ML13190A276

Sequoyah, Units 1 and 2, Response to NRC Request for Additional Information Regarding the Review of the License Renewal Application, Set 4

ML13190A276
Person / Time
Site:	Sequoyah
Issue date:	07/01/2013
From:	Shea J W Tennessee Valley Authority
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
TAC MF0481, TAC MF0482
Download: ML13190A276 (99)

Text

Tennessee Valley Authority, 1101 Market Street, Chattanooga, Tennessee 37402July 1, 201310 CFR Part 54ATTN: Document Control DeskU.S. Nuclear Regulatory CommissionWashington, D.C. 20555-0001Sequoyah Nuclear Plant, Units 1 and 2Facility Operating License Nos. DPR-77 and DPR-79NRC Docket Nos. 50-327 and 50-328Subject: Response to NRC Request for Additional Information Regardingthe Review of the Sequoyah Nuclear Plant, Units I and 2, License RenewalApplication, Set 4 (TAC Nos. MF0481 and MF0482)References: 1. TVA Letter to NRC, "Sequoyah Nuclear Plant, Units 1 and 2 LicenseRenewal," dated January 7, 2013 (ADAMS Accession No. ML13024A004)2. NRC Letter to TVA, "Requests for Additional Information for the Review of theSequoyah Nuclear Plant, Units 1 and 2, License Renewal Application," datedMay 31, 2013 (ADAMS Accession No. ML13128A519)By letter dated January 7, 2013 (Reference 1), Tennessee Valley Authority (WVA) submitted anapplication to the Nuclear Regulatory Commission (NRC) to renew the operating license for theSequoyah Nuclear Plant, Units 1 and 2. The request would extend the license for an additional20 years beyond the current expiration date. By letter dated May 31, 2013 (Reference 2), theNRC forwarded a request for additional information (RAI). The required date for the responseis within 30 days of the date stated in the RAI, i.e., no later than July 1,2013.Enclosure 1 to this letter provides TVA's response to the Reference 2 RAI.Enclosure 2 is an updated listing of the regulatory commitments for license renewal.Printed on recycled paper U.S. Nuclear Regulatory CommissionPage 2July 1, 2013Consistent with the standards set forth in 10 CFR 50.92(c), TVA has determined that theadditional information, as provided in this letter, does not affect the no significant hazardsconsiderations associated with the proposed application previously provided in Reference 1.Please address any questions regarding this submittal to Henry Lee at (423) 843-4104.I declare under penalty of perjury that the foregoing is true and correct.Executed on this 1st day of July 2013.ePresident, Nuclear LicensingEnclosures:1. TVA Responses to NRC Request for Additional Information2. Regulatory Commitment List, Revision 3cc (Enclosures):NRC Regional Administrator- Region IINRC Senior Resident Inspector -Sequoyah Nuclear Plant ENCLOSURE ITennessee Valley AuthoritySequoyah Nuclear Plant, Units 1 and 2 License RenewalTVA Responses to NRC Request for Additional InformationRAI B.1.2-1Background:License renewal application (LRA) Sections A. 1.2 and B. 1.2 state that bolting inspectionactivities include those required by ASME Section X1 for ASME Code Class 1, 2, and 3pressure-retaining components. For non-ASME Code class bolting, these LRA sections statethat periodic system walkdowns and inspections occur at least once per refueling cycle.The "detection of aging effects" program element of Generic Aging Lessons Learned (GALL)Report aging management program (AMP) XI. M18, "Bolting Integrity, " recommends thatperiodic system walkdowns and inspections to detect leakage be performed at least once perrefueling cycle for both ASME Code class bolting and non-ASME Code class bolting. The staffnoted that ASME Code Class 2 and 3 pressure-retaining components are required to beinspected for leakage every inspection period, or 40 months, under the ASME Section Xl,Tables IWC-2500-1 and IWD-2500-1.Issue:Given that ASME Code Class 2 and 3 pressure-retaining components will not be inspected forleakage every refueling outage, it is not clear to the staff how age-related degradation of closurebolting will be detected and corrected prior to the leakage becoming excessive.Request:State why inspections performed every ASME Section X1 inspection period, rather than at leastonce per refueling outage, will be adequate to detect leakage from ASME Code Class 2 and 3bolted connections.RAI B.1.2-1 RESPONSELicense renewal application (LRA) Sections A. 1.2 and B.1.2 were inadvertently worded toindicate that inspections are performed to detect leakage of ASME Class 1, 2, and 3 boltingbased on the ASME Section Xl inspection period rather than GALL XI.M18, which recommendsa frequency of at least once per refueling outage.The change to LRA Section A.1.2 (first paragraph) follows, with additions underlined anddeletions lined through."The Bolting Integrity Program