was fit to the shown data using stepwise multiple regression.The rim holddown bolts are Type 304 stainless steel. The data used to develop the curveinclude several austenitic materials. The applicant analyzed the impact of austenitic material type on stress relaxation from neutron radiation. In its letter, dated October 28, 2005, the applicant stated the following:Relaxation of irradiated, structural materials from radiation creep is much lesssensitive to 'normal material variations' (e.g., in austenitic stainless steels) than other radiation properties. Radiation segregation and hardening characteristics are similar for all austenitic stainless steels, although some experience presegregation (from annealing). Also, neutron relaxation is among the most consistent and reproducible phenomenon, and little variation is observed in stainless steel (e.g., 304, 316, 321, 347/8, L-grade and nuclear grade). The relaxation behavior of these stainless steels is often used for many different austenitic alloys such as Nitronic 50, Alloy X-750 and Alloy 718.To support the conclusion that the GE design curves apply to Type 304 stainless steel, theapplicant presented stress relaxation data from the BWRVIP-99 report, "Crack Growth Rates in Irradiated Stainless Steels in BWR Internal Components," and from J.P. Foster and Halden.

The GE design curve predicts higher relaxation levels (i.e., lower fraction of load remaining) than observed from the Foster and Halden data and is thus conservative compared to these

data.The analysis included the impact of test temperature and neutron flux on stress relaxation:More than 80 percent of the tests, shown in Figure 1, were conducted at atemperature of 550 F and a majority of these were conducted in an operatingBWR environment. The other tests, were conducted at either 570 or 600 Fwhich is expected to produce more relaxation. Since such a large portion of the 4-41data was conducted at typical BWR operating conditions, the data temperature isconsidered fully representative of the core plate bolts.While the cumulative fluence information was available as part of the original testreports and the GE Design Curve documentation, the flux conditions were not directly available. Many of the tests were associated with springs which had reached fluences ranging from 8x10 20 to 8x10 21 n/cm 2. Based on a reasonableexposure time, the flux will be expected to range from 7x10 12 to 9x10 13 n/cm 2/s.The fluxes defined for two of the smaller sets of test data were 2.7x10 14 and2x10 17 n/cm 2/s, respectively. Review of the data over these four orders ofmagnitude showed no discernable flux dependence; however, the neutron flux levels were at least 100 times higher than that experienced by the core plate bolts. As described above, the temperature data are representative for use in the core plate bolt evaluation. The neutron flux data, however, was measured in specimens subject to fluxes ranging from 1x10 13 to 2x10 17 n/cm 2/s, which ishigher than the 8.5x10 9 n/cm 2/s average flux experienced by the core plate boltsthemselves. Given the large range of higher flux for which the properties are the same, the impact of the lower flux to which the bolts are exposed is viewed as negligible.Based on the analysis and supporting data, the staff agreed with the applicant that the GEdesign curves apply to Type 304 stainless steel used in the core plate bolts.Based on the GE design curves and a neutron fluence of 2.2x10 19 n/cm 2 (E > 1.0 MeV), theapplicant determined that the amount of stress relaxation at the end of the period of extendedoperation would be 8 percent. This neutron fluence was calculated using a procedure which is in accordance with the guidance in RG 1.190 and corresponds to the maximum fluence applicable to the bolts at the end of the period of extended operation.The applicant also performed a plant-specific analysis to show that the axial and bendingstresses in the core plate holddown bolts, considering the loss of preload (8 percent) at the endof the period of extended operation, will not exceed the ASME Code,Section III allowable Pm(membrane) and Pm + Pb (membrane + bending) stresses. The analysis was based on the assumption that sufficiently high frictional forces, resulting from the preload forces in the bolts and coefficient of static friction test data between the rim and the support surfaces, will beinduced between the core plate rim and the shroud support to prevent sliding of the core plateunder design-basis loading resulting from maximum horizontal and vertical seismic and accident loads. Under this scenario, no bending stresses are induced in the holddown bolts.

The only stresses sustained by the holddown bolts are axial, resulting from the preload and the vertical loading (differential pressure and seismic) on the plate. These stresses were shown to be considerably lower than the ASME Section III allowable Pm stress.The staff evaluated this analysis and concluded that the postulated coefficient of static frictionwas not applicable under the reactor fluid operating environment because of other coefficientsof friction data indicating that a lower value may be appropriate. A smaller coefficient of static friction permits sliding of the core plate under horizontal acceleration and induces bending stresses in the bolts. This analysis was, therefore, found to be unacceptable.Inspection and flaw evaluation guidelines of BWR core support plates were previouslysubmitted to the NRC in BWRVIP-25, "BWR Core Plate Inspection and Flaw EvaluationGuidelines," issued December 1996. Appendix A to this report contains a prototypical core plate 4-42holddown bolt analysis under representative horizontal and vertical seismic and accident-loading conditions. The analysis was based on a finite element analysis of the core plate and the holddown bolts and did not credit friction between the core rim and the shroud support. This analysis demonstrated that the mean axial and axial + bending stresses in the holddown bolts meet the ASME Section III bolt stress criteria in the report under typical accident loading. Thestaff reviewed this report and found it acceptable for referencing in LRAs, as stated by letter dated September 6, 2000. Therefore, the staff requested that the applicant perform an analysis,consistent with the methodology used in Appendix A to BWRVIP-25, and demonstrate that thebolt axial and bending stresses meet the ASME Section III Pm and Pm + Pb stress criteria inthe report.By letter dated February 27, 2006, the applicant provided GE technical reportGE-NE-0000-0050-5900P, "Comparative Evaluation of the Monticello Core Plate Rim Hold-down Bolts and BWRVIP-25, Appendix A Analysis," issued February 2006. This analysis demonstrates that the MNGP mean axial and bending core plate holddown bolt stresses, considering holddown bolt stress relaxation, were bounded by the analysis approved in BWRVIP-25. However, the horizontal and vertical loads used in the analysis were considerably smaller than those used in the BWRVIP-25 analysis, resulting from the exclusion of certain accident loads, such as SRV hydrodynamic loads, that were considered in the BWRVIP-25 analysis. The staff requested that the applicant provide justification for the exclusion of theseloads. In its response, dated March 31, 2006, the applicant stated that all applicable DBA loadsspecific to the MNGP core plate were applied and provided the horizontal and vertical accelerations at the core plate level. The applicant justified the exclusion of the hydrodynamic loads on the basis that these are not applicable to the MNGP vessel and internals since theMNGP is a BWR/3 Mark I design. The Mark I torus is structurally isolated from the containment by the use of flexible bellows, and the hydrodynamic loads caused by SRV lift and LOCA are, therefore, not transmitted to the containment or the vessel. The staff found this justificationreasonable and acceptable.The BWRVIP-25 analysis is based on a finite element analysis of the core plate and holddownbolts. It was originally performed to help utilities determine a strategy for core plate inspections, wherein conservative geometric conditions and bounding, postulated worst-case scenarios were considered. Because of the similarities in the MNGP and the BWRVIP-25 plates, the applicant/GE used data from the BWRVIP-25 core plate finite element analysis, an analytical procedure, and a comparison to the MNGP specific core plate and loads to extrapolate the BWRVIP-25 analysis to the MNGP core plate and holddown bolts. The applicant showed that the mean core plate bolt axial and axial + bending stresses met the ASME Section III stresscriteria in BWRVIP-25. However, the BWRVIP-25 analysis also indicated that not all holddown bolts are uniformly loaded under horizontal and vertical loading. Based on data shown in BWRVIP-25, the staff also determined that the axial + bending stresses in the highest loadedMNGP holddown bolts could exceed the Pm + Pb stress criterion of BWRVIP-25, but by an insignificant margin. However, the applicant's analysis also included bending stresses in the holddown bolts from core plate bowing, which the BWRVIP-25 analysis did not consider. The staff evaluated the applicant's analysis and concluded that it is acceptable because it conformswith accepted structural analysis practice. Therefore, the staff's concern described in RAI 4.8-2 is resolved.4.8.3 USAR Supplement The applicant provided a USAR supplement summary description of its TLAA evaluation ofstress relaxation of rim holddown bolts in LRA Section A3.6. In its letter, dated April 10, 2006, 4-43the applicant provided a revised USAR supplement description which summarized the results ofthe analysis provided in the GE technical report. On the basis of its review of the USAR supplement description provided in the applicant's letter, dated April 10, 2006, the staffconcluded that the summary description of the applicant's actions to address the stress relaxation of rim holddown bolts adequately describes the analysis characterized in the GE technical report.4.8.4 Conclusion The staff concluded that the applicant provided an acceptable demonstration, pursuant to10 CFR 54.21(c)(1)(ii), that the stress relaxation of rim holddown bolts analyses have been projected to the end of the period of extended operation. The staff also concluded that theUSAR supplement contains an appropriate summary description of this TLAA evaluation, sufficient to satisfy the requirements of 10 CFR 54.21(d).4.9 Reactor Building Crane Load Cycles4.9.1 Summary of Technical Information in the Application In LRA Section 4.9, the applicant summarized the evaluation of the reactor building crane loadcycles for the period of extended operation. The MNGP reactor building cr ane system consistsof an 85-ton bridge crane. The crane is capable of handling the drywell head, reactor vessel head, pool plugs, and spent fuel pool shipping cask. A refueling service platform, with necessary handling and grappling fixtures, services the refueling area and the spent fuel pool.

