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{{Adams
#REDIRECT [[NOC-AE-120027, Response to Requests for Additional Information for the South Texas Project License Renewal Application Aging Management Program, Set 12]]
| number = ML12069A024
| issue date = 02/27/2012
| title = South Texas Project, Units 1 and 2, Response to Requests for Additional Information for the South Texas Project License Renewal Application Aging Management Program, Set 12 (TAC ME4936 and ME4937)
| author name = Rencurrel D W
| author affiliation = South Texas Project Nuclear Operating Co
| addressee name =
| addressee affiliation = NRC/Document Control Desk, NRC/NRR
| docket = 05000498, 05000499
| license number =
| contact person =
| case reference number = TAC ME4936, TAC ME4937, NOC-AE-12002797
| document type = Letter
| page count = 94
| project = TAC:ME4936, TAC:ME4936, TAC:ME4937
| stage = Other
}}
 
=Text=
{{#Wiki_filter:Nuclear Operating CompanySouth Texas Pmo/ect ERectnc Generating Station P.. Box 289 Wadswvrth. Texas 77483 *
* n. -February 27 2012NOC-AE-1206279710 CFR 54STI: 33330748File: G25U. S. Nuclear Regulatory CommissionAttention: Document Control DeskOne White Flint North11555 Rockville PikeRockville, MD 20852-2738South Texas ProjectUnits 1 and 2Docket Nos. STN 50-498, STN 50-499Response to Requests for Additional Information for theSouth Texas Project License Renewal ApplicationAgqingq Managqement Proqram, Set 12 (TAC Nos. ME4936 and ME4937)References: 1. STPNOC letter dated October 25, 2010, from G. T. Powell to NRC DocumentControl Desk, "License Renewal Application" (NOC-AE-1 0002607) (ML1 03010257)2. NRC letter dated February 8, 2012, "Requests for Additional Information for theReview of the South Texas Project, Units 1 and 2 License Renewal Application -Aging Management, Set 12 (TAC Nos. ME4936 and ME 4937)"(ML12009A1 17)By Reference 1, STP Nuclear Operating Company (STPNOC) submitted a License RenewalApplication (LRA) for South Texas Project (STP) Units 1 and 2. By Reference 2, the NRC staffrequests additional information for review of the STP LRA. STPNOC's response to the request foradditional information is provided in Enclosure 1 to this letter. Changes to LRA pages described inEnclosure 1 are depicted as line-in/line-out pages provided in Enclosure 2.Two new regulatory commitments and one revised regulatory commitment are provided inEnclosure 3. There are no other regulatory commitments provided in this letter.Should you have any questions regarding this letter, please contact either Arden Aldridge, STPLicense Renewal Project Lead, at (361) 972-8243 or Ken Taplett, STP License Renewal Projectregulatory point-of-contact, at (361) 972-8416.I declare under penalty of perjury that the foregoing is true and correct.Executed on 'a 1I 1-- i 1 Z.DateD. W. RencurrelSenior Vice President,Technical Support & OversightKJTEnclosure: 1. STPNOC Response to Requests for Additional Information2. STPNOC LRA Changes with Line-in/Line-out Annotations3. Regulatory Commitments /4(4/7 NOC-AE-12002797Page 2cc:(paper copy)(electronic copy)Regional Administrator, Region IVU. S. Nuclear Regulatory Commission1600 East Lamar BoulevardArlington, Texas 76011-4511Balwant K. SingalSenior Project ManagerU.S. Nuclear Regulatory CommissionOne White Flint North (MS 8B13)11555 Rockville PikeRockville, MD 20852Senior Resident InspectorU. S. Nuclear Regulatory CommissionP. 0. Box 289, Mail Code: MN1 16Wadsworth, TX 77483C. M. CanadyCity of AustinElectric Utility Department721 Barton Springs RoadAustin, TX 78704John W. DailyLicense Renewal Project Manager (Safety)U.S. Nuclear Regulatory CommissionOne White Flint North (MS 011-Fl)Washington, DC 20555-0001Tam TranLicense Renewal Project Manager(Environmental)U. S. Nuclear Regulatory CommissionOne White Flint North (MS 011 F01)Washington, DC 20555-0001A. H. Gutterman, EsquireKathryn M. Sutton, EsquireMorgan, Lewis & Bockius, LLPJohn RaganChris O'HaraJim von SuskilNRG South Texas LPKevin PolioRichard PenaCity Public ServicePeter NemethCrain Caton & James, P.C.C. MeleCity of AustinRichard A. RatliffAlice RogersTexas Department of State Health ServicesBalwant K. SingalJohn W. DailyTam TranU. S. Nuclear Regulatory Commission
 
==Enclosure==
1NOC-AE-12002797Enclosure 1STPNOC Response to Requests for Additional Information  
 
==Enclosure==
1NOC-AE-12002797Page 1 of 24SOUTH TEXAS PROJECT, UNITS 1 AND 2REQUEST FOR ADDITIONAL INFORMATION -AGING MANAGEMENT, SET 12(TAC NOS. ME4936 AND ME4937)Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (013)RAI 3.1.1.57-1a -follow-upBackgqround:By letter dated November 21, 2011, the applicant responded to RAI 3.1.1.57-1 that addressesthe susceptibility of the reactor coolant fittings made of cast austenitic stainless steel (CASS). Inits response, the applicant indicated that the Hull's equivalent factor was used to calculate deltaferrite content of Class I fittings using chemistry data from certified material test reports(CMTRs). The applicant also indicated that the screening calculation found that the delta ferritecontent of the fittings to be < 20 percent, and accordingly the fittings are not consideredsusceptible to a loss of fracture toughness due to thermal aging embrittlement.GALL Report, Revision 2, AMP XI.M12, "Thermal Aging Embrittlement of Cast AusteniticStainless Steel Program (CASS)," indicates that in the susceptibility screening method, ferritecontent is calculated by using the Hull's equivalent factors (described in NUREG/CR-4513,Revision 1) or a staff-approved method for calculating delta ferrite in CASS materials.Issue:The staff needs to further confirm if the applicant's susceptibility screening method for materialis consistent with the GALL Report. The GALL Report addresses the guidance ofNUREG/CR-4513, Revision 1 (Section 3.2) for ferrite content calculations using Hull'sequivalent factors.Request:Provide the bounding case chemical composition of the reactor coolant fittings that estimatesthe highest ferrite content of these CASS components, including the contents of Cr, Mo, Si, Ni,Mn, N and C.In addition, provide the calculated highest ferrite content in order to confirm that the applicant'sscreening analysis indicates no susceptibility of these fittings to thermal aging embrittlement. Aspart of the response, clarify if the applicant's susceptibility screening method is consistent withthe GALL Report that addresses the guidance of NUREG/CR-4513, Revision 1, for ferritecontent calculations using Hull's equivalent factors.
 
==Enclosure==
1NOC-AE-12002797Page 2 of 24STPNOC Response:(1) The bounding case chemical composition of Unit 1 reactor coolant fittings that estimates thehighest ferrite content is listed below:Unit 1 highest ferrite content is 14.9% of Heat Number 17743-1 using the Hull's equivalentfactor method.The chemical composition of Heat Number 17743-1 is:Cr%=19.87 Mo%=O Si%= 1.08 Ni%= 8.35 Mn%= 0.73 N
* C%=0.03(2) The bounding case chemical composition of Unit 2 reactor coolant fittings that estimates thehighest ferrite content is listed below:Unit 2 highest ferrite content is 15.4% of Heat Numbers 21389-1 and 21389-2 using theHull's equivalent factor method.The chemical composition of Heat Number 21389-1 is:Cr%= 19.88 Mo%=0 Si%= 1.18 Ni%=8.57 Mn%=0.82 N
* C%=0.02The chemical composition of Heat Number 21389-2 is:Cr%= 19.88 Mo%=0 Si%= 1.18 Ni%=8.57 Mn%=0.82 N
* C%=0.02(3) The calculation of the ferrite content from chemical composition in terms of Hull's equivalentfactors, as shown below, is consistent with the guidance of NUREG/CR-4513, Rev. 1,Section 3.2 for ferrite content calculations using Hull's equivalent factors.The ferrite content (6c%) is given by:6c% = 100.3[Square(Creq/Nieq)] -170.72(Creq/Nieq) + 74.22, whereCreq = Cr% + 1.21 (Mo%) + 0.48(Si%) -4.99Nieq = Ni% + 0.1 l(Mn%) -0.0086[Square(Mn%)] + 18.4(N%) + 24.5(C%) + 2.77* The concentration of N, when not provided on the CMTR, is assumed to be 0.04%.(Ref: NUREG/CR-4513, Rev. 1, Section 3.2)
 
==Enclosure==
1NOC-AE-12002797Page 3 of 24Flow-Accelerated Corrosion (018)RAI B2.1.6-1aBackground:GALL AMP XI.M17, "Flow-Accelerated Corrosion," states that the program relies onimplementation of the guidelines in NSAC-202L for an effective flow-accelerated corrosionprogram. NSAC-202L states, in part, that the systems may be susceptible to damage fromother corrosion or degradation mechanisms, which include cavitation, erosion, liquidimpingement, etc., but these mechanisms are not part of a flow-accelerated corrosion programand should be evaluated separately.In response to RAI 3.4.2.6-1, dated November 21, 2011, STP stated that components in theauxiliary feedwater system were initially identified as not susceptible to flow-acceleratedcorrosion due to infrequent operation. The response stated, however, that wear has been notedin some auxiliary feedwater components and that an item was added to Table 3.4.2-6identifying carbon steel piping exposed to secondary water as being managed for wall thinningby the Flow-Accelerated Corrosion Program. The response also stated that as a result of areview to determine whether other systems in the scope of license renewal should be includedin the program, six systems were identified and LRA Section B2.1.6 was revised to indicate thatthe Flow-Accelerated Corrosion Program manages wall thinning due to other causes, such aserosion/corrosion, in addition to flow-accelerated corrosion. This appears to correlate withinformation provided in response to RAI 3.3.2.19-1, dated November 4, 2011, which stated thatseveral systems are being monitored for wall thinning due to erosion/corrosion, but thesesystems had initially not been identified in the license renewal application (LRA) as beingsubject to wall thinning or as being managed by the Flow-Accelerated Corrosion Program.Issue:The guidance document for the flow-accelerated corrosion programs, NSAC-202L, states thatthe systems may be susceptible to damage from other corrosion or degradation mechanisms,which include cavitation, erosion, liquid impingement, etc., but these mechanisms are not partof a flow-accelerated corrosion program and should be evaluated separately. However, sinceSTP has chosen to include mechanisms other than flow-accelerated corrosion in its program,this is an enhancement to the flow-accelerated corrosion program that needs to be furtherdescribed in the LRA.Request:1) Provide detailed information describing the apparent enhancement to the Flow-AcceleratedCorrosion Program, including which of the 10 program elements are affected and how theyare affected.2) Since the initial integrated plant assessment did not identify the aging effects acknowledgedin response to RAI 3.4.2.6-1, provide information regarding corrective actions taken andextent of condition conducted that provide reasonable assurance that there are no otheraging effects that have been overlooked during the preparation of the LRA.
 
==Enclosure==
1NOC-AE-12002797Page 4 of 24STPNOC Response:1) The Flow-Accelerated Corrosion (FAC) program includes piping and piping componentssusceptible to wall thinning, which cannot be modeled by the predictive codeCHECWORKS. Piping and piping components susceptible to wall thinning due tomechanisms other than FAC are managed as susceptible non-modeled lines. Theinspections for these system components are administratively controlled using a databasedeveloped by the South Texas Project. The LRA Basis Document XI.M17 (B2.1.6) for theFAC aging management program includes a separate discussion of susceptible non-modeled components where appropriate. In several program elements, the discussionapplies equally to modeled and non-modeled system components.For clarification, LRA Appendix A1.6, Appendix B2.1.6, and the LRA Basis Document,XI.M1 7, Flow Accelerated Corrosion program, are revised to state explicitly that systemcomponents susceptible to wall thinning due to causes such as erosion/corrosion,cavitation, flashing, and impingement damage are included in the susceptible non-modeledportion of the FAC program.2) As part of the extent-of-condition review for RAI 3.4.2.6-1, six systems were identified andthe LRA was revised in response to RAI 3.4.2.6-1, dated November 21, 2011(ML1 1335A1 31) to include wall thinning as an aging effect for these systems. This reviewalso concluded that no other managed aging effects are omitted from the LRA submittal.Enclosure 2 provides the line-in/line-out revision for the changes to Appendices A1.6 andB2.1.6.Cast Austenitic Stainless Steel (073)RAI 3.1.1.80-1aBack-ground:By letter dated November 21, 2011, the applicant responded to RAI 3.1.1.80-1 that addressesthe need for AMR line items to manage cracking or loss of material of reactor vessel internalcomponents using the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWDProgram. In its response, the applicant revised LRA Table 3.1.2-1 and Section 3.1.2.2.12. Theapplicant's revisions indicate that consistent with MRP-227, Revision 0, the PWR ReactorInternals Program is not an applicable aging management program for managing cracking ofthe components listed in the revised LRA Section 3.1.2.2.12. One of these components listed inthe revised LRA Section 3.1.2.2.12 is the upper core support plate. The applicant also indicatedthat cracking of the upper core plate is managed by the ASME Section XI Inservice Inspection,Subsections IWB, IWC, and IWD Program.Sections 3.2.2 and 4.1.1 of the staff s safety evaluation (June 22, 2011; ADAMS Accession No.ML 111600498) of MRP-227, Revision 0, address Topical Report Condition 1 for highconsequence components. This condition specifies the upper core plate and lower supportforging or casting as the expansion components linked to the control rod guide tube (CRGT)assembly lower flange welds, which are the primary components. Section 3.2.2 of the staffs
 
==Enclosure==
1NOC-AE-12002797Page 5 of 24safety evaluation also indicates that inspections of these high consequence components shallbe triggered by the degradation of the primary component (in this case, CRGT lower flanges).The staffs safety evaluation further indicates that the examination method for these additionalinspections shall be consistent with the examination method used to detect the degradation ofthe primary component (in this case, EVT-1).Issue:The staff needs clarification as to whether the PWR Reactor Internals Program identifies theupper core plate as an expansion component linked to the CRGT lower flange welds to manageloss of material due to wear and cracking due to fatigue, as specified in the staffs safetyevaluation (June 22, 2011) of MRP-227, Revision 0.The staff also needs clarification as to whether the applicant's PWR Reactor Internals Programidentifies lower internals assembly lower support forging or casting as an expansion componentlinked to the CRGT lower flange welds to ensure adequate aging management and structuralintegrity, consistent with the staffs safety evaluation (June 22, 2011) of MRP-227, Revision 0.Request:1. Clarify whether the applicant's PWR Reactor Internals Program identifies the upper coreplate as an expansion component linked to the CRGT lower flange welds to manage loss ofmaterial due to wear and cracking due to fatigue, consistent with the staffs safetyevaluation (June 22, 2011) of MRP-227, Revision 0.2. Clarify whether the applicant's PWR Reactor Internals Program identifies the lower internalsassembly lower support forging or casting as an expansion component linked to the CRGTlower flange welds to ensure adequate aging management and structural integrity,consistent with the staff's safety evaluation (June 22, 2011) of MRP-227, Revision 0.3. Revise the LRA consistent with the applicant's response.STPNOC Response:The STP PWR Reactor Internals Program (B2.1.35) was initially prepared using EPRI 1016596,Material Reliability Program: PWR Internals Inspection and Evaluation Guidelines (MRP-227).The NRC issued Revision 1 of the NRC Safety Evaluation (ML1 1308A770) for MRP-227, Rev. 0on December 16, 2011 and the industry published EPRI-1022863 (MRP-227-A) as an NRCTopical Report in December 2011. As part of this RAI response, the LRA reactor vesselinternals sections listed below are revised to be consistent with NRC Safety Evaluation,Revision 1 and MRP-227-A. Enclosure 2 provides the line-in/line-out revision to the followingLRA sections:-LRA Table 3.1.1 items 30 and 37-LRA Table 3.1.2-1-LRA Sections 3.1.2.2.6, 3.1.2.2.9, 3.1.2.2.12, 3.1.2.2.15, and 3.1.2.2.17-LRA Appendix A1.35-LRA Table A4-1 Item 27-LRA Appendix B2.1.35
 
==Enclosure==
1NOC-AE-12002797Page 6 of 241) NRC Safety Evaluation, Revision 1, Sections 3.2.2 and 4.1.1 and MRP-227-A, Table 4 6identify the upper core plate as an expansion component linked to the control rod guidetube (CRGT) assembly lower flange welds, which are the primary components. LRAAppendix B2.1.35 and LRA Basis Document, PWRRI (B2.1.35), PWR Reactor Internalsprogram, are revised to include the upper core plate as an expansion component tomanage loss of material due to wear and cracking due to fatigue, consistent with NRCSafety Evaluation, Revision 1, and MRP-227-A, Table 4-6.LRA Table 3.1.2-1 is revised to manage the aging effects of cracking due to fatigue in theupper core plate with Aging Management Program (AMP) Water Chemistry (B2.1.2) andPWR Reactor Internals Program (B2.1.35). LRA Table 3.1.2-1 is revised to manage loss ofmaterial in the upper core plate due to wear using AMP PWR Reactor Internals Program(B2.1.35). LRA Section 3.1.2.2.12 is also revised to delete the upper core support uppercore plate from the list of components not included in the PWR Reactor Internals Program.2) NRC Safety Evaluation, Revision 1, Sections 3.2.2 and 4.1.1 and MRP-227-A, Table 4 6identify the lower internals support lower support forging as an expansion component linkedto the CRGT assembly lower flange welds. LRA Appendix B2.1.35 and LRA BasisDocument PWRRI (B2.1.35), PWR Reactor Internals program, are revised to include thelower internals assembly lower support forging as an expansion component linked to theCRGT lower flange welds to manage cracking due to fatigue, consistent with NRC SafetyEvaluation, Revision 1 and MRP-227-A,Table 4-6.An Aging Management Review (AMR) line exists in LRA table 3.1.2-1 to manage crackingof the lower support forging.3) Enclosure 2 provides the line-in/line-out revision for the changes identified in response to 1and 2 above.RAI 3.1.1.80-2aBackground:By letter dated November 21, 2011, the applicant responded to RAI 3.1.1.80-2 that addressesthe aging management for loss of fracture toughness of the CRGT assembly lower flanges andrelated components. The applicant indicated that the CRGT assembly lower flange welds aresub-components of the reactor vessel internal (RVI) CRGT assembly listed in LRA Table3.1.2-1. The applicant also indicated that the CRGT lower flanges are fabricated of stainlesssteel and cracking is the only aging effect to be managed by MRP-227 for these components.The applicant further indicated that upon detection of cracking in a component susceptible toloss of fracture toughness, the PWR Reactor Internals Program defines an assessment ofcracking with limit load and/or fracture mechanics evaluations.In comparison, LRA Table 3.1.2-1 indicates that loss of fracture toughness due to irradiationembrittlement of the CRGT assembly made of stainless steel is managed by the PWR ReactorInternals Program. In addition, Table 3-3 of MRP-227, Revision 0, indicates that the CRGTlower flanges made of CASS are susceptible to cracking due to stress corrosion cracking
 
==Enclosure==
1NOC-AE-12002797Page 7 of 24(SCC) and fatigue, and loss of fracture toughness due to thermal aging embrittlement andirradiation embrittlement.In its response, the applicant also indicated that the bottom mounted instrumentation (BMI)column bodies are listed in LRA Table 3.1.2-1 as RVI in-core instrumentation (ICI) supportstructures-instrument column (BMI). The applicant further indicated that cracking is the onlyaging effect to be managed by MRP-227 for the BMI column bodies. In comparison, Table 3-3of MRP-227. Revision 0 indicates that the BMI column bodies made of Type 304 stainless steelare susceptible to cracking due to fatigue, and loss of fracture toughness due to irradiationembrittlement.Issue:The staff needs clarification as to whether the CRGT lower flanges are made of CASS. If theCRGT lower flanges are made of CASS, the staff needs to further clarify if loss of fracturetoughness, in addition to cracking, is considered as an aging effect to be managed by the PWRReactor Internals Program for these components. In addition, the staff needs clarification as towhy cracking is the only aging effect to be managed by the PWR Reactor Internals Program forthe BMI column bodies, without inclusion of aging management for loss of fracture toughness.Request:1. Clarify whether the CRGT lower flanges are made of CASS.If the CRGT lower flanges are made of CASS, clarify why cracking is the only aging effectto be managed by the PWR Reactor Internals Program for these components, withoutinclusion of aging management for loss of fracture toughness due to thermal agingembrittlement and irradiation embrittlement.In addition, resolve the apparent conflict between the applicants claim that cracking is theonly aging effect to be managed by the PWR Reactor Internals Program for the CRGTlower flanges and the applicants aging management review results in LRA Table 3.1.2-1indicating that loss of fracture toughness of the CRGT assembly is managed by the PWRReactor Internals Program.2. Clarify why cracking is the only aging effect to be managed by the PWR Reactor InternalsProgram for the BMI column bodies, without inclusion of aging management for loss offracture toughness due to irradiation embrittlement.3. Revise the LRA consistent with the applicants response. As part of the revision, if loss offracture toughness is identified as an applicable aging effect of the BMI column bodies, addan AMR line item to manage this aging effect.
 