manages loss of preload, cracking, and loss of material forclosure bolting for safety-related and nonsafety-related pressure-retaining components usingpreventive and inspection activities. This program does not include the reactor head closurestuds or structural bolting. Preventive measures include material selection (e.g., use ofmaterials with an actual yield strength of less than 150 kilo-pounds per square inch [ksi]),lubricant selection (e.g., restricting the use of molybdenum disulfide), applying theappropriate preload (torque), and checking for uniformity of gasket compression whereappropriate to preclude loss of preload, loss of material, and cracking. This programE1-1 of 79 supplements the linspection activities *Rrlude thee required by ASME Section X1 for ASMEClass 1, 2 and 3 bolting pre.sure retainRi9 components. For ASME Code Class 1, 2, and 3,and non-ASME Code class bolts, periodic system walkdowns and inspection (at least onceper refueling cycle) ensure identification of indications of loss of preload (leakage), cracking,and loss of material before leakage becomes excessive. With the exception of one reactorvessel closure stud, which is managed by the Reactor Head Closure Studs Program (SectionA.1.33), no high-strength bolting has been identified at SQN. Identified leaking boltedconnections will be monitored at an increased frequency in accordance with the correctiveaction process. Applicable industry standards and guidance documents, including NUREG-1339, EPRI NP-5769, and EPRI TR- 104213, are used to delineate the program."The change to LRA Section B.1.2 program description follows, with additions underlined anddeletions lined through."The Bolting Integrity Program manages loss of preload, cracking, and loss of material forclosure bolting for safety-related and nonsafety-related pressure-retaining components usingpreventive and inspection activities. This program does not include the reactor head closurestuds or structural bolting. Preventive measures include material selection (e.g., use ofmaterials with an actual yield strength of less than 150 ksi), lubricant selection (e.g.,restricting the use of molybdenum disulfide), applying the appropriate preload (torque), andchecking for uniformity of gasket compression where appropriate to preclude loss of preload,loss of material, and cracking. This program supplements the linspection activities igthese-required by ASME Section Xl for ASME Class 1, 2 and 3 bolting pressure retainingGGR*peRents. For ASME Code Class 1, 2, and 3, and non-ASME Code class bolts, periodicsystem walkdowns and inspections (at least once per refueling cycle) ensure identification ofindications of loss of preload (leakage), cracking, and loss of material before leakagebecomes excessive. With the exception of one reactor vessel closure stud, which ismanaged by the Reactor Head Closure Studs Program (Section B.1.33), no high-strengthbolting has been identified at SQN. Identified leaking bolted connections will be monitored atan increased frequency in accordance with the corrective action process. Applicable industrystandards and guidance documents, including NUREG-1 339, EPRI NP-5769, and EPRI TR-104213, are used to delineate the program."RAI B.1.2-2Background:LRA Tables 3.3.2-11 and 3.3.2-14 include bolting items in the ERCW and spent fuel pit coolingsystems that are exposed externally to water and managed by the Bolting Integrity Program.The "detection of aging effects" program element of GALL Report AMP XI.M18, "BoltingIntegrity," recommends periodic system walkdowns and inspections of ASME Code class boltingand non-ASME Code class bolting to detect leakage that is indicative of age-related degradationof closure bolting.Issue:It is not clear to the staff how degradation of bolted connections that are submerged will bedetected.E1-2 of 79 Request:1. Describe the configuration of the submerged bolting in the essential raw cooling waterand spent fuel pit cooling systems.2. Describe the aging management activities (method, frequency, etc.) for the submergedbolting and state how these activities are capable of detecting bolting loss of materialand loss of preloadRAI B.1.2-2 RESPONSE1. Submerged bolting configuration for SQN Units 1 and 2The essential raw cooling water (ERCW) system in-scope submerged bolting consists ofbolting that connects the multiple stages of the submerged portion of the vertical pumps.The spent fuel pit cooling system submerged bolting is bolting associated with the fueltransfer tube's normally closed isolation valve. This valve is bolted to the end of the fueltransfer tube within and at the bottom of the fuel transfer canal. This isolation valve issubmerged during normal operations. At the other end