The reactor building cr ane system has been modified to incorporate redundant safety featureswhich were not a part of the original design. The modification consists of a new trolley with redundant design features and a capacity of 85 tons on the main hook with redundancy features and an auxiliary 5-ton capacity hook. This modification was implemented for handlingheavy loads, both during refueling operations and during operations involving the offsite shipment of spent fuel. Such offsite shipments of fuel can take place when the plant is operating or shut down. The redundant crane was installed to reduce the probability of a heavyload drop to the category of an incredible event. NUREG-0612 suggests that cranes should bedesigned to meet the applicable criteria and guidelines of Chapter 2-1 of American National Standards Institute (ANSI) B30.2-1976, "Overhead and Gantry Cranes," and of CraneManufacturers Association of America (CMAA)-70, "Specifications for Electric Overhead Traveling Cranes." The reactor building crane, manufactured before the issuance of CMAA-70 and ANSI B30.2-1976, was designed to meet Electric Overhead Crane Institute (EOCI) 61.

Since the evaluati on used, as a basis, an expected number of load cycles over the 40-year lifeof the plant, reactor building crane load cycles are a TLAA.4.9.2 Staff Evaluation The staff reviewed LRA Section 4.9, pursuant to 10 CFR 54.21(c)(1)(i), to verify that theanalyses will remain valid for the period of extended operation.In LRA Section 4.9, which is related to the reactor building crane load cycles TLAA, theapplicant stated that the current analysis of the fatigue life remains valid for the 60-yearextended operating period. It is the staff's understanding that this crane will also handle spentfuel pool shipping casks. A refueling service platform with handling and grappling fixturesservices the refueling area and the spent fuel pool.

4-44The staff's review of LRA Section 4.9 identified an area for which it needed additionalinformation to complete its evaluation of the applicant's results. The applicant responded to the staff's RAI as discussed below.In RAI 4.9-1, dated July 20, 2005, the staff indicated concerns regarding the fatigue analysis forthe reactor building crane. Therefore, the staff requested that the applicant provide a fatigueanalysis associated with lifts of spent fuel casks and explain how the heavy-load fatigueanalysis in LRA Section 4.9 governs the TLAA.In its response, dated August 16, 2005, the applicant stated the following:Section 4.9 of the LRA accounted for cycles due to anticipated lifts of spent fuel casks by the addition of heavy lift cycles. The current analysis conservativelyassumed 1,120 cycles (for 40 years of operation) due to lifts of reactor buildingshield blocks and plugs, the reactor vessel head, the drywell vessel head, thesteam separator assembly, and the steam dryer assembly. The difference between 1,120 to 2,000 cycles identified in Section 4.9 includes consideration ofadditional spent fuel cask lifts, as well as additional current design basis lifts attributable to the license renewal period of extended operation.The reactor building crane is currently being upgraded from 85 tons to 105 tonsin anticipation of spent fuel cask duty. Crane calculations are being performed in accordance with CMAA 70-1975, which identifies stress ranges and allowable cycles. Preliminary calculations demonstrate that the maximum stress range forthe upgrade design is less than the allowable stress range for the most severe crane classification operating up to 100,000 cycles. The remaining cranecomponents are being designed with a 5:1 safety factor, which assures that the fatigue threshold for 100,000 cycles will not be exceeded. Assuming thatoffloading of fuel to a spent fuel storage facility must begin with the next refuelingoutage at a rate equal to fuel replenishments, as well as spent fuel pool offloading due to decommissioning activities, the total number of additional cycles is not expected to exceed 120. This includes the conservativeconsideration that both cask placement for acceptance of spent fuel and removalof the loaded cask to the spent fuel transfer vehicle are at fully loaded conditions.

This results in a total number of cycles, at maximum load for 60 years ofoperation, of 1,800 out of 70,000 allowable cycles identified in the LRA.The crane upgrade calculations have not been completed. Upon completion ofthe modification analysis, an evaluation will be made to determine the effect, ifany, on Section 4.9. If the results are not bounded by the current LRA evaluation/disposition, a revised Section 4.9 will be included with the first AnnualLRA Supplement required by 10 CFR 54, § 54.21(b).In its letter, dated February 28, 2006, the applicant verified that the new calculations werecompleted and were bounded by the original evaluation; therefore, the staff's concern describedin RAI 4.9-1 is resolved.4.9.3 USAR Supplement The applicant provided a USAR supplement summary description of its TLAA evaluation ofreactor building crane load cycles in LRA Section A3.10. On the basis of its review of the USAR 4-45supplement, the staff concluded that the summary description of the applicant's actions toaddress the reactor building crane load cycles is adequate.4.9.4 Conclusion The staff concluded that the applicant provided an acceptable demonstration, pursuant to10 CFR 54.21(c)(1)(i), that the reactor building crane load cycles analyses will remain valid forthe period of extended operation. The staff also concluded that the USAR supplement containsan appropriate summary description of this TLAA evaluation, sufficient to satisfy 10 CFR 54.21(d) requirements.4.10 Fatigue Analyses of HPCI and RCIC Turbine Exhaust Penetrations4.10.1 Summary of Technical Information in the Application In LRA Section 4.10, the applicant discussed the evaluation of the high-pressure coolantinjection (HPCI) and RCIC turbine exhaust penetrations fatigue analyses. The applicant evaluated these penetrations for the combination of SRV actuations, LOCA loads, andoperational testing of the turbines and concluded that the fatigue usage of the HPCI and RCICturbine exhaust penetrations will remain below 1.0 during the period of extended operation.4.10.2 Staff Evaluation The staff reviewed LRA Section 4.10, pursuant to 10 CFR 54.21(c)(1)(ii), to verify that theanalyses have been projected to the end of the period of extended operation.The applicant evaluated the HPCI and RCIC turbine exhaust penetrations for an increasednumber of SRV cycles resulting from the 1998 power rerate. The applicant combined thefatigue usage from SRV actuations with the LOCA and operating-basis earthquake (OBE) fatigue usage. The resulting 40-year fatigue usage was well below the 1.0 allowable limit. The applicant multiplied the resulting 40-year fatigue usage by 1.5 to estimate the fatigue usage for 60 years of plant operation. The resulting fatigue usage was well below the 1.0 allowable limit.Based on its review, the staff concluded that the 1.5 factor provides a conservative estimate ofthe fatigue usage from SRV actuations, simultaneously with a LOCA and OBE, for the period ofextended operation.The applicant evaluated the fatigue usage from operational testing of the HPCI and RCICturbines separately. The applicant instrumented these nozzles to measure temperatures during the operational tests and calculated the maximum fatigue usage for the RCIC turbine exhaust penetration from these operational tests. The RCIC turbine exhaust penetration had the greatest fatigue usage. The applicant determined that the total fatigue usage will be acceptable,considering more than five RCIC turbine tests per month over the 60-year extended life.

Therefore, the applicant concluded that the analyses of the HPCI and RCIC turbine exhaustpenetrations will remain valid for the period of extended operation. The staff agreed that thenumber of HPCI and RCIC turbine tests will average fewer than five per month.Based on its review of the applicant's analysis, the staff found that the applicant adequatelydemonstrated that the fatigue usage of the HPCI and RCIC turbine exhaust penetrations willremain within acceptable limits for the period of extended operation, in accordance with 10 CFR 54.21(c)(1)(ii) requirements.