==Enclosure==
1NOC-AE-12002797Page 8 of 24STPNOC Response:(1) LRA Table 3.1.2-1 and RAI 3.1.1.80-2 response dated November 21, 2011 (ML11334A131),identified that the control rod guide tube (CRGT) assembly lower flanges are fabricated ofstainless steel, not cast austenitic stainless steel (CASS). Westinghouse confirmed that theCRGT assembly lower flanges are fabricated from forged stainless steel.The STP PWR Reactor Internals Program (B2.1.35) was initially prepared using EPRI1016596, Material Reliability Program: PWR Internals Inspection and Evaluation Guidelines(MRP-227). The NRC issued Revision 1 of the Safety Evaluation (ML1 1308A770) forMRP-227 on December 16, 2011 and the industry published EPRI-1022863 (MRP-227-A)as an NRC Topical Report in December 2011. As part of the response to RAI 3.1.1.80-1a,the LRA reactor vessel internals sections are revised to be consistent with NRC SafetyEvaluation, Revision 1 and MRP-227-A.An aging management line for loss of fracture toughness due to irradiation embrittlement ofthe stainless steel CRGT assembly lower flanges is currently included in LRA Table 3.1.2-1and is consistent with Table 4-3 of MRP-227-A.(2) STP concurs that the aging effect, loss of fracture toughness due to irradiationembrittlement, is applicable to the BMI column bodies. The aging effect of loss of fracturetoughness due to irradiation embrittlement of BMI column bodies is identified inNUREG-1801, Rev. 2, Item IV.B2.RP-292 and MRP-227-A, Table 4-6.(3) LRA Table 3.1.2-1 is revised to add a loss of fracture toughness aging management line forthe BMI column bodies, which is consistent with MRP-227-A Table 4-6.Enclosure 2 provides the line-in/line-out revision for the changes to LRA Table 3.1.2-1.RAI 3.1.2.1-1aBackQround:By letter dated November 21, 2011, the applicant responded to RAI 3.1.2.1-1 that addressesthe aging management of inaccessible locations of the reactor vessel internal components. Inits response, the applicant indicated that the applicant's program will inspect one hundredpercent of the volume/area of each accessible component in accordance with MRP-227 asapproved by the NRC safety evaluation report dated June 22, 2011. The applicant alsoindicated that the minimum examination coverage for primary and expansion inspectioncategories is 75 percent of the component's total (accessible plus inaccessible) inspectionarea/volume or, when addressing a set of like components (e.g. bolting), the inspection willexamine a minimum sample size of 75 percent of the total population of like components. Theapplicant further indicted that a technical justification will be required of any minimum coveragerequirements below 75 percent of total inspection area/volume or sample size. In addition, theapplicant indicated that the PWR Reactor Internals Program is consistent with these conditionsregarding the minimum examination coverage addressed in Section 3.3.1 of the staffs safetyevaluation of MRP-227, Revision 0.
 
==Enclosure==
1NOC-AE-1 2002797Page 9 of 24In RAI 3.1.2.1-1, the staff requested that, if an aging effect has been identified in accessiblelocations of the reactor vessel internal components, the applicant should provide furtherevaluation to ensure that the aging effect is adequately managed for the inaccessible locationsas recommended in GALL Report, Revision 2 (items IV.B2.RP-268 and IV.B2.RP-269) andSRP-LR, Revision 2 (Sections 3.1.2.2.9 and 3.1.2.2.10).SRP-LR Sections 3.1.2.2.9 and 3.1.2.2.10 state that if aging effects are identified in accessiblelocations, the GALL Report recommends further evaluation of the aging effects in inaccessiblelocations on a plant-specific basis to ensure that this aging effect is adequately managed.Issue:The staff noted that the applicant confirmed that the minimum examination coverage criteria ofthe applicant's program are consistent with the Topical Report Conditions in the staffs safetyevaluation (June 22, 2011) of MRP-227, Revision 0. However, the staff noted that in itsresponse, the applicant did not indicate whether the applicant performed further evaluation forthe aging effect in the inaccessible locations of partially accessible components (including a setof multiple components such as bolts), consistent with the GALL Report and SRP-LR, when anaging effect was detected in the accessible locations of the components.In addition, the staff needs clarification as to whether the applicant's aging management willperform further evaluation to ensure adequate aging management for the inaccessible locationsof partially accessible components if an aging effect is identified in the accessible locations ofthe components.Request:1. If an aging effect was detected in the accessible locations of partially accessible reactorvessel internal components (including a set of multiple components such as bolts), describethe plant-specific evaluation of the aging effect in the inaccessible locations of thecomponents, which was performed to ensure that this aging effect is adequately managed.2. Clarify whether the applicant's aging management program will perform plant-specificevaluation to ensure adequate aging management for the inaccessible locations of partiallyaccessible components (including a set of multiple components such as bolts) if an agingeffect is identified in the accessible locations of the components.3. Revise the LRA consistent with the applicant's response.STPNOC Response:1) The STP PWR Reactor Internals Program (B2.1.35) recent operating experienceassociated with ASME Code inspections or modifications of the reactor vessel internals didnot identify any defects requiring MRP-227-A engineering evaluations. ASME Code,Section XI, Examination Category B-N-3 examinations of the reactor internals conductedduring refueling outage 1RE15 (Fall 2009) for Unit 1, and during refueling outage 2RE14(Spring 2010) for Unit 2, did not identify any conditions that required repair, replacement orevaluation. STP replaced the Alloy-750 control rod guide tube support pins (split pins) withstrained hardened (cold worked) 316 stainless steel pins during refueling outage 1 RE12
 
==Enclosure==
1NOC-AE-12002797Page 10 of 24(Spring 2005) for Unit 1 and during refueling outage 2RE1 1 (Fall 2005) for Unit 2. The pinreplacement process did not discover any cracked Alloy X-750 split pins.LRA Appendix B2.1.35 and LRA Basis Document PWRRI (2.1.35), PWR Reactor InternalsProgram, are revised to incorporate the operating experience associated with the recentASME Code inspections and the control rod guide tube support pin (split pin) replacements.(2) One hundred percent of the accessible volume/area of each Primary component and, whenrequired, the Expansion component will be examined subject to the minimum examinationcoverage criteria in NRC safety evaluation sections 3.3.1, 3.3.2 and 4.1.4 for MRP-227-A(December 16, 2011; ADAMS Accession No. ML1 1308A770).LRA Appendix B2.1.35 and LRA Basis Document PWRRI (2.1.35), PWR Reactor InternalsProgram, are revised to specify the component-specific minimum examination coveragecriteria consistent with MRP-227-A Tables 4-3 and 4-6. If defects are discovered during theexamination, STP will enter the information into the corrective action program and evaluatewhether the results of the examination ensure that the component (or set of components)will continue to meet its intended function under all licensing-basis conditions of operationuntil the next scheduled examination. Engineering evaluations that demonstrate theacceptability of a detected condition are performed consistent with WCAP-1 7096-NP.(3) Enclosure 2 provides the line-in/line-out revisions for changes to LRA Appendix B2.1.35.RAI 3.0-1a (Follow-up to RAI 3.0-1)Background:LRA Table 3.0-1 states that the applicant's environment of "plant indoor air" encompasses theGALL Report defined environments of "air-indoor controlled," "air-indoor uncontrolled,""condensation," "air, moist," "air with steam or water leakage," etc., depending on whether the"plant indoor air" is an internal or external environment. The applicant used the term "plantindoor air" in its AMR tables and did not use the GALL Report defined environments. The GALLReport identifies the potential for different aging effects when components are exposed to eachof these different environments.By letter dated September 22, 2011, the staff issued RAI 3.0-1 requesting that the applicantidentify which AMR items in the LRA are exposed to a "plant indoor air" environment for whichhumidity, condensation, or moisture is present. In its response dated November 21,2011, theapplicant stated that some AMR items were inadvertently associated with a GALL Report itemfor exposure to "air-indoor controlled" that should have been associated with a GALL Reportitem for exposure to "air-indoor uncontrolled," and the applicant made the associated changesto the LRA. The applicant did not revise its definition of "plant indoor air" or make any otherchanges to the LRA to indicate whether the AMR items that have an environment of "plantindoor air" are exposed to humidity, condensation, or moisture. In a teleconference heldDecember 12, 2011, the applicant clarified that anytime the environment "plant indoor air" isused in the LRA, there is a potential for moisture in the air.
 
==Enclosure==
1NOC-AE-12002797Page 11 of 24The staff identified several instances in the LRA in which NUREG-1800, "Standard Review Planfor License Renewal of Nuclear Power Plants" (SRP-LR), Table 1 items for exposure to "air-indoor uncontrolled" are being used inappropriately for components with a "plant indoor airenvironment." As a result, the applicant has inappropriately concluded that the componentshave no aging effects requiring management. Examples include:Several aluminum components in the LRA exposed to "plant indoor air" referenceSRP-LR Table 3.2-1, item 50, which is for aluminum components exposed to "air-indooruncontrolled" and recommends that there are no aging effects requiring management.However, since the applicant's definition of "plant indoor air" includes condensation andmoisture, these components are susceptible to loss of material, as documented in SRP-LR Revision 2 Table 3.3-1, item 92.Several stainless steel, copper alloy, and nickel alloy components in the LRA exposed to"plant indoor air" reference SRP-LR Table 3.4-1, item 41, which is for componentsexposed to "air-indoor uncontrolled" and recommends that there are no aging effectsrequiring management. However, these components are susceptible to loss of materialwhen exposed to condensation and moisture, as documented in SRP-LR Revision 2Table 3.3-1, items 79 and 95.Similar situations occur for other aluminum, steel, galvanized steel, stainless steel, copper alloy,and nickel alloy components exposed to a "plant indoor air environment" for which no agingeffects requiring management are identified in the LRA.Issue:It is not clear to the staff why there are aluminum, steel, galvanized steel, stainless steel,copper alloy, and nickel alloy AMR items in the LRA exposed to an environment of "plant indoorair" that do not have any aging effects identified. It is also not clear to the staff how SRP-LRTable 1 items for components exposed to "air-indoor uncontrolled" are adequate references forcomponents in the LRA that are exposed to "plant indoor air." The applicant's "plant indoor air"environment includes moisture or condensation, which is not part of the SRP-LR environment of"air-indoor uncontrolled."Request:For all of the aluminum, steel, galvanized steel, stainless steel, copper alloy, and nickel alloyAMR items in the LRA with an environment of "plant indoor air" that do not have any agingeffects identified, explain why the components have no aging effects requiring management oridentify appropriate aging effects and aging management programs consistent with theguidance in the GALL Report, Revision 2, for air environments that contain moisture.STPNOC Response:The LRA Table 3.0-1 environments of Plant Indoor Air (Internal) and Plant Indoor Air (External)include the NUREG-1801 environment of condensation. LRA Table 3.0-1, MechanicalEnvironments Description, is revised as follows to clarify the use of Plant Indoor Air as aninternal or external environment.
 
==Enclosure==
1NOC-AE-12002797Page 12 of 24Plant Indoor Air (When used as Internal) -Description:Plant Indoor air (Internal) is air with temperatures at or below the dew point.Condensation is assumed to occur and the environment is potentially aggressive. PlantIndoor Air (Internal) includes non-dried compressed air and gases. Plant Indoor Air(Internal) is used for the internal surfaces of drain lines.Plant Indoor Air (When used as External) -Description:Plant Indoor air (External) is air with temperatures higher than the dew point.Condensation can occur, but only rarely, component surfaces are normally dry.Condensation is only assumed to occur on external surfaces of plant components inchilled water and air conditioning systems. These plant systems may produce externalcomponent surface temperatures at or below the dew point. Plant Indoor Air (External)with condensation is potentially aggressive.A review of the aging management review (AMR) lines for components exposed to Plant IndoorAir (Internal) found AMR lines that require the addition of aging effects and aging managementprograms to address loss of material caused by condensation. LRA Tables 3.3.2-8, 3.3.2-16,3.3.2-20, 3.3.2-23, and 3.4.2-1 are revised to assign aging effects and aging managementprograms to these Plant Indoor Air (Internal) AMR lines. In addition, LRA Section 3.3.2.1.8 andSection 3.3.2.1.16 are affected by this change and are revised.A review of the AMR lines for Plant Indoor Air (External) found AMR lines for the chilled waterand the air conditioning systems that require aging effects and aging management programs toaddress loss of material due to condensation. LRA Tables 3.3.2-9, 3.3.2-10, 3.3.2-11, 3.3.2-12,and 3.3.2-15 are revised to assign aging effects and aging management programs to theseAMR lines where components are constructed of galvanized steel and stainless steel. Inaddition, LRA Section 3.3.2.2.10.5 is affected by this change and is revised.Enclosure 2 provides the line-in/line-out revision for the changes to LRA Sections 3.3.2.1.8,3,3.2.1.16, and 3.3.2.2.10.5 and LRA Tables 3.3.2-8, 3.3.2-9, 3.3.2-10, 3.3.2-11, 3.3.2-12,3,3.2-15, 3.3.2-16, 3.3.2-20, 3.3.2-23, and 3.4.2-1.Future consideration of Operating ExperienceRAI B1.4-2Backgqround:In request for additional information (RAI) B13.4-1, issued on May 24, 2011, the staff asked theapplicant to describe the programmatic activities that will be used to continually identify agingissues, evaluate them, and as necessary, enhance the AMPs or develop new AMPs for licenserenewal. In its response dated June 23, 2011, the applicant stated that it maintains proceduresfor feedback of operating information, including aging-related issues, pursuant to NUREG-0737, "Clarification of TMI Action Plan Requirements," Item I.C.5, "Procedures for Feedback ofOperating Experience to Plant Staff." The applicant also stated that the Corrective Action
 
==Enclosure==
1NOC-AE-1 2002797Page 13 of 24Program (CAP) complements the Operating Experience (OE) Program to monitor aging-relatedissues.IssueThe applicant's response provides a general description of how it considers operatingexperience on an ongoing basis; however, it does not directly address several areas in RAIB1.4-1 on which the staff requested information. Further, in certain areas, the applicant'sresponse does not provide enough information on how the operating experience reviewactivities address issues specific to aging. The staff identified the following issues with theapplicant's response:(a) It is not clear as to whether the applicant only reviews certain sources of plant-specificand industry operating experience information. Additional information is needed todetermine whether the applicant's processes would preclude the consideration ofrelevant operating experience information, because it is not from a prescribed source.(b) The applicant did not describe how it ensures the timely completion of operatingexperience evaluations, nor did it describe how it prioritizes the evaluations. It istherefore unclear as to whether the operating experience evaluations will be completedin a timely manner or whether they will be appropriately prioritized.(c) The applicant provided example sources of plant-specific and industry operatingexperience that it monitors on an ongoing basis to identify potential aging issues andstated that the results of the monitoring are documented and maintained in accordancewith plant records management and administration procedures. It is unclear as towhether "results of the monitoring" includes the operating experience evaluations. Also,the applicant did not describe what's recorded on the operating experience evaluationswith respect to addressing aging issues. In addition, it is not clear whether maintenance"in accordance with plant records management and administration procedures" isequivalent to keeping the evaluations in an auditable and retrievable form.(d) The applicant indicated that it only would record the monitoring results for the examplesources of operating experience it provided. It is therefore not clear how the applicantwill keep the monitoring or evaluation results for reviews of other sources of plantspecific and industry operating experience.(e) The applicant listed example sources of plant-specific and industry operating experiencethat are monitored on an ongoing basis to identify potential aging issues and stated thatthey are placed in the CAP, as appropriate. Additional information is needed todetermine how enhancements to the aging management activities, including thedevelopment of new AMPs, will be implemented.(f) For its OE Program, the applicant stated that it maintains procedures for the feedback ofoperating information pursuant to NUREG-0737 Item I.C.5. Additional information isneeded on how the applicant ensures the effectiveness of this program.(g) The applicant did not describe its criteria for identifying and categorizing operatingexperience items as related to aging.
 
==Enclosure==
1NOC-AE-12002797Page 14 of 24(h) The applicant stated that it does not review under its OE Program NRC regulatoryguides, license renewal interim staff guidance, revisions to the GALL Report, andrevisions to industry standards on which the AMPs are based. However, guidancedocuments, like the GALL Report, can provide a convenient source of operatingexperience information, useful recommendations, and best practices, the considerationof which would help to ensure the effectiveness of the AMPs, or indicate the need toenhance the AMPs or develop new AMPs.(i) The applicant did not describe how evaluations of operating experience related to agingconsider the potentially affected plant for the following:* systems, structures, and components* materials* environments* aging effects* aging mechanisms* AMPs(j) The applicant did not describe criteria for considering when AMPs should be modified ornew AMPs developed due to operating experience.(k) The applicant stated that conditions adverse to quality, including adverse results ofinspections performed under the AMPs, are monitored on an ongoing basis to identifypotential aging issues and placed in the CAP. Additional information is needed on howthe applicant will consider as operating experience the results of the inspections, tests,analyses, etc., conducted through implementation of the AMPs, particularly when theresults meet the AMP's acceptance criteria.(I) The applicant stated that engineering support personnel have been trained on theequipment reliability process, which includes age-related inputs, and on the ElectricPower Research Institute's aging assessment field guide. Additional information isneeded on the training that will be provided for those plant personnel responsible forscreening, assigning, evaluating, and submitting operating experience items.(m)The applicant stated that it shares lessons learned with other utilities to promoteindustry-wide safety and reliability; however, the applicant did not provide criteria forreporting its plant-specific operating experience on age-related degradation to theindustry.Request:Provide a response to each item below.(a) Indicate whether plant-specific and industry operating experience is only consideredfrom a prescribed list of sources. If only prescribed sources are considered, provide ajustification as to why it is unnecessary to consider other sources.
 
==Enclosure==
1NOC-AE-1 2002797Page 15 of 24(b) Describe how plant-specific and industry operating experience evaluations will beprioritized and completed in a timely manner.(c) Describe the operating experience evaluation records with respect to what will beconsidered and recorded for aging. Indicate whether the evaluation records will bemaintained in auditable and retrievable form.(d) Indicate whether there are any differences between evaluation records kept for thereview of operating experience from the list of example sources and records kept for thereview of other sources of plant-specific and industry operating experience. If there aredifferences, describe and justify them.(e) Describe how enhancements to the aging management activities will be implemented,including the development of new AMPs, when it is determined through an operatingexperience evaluation that enhancements are necessary.(f) Describe the administrative controls for the OE Program and indicate whether theyinclude periodic audits to ensure the program's effectiveness(g) Describe how operating experience issues will be identified and categorized as relatedto aging. If an identification code is used, provide its definition or the criteria for itsapplication. Also, describe how age-related operating experience will be trended.(h) Provide a plan for considering the content of guidance documents, such as the GALLReport, as operating experience applicable to aging management.(i) Describe how evaluations of operating experience issues related to aging will considerthe following:* systems, structures, or components* materials* environments* aging effects* aging mechanisms* AMPs() Describe criteria for considering when AMPs should be modified or new AMPsdeveloped due to operating experience.(k) Describe how the results of the AMP inspections, tests, analyses, etc. will be consideredas operating experience, both when they meet and do not meet the applicableacceptance criteria.(I) Describe the training requirements and justify the level of training on aging issues forthose plant personnel responsible for screening, assigning, evaluating, and submittingplant-specific and industry operating experience. Also, provide the periodicity of thetraining and describe how it will account for personnel turnover.
 
==Enclosure==
1NOC-AE-12002797Page 16 of 24(m) Provide criteria for reporting plant-specific operating experience on age-relateddegradation to the industry.STPNOC Response:(a) The South Texas Project (STP) Operating Experience Program (OEP) procedure usesvarious source documents (e.g., INPO, NRC, or NEI websites) for applicable OEreports. In addition, STP reviews Nuclear Network Operating Experience Reportsweekly and forwards these documents to the applicable subject matter expert. Thesedocuments are coded and all age-related failures are forwarded to the appropriatepersonnel for disposition.The OEP procedure will be revised to add License Renewal Interim Staff Guidance andrevisions to NUREG-1801, "Generic Aging Lessons Learned (GALL) Report", as sourcedocuments applicable for review. (See Commitment Item 41 in Enclosure 3)(b) Within 10 days of receiving an OE source document, a condition report is initiated toscreen the OE for applicability to STP. The OE is then evaluated within the next 40 daysto determine impact on STP programs and procedures. The OEP process allows forextension of these evaluations up to 180 days. Implementing actions initiated fromplant-specific and industry operating experience evaluations are managed through thecorrection action program with action due dates established commensurate with theirsafety significance.(c) The OEP procedure will be revised to include "aging effects" to the list of characteristicsfor determining applicability of an OE document that may require further evaluation.Evaluations should consider: (a) systems, structures, or components; (b) materials; (c)environments; (d) aging effects; (e) aging mechanisms; and (f) aging managementprograms. (See Commitment Item 41 in Enclosure 3)The screening and evaluation results of OE reviews including implementation actionsare documented in the corrective action program and are captured in a retrievable database.(d) The South Texas Project (STP) Operating Experience Program (OEP) procedure usesvarious source documents (e.g., INPO, NRC, or NEI websites) for applicable OEreports. All source documents evaluated become quality documents once completedand stored for retrieval. All specific documents are identified by event codes and thetypes of evaluations are categorized by action type codes. This procedure applies to allactivities and organizations within STPNOC and is applicable to source documents listedin the procedure and vendor Nuclear Safety Advisory Letters. The OEP procedure willbe revised to add License Renewal Interim Staff Guidance and revisions to NUREG-1801, "Generic Aging Lessons Learned (GALL) Report", as source documentsapplicable for review.The STP Corrective Action Program (CAP) requires that condition owners evaluateconditions (which would include those conditions related to aging effects) and determinethe need to capture OE and enter data in required fields in the CAP data base. TheOEP procedure provides a process for sharing lessons learned from "plant-specific" OE
 
==Enclosure==
1NOC-AE-12002797Page 17 of 24identified in CAP with the industry.(e) The Station Operating Experience Coordinator creates a screening condition reportwhen Industry OE documents for top tier documents identified within the scope of theprocedure is received. A designated line organization evaluator may be required tosupport the screening and evaluation. A number of characteristics are considered fordetermining applicability. The OEP procedure will be revised to include "aging effects" tothe list of characteristics for determining applicability of an OE document that mayrequire further evaluation. Evaluations should consider: (a) systems, structures, orcomponents; (b) materials; (c) environments; (d) aging effects; (e) aging mechanisms;and (f) aging management programs. (See Commitment Item 41 in Enclosure 3) If theOE document is applicable to a plant aging management program (AMP), the programowner is assigned an action to review the OE for impact on the AMP. If the AMPrequires enhancement, it is identified during the impact review.Station-level OE is identified through the generation of condition reports. The CAPprocedure lists "aging" as an example of a condition that can reduce the capability of asystem and thus result in a degraded condition. There are several "event codes" relatedto equipment failures or degradation that are aging-related. Corrective Action ProgramEvent Codes will be reviewed to determine if additional codes are needed to ensureage-related degradation effects are identified. (See Commitment Item 41 in Enclosure 3)The CAP process requires determining the extent of condition of nonconforming ordegraded conditions. Corrective action may include enhancements to existing AMP.Another outcome of either Industry OE or station-level OE is that corrective action couldresult in the development of a new AMP if the condition can not be adequatelyaddressed by an existing AMP. LRA Licensing Commitment #29 states that, asadditional industry and plant-specific applicable operating experience becomesavailable, it will be evaluated and incorporated into each aging management program orin the development of a new aging management program(s), as necessary, to provideassurance that the effects of aging will be managed during the period of extendedoperation.(f) The STP OEP procedure is a quality-related procedure. While OEP effectivenessreviews focus on historical INPO Significant Operating Event Reports and Level 1 andLevel 2 INPO Event Reports, oversight organizations may perform audits andassessments on the OEP. In addition, the Station Self-Assessment Coordinatorperforms a biennial effectiveness review of the OEP and ensures an industry peer isavailable to support this review.(g) The Station Operating Experience Coordinator creates a screening condition reportwhen Industry OE documents are received. A designated line organization evaluatormay be required to support the screening. A number of characteristics are consideredfor determining applicability. The CAP procedure requires that condition ownersevaluate the condition and determine the need to capture OE and enter data in requiredfields.The OEP procedure will be revised to include "aging effects" to the list of characteristicsfor determining applicability of a OE document that may require further evaluation.
 