of the fuel transfer tube is a boltedblind flange, which is removed and installed with the refueling cavity dry, so that the blindflange fasteners are never in a submerged environment. This arrangement is duplicated forboth units.2. Aging management activities for Unit 1 and Unit 2Normally inaccessible submerged bolted connections in the ERCW system are visuallyinspected for degradation when they are made accessible during associated componentmaintenance activities. Visual inspection methods are effective in detecting the applicableaging effects and the frequency of inspection is adequate to prevent significant age-relateddegradation. The referenced ERCW system in-scope vertical pumps are tested quarterly,and removed from the water and rebuilt when trending of pump parameters, such aspressure, indicates that refurbishment is necessary. During refurbishment, the ERCW pumpbolting is inspected for loss of material and replaced as necessary.The spent fuel pit cooling system's submerged bolting is inspected to detect loss of material,consistent with NUREG-1 801 AMP XI.M18, at least once per refueling outage. The fueltransfer tube's normally closed isolation valve and bolting are inspected prior to eachrefueling outage as part of the pre-outage fuel handling equipment inspection with the fueltransfer canal drained. The bolting on the fuel transfer canal blind flange inside containmentis never submerged in borated water. The bolting is inspected whenever the blind flange isremoved at the beginning of an outage and when it is reinstalled at the conclusion of anoutage.To prevent loss of preload for the submerged bolting in the ERCW and the spent fuel pitcooling system, preventive actions consistent with NUREG-1 801 AMP XI.M18 includeproper selection of bolting material, the use of appropriate lubricants and sealants inaccordance with the guidelines of EPRI NP-5769 and NUREG-1 339, consideration of actualyield strength when procuring bolting material, proper torquing of bolts, checking foruniformity of the gasket compression after assembly, and application of an appropriatepreload based on guidance in EPRI documents, manufacturer recommendations, orengineering evaluation.Operating experience (OE) shows that the Bolting Integrity Program has been effective inmanaging loss of material and preventing loss of preload of bolted connections. Therefore,E1-3 of 79 continued implementation of the program with the identified enhancements providesreasonable assurance that the effects of aging will be managed so that componentscrediting this program can perform their intended function consistent with the currentlicensing basis during the period of extended operation (PEO).To clarify the above response, the changes to Commitment 2.C, LRA Sections B. 1.2 andA.1.2, Bolting Integrity, follows with additions underlined.B.1.2 BOLTING INTEGRITYProgram Description"The Bolting Integrity Program manages loss of preload, cracking, and loss of materialfor closure bolting for safety-related and nonsafety-related pressure-retainingcomponents using preventive and inspection activities. This program does not includethe reactor head closure studs or structural bolting. Preventive measures includematerial selection (e.g., use of materials with an actual yield strength of less than 150ksi), lubricant selection (e.g., restricting the use of molybdenum disulfide), applying theappropriate preload (torque), and checking for uniformity of gasket compression whereappropriate to preclude loss of preload, loss of material, and cracking. Inspectionactivities include those required by ASME Section Xl for ASME Class 1, 2 and 3pressure-retaining components. For non-ASME Code class bolts, periodic systemwalkdowns and inspections (at least once per refueling cycle) ensure identification of.indications of loss of preload (leakage), cracking, and loss of material before leakagebecomes excessive. Normally inaccessible submerged bolted connections in the ERCWsystem are visually inspected for degradation when they are made accessible duringassociated component maintenance activities. Visual inspection methods are effective indetecting the applicable aging effects and the frequency of inspection is adequate toprevent significant age-related degradation. With the exception of one reactor vesselclosure stud, which is managed by the Reactor Head Closure Studs Program (SectionB.1.33), no high-strength bolting has been identified at SQN. Identified leaking boltedconnections will be monitored at an increased frequency in accordance with thecorrective action process. Applicable industry standards and guidance documents,including NUREG-1 339, EPRI NP-5769, and EPRI TR-1 04213, are used to delineate theprogram."E1-4 of 79 