4-464.10.3 USAR SupplementThe applicant provided a USAR supplement summary description of its TLAA evaluation offatigue analyses of HPCI and RCIC turbine exhaust penetrations in LRA Section A3.11. On the basis of its review of the USAR supplement, the staff concluded that the summary description of the applicant's actions to address the fatigue analyses of HPCI and RCIC turbine exhaust penetrations is adequate.4.10.4 Conclusion The staff reviewed the applicant's TLAA regarding the fatigue analyses of HPCI and RCICturbine exhaust penetrations, as summarized in LRA Section 4.10, and concluded that the applicant has provided an acceptable demonstration, pursuant to 10 CFR 54.21(c)(1)(ii), thatthe analyses have been projected to the end of the period of extended operation. The staff alsoconcluded that the USAR supplement contains an appropriate summary description of this TLAA evaluation, sufficient to satisfy the requirements of 10 CFR 54.21(d).4.11 Conclusion for Time-Limited Aging AnalysesThe staff reviewed the information in LRA Section 4, "Time-Limited Aging Analyses." On thebasis of its review, the staff concluded that the applicant provided an adequate list of TLAAs, as defined in 10 CFR 54.3. Further, the staff concluded that the applicant demonstrated that(1) the TLAAs will remain valid for the period of extended operation, as required by10 CFR 54.21(c)(1)(i), (2) the TLAAs have been projected to the end of the period of extendedoperation, as required by 10 CFR 54.21(c)(1)(ii), or (3) that the aging effects will be adequatelymanaged for the period of extended operation, as required by 10 CFR 54.21(c)(1)(iii). The staffalso reviewed the USAR supplement for the TLAAs and found that the USAR supplement contains descriptions of the TLAAs sufficient to satisfy the requirements of 10 CFR 54.21(d). In addition, the staff concluded that no plant-specific exemptions are in effect that are based onTLAAs, as required by 10 CFR 54.21(c)(2).

5-1SECTION 5REVIEW BY THE ADVISORY COMMITTEE ON REACTORSAFEGUARDSIn accordance with Title 10, Section 54.25, "Report of the Advisory Committee on ReactorSafeguards," of the Code of Federal Regulations (10 CFR 54.25), the Advisory Committee onReactor Safeguards (ACRS) will review the license renewal application (LRA) for the MonticelloNuclear Generating Plant. The ACRS Subcommittee on Plant License Renewal will continue itsdetailed review of the LRA after this safety evaluation report (SER) is issued. The applicant and the staff from the U.S. Nuclear Regulatory Commission (the staff) will meet with thesubcommittee and the full committee to discuss issues associated with the review of the LRA.After the ACRS completes its review of the LRA and the SER, the full committee will issue areport discussing the results of the review. An update to this SER will include the ACRS report.This update will also include the staff's response to any issues and concerns identified in theACRS report.

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6-1SECTION 6CONCLUSIONThe staff of the U.S. Nuclear Regulatory Commission (NRC or the staff) reviewed the licenserenewal application (LRA) for the Monticello Nuclear Generating Plant (MNGP), in accordance with the NRC regulations and NUREG-1800, "Standard Review Plan for Review of LicenseRenewal Applications for Nuclear Power Plants," dated July 2001. Title 10, Section 54.29, "Standards for Issuance of a Renewed License," of the Code of Federal Regulations(10 CFR 54.29) provides the standards for issuance of a renewed license.On the basis of its review, the staff concluded that the applicant adequately identified thosesystems and components that are within the scope of license renewal, as required by10 CFR 54.4(a), and those systems and components that are subject to an aging managementreview, as required by 10 CFR 54.21(a)(1). The staff also concluded that the applicant demonstrated that the aging effects will be adequately managed so that the intended functionswill be maintained consistent with the current licensing basis (CLB) for the period of extendedoperation, as required by 10 CFR 54.21(a)(3). Further, the staff concluded that the applicantdemonstrated that (1) the time-limited aging analyses (TLAAs) will remain valid for the period ofextended operation, as required by 10 CFR 54.21(c)(1)(i), (2) the TLAAs had been projected tothe end of the period of extended operation, as required by 10 CFR 54.21(c)(1)(ii), or (3) thatthe aging effects will be adequately managed for the period of extended operation, as requiredby 10 CFR 54.21(c)(1)(iii). On the basis of its evaluation of the LRA, the staff determi ned thatthe requirements of 10 CFR 54.29(a) have been met, that there is reasonable assurance thatthe activities authorized by the renewed license will continue to be conducted in accordancewith the CLB, and that any changes made to the plant's CLB in order to comply with this paragraph are in accord with the Act and the Commission's regulations.The staff notes that any requirements of Subpart A, "National Environmental PolicyAct-Regulations Implementing Section 102(2)," of 10 CFR Part 51, "Environmental Protection Regulations for Domestic Licensing and Related Regulatory Functions," are documented in draft Supplement 26 to NUREG-1437, "Generic Environmental Impact Statement for LicenseRenewal of Nuclear Plants: Regarding Monticello Nuclear Generating Plant Final Report,"

dated January 23, 2006.

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A-1APPENDIX ACOMMITMENTS FOR LICENSE RENEWAL OF MNGPDuring the review of the Monticello Nuclear Generating Plant license renewal application, theapplicant made commitments to manage the aging effects of structures and components before the period of extended operation. The following table lists these commitments, along with theimplementation schedule and the source of the commitment.