==Enclosure==
1NOC-AE-12002797Page 18 of 24Evaluations should consider: (a) systems, structures, or components; (b) materials; (c)environments; (d) aging effects; (e) aging mechanisms; and (f) aging managementprograms. (See Commitment Item 41 in Enclosure 3)There are several "event codes" in CAP related to equipment failures or degradationthat are aging-related. Corrective Action Program Event Codes will be reviewed todetermine if additional codes are needed to ensure age-related degradation effects areidentified. (See Commitment Item 41 in Enclosure 3)Each AMP discusses the appropriate elements of monitoring and trending to providepredictability of the extent of degradation and to provide for timely corrective action ormitigating actions.(h) See response to item (a).(i) See response to item (c).(j) Results of inspections, tests, analyses, etc. conducted through the implementation ofaging management programs are considered as operating experience on an ongoingbasis. When applicable acceptance criteria are met, results are retained for future useand evaluation to determine whether it is necessary to adjust the frequency for futureinspections, establish new inspections, and ensure an adequate depth and breadth ofcomponent, material, environment, and aging effect combinations. When applicableacceptance criteria are not met, corrective actions are initiated in accordance with thequality assurance program.(k) See response to item (j).(I) A training "needs analysis" will be performed for those plant personnel who screen,assign, evaluate, and submit plant-specific and industry operating experienceinformation for age-related effects. (See Commitment Item 41 in Enclosure 3)The "needs analysis" should consider whether responsible personnel:* Can appropriately identify when operating experience has the potential to involveage-related degradation,* Understand the purpose and scope of the aging management programs, howthese programs manage the effects of aging applicable to the plant, and whichaging degradation is likely to occur, and* Can identify the difference between an evaluation for operability and anevaluation for age-related degradation.(m)The OEP procedure provides the requirements for posting internal OE to the INPONuclear Network. The procedure will be revised to provide criteria for reportingplant-specific operating experience on age-related degradation. (See Commitment Item41 in Enclosure 3)
 
==Enclosure==
1NOC-AE-12002797Page 19 of 24Enclosures 2 and 3 describe the enhancements to be made to the OEP and the CAPprovided in the above responses to this RAI.RAI A1-1Background:In RAI B13.4-1, the staff asked the applicant to provide, in accordance with 10 CFR 54.21(d), anupdated final safety analysis report (UFSAR) supplement summary description of theprogrammatic activities for the ongoing review of operating experience. By letter dated August18, 2011, the applicant provided this description:Operating experience is applied to all aging management programs discussed in SectionsAl and A2. Plant-specific and industry operating experience is continuously reviewed toconfirm the effectiveness of AMPs and is utilized, as necessary, to enhance each AMP or todevelop new AMPs in order to adequately manage the effects of aging so that the intendedfunction(s) of structures and components are met.Issue:As described above in RAI B13.4-2, the applicant described generally how it intends to consideroperating experience on an ongoing basis; however, it did not provide specific information onhow its operating experience review activities will address issues related to aging. Similarly, theabove entry for UFSAR supplement also lacks details on how aging is considered in theongoing operating experience reviews.Request:Consistent with the response to RAI B13.4-2, provide additional details in the FSAR supplementon how the ongoing operating experience review activities address issues related to aging.STPNOC Response:Enclosure 2 provides the line-in/line-out revision for the changes to Appendix Al. This changeprovides the additional details in the FSAR supplement on how the ongoing operatingexperience review activities address issues related to aging consistent with the response to RAIB13.4-2.Enclosure 3 provides line-in new regulatory commitment Item 41 that captures theenhancements that will be made to the OEP and the CAP.
 
==Enclosure==
1NOC-AE-12002797Page 20 of 24Heat Exchangers (085)RAI 3.3.2.2.4-1aBackground:In RAI 3.3.2.2.4-1, the staff asked the applicant to clarify whether the non-regenerative heatexchangers will be included in the sample of components to be inspected using the One-TimeInspection Program and to justify why eddy current testing is not used to detect cracking in theheat exchanger tubes. In its response, dated November 21, 2011, the applicant stated thatnon-regenerative heat exchangers are included in the material/environment componentpopulation in its One-Time Inspection Program and that the LRA Basis Document for B2.1.16,One-Time Inspection Program, "scope of program" element will be revised to add a specificrequirement to perform eddy current inspections of the tubes in one of the non-regenerativeheat exchangers. Also in its response, the applicant revised LRA Section 3.3.2.2.4.1 by statingthat the one-time inspection will perform eddy current inspection of the tubes in one of thenon-regenerative heat exchangers.Issue:The staff finds the technical portion of response acceptable because the applicant will performeddy current testing of the non-regenerative heat exchanger tubes, which will manage potentialcracking as recommended in SRP-LR 3.3.2.2.4.1. However, it was not clear to the staff that thisspecific license renewal activity had been appropriately captured in the current licensing basis.Request:Revise LRA Section A1.16, associated with the One-Time Inspection Program, to include adescription of the eddy current testing of non-regenerative heat exchanger tubes, or provideanother licensing basis document to accomplish a comparable commitment.STPNOC Response:LRA Appendices A1.16 and B2.1.16 and LRA Basis Document XI.M32(B2.1.16), One-TimeInspection Program, are revised to include the following statement.The sample population includes eddy current testing of the tubes in one non-regenerativeheat exchanger.Enclosure 2 provides the line-in/line-out revision for the changes to LRA Appendices Al. 16 andB2.1.16.B2.1.39-1Background:The generic aging lessons learned (GALL) Report AMP XI.S8 recommends using AmericanSociety for Testing and Materials (ASTM) D 5163, in as much as it defines the Service Level 1
 
==Enclosure==
1NOC-AE-12002797Page 21 of 24coating inspection frequency to be each refueling outage or during other major maintenanceoutages, as needed. The LRA Section B2.1.39 states that general visual inspections of ServiceLevel 1 coatings are conducted as part of American Society of Mechanical Engineers (ASME)Section XI, Subsection IWE program and the Structures Monitoring Program at intervals notexceeding five years.Issue:The LRA does not state the specific standards used to perform coating assessment(e.g., ASTM D 5163). In addition, the frequency of Service Level 1 coating inspection seems tobe inconsistent with the recommendations of the GALL Report.Request:Please discuss the standards and/or guidance used (e.g., ASTM standards) to perform coatingassessments and discuss the frequency of coating inspections and how it is consistent with theGALL Report.STPNOC Response:LRA Appendix B2.1.39 and LRA Basis Document PSCOAT (B2.1.39), Protective CoatingMonitoring and Maintenance program, are revised to specify that condition assessments ofService Level 1 coatings inside the containment be performed consistent with the standardsprovided in ASTM D 5163-08 and NRC Regulatory Guide 1.54, Revision 2, as addressed inNUREG 1801, Rev 2, XI.S8 and are conducted during every refueling outage.LRA Table A4-1, Appendix A1.39, Appendix B2.1.39 and LRA Basis Document PSCOAT(B2.1.39) are revised to include the following enhancements:" Parameters monitored or inspected include any visible defects, such as blistering,cracking, flaking, peeling, rusting, and physical damage." Inspection frequencies, personnel qualifications, inspection plans, inspectionmethods, and inspection equipment meet the requirements of ASTM D 5163-08." A pre-inspection review is performed of the previous two monitoring reports andrepair areas are prioritized as either needing repair during the same outage, needingrepair during the next available outage, or monitored and re-evaluated in nextavailable outage." A standardized coating condition assessment report form includes the identificationof coatings found intact with no defects identified, identification of coatings that werenot inspected, and the reason why the inspection cannot be conducted." A standardized coating condition assessment report includes written and/orphotographic documentation of coating inspection areas, failures, and defects." Destructive/non-destructive tests are performed on an as-needed basis, determinedby the Nuclear Coatings Specialist or Coatings Planner.
 
==Enclosure==
1NOC-AE-12002797Page 22 of 24Enclosure 2 provides the line-in/line-out revision to the changes to LRA Table A4-1, AppendixA1.39, and Appendix B2.1.39.B2.1.39-2Background:The Standard Review Plan (SRP) -LR Section A. 1.2.3.10 provides guidance on requiredinformation for the operating experience program element for aging management programs. Inparticular, SRP-LR states that the operating experience of AMPs that are existing programs,including past corrective actions information operating resulting in program enhancements oradditional programs, should be included in this program element. This information can showwhere an existing program has succeeded and where it has failed (if at all) in intercepting agingdegradation in a timely manner.The LRA operating experience program element gives a general overview of the program anddoes not provide specific instances of degradation and its associated repair or other correctiveactions performed.Issue:The staff does not have adequate information in the LRA operating experience programelement to determine whether this program element is acceptable.Request:Please discuss any instances of degradation and repair of Service Level 1 coatings. In addition,provide information that demonstrates the effectiveness of corrective actions performed.STPNOC Response:The STP Service Level I coatings program owner and coatings planner are qualified NuclearCoatings Specialists in accordance with ASTM D 7108-05 and actively participate inindustry sponsored training and conferences. STP participates in industry benchmarking and innuclear power plant coatings self-assessments, and attends The National Association ofCorrosion Engineers (NACE) and Electric Power Research Institute (EPRI) webcasts. Throughthe above activities, industry issues and operating experience are shared and drawn upon tomaintain and enhance the STP Service Level I coatings program.Unit 1 reactor containment building -Service Level 1 Coating Degradations and RepairExamplesCracks were identified in the concrete coating on the knockout block wall at the -11 footelevation in 1992. The coating degradation was characterized as a minor crack lessthan 30 mils in width and not associated with delamination. The degraded coatings wererepaired in November, 1993 in accordance with safety-related coatings specification3C080AS1001.
 
==Enclosure==
1NOC-AE-12002797Page 23 of 24Mechanical damage to concrete floor coatings at the equipment tugger shaft betweencolumns C5 and C6 at the -11 foot elevation were identified. The coatings degradationwas characterized as mechanical damage. Repairs to the degraded floor coatings weremade during the next scheduled refueling outage (1RE05) in March 1995 in accordancewith safety-related coatings specification 3CO80AS1001.Indications on the containment liner plate at the -11, 19, 37, 52, and 68 foot elevationswere identified when performing IWE surveillance testing during refueling outage(1 RE1 1) in April, 2003. The coating degradations were characterized as mechanicaldamage with a total area less than 30 square inches. The degraded coatings werecleaned and repaired during the next scheduled refueling outage (1RE12) in March,2005 in accordance with safety-related coatings specification 3C080AS1001.Surface corrosion on hanger support CC-1214-RR-010 at the -11 foot elevation wasidentified while performing a coatings condition assessment walkdown during refuelingoutage 1RE15 in November, 2009. The coatings degradation was characterized asminor surface rusting due to condensation. Repairs to degraded coatings were madeduring the subsequent scheduled outage (1RE16) in April, 2011 in accordance with thesafety-related coatings specification 3C080AS1001.During a refueling outage (1 RE09) in May 2000, an indication of approximately 4 inchesby 8 inches on the containment liner plate at the 270 degree azimuth near the 84 footelevation was identified near the reactor vessel head lift rig. An investigation determinedthat the outer coating was removed with the primed surface below exposed with nosigns of corrosion or further coating deterioration noted. The condition was foundacceptable as-is. The indication was re-evaluated the following refueling outage during acoatings condition assessment walkdown and found to be approximately the same sizeand color (i.e., dark primer coat) as the condition identified in May 2000. The indicationshows no signs of corrosion and no streaks of rust on the liner plate below. Theindication will be monitored and re-evaluated during the refueling outage in November2012 (1RE17).Unit 2 reactor containment building -Service Level 1 Coatings Degradations and RepairExamplesMinor surface corrosion on the liner plate at the interface of the liner plate and concretebasemat at the -11 foot elevation was identified in April, 2000. Coatings degradationwas characterized as minor rusting. Repairs to degraded coatings were made in June,2000 in accordance with safety-related coatings specification 3C080AS1001.Minor surface corrosion at the interface of column C8 and the ceiling at 206 degreeazimuth and the -11 foot elevation was identified in February 2005. Coatingsdegradation was characterized as minor rusting due to condensation. The area ofdegraded coatings was cleaned and repaired during the subsequent scheduled refuelingoutage (2RE1 1) in October, 2005 in accordance with safety-related coatingsspecification 3C080AS1001.
 
==Enclosure==
1NOC-AE-12002797Page 24 of 24Mechanical damage to coatings at a 20 inch penetration east of the 270 degree azimuthat 47 foot elevation and at a ten inch penetration west of the 270 degree azimuth at the47 foot elevation was identified while performing a coatings condition assessmentwalkdown during a refueling outage (2RE1 1) in October, 2005. The coatingsdegradation was characterized as mechanical damage of less than one square foot foreach penetration. Repairs to the degraded coatings at both penetrations were madeduring the subsequent scheduled refueling outage (2RE12) in April, 2007 in accordancewith safety-related coatings specification 3CO80AS1001.A crack in the concrete coating on the secondary wall approximately six inches from thefloor at the 159 degree azimuth at the -11 foot elevation was identified while performinga coatings condition assessment walkdown during a refueling outage (2RE12) in April,2007). The coatings degradation was characterized as a minor isolated crackmeasuring less than 30 mils in width and meeting the coatings specification criteria forcosmetic repair. The coating repairs were made during the subsequent scheduledrefueling outage (2RE1 3) in October, 2008. The cosmetic repair was made inaccordance with design change notice 9604087 to Specification 2A010CS1009, whichallows the use of concressive paste as an approved concrete surfacer for cosmeticrepairs in the reactor containment building.Minor surface rusting on bolts at base support of columns located at the 106, 127 and139 degree azimuths at the -11 foot elevation was identified while performing a coatingscondition assessment walkdown during a refueling outage (2RE14) in May, 2010.Coatings degradation was characterized as minor rusting. Repairs to degraded coatingswere made during the subsequent scheduled refueling outage (2RE15) in November,2011 in accordance with safety-related coatings specification 3C080AS1001.SummaryService Level 1 coatings are inspected during Coating Condition Assessment Walkdowns,IWE Inspections, Structures Monitoring Program Inspections and in response to the STPCondition Reporting Process for those degraded coating conditions previously identified.The "Service Level 1 Coatings Degradations and Repair Examples" listed above arerepresentative of the coating failures identified in Unit 1 and Unit 2 reactor containmentbuildings. Historically, Service Level 1 coating failures include mechanical damage, minorisolated cracking measuring less than 30 mils in width, and minor surface rusting.The potential for an adverse impact on the function of the Emergency Core Cooling Systemand the Containment Spray System following a loss-of-coolant accident because of ServiceLevel 1 coating degradation is extremely unlikely based on the Service Level 1 coatingdegradation identified to date and the timely corrective action taken. Flaking, peeling,blistering and delamination of Service Level 1 coatings that have the potential to blocksumps and strainers have not been experienced at STP.
 
==Enclosure==
2NOC-AE-12002797Enclosure 2STPNOC LRA Changes with Line-in/Line-out Annotations
 
==Enclosure==
2NOC-AE-12002797Page 1 of 63List of Revised LRA SectionsRAI Affected LRA SectionB2.1.6-1a A1.6B2.1.63.1.1.80-1a Table 3.1.1Table 3.1.2-1Section 3.1.2.2.6Section 3.1.2.2.9Section 3.1.2.2.12Section 3.1.2.2.15Section 3.1.2.2.17Appendix A1.35Appendix B2.1.35Table A4-1 (See Enclosure 3)3.1.1.80-1b Table 3.1.2-13.1.2.1-1a Appendix B2.1.353.0-1a Section 3.3.2.1.8Section 3.3.2.1.16Section 3.3.2.2.10.5Table 3.3.2-8Table 3.3.2-9Table 3.3.2-10Table 3.3.2-11Table 3.3.2-12Table 3.3.2-15Table 3.3.2-16Table 3.3.2-20Table 3.3.2-23Table 3.4.2-1A1-1 Appendix AlTable A4-1 (See Enclosure 3)3.3.2.2.4-1a Appendix Al.16Appendix B2.1.16B2.1.39-1 Appendix A1.39Appendix B2.1.39Table A4-1 (See Enclosure 3)
 
==Enclosure==
2NOC-AE-12002797Page 2 of 63A1.6 FLOW-ACCELERATED CORROSIONThe Flow-Accelerated Corrosion (FAC) program manages wall thinning due to flow-acceleratedcorrosion on the internal surfaces of carbon or low alloy steel piping and system componentswhich contain high energy fluids (both single phase and two phase). The FAC program alsomanages wall thinning due to other causes, such as erosion/corrosion, cavitation, flashing, andimpingement damage.The objectives of the FAC program are achieved by(a) identifying system components susceptible to wall thinning due to FAC or causes such aserosion/corrosion, cavitation, flashing, and impingement damagesT(b) performing an analysis using a predictive code such as CHECWORKS to determine criticallocations for inspection and evaluation of components that can be modeled:(c) using operating experience and engineering evaluation to determine inspection locations forcomponents which cannot be modeled by the predictive code, including componentssusceptible to wall thinning due to causes such as erosion/corrosion, cavitation, flashing, andimpingement damage;(d) (_)providing guidance for follow-up inspections--.(4) (e) repairing or replacing components, as determined by the guidance provided by theprogram-- and() ff) continual evaluation and incorporation of the latest technologies, industry and plant in-house operating experience.Procedures and methods used by the FAC program are consistent with STP commitments toNRC Bulletin 87-01, Thinning of Pipe Wall in Nuclear Power Plants, and NRC Generic Letter89-08, Erosion/Corrosion-Induced Pipe Wall Thinning. The program relies on implementationof the EPRI guidelines of NSAC-202L, Recommendations for an Effective Flow AcceleratedCorrosion Program.
 
==Enclosure==
2NOC-AE-12002797Page 3 of 63B2.1.6 Flow-Accelerated CorrosionProgram DescriptionThe Flow-Accelerated Corrosion (FAC) program manages wall thinning due to flow-acceleratedcorrosion on the internal surfaces of carbon or low alloy steel piping and system componentswhich contain high energy fluids (both single phase and two phase). The program alsomanages wall thinning due to other causes, such as erosion/corrosion, cavitation, flashing, andimpingement damage. The program implements the EPRI guidelines in NSAC-202L-R3 todetect, measure, monitor, predict and mitigate component wall thinning due to FAC. To aid inthe planning of inspections and choosing inspection locations, STP utilizes the EPRI predictivecomputer program CHECWORKS for components which can be modeled. Inspection locationsfor components which can not be modeled by CHECWORKS are selected based onengineering evaluation and operating experience. that the implementation guid.nce o.NSAG 2021 R3.System components susceptible to wall thinning due to causes such as erosion/corrosion,cavitation, flashing, and impingement damage are also included in the program and areselected for inspection based on engineering evaluation and operating experience.The objectives of the FAC program at STP are achieved by(a) identifying system components susceptible to wall thinning due to FAC or causes such aserosion/corrosion, cavitation, flashing, and impingement damage;:(b) performing analyses using the predictive code CHECWORKS to determine critical locationsfor inspection and evaluation of components that can be modeled:T(c) using operating experience and engineering evaluation to determine inspection locations forcomponents which cannot be modeled or are susceptible to wall thinning due to causes such aserosion/corrosion, cavitation, flashing, and impingement damage:(-) (d) providing guidance for follow up inspections.-7(4) (e) repairing, replacing, or performing evaluations for components not acceptable forcontinued service, based on the wear rates and minimum acceptable design thickness;--and(e)-(fl evaluating and incorporating the latest technologies, industry and plant in-houseoperating experience.Procedures and methods used by the FAC program are consistent with STP commitments toNRC Bulletin 87-01, Thinning of Pipe Wall in Nuclear Power Plants, and NRC Generic Letter89-08, Erosion/Corrosion-Induced Pipe Wall Thinning.NUREG-1801 ConsistencyThe Flow-Accelerated Corrosion program is an existing program that is consistent, withexception, to NUREG-1801, Section XI.M17, Flow-Accelerated Corrosion.
 