EnhancementsThe following enhancements will be implemented prior to the period of extended operation.Element Affected Enhancement2. Preventive Actions Revise Bolting Integrity Program procedures toensure the actual yield strength of replacementor newly procured bolts will be less than 150 ksi.4. Detection of Aging Effects Revise Boltinq Inte-grity Program procedures tospecify a corrosion inspection and a check-off forthe transfer canal isolation valve flange bolts.7. Corrective Actions Revise Bolting Integrity Program procedures toinclude the additional guidance andrecommendations of EPRI NP-5769 forreplacement of ASME pressure-retaining boltsand the guidance provided in EPRI TR-104213for the replacement of other pressure-retainingbolts.A.1.2 Bolting Integrity Program"The Bolting Integrity Program manages loss-of preload, cracking, and loss of materialfor closure bolting for safety-related and nonsafety-related pressure-retainingcomponents using preventive and inspection activities. This program does not includethe reactor head closure studs or structural bolting. Preventive measures includematerial selection (e.g., use of materials with an actual yield strength of less than 150kilo-pounds per square inch [ksi]), lubricant selection (e.g., restricting the use ofmolybdenum disulfide), applying the appropriate preload (torque), and checking foruniformity of gasket compression where appropriate to preclude loss of preload, loss ofmaterial, and cracking. Inspection activities include those required by ASME Section XIfor ASME Class 1, 2 and 3 pressure-retaining components. For non-ASME Code classbolts, periodic system walkdowns and inspection (at least once per refueling cycle)ensure identification of indications of loss of preload (leakage), cracking, and loss ofmaterial before leakage becomes excessive. Normally inaccessible submerged boltedconnections in the ERCW system are visually inspected for degradation when they aremade accessible during associated component maintenance activities. Visual inspectionmethods are effective in detecting the applicable aging effects and the frequency ofinspection is adequate to prevent significant age-related degradation. With the exceptionof one reactor vessel closure stud, which is managed by the Reactor Head ClosureStuds Program (Section A. 1.33), no high-strength bolting has been identified at SQN.Identified leaking bolted connections will be monitored at an increased frequency inaccordance with the corrective action process. Applicable industry standards andguidance documents, including NUREG-1339, EPRI NP-5769, and EPRI TR-104213,are used to delineate the program.E1-5 of 79 The Bolting Integrity Program will be enhanced as follows." Revise Bolting Integrity Program procedures to ensure the actual yield strength ofreplacement or newly procured bolts will be less than 150 ksi.* Revise Bolting Integrity Program procedures to include the additional guidance andrecommendations of EPRI NP-5769 for replacement of ASME pressure-retainingbolts and the guidance provided in EPRI TR-104213 for the replacement of otherpressure-retaining bolts." Revise Bolting Integrity Program procedures to specify a corrosion inspection and acheck-off for the transfer tube isolation valve flange bolts."Commitment changesCommitment 2.C is added with additions underlined."Revise Bolting Integqrity Program procedures to specify a corrosion inspection and acheck-off for the transfer tube isolation valve flange bolts."RAI B.1.6-1Back ground:Title 10 of the Code of Federal Regulations (CFR) 50.55a(b)(2)(ix), "Examination of metalcontainments and the liners of concrete containments, "references ASME Code Section X1,Subsection IWE and specifies additional inspection requirements for inaccessible areas. Itstates that the licensee is to evaluate the acceptability of inaccessible areas when conditionsexist in accessible areas that could indicate the presence of or result in degradation to suchinaccessible areas. ASME Code Subsection IWE-1240 discusses surface areas requiringaugmented examinations that include concrete-to-steel shell or liner interfaces, embedmentzones, and leak chase channels. In addition, the applicant stated in IWE AMP B. 1.6, that, "SQNhas augmented the IWE program to emphasize the inspection of the steel shell at the concretefloor embedment and inaccessible portions (behind mechanical equipment) of the shell."Issue:1. The carbon steel pressure test piping that connect to the embedded leak chase channelsin the containment base slab concrete were found to be corroded. Some of the pipeshad through wall corrosion. The applicant has issued a design change notice (DCN) thatallows, as an option, permanent sealing the pressure test piping