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A-3APPENDIX A: COMMITMENTS FOR LICENSE RENEWAL OF MNGPItem No.CommitmentImplementationScheduleSource1Each year, following the submittal of the MNGP LicenseRenewal Application and at least 3 months before the scheduledcompletion of the NRC review, NMC will submit amendments tothe MNGP application pursuant to 10 CFR 54.21(b). Theserevisions will identify any changes to the CLB that materiallyaffect the contents of the LRA, including the USAR supplementsand any other aspects of the application.AnnuallyLRA Section 1.42In accordance with the guidance of Appendix A.3.2.1.2 toNUREG-1800, Appendix B to the latest issued supplement toNUREG-0933 will be reviewed for new GSls desi gnated asUSI-, HIGH-, or MEDIUM-priority. Any GSIs identified thatinvolve TLAAs or aging effects for structures and componentssubject to an aging management review will be included in theannual update of the LRA. AnnuallyLRA Section 3.0.73Inspection of the steam dryer is to be accomplished using theguidelines in the approved BWRVIP topical report(s) for steamdryer inspection. In the event a new steam dryer is installed,NMC will reevaluate the inspection requirements.As RequiredLRA Table3.1.2-3, Note 1364The interior of the diesel fire pump house masonry block walls iscovered with insulation. The MNGP Structures MonitoringProgram will require the interior surfaces of the walls to beexamined if exterior wall surfaces show evidence of significantaging effects.As RequiredLRA Table3.5.2-8, Note 516 APPENDIX A: COMMITMENTS FOR LICENSE RENEWAL OF MNGPItem No.CommitmentImplementationScheduleSourceA-45The procedures and training used to limit RPV coldoverpressure events will be the same as those approved by the NRC when MNGP requested approval of the BWRVIP-05technical alternative for the term of the current operatinglicense. A request for extension for the 60-yearextended operating period will be submitted to the NRC beforethe period of extended operation.As RequiredLRA Section 4.2.66MNGP site-specific administrative work instructions will beapplicable to both safety- and nonsafety-related systems,structures, and components that are subject to an agingmanagement review consistent with the current licensing basisduring the period of extended operation.Prior to Period ofExtended OperationLRA Section B1.37Site documents that implement aging management activities forlicense renewal will be enhanced to ensure that an AR isprepared in accordance with plant procedures whenevernonconforming conditions are found (i.e., the acceptance criteriais not met).Prior to Period ofExtended OperationLRA Section B1.38Revisions will be made to procedures and instructions thatimplement or administer aging management programs and/oractivities for the purpose of managing the associated agingeffects for the duration of extended operation.Prior to Periodof ExtendedOperationLRA Section B1.39The MNGP ASME Section XI, Subsection IWF Program will beenhanced to provide inspections of Class MC componentsupports consistent with NUREG-1801, Chapter III, Section B1.3.Prior to Periodof ExtendedOperationLRA Section B2.1.3 APPENDIX A: COMMITMENTS FOR LICENSE RENEWAL OF MNGPItem No.CommitmentImplementationScheduleSourceA-510The guidance for performing visual bolting inspections containedin EPRI TR-104213, Bolted Joint Maintenance & ApplicationGuide, and the Good Bolting Practices Handbook (EPRINP-5067 Volumes I and 2) will be included in the Bus DuctInspection Program, Inspection of Overhead Heavy Load andLight Load (Related to Refueling) Handling Systems Program,Structures Monitoring Program, and the System ConditionMonitoring Program.Prior to Periodof ExtendedOperationLRA Section B2.1.411The Buried Piping and Tanks Inspection Program will update theimplementing procedures to include inspections of buriedcomponents when they are uncovered.Prior to Periodof Extended OperationLRA Section B2.1.512The diesel fuel oil storage tank, T-44, internal inspection will beadded to the list of scheduled inspections in the Buried Pipingand Tanks Inspection Program.Prior to Periodof ExtendedOperationLRA Section B2.1.513The Buried Piping and Tanks Inspection Program will be revisedto include a provision that if evaluations of pipe wall thicknessshow a susceptibility to corrosion, further evaluation as to theextent of susceptibility will be performed.Prior to Periodof ExtendedOperationLRA Section B2.1.514The Buried Piping and Tanks Inspection Program will be revisedto specify a 10-year buried pipe inspection frequency.Prior to Periodof ExtendedOperationLRA Section B2.1.515The Buried Piping and Tanks Inspection Program will be revisedto specify a 10-year inspection frequency for diesel fuel oilstorage tank, T-44.Prior to Periodof ExtendedOperationLRA Section B2.1.5 APPENDIX A: COMMITMENTS FOR LICENSE RENEWAL OF MNGPItem No.CommitmentImplementationScheduleSourceA-616The Buried Piping and Tanks Inspection Program will be revisedto include a review of previous buried piping issues to determinepossible susceptible locations.Prior to Periodof Extended OperationLRA Section B2.1.517The Bus Duct Inspection Program will be implementedconsistent with the appropriate 10 elements described inAppendix A to NUREG-1800, Standard Review Plan for Reviewof License Renewal Applications for Nuclear PowerPlants.Prior to Periodof ExtendedOperationLRA Section B2.1.618The BWR Feedwater Nozzle Program will be enhanced so theparameters monitored and inspected are consistent with therecommendations of GE NE-523-A71-0594-A, Revision 1.Prior to Periodof ExtendedOperationLRA Section B2.1.819The BWR Feedwater Nozzle Program will be enhanced so theregions being inspected, examination techniques, personnelqualifications, and inspection schedule are consistent with therecommendations of GE NE-523-A71-0594-A, Revision 1.Prior to Periodof ExtendedOperationLRA Section B2.1.820The BWR Feedwater Nozzle Program will be enhanced so thatinspections will be scheduled in accordance with therecommendations of GE NE-523-A71-0594-A, Revision 1.Prior to Periodof ExtendedOperationLRA Section B2.1.821The repair/replacement guidelines in BWRVIP-16, 19, 44, 45, 50, 51, 52, 57, and 58 will be added, as applicable, to theMNGP BWR Vessel Internals Program.Prior to Periodof ExtendedOperationLRA Section B2.1.1222NMC will perform top guide grid inspections, using the EVT-1method of examination, for the high-fluence locations (gridbeam and beam-to-beam crevice slot locations with fluenceexceeding 5.0x10 20 n/cm 2). Ten percent of the total populationwill be inspected within 12 years, with a minimum of 5 percentinspected within the first 6 years.During thePeriod ofExtendedOperationLRA Section B2.1.12 APPENDIX A: COMMITMENTS FOR LICENSE RENEWAL OF MNGPItem No.CommitmentImplementationScheduleSourceA-723A one-time inspection will be performed to monitor the effects ofcorrosion on select portions of closed-cycle cooling watersystems that perform a pressure-integrity intended function.Prior to Periodof ExtendedOperationLRA Section B2.1.1324The Compressed Air Monitoring Program procedures will berevised to include corrective action requirements, if theacceptance limits for water vapor, oil content, or particulate arenot met. In addition, the acceptance criteria for oil contenttesting will be clarified and the basis for the acceptance limits forthe water vapor, oil content, and particulate tests will beprovided.Prior to Periodof ExtendedOperationLRA Section B2.1.1425The Compressed Air Monitoring Program will be revised toinclude inspection of air distribution piping based on therecommendations of EPRI TR-108147.Prior to Periodof ExtendedOperationLRA Section B2.1.1426The MNGP Electrical Cables & Connections Not Subject To10 CFR 50.49 Environmental Qualification RequirementsProgram will be implemented as a new program consistent withthe recommendations of GALL AMP XI.EI. The program willmanage the aging of conductor insulation material on cables,connectors, and other electrical insulation materials that areinstalled in an adverse localized environment caused by heat,radiation, or moisture.Prior to Periodof ExtendedOperationLRA Section B2.1.1527The Electrical Cables Not Subject to 10 CFR 50.49Environmental Qualification Requirements Used inInstrumentation Circuits Program will be implemented as a newprogram. With exceptions, it will be consistent with therecommendations of GALL AMP XI.E2.Prior to Periodof ExtendedOperationLRA Section B2.1.16 APPENDIX A: COMMITMENTS FOR LICENSE RENEWAL OF MNGPItem No.CommitmentImplementationScheduleSourceA-828The MNGP Fire Protection Program will be revised to incl ude avisual inspection of the halon fire suppression system to detectany signs of degradation, such as corrosion and mechanicaldamage. This visual inspection will provide aging managementfor external surfaces of the halon fire suppression system.Prior to Periodof ExtendedOperationLRA Section B2.1.1729The Fire Protection Program plan document will be revised toinclude qualification criteria for individuals performing visualinspections of penetration seals, fire barriers, and fire doors.The qualification criteria will be in accordance with VT-1 orequivalent and VT-3 or equivalent, as applicable.Prior to Periodof ExtendedOperationLRA Section B2.1.1730The Fire Water System Program implementing procedures willbe revised to include the extrapolation of inspection results tobelow-grade fire water piping with similar conditions that existwithin the above-grade fire water piping.Prior to Periodof ExtendedOperationLRA Section B2.1.1831The Fire Water System Program sprinkler heads will beinspected and tested based on NFPA requirements or replacedbefore the end of the 50-year sprinkler head service life and at10-year intervals thereafter during the extended period ofoperation to ensure that signs of degradation, such ascorrosion, are detected in a timely manner.Prior to Periodof ExtendedOperationLRA Section B2.1.1832NMC will verify the procedures to be used for agingmanagement activities of the fire water system and apply testingin accordance with applicable NFPA codes and standards.Relevant procedures will be revised, as appropriate.Prior to Periodof ExtendedOperationLRA Section B2.1.1833The MNGP procedures related to the diesel fuel oil system willbe revised to include requirements to check for general, pitting,crevice, galvanic, MIC, and cracking.Prior to Periodof ExtendedOperationLRA Section B2.1.20 APPENDIX A: COMMITMENTS FOR LICENSE RENEWAL OF MNGPItem No.CommitmentImplementationScheduleSourceA-934The MNGP Fuel Oil Chemistry Program procedures will berevised to require tank draining, cleaning, and inspection, ifdeemed necessary based on the trends indicated by the resultsof the diesel fuel oil analysis, or as recomm ended by t he syst emengineer based on equipment operating experience.Prior to Periodof ExtendedOperationLRA Section B2.1.2035Existing procedures in the MNGP Fuel Oil Chemistry Programwill be developed or revised to require periodic tank inspectionsof the diesel fuel oil tanks.Prior to Periodof ExtendedOperationLRA Section B2.1.2036The MNGP Inaccessible Medium Voltage (2 kV to 34.5 kV)Cables Not Subject to 10 CFR 50.49 EQ Requirements Programwill be implemented as a new program consistent with therecommendations of GALL AMP XI.E3.Prior to Periodof ExtendedOperationLRA Section B2.1.2137The Inspection of Overhead Heavy Load and Light Load(Related to Refueling) Handling Systems Program will beenhanced to specify a 5-year inspection frequency for the fuelpreparation machines.Prior to Periodof ExtendedOperationLRA Section B2.1.2238The MNGP One-Time Inspection Program will be implementedas a new program consistent with the recommendations ofGALL AMP XI.M32, "One-Time Inspection." This program willinclude measures to verify the effectiveness of the followingaging management programs: Plant Chemistry Program andFuel Oil Chemistry Program. This program will also confirm theabsence of age degradation in selected components (e.g., flowrestrictors, venturis) within the scope of license renewal.Prior to Periodof ExtendedOperationLRA Section B2.1.2339The MNGP Protective Coating Maintenance and MonitoringProgram procedures will be updated to include inspection of allaccessible painted surfaces inside containment.Prior to Periodof ExtendedOperationLRA Section B2.1.27 APPENDIX A: COMMITMENTS FOR LICENSE RENEWAL OF MNGPItem No.CommitmentImplementationScheduleSourceA-1040The MNGP Protective Coating Maintenance and MonitoringProgram will be revised to include a preinspection review of theprevious two inspection reports so that trends can be identified.Prior to Periodof ExtendedOperationLRA Section B2.1.27 41The MNGP Protective Coating Maintenance and MonitoringProgram implementation procedures will be revised to includeprovisions for analysis of suspected reasons for coating failure.Prior to Periodof ExtendedOperationLRA Section B2.1.27 42NMC intends to use the Integrated Surveillance Program forMNGP during the period of extended operation by implementingthe requirements of BWRVIP-116, which is currently beingreviewed by the NRC.Prior to Periodof ExtendedOperationLRA Section B2.1.2943NMC will retain the capsules removed from the MNGP reactorvessel as part of the Reactor Vessel Surveillance Program.Prior to andDuring thePeriod ofExtendedOperationLRA Section B2.1.2944The MNGP Selective Leaching of Materials Program will beimplemented as a new program consistent, with exceptions, tothe recommendations of GALL AMP XI.M33. The program willbe developed and implemented before the start of the period ofextended operation. The program includes a one-time visualinspection and hardness measurement of selected componentsthat are susceptible to selective leaching. In situations in whichhardness testing is not practical, a qualitative method by otherNDE or metallurgical methods will be used to determine thepresence and extent of selective leaching. Theprogram will determine whether selective leaching is occurringfor selected components.Prior to Periodof ExtendedOperationLRA Section B2.1.30 APPENDIX A: COMMITMENTS FOR LICENSE RENEWAL OF MNGPItem No.CommitmentImplementationScheduleSourceA-1145The MNGP Structures Monitoring Program will be ex panded, asnecessary, to include inspections of structures and structuralelements within the scope of license renewal that are notinspected as part of another aging management program.Prior to Periodof ExtendedOperationLRA Section B2.1.3146The MNGP Structures Monitoring Program implementingprocedures will be enhanced to ensure that structuralinspections are performed on submerged portions of the intakestructure from the service water bays to the wing walls.Prior to Periodof ExtendedOperationLRA Section B2.1.3147The MNGP Structures Monitoring Program implementingprocedures will be revised to include the monitoring/inspectionparameters for structural components within the scope oflicense renewal.Prior to Periodof ExtendedOperationLRA Section B2.1.3148The MNGP Structures Monitoring Program will be enhanced toinclude a requirement to sample groundwater for pH, chlorideconcentration, and sulfate concentration.Prior to Periodof ExtendedOperationLRA Section B2.1.3149The MNGP Structures Monitoring Program will be enhanced toinclude concrete evaluations of inaccessible areas ifdegradation of accessible areas is detected.Prior to Periodof ExtendedOperationLRA Section B2.1.3150The MNGP Structures Monitoring Program implementingprocedures will be enhanced to include acceptance criteria forstructural inspections of submerged portions of the intakestructure.Prior to Periodof ExtendedOperationLRA Section B2.1.3151Implementing instructions and procedures for the SystemCondition Monitoring Program will be revised to describespecific age degradation parameters to be monitored andinspected. Acceptance criteria will also be incl uded.Prior to Periodof ExtendedOperationLRA Section B2.1.32 APPENDIX A: COMMITMENTS FOR LICENSE RENEWAL OF MNGPItem No.CommitmentImplementationScheduleSourceA-1252Requirements for inclusion of NUREG/CR-6260 locations will beincorporated in the implementing procedures for the MNGPThermal Fatigue Monitoring Program.Prior to Periodof ExtendedOperationLRA Section B3.253The NMC fleet procedure for the Flow Accelerated CorrosionProgram will be revised to include the accepted 87.5 percent ofnominal pipe wall thickness for nonsafety-related piping as atrigger point for engineering analysis.Prior to Periodof ExtendedOperationLRA Section B2.1.1954Prior to the period of extended operation, coating inspectors willmeet the requirements of ANSI N45.2.6.Prior to Periodof ExtendedOperationLRA Section B2.1.2755NMC will implement a new program at MNGP which isconsistent with GALL AMP XI.E6. Prior to Periodof ExtendedOperationResponse tofollowup to RAI3.6-2, datedFebruary 27, 200656NMC has inspected the incore monitoring dry tubes on anevery-other refueling outage periodicity and will conti nue toperform this inspection during the period of extended operation,as recommended by the guidance provided in GE SIL-409.During the Period ofExtended OperationLRA Section 4.4 and B2.1.1257NMC is an active member of the BWRVIP and will conti nue tofollow applicable inspection guidelines and recommendations,which have been reviewed and approved by the executivecommittee of the BWRVIP, throughout the period of extendedoperation.During the Period ofExtended OperationLRA Section B1.6 and B2.1.1258NMC will follow the guidance provided in BWRVIP-139, SteamDryer Inspection and Flaw Evaluation Guidelines (April 2005),for the MNGP steam dryer inspections.During the Period ofExtended OperationLRA Section 2.1.4.2.2 and B2.1.12 APPENDIX A: COMMITMENTS FOR LICENSE RENEWAL OF MNGPItem No.CommitmentImplementationScheduleSourceA-1359NMC will add inspection requirements for the P1, P2, and P3core spray piping welds at MNGP, in accordance with guidanceprovided in BWRVIP-18 or subsequent revisions.Prior to the Period ofExtended OperationLRA Section B1.6 and B2.1.1260NMC will adhere to BWRVIP inspection guidelines for core plateholddown bolts by implementation of one or more of thefollowing:1.Develop an alternative to the inspections identified in theBWRVIP which will, at a minimum, satisfy the intent of theBWRVIP in terms of assuring core plate functional integritythroughout the period of extended operation. NMC willprovide the alternative to the inspection program to the NRCstaff for their review and approval at least 1 year beforeentering the period of extended operation.2.Inspect the core plate bolts using either UT, some othervolumetric inspections, EVT-1 from below the core plate, orother approved inspections, in accordance with BWRVIP-25,to assure an adequate number of core plate bolts are intactto prevent lateral displacement of the core plate.3.Install core plate wedges to structurally replace the lateralload resistance provided by the rim holddown bolts andperform no inspections.Prior to the Period ofExtended OperationLRA Section B2.1.12 A-14THIS PAGE IS INTENTIONALLY LEFT BLANK.