==Enclosure==
2NOC-AE-12002797Page 4 of 63Exceptions to NUREG-1801Scope of Program (Element 1) and Detection of Aging Effects (Element 4)NUREG-1801, Section XI.M17 indicates the Flow-Accelerated Corrosion program relies onimplementation of EPRI guidelines in NSAC-202L-R2. However, STP uses therecommendations provided in the EPRI Guideline NSAC-202L-R3. The new revision of EPRIguidelines incorporates lessons learned and improvements to detection, modeling, andmitigation technologies that became available since Revision 2 was published. The updatedrecommendations are intended to refine and enhance those of previous revisions withoutcontradictions to ensure continuity of existing plant FAC programs.Scope of Program (Element1), Parameters Monitored or Inspected (Element 3). Detection ofAging Effects (Element 4), Monitoring and Trending (Element 5), Acceptance Criteria (Element6), and Corrective Action (Element 7)NUREG-1801, Section XI.M17 states that the FAC program relies on implementation of NSAC-202L-R2 for an effective FAC program. NSAC-202L-R2 addresses wall thinning due to FAC,but not other mechanisms. STP manages wall thinning due to other mechanisms in addition toFAC. Management of wall thinning due to mechanisms in addition to FAC is acceptablebecause 1) the aging effect of the additional mechanisms, wall thinning, is the same as forFAC, and 2) the management of the additional mechanisms is the same as the management ofFAC for lines which cannot be modeled in CHECWORKS.EnhancementsNoneOperating ExperienceReview of work orders from 1998 through present showed that there has been no reportedFAC-related leak or rupture at STP for the components within the scope of license renewal.Most of the work orders identified the effect of wall thinning during the FAC programinspections. There were cases where the allowable thickness determined in accordance withthe program guidelines was reached and more rigorous stress analyses were performed tojustify continued service and to postpone the replacement. Problems identified duringimplementation of the program activities were not significant to the safe operation of the plant,and adequate corrective actions were taken to prevent recurrence. Industry and plant operatingexperience have been reviewed for applicability and adjustments have been made to outageinspection lists in accordance with program guidelines.For refueling outages 1 RE12 through 1 RE14 (April 2008) and 2RE10 through 2RE12, 102 to112 locations of large-bore systems were selected for inspection before the outage. The scopewas expanded when necessary based on UT findings to adiacent components and similarlocations in other trains. An inspection location included the subject component (such as anelbow) and its adjacent area (such as upstream and downstream piping). For small-boresystems, 28 to 54 inspections were selected before the outage for RT inspections. The scopewas also expanded when necessary based on RT findings. A total of 11 replacements weremade in four of these outages, with no replacements in the other two. Scheduling of pipingreplacements for each outage takes into consideration 1) the projected remaining service life of
 
==Enclosure==
2NOC-AE-12002797Page 5 of 63the pipe based on FAC analysis; 2) industry experience of wall thinning for the pipe and itsoperating environment; and 3) cost of replacement compared to the cost of performing futureinspections. The selections of FAC-resistant materials were stainless steel or chrome-molyalloy. Baseline inspections were performed for selected replacement locations of chrome-molyalloy.Wall thinning due to causes such as erosion/corrosion, cavitation, flashing, and impingementdamage has been minimal for systems within the scope of license renewal. Most of thecomponents exhibiting wall thinning due to erosion/corrosion, cavitation, flashing, andimpingement damage are in the essential cooling water system, the condensate polishersystem, or the circulating water system. The components in the essential cooling water systemare managed by the Open-Cycle Cooling Water System program (XI.M20). The circulatingwater system and most of the components in the condensate polisher system are not within thescope of license renewal.During 1RE12 (spring., 2005), wall thinning was detected in an elbow downstream of valveAF01 19. The cause of the wall thinning was determined to be erosion, not FAC. Based on theresults of the inspection, the elbow was re-inspected in 1 RE1 3 (fall, 2006). This inspectionindicated that the remaining life for the elbow was 5.4 EFPY beyond 1 RE1 4, so the nextinspection was scheduled for 1 RE17 (fall, 2012).Based on the system engineers knowledge of the dynamics of the systems and the results ofvisual inspections during maintenance, components susceptible to wall thinning due to causessuch as erosion/corrosion, cavitation, flashing, and impingement damage have been added tothe FAC program.The operating experience of the Flow-Accelerated Corrosion program demonstrates that theprogram effectively monitors and trends the aging effects of wall thinning. Appropriatecorrective action is taken prior to loss of intended function. Wall thinning occurrences identifiedunder the Flow-Accelerated Corrosion program are evaluated to ensure there is no significantimpact to safe operation of the plant, and corrective action is taken to prevent recurrence.Guidance for re-evaluation, repair, or replacement is provided for locations where aging isfound. There is confidence that the continued implementation of the Flow-AcceleratedCorrosion program will effectively manage aging prior to loss of intended function.ConclusionThe continued implementation of the Flow-Accelerated Corrosion program provides reasonableassurance that aging effects will be managed such that the systems and components within thescope of this program will continue to perform their intended functions consistent with thecurrent licensing basis for the period of extended operation.
 
==Enclosure==
2NOC-AE-12002797Page 6 of 63Table 3.1.1Summary of Aging Management Evaluations in Chapter IV of NUREG-1801 for Reactor Vessel, Internals, andReactor Coolant SystemItem Component Type Aging Effect / Mechanism Aging Management Further DiscussionNumber Program EvaluationI Recommended3.1.1.30 Stainless steel reactor Cracking due to stress Water Chemistry (B2.1.2) and No Consistent with NUREGvessel internals corrosion cracking, irradiation- FSAR supplement 1801 for material,components (e.g., assisted stress corrosion commitment to (1) participate environment, and agingUpper internals cracking in industry RVI aging effect, but different AMPs areassembly, RCCA guide programs (2) implement credited: Water Chemistrytube assemblies, applicable results (3) submit program (B2.1.2) augmentedBaffle/former for NRC approval > 24 by the plant-specific agingassembly, Lower months before the extended management program PWRinternal assembly, period an RVI inspection plan Reactor Internals (B2.1.35).shroud assemblies, based on industry Consistent with EPRIPlenum cover and recommendation. 1022863 101656-(MRP-plenum cylinder, Upper 227-A), cracking is managedgrid assembly, Control by ASME Section XIrod guide tube (CRGT) Inservice Inspection forassembly, Core selected components.support shield **See further evaluation inassembly, Core barrel Section 3.1.2.2.12.assembly, Lower gridassembly, Flowdistributor assembly,Thermal shield,Instrumentationsupport structures)
 
==Enclosure==
2NOC-AE-1 2002797Page 7 of 63Item Component Type Aging Effect / Mechanism Aging Management Further DiscussionNumber Program EvaluationRecommended3.1.1.37Stainless steel andnickel alloy reactorvessel internalscomponents (e.g.,Upper internalsassembly, RCCA guidetube assemblies,Lower internalassembly, CEA shroudassemblies, Coreshroud assembly, Coresupport shieldassembly, Core barrelassembly, Lower gridassembly, Flowdistributor assembly)Cracking due to stresscorrosion cracking, primarywater stress corrosioncracking, irradiation-assistedstress corrosion crackingWater Chemistry (B2.1.2) andFSAR supplementcommitment to (1) participatein industry RVI agingprograms (2) implementapplicable results (3) submitfor NRC approval > 24months before the extendedperiod an RVI inspection planbased on industryrecommendation.NoConsistent withNUREG-1801 for material,environment, and agingeffect, but different AMPs arecredited: Water Chemistryprogram (B2.1.2) augmentedby the plant-specific agingmanagement program PWRReactor Internals (B2.1.35).Consistent with EPRI1022863 0!6596 (MRP-227-A), cracking is managedby ASME Section XIInservice Inspection forselected components.**See further evaluation inSection 3.1.2.2.17.
 
==Enclosure==
2NOC-AE-12002797Page 8 of 63Table 3.1.2-1Reactor Vessel, Internals, and Reactor Coolant System -Summary of Aging Management Evaluation -ReactorVessel and Internals (Continued)Component Type Intended Material Environment Aging Effect Aging Management NUREG- Table I NotesFunction Requiring Program 1801 Vol. ItemManagement 2 ItemRVI Upper Core SS Stainless Reactor Coolant None None IV.B2-41 3.1.1.33 I, 4Support-Upper Steel (Ext)Core PlateRVI Upper Core SS Stainless Reactor Coolant Loss of material PWR Reactor Internals IV.B2-34 3.1.1.63 E, 3Support-Upper Steel (Ext) (B2.1 .35)Core PlateRVI Upper Core SS Stainless Reactor Coolant Cracking ASME S9etion Xl IV.B2-42 3.1.1.30 E, 35Support-Upper Steel (Ext) n..r... Insp'ction,Core Plate Subsections IWB, !WC,and IWD (12, ".A)WaterChemistry (B2.1.2) andPWR Reactor Internals(B2.1.35)_RVI Upper Core SS Stainless Reactor Coolant Cumulative Time-Limited Aging IV.B2-31 3.1.1.05 ASupport-Upper Steel (Ext) fatigue damage Analysis evaluated forSupport Column the period of extended_operationRVI ICI Support SS Stainless Reactor Coolant Cracking Water Chemistry IV.B2-12 3.1.1.30 E, 3Structures-lnstr Steel (Ext) (B2.1.2) and PWRColumn (BMI) Reactor Internals(B2.1.35)RVI ICI Support SS Stainless Reactor Coolant Loss of fracture PWR Reactor Internals IV.B2-9 3.1.1.22 E. 3Structures-lnstr Steel (Ext) toughness (B2.1.35)Column (BMI)RVI ICI Support SS Stainless Reactor Coolant Loss of material Water Chemistry IV.B2-32 3.1.1.83 AStructures-lnstr Steel (Ext) (B2.1.2)Column (BMI) I
 
==Enclosure==
2NOC-AE-1 2002797Page 9 of 633.1.2.2.6 Loss of Fracture Toughness due to Neutron Irradiation Embrittlement andVoid SwellingLoss of fracture toughness due to neutron irradiation embrittlement and void swelling forstainless steel reactor internals components exposed to reactor coolant is managed by theplant-specific PWR Reactor Internals program (B2.1.35) based on the guidelines provided inEPRI 1022863 !016596 (MRP-227-A). Consistent with EPRI 1022863 10!596 (MRP-227-A),loss of fracture toughness is not an applicable aging effect requiring management for the RVIneutron shield panel.3.1.2.2.9 Loss of Preload due to Stress RelaxationLoss of preload due to stress relaxation for nickel-alloy and stainless steel reactor internalscomponents exposed to reactor coolant is managed by the plant-specific PWR Reactor Internalsprogram (B2.1.35) based on the guidelines provided in EPRI 1022863 1016596 (MRP-227-A).Consistent with EPRI 1022863 4016596 (MRP-227-A), loss of preload is not an applicable agingeffect requiring management for the RVI Lower Core Support-Clevis Insert Bolting and RVI UpperSupport Column Bolting.
 
==Enclosure==
2NOC-AE-12002797Page 10 of 633.1.2.2.12 Cracking due to Stress Corrosion Cracking and Irradiation-Assisted StressCorrosion Cracking (IASCC)For managing the aging effect of cracking due to stress corrosion cracking and irradiation-assisted stress corrosion cracking of stainless steel reactor internals components exposed toreactor coolant, Water Chemistry (B2.11.2) is augmented by the plant-specific PWR ReactorInternals program (B2.1.35) based on the guidelines provided in EPRI 1022863 !0!6596 (MRP-227-A). Consistent with EPRI 1022863 1016596 (MRP-227-A), PWR Reactor Internals(B2.1.35) is not an applicable aging program for managing cracking of the followingcomponents. Instead, cracking is managed by ASME Section Xl Inservice Inspection (B2. 1.1):-RVI Hold Down Spring-RVI Neutron Shield PanelRVI Upper Cro Support UppoIr Core Plate-RVI Upper Core Support-Upper Support Column-RVI Upper Core Support-Upper Support Column Base-RVI Upper Core Support-Upper Support Plate-RVI Control Rod Guide Tube Guide Plates-RVI ICI Support Structures -Exit Thermocouples-RVI ICI Support Structures -Upper/Lower Tie Plates-RVI Irradiation Specimen Basket-RVI Lower Core Support -Energy Absorber Assembly
 
==Enclosure==
2NOC-AE-12002797Page 11 of 633.1.2.2.15 Changes in dimensions due to Void SwellingChanges in dimensions due to void swelling for stainless steel reactor internals componentsexposed to reactor coolant will be managed by the plant-specific PWR Reactor Internalsprogram (B2.1.35) based on the guidelines provided in EPRI 1022863 4016596 (MRP-227-A).Consistent with EPRI 1022863 4016596 (MRP-227-A), changes in dimension is not anapplicable aging effect requiring management for the following components:-RVI Control Rod Guide Tube Assembly-RVI Control Rod Guide Tube Bolting-RVI Control Rod Guide Tube Guide Plates-RVI Core Barrel Assembly-RVI Hold Down Spring-RVI ICI Support Structures-Instrument Column (BMI)-RVI ICI Support Structures-Upper/Lower Tie Plates-RVI Lower Core Support Bolts-RVI Lower Core Support-Clevis Insert Bolting-RVI Lower Core Support-Core Support Plate Forging-RVI Neutron Shield Panel-RVI Radial Support Keys and Clevis Inserts-RVI Upper Core Plate Guide Pins-RVI Upper Core Support-Protective Skirt-RVI Upper Core Support-Upper Core Plate-RVI Upper Core Support-Upper Support Column-RVI Upper Core Support-Upper Support Column Base-RVI Upper Core Support-Upper Support Plate-RVI Upper Support Column Bolting
 
==Enclosure==
2NOC-AE-1 2002797Page 12 of 633.1.2.2.17 Cracking due to Stress Corrosion Cracking, Primary Water StressCorrosion Cracking, and Irradiation-Assisted Stress Corrosion CrackingFor managing the aging effect of cracking due to stress corrosion cracking, primary waterstress corrosion cracking, and irradiation-assisted stress corrosion cracking of stainless steelreactor internals components exposed to reactor coolant, Water Chemistry program (B2.1.2) isaugmented by the plant-specific PWR Reactor Internals program (B2.1.35) based on theguidelines provided in EPRI 1022863 !016596 (MRP-227-A). Consistent with EPRI 10228631016596 (MRP-227-A), PWR Reactor Internals (B2.1.35) is not an applicable agingmanagement program for managing cracking of the following components. Instead, cracking ismanaged by ASME Section XI Inservice Inspection (B2. 1.1):-RVI Lower Core Support-Clevis Insert Bolting-RVI Radial Support Keys and Clevis Inserts-RVI Upper Support Column Bolting-RVI Lower Core Support Bolts
 
==Enclosure==
2NOC-AE-12002797Page 13 of 63A1.35 PWR REACTOR INTERNALSThe PWR Reactor Internals program manages cracking, loss of material, loss of fracturetoughness, dimensional changes, and loss of preload for reactor vessel components thatprovide a core structural support intended function. The program implements the guidance ofEPRI 4016696 1022863, PWR Internals Inspection and Evaluation Guideline (MRP-227-A, Rev.0) and EPRI 1016609, Inspection Standard for PWR Internals (MRP-228). The programmanages aging consistent with the inspection guidance for Westinghouse designated primarycomponents in Table 4-3 of MRP-227-A and Westinghouse designated expansion componentsin Table 4-6 of MRP-227-A. The expansion components are specified to expand the primarycomponent sample should the indications of the sample be more severe than anticipated. Theaging effects of a third set of MRP-227-A internals locations are deemed to be adequatelymanaged by existing program components whose aging is managed consistent with ASMESection XI Table IWB-2500-1, Examination Category B-N-3.Program examination methods include visual examination (VT-3), enhanced visual examination(EVT-1), volumetric examination, and physical measurements. The program provides bothexamination acceptance criteria for conditions detected as a result of monitoring the primarycomponents, as well as criteria for expanding examinations to the expansion components whenwarranted by the level of degradation detected in the primary components. Based on theidentified aging effect, and supplemental examinations if required, the disposition processresults in an evaluation and determination of whether to accept the condition until the nextexamination or implement corrective actions. Any detected conditions that do not satisfy theexamination acceptance criteria are required to be dispositioned through the corrective actionprogram, which may require repair, replacement, or analytical evaluation for continued serviceuntil the next inspection.The PWR Reactor Internals program is a new program and will be implemented within 24months after the issuance of EPRI !0!6596 1022863, PWR Internals Inspection and EvaluationGuideline MRP-227-A.
 
==Enclosure==
2NOC-AE-12002797Page 14 of 63B2.1.35 PWR Reactor InternalsProgram DescriptionThe PWR Reactor Internals program manages cracking, loss of material, loss of fracturetoughness, dimensional changes, and loss of preload for reactor vessel components thatprovide a core structural support intended function. The program implements the guidance ofEPRI 10465961022863, PWR Internals Inspection and Evaluation Guideline (MRP-227-A) andEPRI 1016609, Inspection Standard for PWR Internals (MRP-228, Rev. 0). The programmanages aging consistent with the inspection guidance for Westinghouse designated primarycomponents in Table 4-3 of MRP-227-A, Westinghouse designated expansion components inTable 4-6 of MRP-227-A, and the Westinghouse designated existing components in Table 4-9of MRP-227-A. Primary components are expected to show the leading indications of thedegradation effects. The expansion components are specified to expand the primarycomponent sample should the indications of the sample be more severe than anticipated. Theaging effects of a third set of MRP-227-A internals locations are deemed to be adequatelymanaged by existing program components whose aging is managed consistent with ASMESection Xl Table IWB-2500-1, Examination Category B-N-3.Program examination methods include visual examination (VT-3), enhanced visual examination(EVT-1), volumetric examination, and physical measurements. Bolting ultrasonic examinationtechnical justifications in MRP-228 have demonstrated the indication detection capability todetect loss of integrity of PWR internals bolts, pins, and fasteners, such as baffle-formerbolting. For some components, the MRP-227-A_ methodology specifies a focused visual (VT-3)examination, similar to the current ASME Code, Section XI, Examination Category B-N-3examinations, in order to determine the general mechanical and structural condition of theinternals by (a) verifying parameters, such as clearances, settings, and physical displacements;and (b) detecting discontinuities and imperfections, such as loss of integrity at bolted or weldedconnections, loose or missing parts, debris, corrosion, wear, or erosion. In some cases, VT-3visual methods are used for the detection of surface cracking when the component material hasbeen shown to be tolerant of easily detected large flaws. In some cases, where even morestringent examinations are required, enhanced visual (EVT-1) examinations or ultrasonicmethods of volumetric inspection, are specified for certain selected components and locations.The program provides both examination acceptance criteria for conditions detected as a resultof monitoring the primary components, as well as criteria for expanding examinations to theexpansion components when warranted by the level of degradation detected in the primarycomponents. Based on the identified aging effect, and supplemental examinations if required,the disposition process results in an evaluation and determination of whether to accept thecondition until the next examination or implement corrective actions. Any detected conditionsthat do not satisfy the examination acceptance criteria are required to be dispositioned throughthe corrective action program, which may require repair, replacement, or analytical evaluationfor continued service until the next inspection.The PWR Vessel Internals program is a new program that will be implemented within 24months after the issuance of MRP-227-A, PWR Internals Inspection and Evaluation Guideline.The program will include future industry operating experience, as it is incorporated into thefuture revisions of MRP-227-A, to provide reasonable assurance for long-term integrity of thereactor internals. The reactor vessel internals included in the scope of the PWR Reactor
 
==Enclosure==
2NOC-AE-12002797Page 15 of 63Internals program are identified in Element 1. The scope of the program does not includewelded attachments to the internal surface of the reactor vessel because these components aremanaged by the ASME Section XI Inservice Inspection, Subsections IWB, IWC, and IWDprogram (B2.1.1) (exam category B-N-2) and /or the Nickel-Alloy Aging Management Program(B2.1.34). The scope of the program also does not include BMI flux thimble tubes which aremanaged by the Flux Thimble Tube Inspection program (B2.1.21).Aging Management Program ElementsThe results of an evaluation of each element against the 10 elements described in Appendix Aof NUREG-1 800, Standard Review Plan for Review of License Renewal Applications forNuclear Power Plants are provided below.Scope of Program -Element IThe scope of the program applies the guidance in MRP-227-A which provides augmentedinspection and flaw evaluation methodology for assuring the functional integrity ofWestinghouse reactor vessel internals. The scope of the PWR Reactor Internals programincludes components that provide a core structural support intended function and are managedby the Westinghouse designated primary components in Table 4-3 of MRP-227-A andWestinghouse designated expansion components in Table 4-6 of MRP-227-A and applicableMRP-227-A methodology license renewal applicant action items. MRP-227-A Table 4-9 alsoidentifies existing program components whose aging is managed consistent with ASME SectionXI Table IWB-2500-1, Examination Category B-N-3.Primary components are expected to show the leading indications of the degradation effects.The expansion components are specified to expand the primary component sample should theindications of the sample be more severe than anticipated. The aging effects of a third set ofMRP-227-A internals locations are deemed to be adequately managed by existing programcomponents whose aging is managed consistent with ASME Section XI Table IWB-2500-1,Examination Category B-N-3.The STP reactor vessel internals are divided into the following major component groups: thelower core support assembly (including the entire core barrel assembly, baffle-former assembly,neutron shield panel, core support plate, and energy absorber assembly), the upper coresupport (UCS) assembly (including the upper support plate, support column, control rod guidetube assembly, upper core plate, and protective skirt), the incore instrumentation supportstructures (including the instrumentation columns (exit thermocouples), upper/lower tie plates,and instrumentation columns (BMI)), and miscellaneous alignment/interface components(including internals hold-down spring, upper core plate guide pins, and radial support keysincluding clevis inserts).The following reactor vessel internals are included in the scope of the PWR Reactor Internalsprogram:1. Control rod guide tube assembly and Bolting-Guide plate (cards) [Primary componentl-Lower flange welds and adjacent base metal (Addressed in AMR by Component Type of"RVI Control Rod Guide Tube Assembly") [Primary componenti
 
==Enclosure==
2NOC-AE-12002797Page 16 of 63-Guide Tube Support Pins (Split Pins) (Addressed in AMR by Component Type of "RVIControl Rod Guide Tube Bolting") rExisting programs component]2. Core barrel assembly-Upper core barrel flange weld and adjacent base metal (Addressed in AMR byComponent Types of "RVI Core Barrel Assembly") [Primary component]-Core barrel assembly-former bolting [Expansion componentiCore barrel flange (Addressed in AMR by Component Types of "RVI Core BarrelAssembly") [Expansion component and Existing programs component]-Core barrel axial welds and adjacent base metal [Expansion component]-Core barrel girth welds and adiacent base metal [Primary component]-Core barrel outlet nozzle welds and adjacent base metal [Expansion component]-Lower core barrel flange weld and adjacent base metal (Addressed in AMR byComponent Types of "RVI Core Barrel Assembly") [Primary component]3. Baffle-former assembly and bolting-Baffle-edge bolting [Primary component]-Baffle-former bolting [Primary component1-Baffle-former assembly [Primary component]4. Alignment and interfacing components-Internals hold-down spring [Primary component]-Radial support key clevis insert bolts rExisting programs component]-Upper core plate guide pins [Existing pro-grams component]-5. Neutrot~n shield panel (thermal shield arssembly)5. Instrumentation support structures-Instrumentation columns -BMI [Expansion component]6. Upper core support assembly-Upper core support protective skirt [Existing programs component]-Upper Core Plate [Expansion component]7. Lower Core Support Structure
 
==Enclosure==
2NOC-AE-12002797Page 17 of 63Core Support Plate Forging [Expansion component]The scope of the program also does not include welded attachments to the internal surface ofthe reactor vessel because these components are managed by the ASME Section XI InserviceInspection, Subsections IWB, IWC, and IWD program (B2.1.1) (exam category B-N-2) and /orthe Nickel-Alloy Aging Management Program (B2.11.34). The scope of the program also doesnot include BMI flux thimble tubes which are managed by the Flux Thimble Tube Inspectionprogram (B2.1.21).The STP reactor vessel internals configuration does not include the lower internals assembly(lower support column bodies and lower core plate) noted in MRP-227-A.The PWR Reactor Internals program is consistent with the following MRP-227-A assumptions(determination of applicability) which are based on PWR representative internals configurationsand operational histories.(1) STP has operated for less than 30 years of operation with high leakage core loadingpatterns. Operation with high leakage core loading was followed by implementation of alow-leakage fuel management pattern for the remaining operating life.(2) STP operates at fixed power levels and does not usually vary power based on calendar orload demand schedule.(3) STP has not implemented any design changes beyond those identified in industry guidanceor recommended by Westinghouse.Preventive Actions -Element 2The PWR Reactor Intornals program is consistent with the following MRP 227 assumptions(detormination of applicability) which are basod- on; PWR representatiVe internalsconfiguFatioRn and opeFational histories(1) STP has ope.atod for lem s than 30 years of operation with high leakage core loadingpatterR Operatior with high leakagm oe coreading was foallowed by iopilefmetation of alow loakago fuel management pattern for the remaining operatfing life-.(2) STPR operates at fixed power levels- and- does not usually var,' power based on calendaror load dem~and schedule1A.(3) STP has not ipentdany design changes be9yond these4 id-entified in industr,'guidance or recoFmmended by Wes6tinghouse8.The PWR Reactor Internals program does net prevent degradation due to aging effects, butprovides measures for monitoring to detect the degradation prior to loss of intended function.Preventive measures to mitigate aging effects such as loss of material and cracking includemonitoring and maintaining reactor coolant water chemistry consistent with the guidelines ofEPRI TR 1014986, PWR Primary Water Chemistry Guidelines, Volume 1. The primary waterchemistry program is described separately in the Water Chemistry program (B2.1.2).
 