B-1APPENDIX BCHRONOLOGYThis appendix contains a chronological listing of the routine licensing correspondence betweenthe staff of the U.S. Nuclear Regulatory Commission (NRC or the staff) and the NuclearManagement Company, LLC (NMC), and other correspondence regarding the NRC staff'sreviews of the Monticello Nuclear Generating Plant (MNGP) (Docket No. 50-263) license renewal application (LRA).March 16, 2005Letter from T. Palmisano, NMC, to the NRC Transmitting Application forRenewed Operating License for the Monticello Nuclear Generating Plant(ADAMS Accession No. ML050880241)March 24, 2005NRC Press Release 053-NRC Announces Availability of LicenseRenewal Application for Monticello (ADAMS Accession No. ML050830481)March 31, 2005Letter from P.T. Kuo, NRC, to T. Palmisano, NMC, Acknowledging theReceipt and Availability of the LRA for MNGP (ADAMS AccessionNo. ML050900052)April 6, 2005Notice of April 20, 2005, Meeting for the NRC to Describe the LicenseRenewal Process (ADAMS Accession No. ML050960308)April 14, 2005NRC Press Release-III-05-016-NRC Staff Schedules Public Meeting forApril 20 to Discuss License Renewal Process for Monticello Nuclear Generating Plant (ADAMS Accession No. ML051040142)April 25, 2005Notice of May 11, 2005, Meeting Between the NRC and NMC to Discussthe LRA for MNGP (ADAMS Accession No. ML051150221)May 5, 2005Determination of Acceptability and Sufficiency for Docketing, ProposedReview Schedule, and Opportunity for a Hearing Regarding the Application for Renewal of the Operating License for MNGP (ADAMS Accession No. ML051260029)May 9, 2005Letter from J. Davis, NRC, to M. Askin regarding maintenance ofreference material at the Monticello Public Library for the MNGP LRA (ADAMS Accession No. 051300167)May 9, 2005Letter from J. Davis, NRC, to A. Wittmann regarding maintenance ofreference material at the Buffalo Public Library for the MNGP LRA (ADAMS Accession No. 051300195)May 12, 2005NRC Press Release 081-NRC Announces Opportunity for Hearingon Application to Renew Operating License for MNGP (ADAMS Accession No. ML051320170)