==Enclosure==
2NOC-AE-1 2002797Page 18 of 63Parameters Monitored or Inspected -Element 3The PWR Reactor Internals program monitors the following aging effects by inspection inaccordance with the guidance of MRP-227-A or ASME Section XI Category B-N-3:(1). CrackingCracking is due to stress corrosion cracking (SCC), primary water stress corrosion cracking(PWSCC), irradiation assisted stress corrosion cracking (IASCC), or fatigue /cyclical loading.Cracking is monitored with a visual inspection for evidence of surface breaking lineardiscontinuities or a volumetric examination. Surface examinations may also be used tosupplement visual examinations for detection and sizing of surface-breaking discontinuities.(2). Loss of MaterialLoss of Material is due to wear. Loss of material is monitored with a visual inspection for grossor abnormal surface conditions.(3). Loss of Fracture ToughnessLoss of fracture toughness is due to thermal aging7 or neutron irradiation embrittlement,-or-Yeidswellig. The impact of loss of fracture toughness is indirectly monitored by using visual orvolumetric examination techniques to monitor for cracking and by applying applicable reducedfracture toughness properties in the flaw evaluations if cracking is detected and is extensiveenough to warrant a supplemental flaw growth or flaw tolerance evaluation.(4). Dimensional ChangesDimensional Changes are due to void swelling and irradiation growth, distortion or deflection.The program supplements visual inspection with physical measurements to monitor for anydimensional changes due to void swelling, irradiation growth, distortion, or deflection.(5). Loss of PreloadLoss of preload is caused by thermal and irradiation-enhanced stress relaxation or creep. Lossof preload is monitored with a visual inspection for gross surface conditions that may beindicative of loosening in applicable bolted, fastened, keyed, or pinned connections.The PWR Reactor Internals program manages the aging effects noted above consistent withthe inspection guidance for Westinghouse designated primary components in Table 4-3 ofMRP-227-A and Westinghouse designated expansion components in Table 4-6 of MRP-227-A.MRP-227-A also identifies Existing Program components whose aging is managed consistentwith ASME Section XI Table IWB-2500-1, Examination Category B-N-3. See the componentlist in element 1 to identify Primary, Expansion, and Existing components.Detection of Aging Effects -Element 4The PWR Reactor Internals program detects aging effects through the implementation of theparameters monitored or inspected criteria and bases for Westinghouse designated PrimaryComponents in Table 4-3 of MRP-227-A and for Westinghouse designated ExpansionComponents in Table 4-6 of MRP-227-A. The aging effects of a third set of MRP-227-Ainternals locations identified in Table 4-9 of MRP-227-A are deemed to be adequately managedby existing program components whose aging is managed consistent with ASME Section XlTable IWB-2500-1, Examination Category B-N-3.
 
==Enclosure==
2NOC-AE-12002797Page 19 of 63One hundred percent of the accessible volume/area of each component will be examined forthe Primary and Expansion components inspection category components. The minimumexamination coverage for primary and expansion inspection categories is 75 percent of thecomponent's total (accessible plus inaccessible) inspection area/volume be examined. Whenaddressing a set of like components (e.g. bolting), the minimum examination coverage forprimary and expansion inspection categories is 75 percent of the component's total populationof like components (accessible plus inaccessible).If defects are discovered during the examination, STP enters the information into the STPcorrective action program and evaluates whether the results of the examination ensure that thecomponent (or set of components) will continue to meet its intended function under all licensingbasis conditions of operation until the next scheduled examination. Engineering evaluationsthat demonstrate the acceptability of a detected condition will be performed consistent withWCAP-1 7096-NP.Monitoring and Trending -Element 5The program provides both examination acceptance criteria (See Element 6) for conditionsdetected as a result of monitoring the primary components as described in Element 4, as wellas criteria for expanding examinations to the expansion components when warranted by thelevel of degradation detected in the primary components. Based on the identified aging effect,and supplemental examinations if required, the disposition process results in an evaluation anddetermination of whether to accept the condition until the next examination or implementcorrective actions. Any detected conditions that do not satisfy the examination acceptancecriteria (See Element 6) are required to be dispositioned through the corrective action program(See Element 7), which may require repair, replacement, or analytical evaluation for continuedservice until the next inspection.Acceptance Criteria -Element 6Examination acceptance for the Primary and Expansion component examinations areconsistent with Section 5 of MRP-227-A. ASME Section Xl section IWB-3500 acceptancecriteria apply to Existing Programs components. The following examination acceptance criteriaapply to the STP reactor vessel internals:Visual examination (VT-3) and enhanced visual examination (EVT-1)For existing program components, the ASME Code Section XI, Examination Category B-N-3provides the following general relevant conditions for the visual (VT-3) examination ofremovable core support structures.(1) Structural distortion or displacement of parts to the extent that component function may beimpaired,(2) Loose, missing, cracked, or fractured parts, bolting, or fasteners,(3) Corrosion or erosion that reduces the nominal section thickness by more than 5 percent,(4) Wear of mating surfaces that may lead to loss of function; and
 
==Enclosure==
2NOC-AE-12002797Page 20 of 63(5) Structural degradation of interior attachments such that the original cross-sectional area isreduced more than 5 percent.In addition, for the visual examinations (VT-3) of Primary and Expansion components, the PWRReactor Internals program is consistent with the more specific descriptions of relevantconditions provided in Table 5-3 of MRP-227-A. EVT-1 examinations are used for detectingsmall surface breaking cracks and surface crack length sizing when used in conjunction withsizing aids. EVT- 1 examination has been selected to be the appropriate NDE method fordetection of cracking in plates or their welded joints. The relevant condition applied for EVT-1examination is the same as found for cracking in ASME Section XI section 3500 which is crack-like surface breaking indications.Volumetric examinationIndividual bolts are accepted (pass/fail acceptance) based on the detection of relevantindications established as part of the examination technical justification. When a relevantindication is detected in the cross-sectional area of the bolt, it is assumed to be non-functionaland the indication is recorded. Bolted assemblies are evaluated for acceptance based onmeeting a specified number and distribution of functional bolts. Acceptance criteria forvolumetric examination of STP reactor internals bolting are consistent with Table 5-3 of MRP-227-A.Physical MeasurementsContinued functionality of the internals hold down spring is confirmed by direct physicalmeasurement. The examination acceptance criterion for this measurement is consistent withTable 5-3 of MRP-227-A and requires that the remaining compressible height of the spring shallprovide hold-down forces within the plant-specific design tolerance.Corrective Actions -Element 7The following corrective actions are available for the disposition of detected conditions thatexceed the examination acceptance criteria:(1) Supplemental examinations to further characterize and potentially dispose of a detectedcondition consistent with (Section 5.0 of MRP-227)-A;(2) Engineering evaluation that demonstrates the acceptability of a detected condition (SeetieR6.0 ef MRP 227)-consistent with WCAP-1 7096-NP;(3) Repair, in order to restore a component with a detected condition to acceptable status(ASME Section XI); or(4) Replacement of a component with an unacceptable detected condition (ASME Section Xl)(5) Other alternative corrective action bases if previously approved or endorsed by the NRC.Relevant indications failing to meet applicable acceptance criteria are repaired or replaced inaccordance with plant procedures. Appropriate codes and standards are specified in both the"ASME Section Xl Repair, Replacement, and Post-Maintenance Pressure Testing" procedure
 
==Enclosure==
2NOC-AE-1 2002797Page 21 of 63and in design drawings. Quality assurance requirements for repair and replacement activitiesare also included in the STP Operations Quality Assurance Plan.STP site QA procedures, review and approval process, and administrative controls areimplemented in accordance with the requirements of 10 CFR 50 Appendix B and areacceptable in addressing corrective actions. The QA program includes elements of correctiveaction, confirmation process and administrative controls, and is applicable to the safety-relatedand non-safety related systems, structures, and components that are subject to agingmanagement review.Confirmation Process -Element 8STP site QA procedures, review and approval process, and administrative controls areimplemented in accordance with the requirements of 10 CFR 50 Appendix B and areacceptable in addressing the confirmation process. The QA program includes elements ofcorrective action, confirmation process and administrative controls and is applicable to thesafety-related and non-safety related systems, structures and components that are subject toaging management review.Administrative Controls -Element 9STP site QA procedures, review and approval process, and administrative controls areimplemented in accordance with the requirements of 10 CFR 50 Appendix B and areacceptable in addressing administrative controls. The QA program includes elements ofcorrective action, confirmation process and administrative controls and is applicable to thesafety-related and non-safety related systems, structures and components that are subject toaging management review.Operating Experience -Element 10Relatively few incidents of PWR internals aging degradation have been reported in operatingU.S. commercial PWR plants. However, a considerable amount of PWR internals agingdegradation has been observed in European PWRs, with emphasis on cracking of baffle-formerbolting. The experience reviewed includes NRC Information Notice 84-18, Stress CorrosionCracking in PWR Systems and NRC Information Notice 98-11, Cracking of Reactor VesselInternal Baffle Former Bolts in Foreign Plants. Most of the industry operating experiencereviewed has involved cracking of austenitic stainless steel baffle-former bolts, or SCC of high-strength internals bolting. SCC of control rod guide tube split pins has also been reported.Several other items with existing or suspected material degradation concerns that have beenidentified for PWR components are wear in thimble tubes and potentially in control guide cardsand observed cracking in some high-strength bolting and in control rod guide tube alignment(split) pins. The latter are conditions that have been corrected primarily through boltreplacement with less susceptible material and improved control of pre-load.Based on industry operating experience, STP replaced the Alloy-750 guide tube support pins(split pins) with strained hardened (cold worked) 316 stainless steel pins during RefuelingOutage 1RE12 (Spring 2005) for Unit 1 and Refueling Outage 2RE11 (Fall 2005) for Unit 2.The replacement was conducted to reduce the susceptibility for stress corrosion cracking in thesplit pins. There were no cracked Alloy X-750 pins discovered during the replacement process.
 
==Enclosure==
2NOC-AE-12002797Page 22 of 63The ASME Code, Section XI, Examination Category B-N-3 examinations of core supportstructures conducted during Refueling Outage 1RE15 (Fall 2009) for Unit 1, and RefuelingOutage 2RE14 (Spring 2010) for Unit 2, did not identify any conditions that required repair,replacement or evaluation.The ISI Program portion of the PWR Reactor Internals program at STP is updated to accountfor industry operating experience. ASME Section XI is also revised every three years andaddenda issued in the interim, which allows the code to be updated to reflect operatingexperience. The requirement to update the IS[ Program to reference more recent editions ofASME Section XI at the end of each inspection interval ensures the IS[ Program reflectsenhancements due to operating experience that have been incorporated into ASME Section XI.With exception of the ASME Section ISI portions, the PWR Reactor Internals program will be anew program and has no direct programmatic history. A key element of the MRP-227-Aprogram is the reporting of aging of reactor vessel components. STP, through its participationin PWR Owners Group and EPRI-MRP activities, will continue to benefit from the reporting ofinspection information and will share its own operating experience with the industry throughthose groups or INPO, as appropriate.As additional Industry and applicable plant-specific operating experience become available, theOE will be evaluated and appropriately incorporated into the program through the STPCorrective Action and Operating Experience Programs. This ongoing review of OE willcontinue throughout the period of extended operation, and the results will be maintained on site.This process will confirm the effectiveness of this new license renewal aging managementprogram by incorporating applicable OE and performing self assessments of the program.ConclusionThe implementation of the PWR Reactor Internals program provides reasonable assurance thataging effects will be adequately managed such that the systems and components within thescope of this program will continue to perform their intended functions consistent with thecurrent licensing basis for the period of extended operation.
 
==Enclosure==
2NOC-AE-1 2002797Page 23 of 633.3.2.1.8 Primary Process Sampling SystemMaterialsThe materials of construction for the primary process sampling system component types are:* Carbon Steel* Stainless SteelEnvironmentThe primary process sampling system component types are exposed to the followingenvironments:* Borated Water Leakage* Closed-Cycle Cooling Water* Demineralized Water* Plant Indoor Air* Treated Borated WaterAging Effects Requiring ManagementThe following primary process sampling system aging effects require management:* Cracking* Loss of material* Loss of preloadAging Management ProgramsThe following aging management programs manage the aging effects for the primary processsampling system component types:* Bolting Integrity (B2.1.7)* Boric Acid Corrosion (B2.1.4)* Closed-Cycle Cooling Water System (B2.1.10)* External Surfaces Monitoring Program (B2.1.20)* Inspection of Internal Surfaces in Miscellaneous Piping and Ductinq Components(B2.1.22)* One-Time Inspection (B2.1.16)* Water Chemistry (B2.1.2)
 
==Enclosure==
2NOC-AE-1 2002797Page 24 of 633.3.2.1.16 Containment Hydrogen Monitoring and Combustible Gas Control SystemMaterialsThe materials of construction for the containment hydrogen monitoring and combustible gascontrol system component types are:* Glass* Stainless SteelEnvironmentThe containment hydrogen monitoring and combustible gas control system component typesare exposed to the following environment:* Plant Indoor AirAging Effects Requiring ManagementThe following containment hydrogen monitoring and combustible gas control system agingeffects require management:* Loss of material* Loss of preloadAging Management ProgramsThe following aging management programs manage the aging effects for the containmenthydrogen monitoring and combustible gas control system component types:* Bolting Integrity (B2.1.7)* Inspection of Internal Surfaces in Miscellaneous Pipinq and Ductinq Components(B2.1.22)
 
==Enclosure==
2NOC-AE-12002797Page 25 of 633.3.2.2,10.5HVAC aluminum piping and components and stainless steel ducting andcomponents exposed to condensationThe inSPec-tion of Inona uraesi iscellaaneous Piping and Duc~ting Components program(1B2.1.22) managos the m-Aterial from pitting an creice cr-rosio for st;i0nl-es stol aRdaluminum into-rnAl; surfacosr exposeqd to otlto atmosphFro anAd cond-ensation.Condensation applies to both internal and external environments for HVAC aluminum pipingand components and stainless steel ducting and components.The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program(B2.1.22) manages the loss of material from pitting and crevice corrosion for stainless steel andaluminum internal surfaces exposed to ventilation atmosphere and condensation.The External Surfaces Monitoring Program (B2.1.20) manages the loss of material from pittingand crevice corrosion for stainless steel and aluminum external surfaces exposed to plantindoor air and condensation.
 
==Enclosure==
2NOC-AE-12002797Page 26 of 63I able 3..32-8 Auxiliary Systems -Summary ot Agin g Management Evaluation -Primary Process Samp ling System (Continued)Component Intended Material Environment Aging Effect Aging Management NUREG- Table I Item NotesType Function Requiring Program 1801 Vol.Management 2 ItemValve LBS, PB, Stainless Plant Indoor Air None None VII.J-15 3.3.1.94 ASIA Steel (Ext)_Valve LBS, PB, Stainless Plant Indoor Air Nene Loss of Nene-Insoection of NeRe Nne E, GE 2SIA Steel (Int) material Internal Surfaces in VII.D-4 3.3.1.54Miscellaneous Pipinqand DuctingComponents (B2.1.22)Valve LBS, PB, Stainless Treated Borated Loss of material Water Chemistry VII.E1-17 3.3.1.91 E, 1SIA Steel Water (Int) (B2.1.2) and One-TimeInspection (B2.1.16)Notes for Table 3.3.2-8:Standard Notes:A Consistent with NUREG-1 801 item for component, material, environment, and aging effect. AMP is consistent with NUREG-1 801 AMP.B Consistent with NUREG-1 801 item for component, material, environment, and aging effect. AMP takes some exceptions to NUREG-1 801AMP.C Component is different, but consistent with NUREG-1801 item for material, environment, and aging effect. AMP is consistent withNUREG-1801 AMP.E Consistent with NUREG-1 801 for material, environment, and aging effect, but a different aging management program is credited orNUREG-1801 identifies a plant-specific aging management program.Enironment Anot Nin NUREG;1801 for this compoenet and matorialPlant Specific Notes:1 The Water Chemistry program (B2.1.2) and the One-Time Inspection program (B2.1.16) manage loss of material due to pitting and crevicecorrosion and cracking due to stress corrosion cracking. The One-Time Inspection program (B2.1.16) includes selected components atsusceptible locations.2 B2.1.22, Inspection of Internal Surfaces in Miscellaneous Pipincq and Ducting Components, is used because this is an a-qingq mechanismwhich occurs on the internal surfaces of these components.
 
==Enclosure==
2NOC-AE-12002797Page 27 of 63Tnhl,'I I 1)_0A # viIon, Q,,e'*&#xfd;mo -Qm .r, rf A ;n # C /- #;-, IAI..,#,- L.AIAf' It-.,~Awa, ....- -, l y W .O -- ,cj, IJi I Vl I Ill~llL L.-VOIU ILILIII -- ca lllllfll VV l T /I y./I. II UII VIIIL j.IComponent Type Intended Material Environment Aging Effect Aging Management NUREG- Table I NotesFunction Requiring Program 1801 Vol. ItemManagement 2 ItemFlow Element LBS Stainless Closed Cycle Loss of material Closed-Cycle Cooling VII.C2-10 3.3.1.50 BSteel Cooling Water Water System(Intt) (132. 1.10)Flow Element LBS Stainless Plant Indoor Air None Loss of _NeneExternal Surfaces VWj-15 3.3.. AESteel (Ext) material Monitoring Program VII.F2-1 3.3.1.27(B2.1 .20)Heat Exchanger PB Carbon Borated Water Loss of material Boric Acid Corrosion VI.I-10 3.3.1.89 A(AHU Condenser) _ Steel Leakage (Ext) 1 (B2.1.4)Strainer LBS Carbon Closed Cycle Loss of material Closed-Cycle Cooling VII.F2-18 3.3.1.47 BSteel Cooling Water Water System(Galvanized) _(Int) _(B2.1.10)Strainer LBS Carbon Plant Indoor Air None Loss of None External Surfaces VIJ-6 34..2 A BSteel (Ext) material Monitoring Program VII.F2-2 3.3.1.56(Galvanized) 1 (B2.1.20)Tank LBS, PB, Carbon Borated Water Loss of material Boric Acid Corrosion VII.I-10 3.3.1.89 ASIA Steel Leakage (Ext) (B2.1.4)Tank PB Stainless Lubricating Oil Loss of material Lubricating Oil Analysis VII.C2-12 3.3.1.33 BSteel (Int) (B2.1.23) and One-Time Inspection(B2.1.16)Tank PB Stainless Plant Indoor Air None Loss of None External Surfaces VWIJ-15 34.94 A ESteel (Ext) material Monitoring Program VII.F2-1 3.3.1.27_________(B2.1 .20)Thermowell PB Stainless Dry Gas (Int) None None VII.J-19 3.3.1.97 ASteelThermowell PB Stainless Plant Indoor Air None Loss of Nene External Surfaces VWIj 15 1-A4 A ESteel (Ext) material Monitoring Program VII.F2-1 3.3.1.27_(B2.1.20)
 
==Enclosure==
2NOC-AE-12002797Page 28 of 63Tohiln z Q 1_Aij ,ilyrin Qi/,-fnme -immnri ff A ;nr Annn~mn i jr- 111f1 ti;1 IAIf#~- L.IIIAf fn ~ ~ .~,II 1110 -UJ. UJ. ., III.J -,JUI lI ll y: If IVC4 ll jWI Il l I.--VCJIlIOLIIa.II -- 'JI IIIIlU V V .l I I V ,ULS I UIU/Component Type Intended Material Environment Aging Effect Aging Management NUREG- Table I NotesFunction Requiring Program 1801 Vol. ItemI Management 2 ItemTubing LBS, PB Stainless Closed Cycle Loss of material Closed-Cycle Cooling VII.C2-10 3.3.1.50 BSteel Cooling Water Water System(Int) ((B2.1.10)Tubing PB Stainless Dry Gas (Int) None None VII.J-19 3.3.1.97 A_ SteelTubing PB Stainless Lubricating Oil Loss of material Lubricating Oil Analysis VII.C2-12 3.3.1.33 BSteel (Int) (B2.1.23) and One-Time Inspection(B2.1.16)Tubing LBS, PB Stainless Plant Indoor Air Neoe Loss of None External Surfaces J-15 3.34.94 A ESteel (Ext) material Monitoring Program VII.F2-1 3.3.1.27(B2.1.20)Valve LBS, PB, Carbon Closed Cycle Loss of material Closed-Cycle Cooling VII.F2-18 3.3.1.47 BSIA Steel Cooling Water Water System_ (Int) (B2.1.10)
 
==Enclosure==
2NOC-AE-1 2002797Page 29 of 63Notes for Table 3.3.2-9:Standard Notes:A Consistent with NUREG-1801 item for component, material, environment, and aging effect. AMP is consistent with NUREG-1801 AMP.B Consistent with NUREG-1 801 item for component, material, environment, and aging effect. AMP takes some exceptions to NUREG-1 801AMP.E Consistent with NUREG-1 801 for material, environment, and aging effect, but a different aging management program is credited orNUREG-1 801 identifies a plant-specific aging management proqram.F Material not in NUREG-1 801 for this component.H Aging effect not in NUREG-1 801 for this component, material and environment combination.Plant Specific Notes:1 Wall thinning due to erosion-corrosion is managed by the Flow-Accelerated Corrosion program (B2.1.6)
 
==Enclosure==
2NOC-AE-12002797Page 30 of 63Table 3.3.2-10 Auxiliary Systems -Summary of Aging Management Evaluation -Electrical Auxiliary Building and Control RoomHVAC System (Continued)Component Intended Material Environment Aging Effect Aging Management NUREG- Table I Item NotesType Function Requiring Program 1801 Vol.Management 2 ItemDamper FB, PB Carbon Steel Encased in None None VII.J-21 3.3.1.96 C(Galvanized) Concrete (Ext)Damper FB, PB Carbon Steel Plant Indoor Air Nene Loss of NeOe External Surfaces Vl-IJ-6 3..92 G B(Galvanized) (Ext) material Monitoring Program VII.F1-2 3.3.1.56(B2.1.20)Damper FB, PB Carbon Steel Ventilation Loss of material Inspection of Internal VII.F1-3 3.3.1.72 B(Galvanized) Atmosphere (Int) Surfaces inMiscellaneous Pipingand DuctingComponents (B2.1.22)Ductwork PB Carbon Steel Ventilation Loss of material Inspection of Internal VII.F2-3 3.3.1.72 BAtmosphere (Int) Surfaces inMiscellaneous Pipingand DuctingComponents (B2.1.22)Ductwork LBS, PB Carbon Steel Plant Indoor Air None Loss of Nene External Surfaces VWJ-6 3.31.92 G B(Galvanized) (Ext) material Monitoring Program VII.F1-2 3.3.1.56_ 1_ _ 1__ 1__ _(B2.1.20) I IDuctworkPBCarbon Steel(Galvanized)VentilationAtmosphere (Int)Loss of materialInspection of InternalSurfaces inMiscellaneous Pipingand DuctingComponents (B2.11.22)VII.F1-33.3.1.72B
 
==Enclosure==
2NOC-AE-12002797Page 31 of 63Table 3.3.2-10Auxiliary Systems -Summary of Aging Management Evaluation -Electrical Auxiliary Building and Control RoomHVAC Sv~te~m (Continuted)VAC R , ... Z... __ ...........Component Intended Material Environment Aging Effect Aging Management NUREG- Table I Item NotesType Function Requiring Program 1801 Vol.I Management __2 ItemDuctwork PB Carbon Steel Ventilation Loss of material Inspection of Internal VII.F2-3 3.3.1.72 B(Galvanized) Atmosphere (Int) Surfaces inMiscellaneous Pipingand DuctingComponents (B2.1.22LDuctwork PB Stainless Plant Indoor Air None Loss of Nene External Surfaces V~kJ 6 3.3.94 G ESteel (Ext) material Monitoring Procqram VII.F1-1 3.3.1.27(B2.1.20)Ductwork LBS Stainless Ventilation Loss of material Inspection of Internal VII.F2-1 3.3.1.27 ESteel Atmosphere (Ext) Surfaces inMiscellaneous Pipingand DuctingComponents (B2.11.22)Ductwork PB Stainless Ventilation Loss of material Inspection of Internal VII.F1-1 3.3.1.27 ESteel Atmosphere (Int) Surfaces inMiscellaneous Pipingand DuctingComponents (B2.1.22)Ductwork LBS, PB Stainless Ventilation Loss of material Inspection of Internal VII.F2-1 3.3.1.27 ESteel Atmosphere (Int) Surfaces inMiscellaneous Pipingand DuctingI_ Components (B2.1.22)Filter PB Carbon Steel Plant Indoor Air None Loss of Nene External Surfaces V44-j 6 3.3..9 G B(Galvanized) (Ext) material Monitoring Program VII.F1-2 3.3.1.56(B2.1.20)Filter PB Carbon Steel Ventilation Loss of material Inspection of Internal VII.F1-3 3.3.1.72 B(Galvanized) Atmosphere (Int) Surfaces inMiscellaneous Pipingand DuctingComponents (B2.1.22)
 
==Enclosure==
2NOC-AE-12002797Page 32 of 63Table 3.3.2-10Auxiliary Systems -Summary of Aging Management Evaluation -Electrical Auxiliary Building and Control RoomHVAC System (Continued)Component Intended Material Environment Aging Effect Aging Management NUREG- Table I Item NotesType Function Requiring Program 1801 Vol.Management 2 ItemFilter PB Carbon Steel Ventilation Loss of material Inspection of Internal VII.F2-3 3.3.1.72 B(Galvanized) Atmosphere (Int) Surfaces inMiscellaneous Pipingand DuctingComponents (B2.1.22LFilter PB Stainless Plant Indoor Air Nene Loss of Nene External Surfaces V11J-45 3.3..4 CG ESteel (Ext) material Monitoring Program VII.F1-1 3.3.1.27(B2.1.20)Filter PB Stainless Ventilation Loss of material Inspection of Internal VII.F1-1 3.3.1.27 ESteel Atmosphere (Int) Surfaces inMiscellaneous Pipingand DuctingComponents (B2.1.22)Flex PB Elastomer Ventilation Hardening and Inspection of Internal VII.F2-7 3.3.1.11 EConnectors Atmosphere (Int) loss of strength Surfaces inMiscellaneous Pipingand Ducting_ Components (B2.1.22)Flow Element PB Carbon Steel Plant Indoor Air NoeR Loss of None External Surfaces V-1-6 3.3..92 CG B(Galvanized) (Ext) material Monitoring Program VII.F1-2 3.3.1.56(B2.1.20)Flow Element PB Carbon Steel Ventilation Loss of material Inspection of Internal VII.F1-3 3.3.1.72 B(Galvanized) Atmosphere (Int) Surfaces inMiscellaneous Pipingand Ducting;Components (B2.1.22)
 
==Enclosure==
2NOC-AE-12002797Page 33 of 63Table 3.3.2-10Auxiliary Systems -Summary of Aging Management Evaluation -Electrical Auxiliary Building and Control RoomHVAC System (Continued)Component Intended Material Environment Aging Effect Aging Management NUREG- Table I Item NotesType Function Requiring Program 1801 Vol.Management 2 ItemHeat LBS Copper Alloy Ventilation Loss of material Inspection of Internal VII.F2-14 3.3.1.25 EExchanger Atmosphere (Ext) Surfaces in(Pen Space Miscellaneous PipingAHU Cooling and DuctingCoil) Components (B2.1.22)Heater PB Carbon Steel Plant Indoor Air NeAe Loss of NeGe External Surfaces VIl-6 3.3-1.692 G B(Galvanized) (Ext) material Monitoring Program VII.F1-2 3.3.1.56(B2.1.20)Heater PB Carbon Steel Ventilation Loss of material Inspection of Internal VII.F1-3 3.3.1.72 B(Galvanized) Atmosphere (Int) Surfaces inMiscellaneous Pipingand DuctingComponents (B2.1.22)Heater PB Carbon Steel Ventilation Loss of material Inspection of Internal VII.F2-3 3.3.1.72 B(Galvanized) Atmosphere (Int) Surfaces inMiscellaneous Pipingand DuctingComponents (B2.1.22)Heater PB Stainless Plant Indoor Air Nee Loss of NeOe External Surfaces V4lA 1- 2 31-4 G ESteel (Ext) material Monitoring Program VII.F1-1 3.3.1.27(B2.1.20)Heater PB Stainless Ventilation Loss of material Inspection of Internal VII.F2-1 3.3.1.27 ESteel Atmosphere (Int) Surfaces inMiscellaneous Pipingand DuctingComponents (B2.1.22)
 
==Enclosure==
2NOC-AE-12002797Page 34 of 63Table 3.3.2-10 Auxiliary Systems -Summary of Aging Management Evaluation -Electrical Auxiliary Building and Control RoomHVAC System (Cont inued)Component Intended Material Environment Aging Effect Aging Management NUREG- Table I Item NotesType Function Requiring Program 1801 Vol.Management 2 ItemPiping PB Carbon Steel Ventilation Loss of material Inspection of Internal VII.F2-3 3.3.1.72 DAtmosphere (Int) Surfaces inMiscellaneous Pipingand DuctingComponents (B2.1.22)Piping PB Carbon Steel Plant Indoor Air Nene Loss of Nene External Surfaces V4bJ-6 3.1.92 G B(Galvanized) (Ext) material Monitoring Pro~gram VII.F1-2 3.3.1.56(B2.1.20)Piping PB Carbon Steel Ventilation Loss of material Inspection of Internal VII.F1-3 3.3.1.72 B(Galvanized) Atmosphere (Int) Surfaces inMiscellaneous Pipingand DuctingComponents (B2.1.22)Piping PB Carbon Steel Ventilation Loss of material Inspection of Internal VII.F2-3 3.3.1.72 B(Galvanized) Atmosphere (Int) Surfaces inMiscellaneous Pipingand DuctingComponents (B2.1.22)Piping PB Stainless Plant Indoor Air NOee Loss of NOee External Surfaces VJ 34 ..1.4 A ESteel (Ext) material Monitoring Program VII.F1-1 3.3.1.27(B2.1.20)Piping PB Stainless Ventilation Loss of material Inspection of Internal VII.F1-1 3.3.1.27 ESteel Atmosphere (Int) Surfaces inMiscellaneous Pipingand DuctingComponents (B2.1.22)Piping PB Stainless Ventilation Loss of material Inspection of Internal VII.F2-1 3.3.1.27 ESteel Atmosphere (Int) Surfaces inMiscellaneous Pipingand DuctingI _ I I I Components (B2.1.22) 1
 
==Enclosure==
2NOC-AE-1 2002797Page 35 of 63Table 3.3.2-10 Auxiliary Systems -Summary of Aging Management Evaluation -Electrical Auxiliary Building and Control RoomHVAC System (Continued)Component Intended Material Environment Aging Effect Aging Management NUREG- Table N Item otesType Function Requiring Program 1801 Vol..IIManagement 2 ItemSilencer PB Carbon Steel Plant Indoor Air Nene Loss of NOee External Surfaces V 6 3.3.-.1.92 G B(Galvanized) (Ext) material Monitoring Program VII.F1-2 3.3.1.56(B2.1.20)Silencer PB Carbon Steel Ventilation Loss of material Inspection of Internal VII.F1-3 3.3.1.72 B(Galvanized) Atmosphere (Int) Surfaces inMiscellaneous Pipingand Ducting_Components (B2.1.22)Tubing PB Copper Alloy Ventilation Loss of material Inspection of Internal VII.G-9 3.3.1.28 EAtmosphere (Int) Surfaces inMiscellaneous Pipingand DuctingComponents (B2.1.22)Tubing PB Stainless Plant Indoor Air NeRe Loss of Nene External Surfaces 3.3. .94 A ESteel (Ext) material Monitoring Program VII.F1-1 3.3.1.27(B2.1.20)Tubing PB Stainless Ventilation Loss of material Inspection of Internal VII.F1-1 3.3.1.27 ESteel Atmosphere (Int) Surfaces inMiscellaneous Pipingand DuctingI_ I_ I Components (B2.1.22)
 
==Enclosure==
2NOC-AE-12002797Page 36 of 63Notes for Table 3.3.2-10:Standard Notes:A Con.i.tent with IiIr-UREG 1A8-01 for compopnent, material, aging efect.- AMAP i c.ni.tnt with N-",-R.G 1802 AhM."B Consistent with NUREG-1801 item for component, material, environment, and aging effect. AMP takes some exceptions to NUREG-1801AMP.C Component is different, but consistent with NUREG-1801 item for material, environment, and aging effect. AMP is consistent withNUREG-1801 AMP.D Component is different, but consistent with NUREG-1801 item for material, environment, and aging effect. AMP takes some exceptions toNUREG-1801 AMP.E Consistent with NUREG-1 801 for material, environment, and aging effect, but a different aging management program is credited orNUREG-1 801 identifies a plant-specific aging management program.H Aging effect not in NUREG-1 801 for this component, material, and environment combination.Plant Specific Notes:1 Loss of preload is conservatively considered to be applicable for all closure bolting.
 
==Enclosure==
2NOC-AE-12002797Page 37 of 63Table 3.3.2-11Auxiliary Systems -Summary of Aging Management Evaluation -Fuel Handling Building HVAC System(Continued)Component Intended Material Environment Aging Effect Aging Management NUREG- Table I Item NotesType Function Requiring Program 1801 Vol.Management 2 ItemDamper FB Carbon Steel Encased in None None VII.J-21 3.3.1.96 A(Galvanized) Concrete (Ext)Damper PB Carbon Steel Plant Indoor Air Nene Loss of NOee External Surfaces VW4-6 3.3.1.92 A 13(Galvanized) (Ext) material Monitorinq Program VII.F2-2 3.3.1.56(B2.1.20)Damper FB, PB Carbon Steel Ventilation Loss of material Inspection of Internal VII.F2-3 3.3.1.72 B(Galvanized) Atmosphere (Int) Surfaces inMiscellaneous Pipingand DuctingComponents (B2.1.22)Ductwork LBS, PB Carbon Steel Plant Indoor Air Neoe Loss of None External Surfaces VWj 6 3... A B(Galvanized) (Ext) material Monitoring Program VII.F2-2 3.3.1.56(B2.1.20)Ductwork LBS Carbon Steel Plant Indoor Air Loss of material Inspection of Internal VII.F2-3 3.3.1.72 B(Galvanized) (Int) Surfaces inMiscellaneous Pipingand DuctingComponents (B2.1.22)Ductwork PB Carbon Steel Ventilation Loss of material Inspection of Internal VII.F2-3 3.3.1.72 B(Galvanized) Atmosphere (Int) Surfaces inMiscellaneous Pipingand DuctingComponents (B2.1.22)Ductwork PB Stainless Plant Indoor Air NOne Loss of None External Surfaces V-4, 15 3-3-.-.4 A ESteel (Ext) material Monitoring Program VII.F2-1 3.3.1.27(B2.1.20)Ductwork PB Stainless Ventilation Loss of material Inspection of Internal VII.F2-1 3.3.1.27 ESteel Atmosphere (Int) Surfaces inMiscellaneous Pipingand DuctingComponents (B2.1.22)
 
==Enclosure==
2NOC-AE-1 2002797Page 38 of 63Table 3.3.2-11Auxiliary Systems -Summary of Aging Management Evaluation -Fuel Handling Building HVAC System(Continued)Component Intended Material Environment Aging Effect Aging Management NUREG- Table I Item NotesType Function Requiring Program 1801 Vol.Management 2 Item IFilter PB Carbon Steel Ventilation Loss of material Inspection of Internal VIL.F2-3 3.3.1.72 BAtmosphere (Ext) Surfaces inMiscellaneous Pipingand DuctingComponents (B2.1.22)Filter PB Carbon Steel Ventilation Loss of material Inspection of Internal VII.F2-3 3.3.1.72 BAtmosphere (Int) Surfaces inMiscellaneous Pipingand DuctingComponents (B2.1.22)Filter PB Carbon Steel Plant Indoor Air Neoe Loss of None External Surfaces VI-IA6 3.31.92 A B(Galvanized) (Ext) material Monitoring Program VII.F2-2 3.3.1.56(B2.11.20)Filter PB Carbon Steel Ventilation Loss of material Inspection of Internal VII.F2-3 3.3.1.72 B(Galvanized) Atmosphere (Int) Surfaces inMiscellaneous Pipingand DuctingComponents (B2.1.22)
 
==Enclosure==
2NOC-AE-12002797Page 39 of 63Table 3.3.2-11Auxiliary Systems -Summary of Aging Management Evaluation -Fuel Handling Building HVAC System(Continued)Component Intended Material Environment Aging Effect Aging Management NUREG- Table I Item NotesType Function Requiring Program 1801 Vol.__Management 2 ItemHeat HT, LBS, Copper Alloy Ventilation Loss of material Inspection of Internal VII.F2-14 3.3.1.25 EExchanger PB Atmosphere (Ext) Surfaces in(ESF Miscellaneous PipingEquipment and DuctingRoom AHU) Components (B2.1.22)Heat PB Stainless Plant Indoor Air NeWAe Loss of Nene External Surfaces V4kj- ,=%3-.1.-94 G EExchanger Steel (Ext) material Monitoring Program VII.F2-1 3.3.1.27(ESF (B2.1.20)EquipmentRoom AHU)Heat PB Stainless Ventilation Loss of material Inspection of Internal VII.F2-1 3.3.1.27 EExchanger Steel Atmosphere (Int) Surfaces in(ESF Miscellaneous PipingEquipment and DuctingRoom AHU) I I _Components (B2.1.22) 1 1Notes for Table 3.3.2-11:Standard Notes:A Consistent with NUREG-1801 item for component, material, environment, and aging effect. AMP is consistent with NUREG-1801 AMP.B Consistent with NUREG-1801 item for component, material, environment, and aging effect. AMP takes some exceptions to NUREG-1801AMP.,. ., .., h L v. ....,., I , , m ., ... ,, , ,N.,i. RV., ., ..., ..A and g " 1, .* ...... ...,;,, ,, I4904-AMPD Component is different, but consistent with NUREG-1801 item for material, environment, and aging effect. AMP takes some exceptions toNUREG-1801 AMP.E Consistent with NUREG-1 801 for material, environment, and aging effect, but a different aging management program is credited orNUREG-1801 identifies a plant-specific aging management program.Plant Specific Notes:None
 
==Enclosure==
2NOC-AE-12002797Page 40 of 63Table 3.3.2-12Auxiliary Systems -Summary of Aging Management Evaluation -Mechanical Auxiliary Building HVAC System(Continued)Component Intended Material Environment Aging Effect Aging Management NUREG- Table I Item NotesType Function Requiring Program 1801 Vol.Management 2 ItemDamper FB, PB Carbon Steel Encased in None None VII.J-21 3.3.1.96 C(Galvanized) Concrete (Ext)Damper PB Carbon Steel Plant Indoor Air NOee Loss of NORe-External Surfaces VI4J--6 3.3.-92 G B(Galvanized) (Ext) material Monitoring Program VII.F2-2 3.3.1.56(B2.1.20)Damper FB Carbon Steel Plant Indoor Air Loss of material Inspection of Internal VII.F2-3 3.3.1.72 B(Galvanized) (Int) Surfaces inMiscellaneous Pipingand DuctingComponents (B2.1.22)Damper FB, PB Carbon Steel Ventilation Loss of material Inspection of Internal VII.F2-3 3.3.1.72 B(Galvanized) Atmosphere (Int) Surfaces inMiscellaneous Pipingand DuctingComponents (B2.1.22) _ IDuctwork PB Carbon Steel Plant Indoor Air None Loss of NeOe External Surfaces VIkj-6 33.1.92 G B(Galvanized) (Ext) material Monitoring Program VII.F2-2 3.3.1.56(B2.1.20)Ductwork PB Carbon Steel Ventilation Loss of material Inspection of Internal VII.F2-3 3.3.1.72 B(Galvanized) Atmosphere (Int) Surfaces inMiscellaneous Pipingand DuctingComponents (B2.1.22)Ductwork PB Stainless Plant Indoor Air NeOe Loss of NORe External Surfaces VIkj-15 3..1.94 G ESteel (Ext) material Monitoring Program VII.F2-1 3.3.1.27(B2.1.20)Ductwork PB Stainless Plant Indoor Air Loss of material Inspection of Internal VII.F2-1 3.3.1.27 ESteel (Int) Surfaces inMiscellaneous Pipingand DuctingComponents (B2.1.22)
 
==Enclosure==
2NOC-AE-12002797Page 41 of 63Table 3.3.2-15 Auxiliary Systems -Summary of Aging Management Evaluation -Standby Diesel Generator Building HVACSystemComponent Intended Material Environment Aging Effect Aging Management NUREG- Table I Item NotesType Function Requiring Program 1801 Vol.Management 2 ItemDamper FB, PB Carbon Steel Ventilation Loss of material Inspection of Internal VII.F4-2 3.3.1.72 B(Galvanized) Atmosphere (Int) Surfaces inMiscellaneous Pipingand DuctingComponents (B2.1.22L _Damper PB Stainless Plant Indoor Air None Loss of Neoe External Surfaces V114-14 224 Q4 G ESteel (Ext) material Monitoring Program VII.F2-1 3.3.1.27S1(B2.11.20)Damper PB Stainless Ventilation Loss of material Inspection of Internal VII.F2-1 3.3.1.27 ESteel Atmosphere (Int) Surfaces inMiscellaneous Pipingand DuctingComponents (B2.1.22)Flex PB Elastomer Ventilation Hardening and Inspection of Internal VII.F4-6 3.3.1.11 EConnectors Atmosphere (Int) loss of strength Surfaces inMiscellaneous Pipingand DuctingComponents (B2.1.22)Tubing PB Stainless Plant Indoor Air None Loss of NeRe External Surfaces VI J 45 3.3.1.4 A ESteel (Ext) material Monitoring Program VII.F2-1 3.3.1.273(B2.1.20)Tubing PB Stainless Ventilation Loss of material Inspection of Internal VII.F2-1 3.3.1.27 ESteel Atmosphere (Int) Surfaces inMiscellaneous Pipingand DuctingComponents (B2.1.22)
 
==Enclosure==
2NOC-AE-1 2002797Page 42 of 63Notes for Table 3.3.2-15:Standard Notes:A Consistent with NUREG 1801 item for componont, material, environment, and aging effect. AMP iks cnsiStent with NUREG 1801 AMP.B Consistent with NUREG-1 801 item for component, material, environment, and aging effect. AMP takes some exceptions to NUREG-1 801AMP.C Component is different, but consistent with NUREG-1801 item for material, environment, and aging effect. AMP is consistent with NUREG-1801 AMP.E Consistent with NUREG-1 801 for material, environment, and aging effect, but a different aging management program is credited orNUREG-1 801 identifies a plant-specific aging management program.Plant Specific Notes:1 Loss of preload is conservatively considered to be applicable for all closure bolting.
 