B-2May 12, 2005 NRC Request for Additional Information for the Review of the MNGP LRA(ADAMS Accession No. ML051330005)May 13, 2005Summary of the Public Information Session Held April 20, 2005, for theNRC to Describe the License Renewal Process (ADAMS AccessionNo. ML051310174)May 18, 2005Summary of Meeting Held May 11, 2005, between the NRC and NMC toDiscuss the MNGP LRA (ADAMS Accession No. ML051400115)May 18, 2005Revision of Schedule for the Review of the MNGP LRA (ADAMSAccession No. ML051400234)May 25, 2005Notice of June 24, 2005, Exit Meeting for the License Renewal Scopingand Screening Methodology Audit for the MNGP LRA (ADAMS Accession No. ML051450575)June 2, 2005NRC Audit and Review Plan for Plant Aging Management Reviews andPrograms for MNGP (ADAMS Accession No. ML051600008)June 10, 2005NMC Response to Request for Additional Information and Submittal ofAdditional Information in Support of the Monticello LRA (ADAMS Accession No. ML051680145)June 17, 2005Summary of Telephone Conference Held on June 9, 2005, between the NRC and NMC Concerning Draft Requests for Additional InformationPertaining to the MNGP LRA (ADAMS Accession No. ML051680443)June 21, 2005 NRC Request for Additional Information for the Review of the MNGP LRA(ADAMS Accession No. ML051720593)July 6, 2005Summary of Meeting Held June 24, 2005, between the NRC and NMC toDiscuss the Results of the Scoping and Screening Methodology Audit for the MNGP LRA (ADAMS Accession No. ML051880402)July 9, 2005Request for a Hearing and Petition for Leave to Intervene by the NorthAmerican Water Office (ADAMS Accession No. ML052280043)July 12, 2005Revision of Schedule for the Review of the MNGP LRA (ADAMSAccession No. ML051950002)July 13, 2005Notice of August 18, 2005, Exit Meeting With NMC on License RenewalAudits of Aging Management Programs and Reviews for MNGP (ADAMS Accession No. ML051940509)July 13, 2005Summary of Telephone Conference Held on July 6, 2005, between the NRC and NMC Concerning Draft Requests for Additional InformationPertaining to the MNGP LRA (ADAMS Accession No. ML051950060)July 18, 2005Audit Trip Report Regarding the NMC Application for License Renewalfor MNGP (ADAMS Accession No. ML051990091)

B-3July 20, 2005 NRC Request for Additional Information for the Review of the MNGP LRA(ADAMS Accession No. ML052020005)July 21, 2005NMC Response to Request for Additional Information Regarding theMonticello LRA (ADAMS Accession No. ML052080040)July 28, 2005Summary of Telephone Conference Held on July 14, 2005, between the NRC and NMC Concerning Draft Requests for Additional InformationPertaining to the MNGP LRA (ADAMS Accession No. ML052100060)July 28, 2005Summary of Public Scoping Meetings to Support Review of the MNGPLRA (ADAMS Accession No. ML052110002)August 3, 2005NRC Staff Answer to Petition to Intervene and Request for Hearing of theNorth American Water Office (ADAMS Accession No. ML052200245)August 3, 2005Notice of Appearance of David R. Lewis on Behalf of NMC (ADAMSAccession No. ML052280129)August 3, 2005NMC Answer to Request for Hearing and Petition to Intervene by theNorth American Water Office (ADAMS Accession No. ML052280136)August 8, 2005Memorandum of the Secretary referring the Petition for Leave toIntervene Submitted by the North American Water Office (ADAMS Accession No. ML052270368)August 9, 2005Reply Comment of the North American Water Office (ADAMS AccessionNo. ML052300291)August 11, 2005Summary of Telephone Conference Held on August 4, 2005, between the NRC and NMC Concerning Information Pertaining to the MNGP LRA(ADAMS Accession No. ML052230323)August 11, 2005NMC Responses to Aging Management Program and AgingManagement Review Audits for the Monticello LRA (ADAMS Accession No. ML052280269)August 12, 2005Establishment of Atomic Safety and Licensing Board (ADAMS AccessionNo. ML052270406)August 16, 2005NMC Response to Request for Additional Information Regarding theMonticello LRA (ADAMS Accession No. ML052340510)August 18, 2005 NRC Request for Additional Information for the Review of the MNGP LRA(ADAMS Accession No. ML052310013)August 18, 2005 NRC Request for Additional Information for the Review of the MNGP LRA(ADAMS Accession No. ML052310044)August 18, 2005 NRC Request for Additional Information for the Review of the MNGP LRA(ADAMS Accession No. ML052310055)

B-4August 19, 2005NRC Staff Motion to Strike Comment of the North American Water Office(ADAMS Accession No. ML052310573)August 29, 2005Reply of North American Water Office to the NRC Staff Motion to StrikeComment of the North American Water Office (ADAMS Accession No. ML052500328)August 31, 2005Summary of Telephone Conference Held on August 15, 2005, betweenthe NRC and NMC Concerning Information Pertaining to the MNGP LRA(ADAMS Accession No. ML052430782)August 31, 2005NMC Additional Information in Response to Aging Management Programand Aging Management Review Audits of the Monticello LRA (ADAMS Accession No. ML052500294)September 6, 2005Summary of Meeting Held August 18, 2005, between the NRC and NMCto Discuss the Results for Aging Management Programs and Reviews for the MNGP LRA (ADAMS Accession No. ML052520251)September 15, 2005 NRC Request for Additional Information for the Review of the MNGP LRA(ADAMS Accession No. ML052620622)September 16, 2005 NRC Request for Additional Information for the Review of the MNGP LRA(ADAMS Accession No. ML052620609)September 16, 2005NMC Response to Three Requests for Additional Information Regardingthe Monticello LRA (ADAMS Accession No. ML052630320)September 26, 2005Docketing of Additional Information Pertaining to the LRA for MNGP(ADAMS Accession No. ML052700535)September 27, 2005Summary of Telephone Conference Held on September 1, 2005,between the NRC and NMC Concerning Information Pertaining to theMNGP LRA (ADAMS Accession No. ML052700456)September 27, 2005Summary of Telephone Conference Held on September 7, 2005,between the NRC and NMC Concerning Information Pertaining to theMNGP LRA (ADAMS Accession No. ML052700227)September 28, 2005 NRC Request for Additional Information for the Review of the MNGP LRA(ADAMS Accession No. ML052730175)October 11, 2005Letter from G. Crocker to Administrative Judge McDade discussingincompleteness of the MNGP LRA (ADAMS Accession No. ML052930174)October 12, 2005Audit and Review Report for Plant Aging Management Reviews andPrograms for Monticello Nuclear Generating Plant (ADAMS Accession No. ML052850461)

B-5October 14, 2005NMC Response to Two Requests for Additional Information Regardingthe MNGP LRA (ADAMS Accession No. ML052910370)October 17, 2005NRC Staff Answer to the Motion of the North American Water Office toFind the License Renewal Application for the MNGP Incomplete (ADAMS Accession No. ML052900401)October 17, 2005NMC Response to North American Water Office's Motion to Find theApplication Incomplete (ADAMS Accession No. ML052970399)October 21, 2005Summary of Telephone Conference Held on October 6, 2005, betweenthe NRC and NMC Concerning Information Pertaining to the MNGP LRA(ADAMS Accession No. ML052970210)October 28, 2005NMC Response to Requests for Additional Information Regarding theMNGP LRA (ADAMS Accession No. ML053070217)October 31, 2005 NRC Request for Additional Information for the Review of the MNGP LRA(ADAMS Accession No. ML053050436)November 1, 2005Memorandum and Order, Ruling on Standing and ContentionAdmissibility (ADAMS Accession No. M L053050414)November 2, 2005Summary of Telephone Conference Call Held on October 11, 2005,between the NRC and NMC Concerning Information Pertaining to theMNGP LRA (ADAMS Accession No. ML053070112)November 7, 2005 NRC Request for Additional Information for the Review of the MNGP LRA(ADAMS Accession No. ML053120003)November 8, 2005Letter from D. Merzke, NRC, to J. Conway, NMC, Regarding PublicAvailability of Audit and Review Report (ADAMS AccessionNo. ML053140265)November 14, 2005 NRC Request for Additional Information for the Review of the MNGP LRA(ADAMS Accession No. ML053190429)November 16, 2005Letter from D. Merzke, NRC, to J. Conway, NMC, Regarding PublicAvailability of Audit Report for Scoping and Screening Methodology(ADAMS Accession No. ML053220358)November 17, 2005NMC Supplement to Responses for Requests for Additional InformationRegarding the MNGP LRA (ADAMS Accession No. ML053250099)November 18, 2005Summary of Telephone Conference Call Held on November 9, 2005,between NRC and NMC Concerning Information Pertaining to the MNGPLRA (ADAMS Accession No. ML053250489)November 22, 2005Summary of Telephone Conference Held on November 15, 2005,between the NRC and NMC Concerning Information Pertaining to theMNGP LRA (ADAMS Accession No. ML053290157)

B-6November 22, 2005NMC Response to Two Requests for Additional Information Regardingthe MNGP LRA (ADAMS Accession No. ML053340269)December 7, 2005NMC Response to Request for Additional Information Regarding theMNGP LRA (ADAMS Accession No. ML053460242)December 16, 2005NMC Supplement to Responses to Requests for Additional InformationRegarding the MNGP LRA (ADAMS Accession No. ML053550250)January 10, 2006Summary of Telephone Conference Call Held on December 21, 2005,between the NRC and NMC Concerning Information Pertaining to theMNGP LRA (ADAMS Accession No. ML060130004)January 30, 2006Summary of Telephone Conference Call Held on January 9, 2006,between the NRC and NMC Concerning Information Pertaining to theMNGP LRA (ADAMS Accession No. ML060310635)January 30, 2006Summary of Telephone Conference Call Held on January 12, 2006,between the NRC and NMC Concerning Information Pertaining to theMNGP LRA (ADAMS Accession No. ML060340200)February 8, 2006Meeting Notice Regarding Public Exit Meeting to Discuss the Results ofthe License Renewal Inspections for the Review of the MNGP LRA (ADAMS Accession No. ML060390125)February 27, 2006NMC Supplement to Responses to Requests for Additional InformationRegarding the MNGP LRA (ADAMS Accession No. ML060610583)February 28, 2006Confirmatory Items Response Regarding the MNGP LRA (ADAMSAccession No. ML060620056)March 15, 2006NMC License Renewal Application Annual Update Letter (ADAMSAccession No. ML060800360)March 30, 2006NRC License Renewal Scoping, Screening, and Aging ManagementInspection Report (ADAMS Accession No. ML060940194)March 31, 2006NMC Supplemental Information and Response to Requests for AdditionalInformation Regarding the MNGP LRA (ADAMS Accession No. ML060940124)April 10, 2006NMC Supplemental Information Regarding the MNGP LRA (ADAMSAccession No. ML061030406)April 26, 2006NRC letter to NMC Transmitting the Safety Evaluation Report Related tothe License Renewal of MNGP (ADAMS Accession No. ML061170035)June 15, 2006NMC Comments Regarding the Safety Evaluation Report for the MNGPLicense Renewal Application (ADAMS Accession No. ML061710264)

B-7June 23, 2006NMC Supplemental Information Regarding the MNGP LRA (ADAMSAccession No. ML061780532)

B-8THIS PAGE IS INTENTIONALLY LEFT BLANK.

C-1APPENDIX CPRINCIPAL CONTRIBUTORSNAMERESPONSIBILITYF. AkstulewiczManagement OversightH. AsharStructural Engineering W. BatemanManagement Oversight B. BogerManagement Oversight E. BrownManagement Oversight T. ChanManagement Oversight K. ChangGALL Audit and Review O. ChopraElectrical Engineering G. CranstonGALL Audit and Review R. DennigManagement Oversight N. DudleyGALL Audit and Review B. ElliotMaterial EngineeringJ. FairMechanical Engineering T. FordReactor Systems G. GallettiQuality Assurance G. GeorgievMechanical Engineering F. GillespieManagement OversightR. GoelMechanical Engineering V. GoelElectrical Engineering J. GrobeManagement Oversight M. HartzmanMechanical Engineering R. HernandezPlant Systems A. HodgdonLegal Counsel N. IqbalFire Protection R. JenkinsManagement Oversight S. JonesManagement Oversight R. KarasManagement Oversight K. KavanaghQuality Assurance J. KnoxElectrical Engineering P. KuoManagement Oversight C. LauronMaterial Engineering S. LeeManagement Oversight C. LiPlant Systems Y. LiMechanical Engineering M. LintzGALL Audit and Review P. LougheedRegion III InspectionL. LundManagement Oversight J. LyonsManagement Oversight J. MaMechanical Engineering K. ManolyManagement Oversight T. MartinManagement Oversight D. MatthewsManagement Oversight M. MayfieldManagement Oversight R. McNallyMechanical Engineering D. MerzkeLead Project Manager C-2M. MitchellManagement OversightJ. RajanMechanical Engineering J. RavalMechanical Engineering B. RogersQuality Assurance J. RowleyProject Management D. ShumPlant Systems D. SolarioManagement Oversight J. StrnishaMechanical Engineering D. ThatcherManagement Oversight S. TingenQuality Assurance M. TschiltzManagement Oversight S. WeerakkodyManagement Oversight P. WenGALL Audit and Review G. WilsonManagement Oversight R. WolfgangFire Protection M. WoodsLegal Counsel M. YoderMaterial Engineering J. ZimmermanManagement OversightCONTRACTORSCONTRACTORTECHNICAL AREALegin Group, Inc.SER SupportAdvanced Technologies and GALL Audit and Report Laboratories International, Inc.

Pacific Northwest NationalPlant Systems Laboratory D-1APPENDIX DREFERENCESThis appendix contains a listing of the references used in the preparation of the SafetyEvaluation Report developed during the review of the license renewal application for Monticello Nuclear Generating Plant (MNGP), Docket Number 50-263.Boiling Water Reactor Vessel and Internals Project (BWRVIP)BWRVIP-03, "BWR Vessel and Internals Project, Reactor Pressure Vessel and InternalsExamination Guidelines."BWRVIP-18, "BWR Core Spray Internals Inspection and Flaw Evaluation Guidelines."BWRVIP-25, "BWR Core Plate Inspection and Flaw Evaluation Guidelines."BWRVIP-26, "BWR Top Guide Inspection and Flaw Evaluation Guidelines."BWRVIP-27, "BWR Vessel and Internals Project, BWR Standby Liquid Control System/CorePlate DP Inspection and Flaw Evaluation Guidelines."BWRVIP-29, "BWR Water Chemistry Guidelines-1993 Revision," EPRI Topical Report,TR-103515.BWRVIP-38, "BWR Shroud Support Inspection and Flaw Evaluation Guidelines."BWRVIP-41, "BWR Jet Pump Assembly Inspection and Flaw Evaluation Guidelines."BWRVIP-47, "BWR Lower Plenum Inspection and Flaw Evaluation Guidelines."BWRVIP-48, "Vessel ID Attachment Weld and Inspection and Flaw Guidelines," EPRI TopicalReport TR-108724.BWRVIP-49, "BWR Instrument Penetration Inspection and Flaw Evaluation Guidelines."BWRVIP-74-A, "BWR Reactor Pressure Vessel Inspection and Flaw Evaluation Guidelines forLicense Renewal."BWRVIP-78, "BWR Integrated Surveillance Program (ISP) Plan."BWRVIP-86, "BWR Vessel and Internals Project: BWR Integrated Surveillance Program (ISP)Implementation."BWRVIP-130, "BWR Water Chemistry Guidelines-2004 Revision," EPRI Topical Report,TR-1008192.Code of Federal Regulations Title 10, Part 50, "Domestic Licensing of Production and Utilization Facilities," of the Code ofFederal Regulations

.Title 10, Part 50, Appendix B, "Quality Assurance Criteria for Nuclear Power Plants and FuelProcessing Plants,"of the Code of Federal Regulations.Title 10, Part 50, Appendix H, "Reactor Vessel Material Surveillance Program Requirements," of the Code of Federal Regulations.

D-2Title 10, Part 50, Appendix J, "Primary Reactor Containment Leakage Testing for Water-CooledPower Reactors," of the Code of Federal Regulations.Title 10, Part 50, Appendix R, "Fire Protection Program for Nuclear Power Facilities OperatingPrior to January 1, 1979," of the Code of Federal Regulations

.Title 10, Part 51, "Environmental Protectioin Regulations for Domestic Licensing and RelatedRegulatory Functions," of the Code of Federal Regulations.Title 10, Part 54, "Requirements for Renewal of Operating Licenses for Nuclear Power Plants,"of the Code of Federal Regulations.Title 10, Part 100, "Reactor Site Criteria," of the Code of Federal Regulations

.Electric Power Research Institute (EPRI)

EPRI NP-5067, Volumes 1 and 2, "Good Bolting Practices."EPRI NP-5769, "Degradation and Failure of Bolting in Nuclear Power Plants." EPRI Report 1002950, Revision 1, "Aging Effects for Structures and Structural Components(Structural Tools)," May 2003.EPRI Report 1003056, Revision 3, "Non-Class 1 Mechanical Implementation Guideline andMechanical Tools."EPRI Report 1007933, "Aging Assessment Field Guide," December 2003.EPRI Report 1008035, Revision 1, "Expansion Joint Maintenance Guide," May 2003.EPRI Topical Report, TR-1007820, "Closed Cooling Water Chemistry Guideline."EPRI Topical Report, TR-103595, "Report of the Instrument Air Working Group."EPRI TR-104213, "Bolted Joint Maintenance & Application Guide." EPRI Topical Report, TR-108147, "Compressor and Instrument Air System MaintenanceGuide," March 1998.EPRI Topical Report, TR-112657, Revision B-A, "Revised Risk Informed In-Service InspectionEvaluation Procedure."NSAC-202L-R2, "Recommendations for an Effective Flow-Accelerated Corrosion Program,"Electric Power Research Institute.Miscellaneous American Concrete Institute (ACI) 349.3R-96, "Evaluation of Existing Nuclear Safety RelatedConcrete Structures."American Society of Mechanical Engineers (ASME), Boiler and Pressure Vessel Code, SectionXI, Subsection IWB, IWC, and IWD.ASME, Boiler and Pressure Vessel Code,Section XI, Subsection IWE.ASME, Boiler and Pressure Vessel Code,Section XI, Subsection IWF.ASME, Boiler and Pressure Vessel Code,Section XI, Subsection NF.American Society for Testing and Materials (ASTM) D 6217, "Test Method for ParticulateContamination in Middle Distillate Fuels by Laboratory Filtration."