==Enclosure==
2NOC-AE-1 2002797Page 43 of 63Table 3.3.2-16 Auxiliary Systems -Summary of Aging Management Evaluation -Containment Hydrogen Monitoring andCombustible Gas Control SystemComponent Intended Material Environment Aging Effect Aging Management NUREG- Table I Item NotesType Function Requiring Program 1801 Vol.Management 2 ItemHeat HT, PB Stainless Plant Indoor Air None None VII.J-15 3.3.1.94 CExchanger Steel (Ext)(HydrogenAnallYzer)___r )...Heat HT, PB Stainless Plant Indoor Air None Loss of None Inspection of None Nee G EExchanger Steel (Int) material Internal Surfaces in VII.F3-1 3.3.1.27(Hydrogen Miscellaneous PipingAnalyzer) and DuctincqComponents (B2.1.22)Orifice PB, TH Stainless Plant Indoor Air None None VII.J-15 3.3.1.94 ASteel (Ext)Orifice PB, TH Stainless Plant Indoor Air Neoe Loss of Neoe Inspection of None None G ESteel (Int) material Internal Surfaces in VII.F3-1 3.3.1.27Miscellaneous Pipingand DuctinqComponents (B2.1.22)Piping PB, SIA Stainless Plant Indoor Air None None VII.J-15 3.3.1.94 ASteel (Ext)Piping PB, SIA Stainless Plant Indoor Air None Loss of Noea Inspection of None Nene G ESteel (Int) material Internal Surfaces in VII.F3-1 3.3.1.27Miscellaneous Pipingand DuctingComponents (B2.1.22)Pump PB Stainless Plant Indoor Air None None VII.J-15 3.3.1.94 ASteel (Ext)Pump PB Stainless Plant Indoor Air Neoe Loss of None Inspection of None None G ESteel (Int) material Internal Surfaces in VII.F3-1 3.3.1.27Miscellaneous Pipingand DuctinqI______ _Components (B2.1.22) 1 1
 
==Enclosure==
2NOC-AE-12002797Page 44 of 63Table 3.3.2-16 Auxiliary Systems -Summary of Aging Management Evaluation -Containment Hydrogen Monitoring andCombustible Gas Control System (Continued)Component Intended Material Environment Aging Effect Aging Management NUREG- Table I Item NotesType Function Requiring Program 1801 Vol.I Management 2 ItemTubing PB Stainless Plant Indoor Air None None VII.J-15 3.3.1.94 *ASteel (Ext)Tubing PB Stainless Plant Indoor Air NOee Loss of NOee Inspection of NeRe NeRe G ESteel (Int) material Internal Surfaces in VII.F3-1 3.3.1.27Miscellaneous Pipingand DuctinqComponents (B2.1.22)Valve PB Stainless Plant Indoor Air None None VII.J-15 3.3.1.94 ASteel (Ext)Valve PB Stainless Plant Indoor Air Nene Loss of Nene Inspection of Nene Nee G ESteel (Int) material Internal Surfaces in VII.F3-1 3.3.1.27Miscellaneous Pipinqand DuctingI__ I_ _ _Components (B2.1.22) I INotes for Table 3.3.2-16:Standard Notes:A Consistent with NUREG-1801 item for component, material, environment, and aging effect. AMP is consistent with NUREG-1801 AMP.C Component is different, but consistent with NUREG-1 801 item for material, environment, and aging effect. AMP is consistent withNUREG-1801 AMP.E Consistent with NUREG-1 801 for material, environment, and aging effect, but a different aging mana-gement pro-gram is credited orNUJREG-1801 identifies a nlant-sn)ecific anina manaaement nrooram.NUREG-11 801 identifies a plant-specific aging management proorarnAI L i .... A A J F .. ....t-nIyplpl Mn AV, %i lU"Ml- 'I OA-l 4^ r 4f,c. nan, &#xfd;nanna &#xfd;nflt mlaH Aging effect not in NUREG-1801 for this component, material, and environment combination.Plant Specific Notes:1 Loss of preload is conservatively considered to be applicable for all closure bolting.
 
==Enclosure==
2NOC-AE-1 2002797Page 45 of 63Table 3.3.2-20Auxiliary Systems -Summary of Aging Management Evaluation -Standby Diesel Generator and Auxiliaries(flnntinue!d)Component Intended Material Environment Aging Effect Aging Management NUREG- Table I Item NotesType Function Requiring Program 1801 VolManagement 2 ItemExpansion PB Stainless Plant Indoor Air None None VII.J-15 3.3.1.94 CJoint Steel (Ext)Expansion PB Stainless Plant Indoor Air NeRe Loss of NeFe Inspection of Internal NORe Nene 4,-4 E, 3Joint Steel (Int) material Surfaces in Miscellaneous VII.D-4 3.3.1.54Piping and DuctingComponents (B2.1.22)Expansion PB Stainless Raw Water (Int) Loss of material Open-Cycle Cooling Water VII.H2-18 3.3.1.80 DJoint Steel System (B2.1.9)Thermowell PB, SIA Stainless Plant Indoor Air None None VII.J-15 13.3.1.94 ASteel (Ext)Thermowell SIA Stainless Plant Indoor Air NOne Loss of NOne Inspection of Internal Noe NRe G-E, 3Steel (Int) material Surfaces in Miscellaneous VII.D-4 3.3.1.54Piping and DuctinqComponents (B2.1.22)Thermowell PB Stainless Raw Water (Int) Loss of material Open-Cycle Cooling Water VII.H2-18 3.3.1.80 BSteel System (B2.1.9) 1 1 1Tubing LBS, PB, Stainless Plant Indoor Air None None VII.J-15 3.3.1.94 ASIA Steel (Ext)Tubing LBS, PB, Stainless Plant Indoor Air None Loss of None Inspection of Internal Neoe NOne G E 3SIA Steel (Int) material Surfaces in Miscellaneous VII.D-4 3.3.1.54Piping and DuctingComponents (B2.1.22)Tubing LBS, PB, Stainless Raw Water (Int) Loss of material Open-Cycle Cooling Water VII.H2-18 3.3.1.80 BSIA Steel System (B2.1.9)
 
==Enclosure==
2NOC-AE-12002797Page 46 of 63Table 3.3.2-20 Auxiliary Systems -Summary of Aging Management Evaluation -Standby Diesel Generator and Auxiliaries(Continued)Component Intended Material Environment Aging Effect Aging Management NUREG- Table I Item NotesType Function Requiring Program 1801 Vol.Management 2 ItemValve LBS, PB, Stainless Plant Indoor Air None None VII.J-15 3.3.1.94 ASIA Steel (Ext)Valve LBS, PB, Stainless Plant Indoor Air None Loss of None Inspection of Internal None None G E 3SIA Steel (Int) material Surfaces in Miscellaneous VII.D-4 3.3.1.54Piping and DuctingCom ponents (B2.1.22)Notes for Table 3.3.2-20:Standard Notes:A Consistent with NUREG-1 801 item for component, material, environment, and aging effect. AMP is consistent with NUREG-1 801 AMP.B Consistent with NUREG-1 801 item for component, material, environment, and aging effect. AMP takes some exceptions to NUREG-1 801AMP.C Component is different, but consistent with NUREG-1801 item for material, environment, and aging effect. AMP is consistent withNUREG-1801 AMP.D Component is different, but consistent with NUREG-1 801 item for material, environment, and aging effect. AMP takes some exceptions toNUREG-1801 AMP.E Consistent with NUREG-1 801 for material, environment, and aging effect, but a different aging management program is credited orNUREG-1801 identifies a plant-specific aging management program.F Material not in NUREG-1801 for this componentG Environment not in NUREG-1 801 for this component and material.H Aging effect not in NUREG-1801 for this component, material, and environment combination.Plant Specific Notes:1 Loss of preload is conservatively considered to be applicable for all closure bolting.2 Reduction in heat transfer due to fouling is a potential aging effect/mechanism for cast iron (gray cast iron) turbocharger components inclosed cycle cooling water.3 B2.1.22, Inspection of Internal Surfaces in Miscellaneous Pipincq and Ductinq Components, is used because this is an aging mechanismwhich occurs on the internal surfaces of these components.
 
==Enclosure==
2NOC-AE-12002797Page 47 of 63Table 3.3.2-23Auxiliary Systems -Summary of Aging Management Evaluation -Radioactive Vents and Drains System(Continued)Component Intended Material Environment Aging Effect Aging Management NUREG- Table I Item NotesType Function Requiring Program 1801 Vol.._ Management 2 ItemValve LBS, PB, Stainless Plant Indoor Air None None VII.J-15 3.3.1.94 ASIA Steel (Ext)Valve LBS, PB Stainless Plant Indoor Air NeRe Loss of NeOe Inspection of Nene Nene G ESteel (Int) material Internal Surfaces in V.A-26 3.2.1.08Miscellaneous Pipingand DuctinqComronents (B2.1.22)Valve LBS, PB, Stainless Raw Water (Int) Loss of material Inspection of Internal VI1.C1-15 3.3.1.79 E, 2SIA Steel Surfaces inMiscellaneous Pipingand Ducting_Components (B2.1.22LNotes for Table 3.3.2-23:Standard Notes:A Consistent with NUREG-1801 item for component, material, environment, and aging effect. AMP is consistent with NUREG-1801 AlB Consistent with NUREG-1801 item for component, material, environment, and aging effect. AMP takes some exceptions to NUREGAMP.E Consistent with NUREG-1 801 for material, environment, and aging effect, but a different aging management program is credited orNUREG-1801 identifies a plant-specific aging management program.EnVironment not in NilURE=G 1801 for this comAPOnent and mfaterial.MIP.-1801H Aging effect not in NUREG-1 801 for this component, material and environment combination.Plant Specific Notes:1 Loss of preload is conservatively considered to be applicable for all closure bolting.2 The component environment is miscellaneous radioactive waste drains that have been evaluated as a raw water environment. Loss ofmaterial on internal component surfaces exposed to a mixed waste water environment classified as raw water is managed by Inspection ofInternal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.22) instead of Open-Cycle Cooling Water System (B2.1.9).
 
==Enclosure==
2NOC-AE-1 2002797Page 48 of 633 The component environment is radioactive waste drains that have been evaluated as a raw water environment. Loss of material onexternal component surface exposed to floor and equipment drains environment is managed by External Surfaces Monitoring (B2.1.20)instead of Open-Cycle Cooling Water System (B2.1.9).4 The Water Chemistry program (B2.1.2) and the One-Time Inspection program (B2.1.16) manage loss of material due to pitting and crevicecorrosion and cracking due to stress corrosion cracking. The One-Time Inspection program (B2.1.16) includes selected components atsusceptible locations.5 The component type is internal to the ducting system, so internal inspection was selected instead of using external surfaces inspection.The environment is external ventilation air.
 
==Enclosure==
2NOC-AE-1 2002797Page 49 of 63Table 3.4.2-1Steam and Power Conversion System -Summary of Aging Management Evaluation -Main Steam System(Continued)Component Intended Material Environment Aging Effect Aging Management NUREG- Table I Item NotesType Function Requiring Program 1801 Vol.Management 2 ItemSolenoid Valve PB Aluminum Plant Indoor Air None None V.F-2 3.2.1.50 A(Ext)Solenoid Valve PB Aluminum Plant Indoor Air Nene Loss of None Inspection of V.F2 322 so A E(Int) material Internal Surfaces in VII.F2-12 3.3.1.27Miscellaneous Pipingqand Ductinq_Components (B2.1.22)Tank PB Stainless Lubricating Oil (Int) Loss of material Lubricating Oil Analysis VIII.A-9 3.4.1.19 DSteel (B2.1.23) and One-Time_Inspection (B2.1.16)
 
==Enclosure==
2NOC-AE-12002797Page 50 of 63Al SUMMARY DESCRIPTIONS OF AGING MANAGEMENTPROGRAMSThe integrated plant assessment and evaluation of time-limited aging analyses (TLAA)identified existing and new aging management programs necessary to providereasonable assurance that components within the scope of license renewal will continueto perform their intended functions consistent with the current licensing basis (CLB) forthe period of extended operation. Sections Al and A2 describe the programs and theirimplementation activities.Three elements common to all aging management programs discussed in Sections Aland A2 are corrective actions, confirmation process, and administrative controls. TheSTP Quality Assurance Program includes the elements of corrective action, confirmationprocess, and administrative controls, and is applicable to the safety-related andnonsafety-related systems, structures, and components that are subject to agingmanagement activities.Results of inspections, tests, analyses, etc. conducted throuqh the implementation ofaging management programs are considered as operating experience on an onqoingbasis. When applicable acceptance criteria are met, results are retained for future useand evaluation to determine whether it is necessary to adjust the frequency for futureinspections, establish new inspections, and ensure an adequate depth and breadth ofcomponent, material, environment, and aging effect combinations. When applicableacceptance criteria are not met, corrective actions are initiated in accordance with thequality assurance program.Operating experience is applied to all aging management programs discussed inSections Al and A2. Plant-specific and industry operating experience is continuouslyreviewed to confirm the effectiveness of aging management programs and is utilized, asnecessary, to enhance each aging management program or to develop new agingmanagement programs in order to adequately manage the effects of aging so that theintended function(s) of structures and components are met.A systematic review of operating experience related to aqing management ensures thatlicense renewal aging management programs are effective in manaqing the agingeffects for which they are credited. Processes gather information on license renewalstructures and components identified in the integrated plant assessment, and theirmaterials, environments, aging effects, and aging mechanisms. Programs andprocedures specify reviews of sources of information related to aging effects. Formalevaluations related to aginq effects are completed and prioritized commensurate withthe potential significance on the issue. The evaluations are documented and retained inan auditable and retrievable form. Enhancements to programs and procedures toadequately manage the effects of aging are entered into and implemented consistentwith the plant corrective action program. Aging management programs areadministratively controlled to include a formal review and approval process and periodicaudits.
 
==Enclosure==
2NOC-AE-12002797Page 51 of 63The following enhancements will be made to the STP Operating Experience Programand Corrective Action Program for managing the effects of aging.* The OEP procedure will be revised to add License Renewal Interim StaffGuidance and revisions to NUREG-1 801, "Generic Aging Lessons Learned(GALL) Report", as source documents applicable for review.* The OEP procedure will be revised to include "aging effects" to the list ofcharacteristics for determining applicability of an OE document that may requirefurther evaluation. A screened-in evaluation should consider (a) systems,structures, or components, (b) materials, (c) environments, (d) aging effects, (e)aging mechanisms, and (f) aging management programs.* Corrective Action Program Event Codes will be reviewed to determine ifadditional codes are needed to ensure age-related degradation effects areidentified.* A training "needs analysis" will be performed for those plant personnel whoscreen, assign, evaluate, and submit plant-specific and industry operatingexperience information for age-related effects.* The OEP procedure will be revised to provide criteria for reporting plant-specificoperatinq experience on aqe-related degradation.
 
==Enclosure==
2NOC-AE-12002797Page 52 of 63A1.16 One-Time InspectionThe One-Time Inspection program conducts one-time inspections of plant system pipingand components to verify the effectiveness of the Water Chemistry program (Al.2), FuelOil Chemistry program (A1.14), and Lubricating Oil Analysis program (A1.23). Theaging effects to be evaluated by the One-Time Inspection program are loss of material,cracking, and reduction of heat transfer. The One-Time Inspection program determinesnon-destructive examination (NDE) sample sizes based on the population ofcomponents in a group sharing the same material, environment and aging effects. Foreach population, a representative sample size of 20 percent of the population isselected up to a maximum of 25 components. The components making up the sampleare those determined to be most susceptible to degradation based on a review ofenvironment, condition and operating experience. The sample population includes eddycurrent testing of the tubes in one non-regenerative heat exchanger. The program willfocus on bounding or lead components most susceptible to aging due to time in service,and severity of operating conditions. Inspections will be performed using a variety ofNDE methods, including visual, volumetric, and surface techniques by qualifiedinspectors. The program will not be used for component inspections with known age-related degradation mechanisms, or when the environment in the period of extendedoperation is not equivalent to that in the prior 40 years. The One-Time Inspectionprogram specifies corrective actions if aging effects are found. The corrective actionprogram may specify follow-up inspections for confirmation of aging effects at the sameor different locations. If aging effects are detected, a plant-specific program will bedeveloped for the material, environment, and aging effect combination that hasproduced the aging effects.This new program will be implemented and completed within the 10 year period prior tothe period of extended operation. Industry and plant-specific operating experience willbe evaluated in the development and implementation of this program.
 
==Enclosure==
2NOC-AE-1 2002797Page 53 of 63B2.1.16 One-Time InspectionProgram DescriptionThe One-Time Inspection program manages loss of material, cracking, and reduction ofheat transfer. The One-Time Inspection program conducts one-time inspections of plantsystem piping and components to verify the effectiveness of the Water Chemistryprogram (B2.1.2), Fuel Oil Chemistry program (B2.1.14), and Lubricating Oil Analysisprogram (B2.1.23).The One-Time Inspection program will be implemented by STP prior to the period ofextended operation. Plant system piping and components identified in the one-timeinspection procedure will be subject to one-time inspections on a sampling basis, usingqualified inspection personnel, following established ASME Code Section VNon-Destructive Examination techniques appropriate to each inspection. The One-TimeInspection program determines non-destructive examination (NDE) sample sizes basedon the population of components in a group sharing the same material, environment andaging effects. For each population, a representative sample size of 20 percent of thepopulation is selected up to a maximum of 25 components. The components making upthe sample are those determined to be most susceptible to degradation based on areview of environment conditions and operating experience. The sample populationincludes eddy current testing of the tubes in one non-regenerative heat exchanger. Theprogram will focus on bounding or lead components most susceptible to aging due totime in service, and severity of operating conditions. Inspections will be performedusing a variety of NDE methods, including visual, volumetric, and surface techniques byqualified inspectors. The program will not be used for component inspections withknown age-related degradation mechanisms, or when the environment in the period ofextended operation is not equivalent to that in the prior 40 years. The One-TimeInspection program specifies corrective actions if aging effects are found. Thecorrective action program may specify follow-up inspections for confirmation of agingeffects at the same or different locations. If aging effects are detected, a plant-specificprogram will be developed for the material, environment, and aging effect combinationthat has produced the aging effects.The one-time inspections will be performed no earlier than 10 years prior to the period ofextended operation. All one-time inspections will be completed prior to the period ofextended operation. Completion of the One-Time Inspection program in this time periodwill assure that potential aging effects will be manifested based on at least 30 years ofSTP operation. Major elements of the STP One-Time Inspection program will include:a) Identifying piping and component populations subject to one-time inspections basedon common materials and environments,b) Determining the sample size of components to inspect for each material-environmentgroup,c) Selecting piping and components within the material-environment groups forinspection based on criteria provided in the one-time inspection procedure,
 
==Enclosure==
2NOC-AE-12002797Page 54 of 63d) Conducting one-time inspections of the selected components within the sample usingASME Code Section V Non-Destructive Examination techniques and acceptance criteriaconsistent with the design codes/standards or ASME Section XI as applicable to thecomponent,e) Evaluating inspection results and initiating corrective action for any aging effectsfound.NUREG-1801 ConsistencyThe One-Time Inspection program is a new program that, when implemented, will beconsistent with NUREG-1 801, Section XI.M32, One-Time Inspection.Exceptions to NUREG-1801NoneEnhancementsNoneOperating ExperienceDuring the 10 year period prior to the period of extended operation, one-time inspectionswill be accomplished at STP using ASME Code Section V Non-Destructive Examinationtechniques to identify possible aging effects. ASME code techniques in the ASMESection X1 ISI Program have proven to be effective in detecting aging effects prior toloss of intended function. Review of STP plant-specific operating experience associatedwith the ISI Program has not revealed any ISI Program adequacy issues with the STPASME Section XI ISI Program. The same Non-Destructive Examination techniquesused in the ASME Section XI ISI Program will be used in the One-Time Inspectionprogram. Using ASME Code Section V Non-Destructive Examination techniques will beeffective in identifying aging effects, if present.As additional industry and plant-specific applicable operating experience becomesavailable, it will be evaluated and incorporated into the program through the STPcondition reporting and operating experience programs.ConclusionThe implementation of the One-Time Inspection program will provide reasonableassurance that aging effects will be managed such that the systems and componentswithin the scope of this program will continue to perform their intended functionsconsistent with the current licensing basis for the period of extended operation.
 
==Enclosure==
2NOC-AE-12002797Page 55 of 63A1.39 PROTECTIVE COATING MONITORING AND MAINTENANCE PROGRAMThe Protective Coating Monitoring and Maintenance Program manages loss of coatingintegrity for Service Level 1 coatings inside containment so that the intended functionsof post-accident safety systems that rely on water recycled through the containmentsump/drain system are maintained consistent with the current licensing basis. Theprogram includes a visual examination of all reasonably accessible Service Level 1coatings inside containment during every refueling outage, including those applied to thesteel containment liner, structural steel, supports, penetrations, uninsulated equipment,and concrete walls and floors receiving epoxy surface systems. This program does notinclude coating of surfaces that are insulated or otherwise enclosed in normal serviceand concrete receiving a non-film forming clear sealer coat only. This program isconsistent with the standards provided in ASTM D 5163-08 and Regulatory Guide 1.54,Rev. 2, as addressed in NUREG 1801, Rev. 2, XI.S8.
 
==Enclosure==
2NOC-AE-12002797Page 56 of 63B2.1.39 Protective Coating Monitoring and Maintenance ProgramProgram DescriptionThe Protective Coating Monitoring and Maintenance Program manages loss of coatingintegrity for Service Level 1 coatings inside containment so that the intended functionsof post-accident safety systems that rely on water recycled through the containmentsump/drain system are maintained consistent with the current licensing basis. Theprogram includes a visual examination of all reasonably accessible Service Level 1coatings inside containment, including those applied to the steel containment liner,structural steel, supports, penetrations, uninsulated equipment, and concrete walls andfloors receiving epoxy surface systems. This program does not include coating ofsurfaces that are insulated or otherwise enclosed in normal service and concretereceiving a non-film forming clear sealer coat only. This program is consistent with thestandards provided in ASTM D 5163-08 and Regulatory Guide (RG) 1.54, Rev. 2, asaddressed in NUREG 1801, Rev. 2, XI.S8.General visual inspections of the containment building Service Level 1 coatings areconducted a. part of the ASRE SActOn Xl, Subsection IWE program and the StructureMonitoring Program at inte or.als not excooding five yoars. during every refueling outage.Additional inspections may be necessary depending on inspection results. Thoroughvisual inspections are performed on previously designated areas and on areas noted asdeficient during the inspection. Characterization of doficiont-ar4a- blistering, cracking,flaking, peeling, de-lamination, rusting, and physical damage is performed to allowevaluation of the deficiency for fu-tu-re su',oeillaRce or repair, and prioritization of repairs,or for future surveillance. .haracteFrizatin of b I.literi crc I iGng, flaking, Pooling, deru.tig is consi.tent with applicable AST^ standards.&. Physical testingmay be performed when directed by the evaluate Nuclear Coating Specialist. Physicaltests are performed by individuals trained in applicable referenced standards of GuideD5498. Examinations are conducted by qualified personnel.Service Level I coatings are not credited for managing loss of material of the steelcontainment liner.Aging Management Program ElementsThe results of an evaluation of each element against the 10 elements described inAppendix A of NUREG-1 800, Standard Review Plan for Review of License RenewalApplications for Nuclear Power Plants are provided below.Scope of Program (Element 1)The Protective Coating Monitoring and Maintenance Program includes a visualexamination of all reasonably accessible Service Level 1 coatings inside containment,.ik g theee-as defined in RG 1.54, Rev. 2. This scope includes coatings applied tothe steel containment liner, structural steel, supports, penetrations, uninsulatedequipment, and concrete walls and floors receiving epoxy surface systems. This
 
==Enclosure==
2NOC-AE-1 2002797Page 57 of 63program pertains to the containment interior and equipment, structures or componentswhich are permanently located inside containment. This program does not includecoating of surfaces that are insulated or otherwise enclosed in normal service andconcrete receiving a non-film forming clear sealer coat only.Service Level I coatings are not credited for preventing loss of material due to corrosionfor the steel containment liner. (See AMP XI.S1, ASME Section XI, SubSection IVWE)Preventive Actions (Element 2)The Protective Coating Monitoring and Maintenance Program does not preventdegradation due to aging effects but provides measures for monitoring to detect thedegradamO -aging prior to loss of intended function. Coatings are not credited forpreventing loss of material.Parameters Monitored or Inspected (Element 3)The Protective Coating Monitoring and Maintenance Program inspects coated surfacesfor flaking, blistering, cracking, do lamination, pooling, or rustingany visible defects,such as blistering, cracking, flaking, peeling, rusting, and physical damage, as specifiedin ASTM D 5163-08. Any areas of coating discoloration or areas where corrosion hasformed under the coating system are documented and evaluated.Detection of Aging Effects (Element 4)The South Texas Project (STP) petiedieally conducts condition assessments of ServiceLevel 1 coatings inside containment during every refueling outage, as specified in ASTMD 5163-08. as part of the ASME= Xl, Subseton1. IVVE, program and theS.tructu.res Mo-nitor Program A at int.rval nOt exceeding five years. Additionalinspections may be necessary depending on condition assessment results. Vis-uali nspection of coatings in containment is intended to characterize the cond-ition of thcoating systems. 'n some8 cases, a comnplete inspection is not possible due toinaccessibility. ForF these cases, the coating systems are characterized based On aninpeton of coatinlg systems that are reaSonably accessible o tr- b-aed- 9n arpeentative sample If" loaized areas. of degraded coatings are identified, thoseareas a~reR eigaluate~d aind scnheduled for repair/replacement, as necessary. The perioicondition assessmen8ts, and the resulting repair/eplacement actiVities, assure that thamount Of SerVOce Level 1 coatings Which mnay be suGsceptible to detachment fromthsubstrate during a leGs of coolant accident design basis eVent i6 m*inimized.The Coatings Engineer in charge of the safety-related coatings pro-gram meets thequalification criteria for a Nuclear Coatings Specialist in accordance with ASTMD 7108-05. The Coating Planner is responsible for planning all coating activities,providing technical support to the applicator, and conducting assessment inspectionsand physical tests when directed by the Nuclear Coating Specialist. The CoatingPlanner meets the qualification criteria for a Nuclear Coatings Specialist in accordancewith ASTM D 7108-05, is a NACE Certified Inspector, and is trained in the applicablereferenced standards of Guide D 5498. These qualifications are as specified in ASTM D
 
==Enclosure==
2NOC-AE-12002797Page 58 of 635163-08.The Coating Inspector is certified as a NACE Level II Coating Inspector inaccordance with ASTM D 5498. These qualifications are as specified in ASTM D 5163-08.The coatings condition assessment includes a visual examination of all accessibleService Level 1 coatings inside containment, including areas near sumps associatedwith the emergency core cooling system. Thorough visual inspections are conducted toidentify and evaluate all accessible areas of degraded coatings, as specified in ASTM D5163-08, Section 10.1. Location maps and checklists are used to identify the areas tobe inspected and to document the inspection results. The coatings conditionassessment inspectors have available to them the necessary tools to conduct athorough inspection of accessible Service Level 1 coatings in containment, consistentwith the recommendations in ASTM D 5163-08, Section 10.5.Monitoring and Trending (Element 5)Prior to performing the inspection, the inspector reviews the two previous coatingcondition assessment reports. The inspection reports prioritize repair areas as eitherneeding repair during the same outage or as pstpon, d to future outage,, needingrepair during the next available outage, or monitored and re-evaluated in the nextavailable outage. These monitoring and trending activities are as specified in ASTM D5163-08.The containment plate se1- s part of the ASI-E SecGtiRn XI, SubsetinIWE inspection program. The resu-lts Of this inspection are reviewed to assist iRidentifYing areas of degraded Or damaged coating.Acceptance Criteria (Element 6)As specified in ASTM D 5163-08, paragraph 11, Ppotentially defective coating surfacesidentified during the course of an inspection are documented, their severity is evaluated,and corrective actions are taken to ensure there is no loss of intended functionsbetween the inspections. Defective or deficient coating surfaces are prioritized as eitherneeding repair during the same outage or as to futur outages, needingrepair during the next available outage, or monitored and re-evaluated in the nextavailable outage. The evaluation covers blistering, cracking, flaking, peeling, de-lamination, and rusting as specified below. These acceptance criteria are consistentwith, or more conservative than, the acceptance criteria specified in ASTM D 5163-08,subparagraphs 10.2, 10.3, and 10.4.Blistering-Blistering of any size is a reiectable condition. Compare any blisteringfou nd te the 19I0MWORqn [)dntGFmnl pI.,ndand Of Getnp-,fn rdpf9GSnRd 8Ode -Am An~pr prp niraml ,nRn If. h-ih laR- lR-, m VI Ia-I nV VIha v anm9 OF; thaeln r Ica V VIn Photomlhaem sre raF,-r- ei-i. -;n;R a ant 9 nn nhafnn r, nh Da R I f h leatrari 13nr 'ra4Vaw.-m
 
==Enclosure==
2NOC-AE-12002797Page 59 of 63Cracking- Cracking of any size is a relectable condition. All cracks under 30 mils inwidth are documented and repaired in accordance with plant procedures. Cracksexceeding 30 mils in width and all cracks associated with delamination are evaluatedunder the site corrective action program. Crncking, may be limited to thoe layer otfcotngo oxtondl through to tho substrate. Measuo th lngth o th crac orifextensiVe cracking haso occurred, mneasure the rsiOze of the Area affecnted. Determineifthecackn sioae or is part of a pattern. Record measuremenRts- and describecrack depth and pattern On the inspection report. Photograph the are~a affected.Flaking/Peeling/De-lamination- Flaking/peeling/de-lamination of any size is areiectable condition. All flaking/peeling/de-lamination is documented and repaired inaccordance with plant procedures. If the sum total of the repair area exceeds 25percent of that item's total painted area or if each individual repair area exceeds 30.rnuJ~rA. thE. n~nnditinn nn ..n~rntA. fnrmMlneasura th a nrei 4 Siz i'o f the A qan e G- nAratwR-Q an ero a md Rotek ntfrfarmned ('..ra. I,l , ta t,. a if, v iflim ,,,,a ,, ,a ap ,, pn i, ,a ha ,,,,,ame ,,ha r ,-.. upeeled aprop Note all nahsepamattiiami *RGallR miGe lattin-A of. failu re .a~thim the atiefilm , whethr the ,ra 66 G-hpim,, ar pahegix;,, eG., OR th0 inae.fhem range4rt amAhutinwp fhita CmarAisn wsffaete i dRusting- Comparison with pictorial standards are Performed by individuals trainedin applicable referenced standards of Guide D5498 on an as-needed basis asdetermined by the Nuclear Coatings Specialist. The source and extent of rusting isevaluated during the visual examination by the Nuclear Coatings Specialist.Gonnam a the, 0ie4,rial eM &,ardp4 Ant ar,,m, the Ann,8 Of, FU ,imn. Tni t-AntreFnuma thgear iron-m-t q-f ri mefim (thkat *je ip 4 ,anaeam 6 aoR ,eau ed by, em ,fmnnelpio Er r ic. it a fapilure Of the ,-Gea;*m allnGAimn tha el iho b leltepta *e iIu ) Ohofnranhthe nffar.4gA arean mad rae-.e.. obep~eAfn ARm men the imP me~ia e mIf no defects are found, mark "Coating Intact, No Defects" on the inspGction reportcoating condition assessment report form.If portions of the coating cannot be inspected, note the specific areas on the hfspeG.iGR-epGe coating condition assessment report form, along with the reason why theinspection cannot be conducted.Written or photographic documentation, or both, of coating inspection areas, failures,and defects shall be made and the pro-ess of douetto s-tand-ard-ized by the facilitygwRef peatF are included in the final coating condition assessment report.
 
==Enclosure==
2NOC-AE-12002797Page 60 of 63For coating surfaces determined to be suspect, defective, or deficient, destructive/non-destructive tests are performed by individuals trained in applicable referenced standardsof Guide D5498 on an as-needed basis as determined by the Nuclear CoatingsSpecialist. "k,"0r"., t9*64.6, h em di ; An, frlm th, e c.. and ,ad ,,ha,-,. may be performedap -a xci n oAa fa ml-9 Afar4,, pa ittemrp mi, ay baen haAF~edCorrective Actions (Element 7)STP site Quality Assurance (QA) procedures, review and approval process, andadministrative controls are implemented in accordance with the requirements of 10 CFR50 Appendix B and are acceptable in addressing corrective actions. The QA programincludes elements of corrective action, and is applicable to the safety-related andnonsafety-related systems, structures and components that are subject to agingmanagement review.Confirmation Process (Element 8)STP site QA procedures, review and approval process, and administrative controls areimplemented in accordance with the requirements of 10 CFR 50 Appendix B and areacceptable in addressing confirmation processes and administrative controls. TheQAprogram includes elements of corrective action, and is applicable to the safety-relatedand nonsafety-related systems, structures and components that are subject to agingmanagement review.Administrative Controls (Element 9)STP site QA procedures, review and approval process, and administrative controls areimplemented in accordance with the requirements of 10 CFR 50 Appendix B and areacceptable in addressing confirmation processes and administrative controls. The QAprogram includes elements of corrective action, and is applicable to the safety-relatedand nonsafety-related systems, structures and components that are subject to agingmanagement review.Operating Experience (Element 10)The South Texas Project conducts condition assessments of Service Level 1 coatingsinside containment during every refueling outage. Service Level 1 coatings areinspected during Coating Condition Assessment walkdowns, IWE inspections,Structures Monitoring Program inspections, and through STP's Condition ReportingProcess for identification and timely correction of an existing degraded coatingcondition. A review of Service Level 1 Coatings inspection and repair documentationshows that coating failures identified in Unit 1 and Unit 2 Reactor Containment Buildinghave not been significant. Historically, Service Level 1 coating failures include:mechanical damage, minor isolated cracking measuring less than 30 mils in width, andminor surface rusting. Peeling, blistering, and delamination of Service Level 1 coatingsthat have the potential to block sumps and strainers have not been reported.
 
==Enclosure==
2NOC-AE-12002797Page 61 of 63In 1992, cracks were identified in the concrete coating on the Unit 1 RCB knockout blockwall. The coating degradation was characterized as a minor crack less than 30 mils inwidth, not associated with delamination. The degraded coatings were repaired inaccordance with the safety-related coatings specification.In April, 2000, minor surface corrosion on the Unit 2 liner plate at the interface of theliner plate and concrete basemat was identified through the Condition ReportingProcess. Coating degradation is characterized as minor rusting. Repairs to degradedcoatings were made in accordance with the safety-related coating specification.In May 2000, an indication approximately 4" x 8" on the Unit 1 containment liner platewas identified near the reactor vessel head lift rig. Engineering investiqated anddetermined that the outer coating was removed with the primed surface below exposedwith no signs of corrosion or further coating deterioration noted. The condition wasfound acceptable as-is. The indication was re-evaluated in 1RE16 during the nextCoatings Condition Assessment Walkdown. The indication was identified to beapproximately the same size and color as was identified in May 2000. The indicationshows no signs of corrosion and no streaks of rust on the liner plate below. The size ofthe indication or its condition has not changed since May 2000: however, the indicationwill be monitored and re-evaluated during the next outage.In November, 2009, surface corrosion on a hanger support was identified in Unit 1 duringthe Coatings Condition Assessment Walkdown. The coatings degradation wascharacterized as minor surface rusting due to condensation. Repairs to degraded coatingswere made in accordance with the safety-related coatings specification.STP has implemented controls for the procurement, application, and maintenance ofService Level 1 protective coatings used inside containment in a manner consistent withthe licensing basis and regulatory requirements applicable to the South Texas Proeect.The requirements of 10 CFR 50 Appendix B are implemented through specification ofappropriate technical and quality requirements for the Service Level 1 coatings programwhich includes onqoinq maintenance activities.Service Level 1 coatings have been tested, selected, and applied to assure that they willwithstand nuclear, chemical, and physical conditions of a Design Basis Accident. Thehistorical Service Level 1 coating performance provides reasonable assurance thatcoating aging effects are managed such that the operability of the Emergency CoreCooling System and the Containment Spray System will not be impaired due to ServiceLevel 1 coating failure.S-TP has imleenedntrols for the procureme~nt, application, and maintenance otSeRvice L9Vel 1 protectiVe coatings used inside contain~ment in a; manner that is6consistent with the licensing basic and regulator,' requir8emets applicable to ST-P. TherequiF8rements of 10Q CFR 50 Appendix BR are- implemen~ted through specification ofapproapriate tocnhnicral and qualit, rqrents for theq Sepr-Ic Level 1 coatings programwhich includes ongoing maintenance-&#xfd; actdivfitwios.For -T-P, Servic LevI I coatings have been tested, selected, and applied to assure9'W"I[I WAIIRS12lR~~ld RUGleaF, GhGFneGal, and phyri
 
==Enclosure==
2NOC-AE-12002797Page 62 of 63A,,ident as required by Nucleal r Ge"nso-,n -Reulatr. Guide ( 'G- 1.54-Rev. 0, and ANSI N101.2 1972. Coatings used in0ide the containmet hAVe beene-stablis.h-d- as_ safety related, thus imposing the quality assurance requirem~ents ofAneend-ix B to 10 GCFIR Part 50.The South Texas Project periodically conducts condition arsessments of Service Level4 coatings inside containment. Coating condition assessmentS are conducted as part o9the structures monitoriRg program. The moni-tring- .. over.s thebas-.eline inspection and subsequent inspections that are condu-cted at intrvals notexceeding Wie years.EnhancementsPrior to the period of extended operation, the following enhancements will beimplemented in the following program elements:Parameters Monitored or Inspected -Element 3Procedures will be enhanced to specify parameters monitored or inspected to include:any visible defects, such as blistering, cracking, flaking, peeling, rusting, and physicaldamage, as specified in ASTM D 5163-08.Detection of Aging Effects -Element 4Procedures will be enhanced to specify inspection frequencies, personnel qualifications,inspection plans, inspection methods, and inspection equipment that meet therequirements of ASTM D 5163-08.Monitoring and Trending -Element 5Procedures will be enhanced to specify a pre-inspection review of the previous twomonitoring reports and, based on inspection report results, prioritize repair areas aseither needing repair during the same outage, needing repair during the next availableoutage, or monitored and re-evaluated in next available outaqe.Acceptance Criteria -Element 6Procedures will be enhanced to include a standardized coating condition assessmentreport form that will include the identification of coatings found intact with no defectsidentified, and the identification of coatings that were not inspected and the reason whythe inspection cannot be conducted.Procedures will be enhanced to include a standardized coating condition assessmentreport that will include written and/or photographic documentation of coating inspectionareas, failures, and defects.Procedures will be enhanced to specify that destructive/non-destructive tests areperformed by individuals trained in applicable referenced standards of Guide D5498.onan as-needed basis as determined by the Nuclear Coatingis Specialist.
 
==Enclosure==
2NOC-AE-12002797Page 63 of 63ConclusionThe continued implementation of the Protective Coating Monitoring and MaintenanceProgram, following enhancements, provides reasonable assurance that aging effectswill be managed such that the systems and components within the scope of thisprogram will continue to perform their intended functions consistent with the currentlicensing basis for the period of extended operation.
 
==Enclosure==
3NOC-AE-12002797Enclosure 3Regulatory Commitments
 
==Enclosure==
3NOC-AE-12002797Page 1 of 2A4 LICENCE RENEWAL COMMITMENTSTable A4-1 identifies proposed actions committed to by STPNOC for STP Units 1 and 2 in its License Renewal Application. Theseand other actions are proposed regulatory commitments. This list will be revised, as necessary, in subsequent amendments toreflect changes resulting from NRC questions and STPNOC responses. STPNOC will utilize the STP commitment trackingsystem to track regulatory commitments. The Condition Report (CR) number in the Implementation Schedule column of the tableis for STPNOC tracking purposes and is not part of the amended LRA.Table A4-1 License Renewal CommitmentsItem # Commitment LRA ImplementationSection Schedule27 Implement the PWR Reactor Internals program as described in LRA Section B2.1.35. B2.1.35 Within 24 monthsafter the issuance ofEPRI 10165631022863, PWRInternals Inspectionand EvaluationGuideline MRP-227-ACR 10-2360240 Enhance the Protective Coating Monitoring and Maintenance Program procedures to specify: B2.1.39 Prior to the period of" Parameters monitored or inspected include any visible defects, such as blistering, extended operationcracking, flaking., peelinq, rusting, and physical damage, as specified in ASTM D 5163-08. CR 12-8955* Inspection freguencies, personnel gualifications, inspection plans, inspection methods,and inspection equipment that meet the requirements of ASTM D 5163-08." A pre-inspection review is performed of the previous two monitoring reports and, basedon inspection report results, prioritize repair areas as either needing repair during thesame outage, needing repair during the next available outage, or re-evaluated in nextavailable outage." A standardized coating condition assessment report form that will include theidentification of coatings found intact with no defects identified, and the identification of
 
==Enclosure==
3NOC-AE-12002797Page 2 of 2coatings that were not inspected and the reason why the inspection cannot beconducted." A standardized coating condition assessment report that will include written and/orphotographic documentation of coating inspection areas, failures, and defects.* Destructive/non-destructive tests are performed by individuals trained in the applicablereferenced standards of Guide D5498 on an as-needed basis as determined by theNuclear Coatings Specialist.41 Enhance the STP Operating Experience Program and Corrective Action Program for managing A1.1 December 31, 2014the effects of aging to:* Add License Renewal Interim Staff Guidance and revisions to NUREG-1801, "Generic CR 12-8990Aging Lessons Learned (GALL) Report", to the Operating Experience Program (OEP)procedure as sources of information within the scope of this program,* Revise the OEP procedure to include "aging effects" to the list of characteristics fordetermining applicability of an OE document that may require further evaluation. Ascreened-in evaluation should consider (a) systems, structures, or components, (b)materials, (c) environments, (d) aging effects, (e) aging mechanisms, and (f) agingmanagement programs,* Review the Corrective Action Program Event Codes to determine if additional codes areneeded to ensure age-related degradation effects are identified,* Perform a training "needs analysis" for those plant personnel who screen, assign,evaluate, and submit plant-specific and industry operating experience information forage-related effects.* Revise the OEP procedure to provide criteria for reporting plant-specific operatingexperience of age-related degradation.
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