D-3American National Standards Institute (ANSI)/Instrument Society of America (ISA) S7.3,"Quality Standard for Instrument Air." ANSI/ISA Z86.1-1973, "Commodity Specification for Air and Drager Operating Instruction." ANSI N45.2.6, "Qualification of Inspection, Examination, and Testing Personnel for theConstruction Phase of Nuclear Power Plants."ANSI N45.2.9, "Requirements for Collection, Storage, and Maintenance of Quality AssuranceRecords for Nuclear Power Plants," 1974.ASTM D 5163-96, "Standard Guide for Establishing Procedures To Monitor the Performance ofSafety Related Coatings in an Operating Nuclear Power Plant."Audit and Review Plan for Plant Aging Management Reviews and Programs for MonticelloNuclear Generating Plant, June 2, 2005.Audit and Review Report for Plant Aging Management Reviews and Programs for MonticelloNuclear Generating Plant, October 12, 2005.Fire Protection Safety Evaluation Report, August 29, 1979.J.P. Foster, "Analysis of In-reactor Stress Relaxation Using Irradiation Creep Models," ASTMSTP611, Irradiation Effects on the Microstructure and Properties of Metals , 1976.General Electric Document SASR 89-77, "Accumulated Fatigue Usage for the MonticelloNuclear Generating Station Reactor Pressure."General Electric Service Information Letter (SIL)-409, "Incore Dry Tube Cracks" General Electric Topical Report, GE-NE-523-A71-0594, Revision 1, "Alternate BWR FeedwaterNozzle Inspection Requirements." General Electric Topical Report NEDC-32983P, "General Electric (GE) Methodology forReactor Pressure Vessel Fast Neutron Flux Evaluation." Letter from NRC to MNGP, "Monticello Nuclear Generating Plant-Risk Informed In-ServiceInspection Program (TAC NO. MB3819)," July 24, 2002.Letter from NRC to MNGP, "Monticello Nuclear Generating Plant-Fourth 10-Year In-ServiceInspection Interval Request for Relief No. 4 (TAC No. MC2222)," January 6, 2005.Letter from NRC to Nuclear Energy Institute and Union of Concerned Scientists, "StandardizedFormat for License Renewal Applications (MB7344)," April 7, 2003. "Metals Handbook," Ninth Edition, American Society for Metals International.Monticello Nuclear Generating Plant Updated Safety Analysis Report (USAR), Revision 21.NEDO-32205-A, Revision 1, "10 CFR 50 Appendix G Equivalent Margin Analysis for Low UpperShelf Energy in BWR/2-6 Vessels," February 1994.NEI 94-01, "Industry Guideline for Implementing Performance-Based Option of 10 CFR Part 50,Appendix J," March 1996.NEI 95-10, "Industry Guideline for Implementing the Requirements of 10 CFR Part 54-TheLicense Renewal Rule," Revision 3, March 2001.NUMARC 93-01, Revision 2, "Industry Guideline for Monitoring the Effectiveness ofMaintenance at Nuclear Power Plants," April 1996.

D-4SAND96-0344, "Aging Management Guideline for Commercial Nuclear Power Plants-ElectricalCable and Terminations," Sandia National Laboratories, September 1996.NRC Generic Communications NRC GL 80-95, "Generic Activity A-10," November 13, 1980.NRC GL 81-11, "BWR Feedwater Nozzle and Control Rod Drive Return Line Nozzle Cracking(NUREG-0619)," February 29, 1981.NRC GL 88-01, "NRC Position on IGSCC in BWR Austenitic Stainless Steel Piping,"January 25, 1988.NRC GL 88-14, "Instrument Air Supply System Problems Affecting Safety Equipment,"August 8, 1988.NRC Generic Letter (GL) 89-08, "Erosion/Corrosion-Induced Pipe Wall Thinning," May 2, 1989.NRC GL 89-13, "Service Water System Problems Affecting Safety-Related Equipment,"July 18, 1989.NRC GL 98-04, "Potential for Degradation of the Emergency Core Cooling System (ECCS) andthe Containment Spray System after a Loss-of-Cooling Accident because of Construction and Protective Coating Deficiencies and Foreign Material in Containment," July 14, 1998.NRC GL 98-05, "Boiling Water Reactor Licensees Use of the BWRVIP-05 Report to RequestRelief from Augmented Inspection." NRC IN 81-38, "Potentially Significant Equipment Failures Resulting from Contamination ofAir-Operated Systems," December 17, 1981.NRC IN 87-28, "Air System Problems at U.S. Light Water Reactors," J une 22, 1987.NRC IN 87-67, "Lessons Learned from Regional Inspections of Licensee Actions in Responseto IE Bulletin 80-11," December 31, 1987.NRC Information Notice (IN) 2001-09, "Main Feedwater System Degradation in Safety-RelatedASME Code Class 2 Piping Inside the Containment of a Pressurized Water Reactor," June 12, 2001.NRC Regulatory Guides NRC RG 1.127, Revision 1, "Inspection of Water-Control Structures Associated with NuclearPower Plants," March 1978.NRC RG 1.147, Revision 13, "In-Service Inspection Code Case Acceptability, ASME Section XI,Division 1," January 2004.NRC RG 1.160, Revision 2, "Monitoring the Effectiveness of Maintenance at Nuclear PowerPlants," March 1997.NRC RG 1.163, "Performance-Based Containment Leak-Test Program," September 1995.NRC RG 1.174, Revision 1, "An Approach for Using Probabilistic Risk Assessment inRisk-Informed Decisions on Plant-Specific Changes to the Licensing Basis," November 2002.NRC RG 1.178, Revision 1, "An Approach for Plant-Specific Risk-Informed Decision-Making forIn-Service Inspection of Piping," September 2003.NRC RG 1.190, "Calculational and Dosimetry Methods for Determining Pressure VesselNeutron Fluence," March 2001.

D-5NRC RG 1.54, "Service Level I, II, and III Protective Coatings Applied to Nuclear Power Plants,"June 1973.NRC RG 1.65, "Materials and Inspections for Reactor Vessel Closure Studs," October 1973.NRC RG 1.99, Revision 2, "Radiation Embrittlement of Reactor Vessel Materials," May 1988.NUREG Series Reports NUREG-0313, "Technical Report on Material Selection and Processing Guidelines for BWRCoolant Pressure Boundary Piping," Revision 2, January 1988.NUREG-0619, "BWR Feedwater Nozzle and Control Rod Drive Return Line Nozzle Cracking: Resolution of Generic Technical Activity A-10," November 1980.NUREG-0661, "Safety Evaluation Report, Mark I Containment Long Term Program, Resolutionof Generic Technical Activity A-7," July 1980.NUREG-1339, "Resolution of Generic Safety Issue 29: Bolting Degradation or Failure inNuclear Power Plants."NUREG-1344, "Erosion/Corrosion-Induced Pipe Wall Thinning in U.S. Nuclear PowerPlants," 1989.NUREG-1743, "Safety Evaluation Report Related to the License Renewal of Arkansas NuclearOne, Unit 1," April 2001.NUREG-1800, "Standard Review Plan for Review of License Renewal Applications for NuclearPower Plants," April 2001.NUREG-1801, "Generic Aging Lessons Learned (GALL) Report," July 2001.NUREG/CR-5643, "Insights Gained from Aging Research," March 1992.NUREG/CR-5704, "Effects of LWR Coolant Environments on Fatigue Design Curves ofAustenitic Stainless Steels," April 1999.NUREG/CR-6260, "Application of NUREG/CR-5999 Interim Fatigue Curves for SelectedNuclear Power Plant Components." NUREG/CR-6583, "Effects of LWR Coolant Environments on Fatigue Design Curves of Carbonand Low-Alloy Steels," February 1998.

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