by a steel plate afterremoving a portion of the piping. It is not clear how this change will prevent furthercorrosion of the pressure test piping, containment liner plate, including the full penetrationwelds in the base slab, and associated embedded leak chase channels.2. During the audit, the staff reviewed photographs that show evidence of corrosion in thesteel containment shell at the moisture barrier due to water leakage. The moisturebarrier had been found to be degraded in certain areas. The water may have also leakedbeyond past the degraded moisture barrier into the inaccessible area of steelcontainment embedded in the concrete resulting in corrosion of the liner plate.E1-6 of 79 Request:Discuss the actions the applicant has initiated or planned to ensure that the steel containmentpressure boundary integrity will be maintained during the period of extended operation relativeto the issues noted above. The response should include:1. Details of any periodic tests to be performed on the liner plate and leak chase channel.2. Plans, if any, for an ultrasonic test (UT) examination of the steel containment below themoisture barrier from the annulus area, exposure of a portion of the embedded liner plateand rebars in concrete to determine the presence and extent of corrosion.RAI B.1.6-1 RESPONSE1. The actions to ensure the steel containment vessel (SCV) pressure boundary integritywill be maintained during the PEO are detailed in LRA Table 3.5.2-1 and described inLRA Appendices B.1.6 and B.1.7. SQN plans to continue managing aging effects of theSCV and its attachments by conducting periodic inspections and testing in accordancewith the Containment Leak Rate (10 CFR Part 50, Appendix J) and ContainmentInservice Inspection -IWE programs. Details regarding the pressure test piping and themoisture barrier are provided as follows.The leak test (leak chase) channel is a channel enclosing the SCV bottom steel linerplate welds on the containment side, which was designed to allow pressurization of thewelds for post-installation pressure testing. The leak test channel and associated leaktest connection are shown in Exhibit A "Typical Test Connection Detail" below.. Thepotential paths for moisture into the leak test channel are through the 3/4 inch diameter(dia) test connection tubing directly into the channel or through the annulus between the2-inch dia pipe sleeve and the 3/4 inch dia test connection tubing and then entering thechannel through a flaw, if one exists. SQN plans to modify the configuration of the testconnection access boxes to prevent moisture from entering the %-inch dia testconnection tubing or the annulus between the 3/4-inch tubing and the 2-inch dia pipesleeve that encloses the tubing, thus preventing corrosion of the pressure test tubing,containment liner plate, including the full penetration welds in the base slab, and theassociated embedded leak test channels. The design modification requires cutting the3/4 inch dia test connection tubing at the bottom of the access box and welding a steelcover plate over the opening as shown in Exhibit A below. This modification has alreadybeen installed in SQN Unit 2, and plans are in place to install a similar modification inSQN Unit 1. Prior to installing this design modification in SQN Unit 2, remote visualexaminations were performed, to the extent possible, inside the leak test channels byinserting a borescope video probe into the test connection tubing. Similar inspectionswill also be performed prior to installation of the modification on Unit 1. Based on thesatisfactory examination results to date, following installation of the design modificationSQN has no plans to perform future visual examinations of the embedded SCV linerplate or embedded leak test channels.Examinations of the SCV moisture barrier sealant are performed in accordance withASME Section Xl, at the frequency specified in Table IWE-2500-1, as required by10 CFR 50.55a. Examinations will continue through the PEO. Past examinations haveidentified areas of disbonding between the moisture barrier sealant and the SCV. Foreach instance identified, additional examinations of the inaccessible portions of the SCVwere performed in accordance with 10 CFR 50.55 a(b)(2)(ix), by removing the moisturebarrier sealant to allow direct visual examination of the affected portion of the SCV.These direct visual examinations have identified minor degradation that was determinedE1-7 of 79 acceptable. These visual examinations did not identify corrosion extending into theinaccessible area of the SCV embedded in the concrete. SQN modified the SCVmoisture barrier sealant material to provide a more robust moisture seal with a strongerbond to the SCV surface.2. Based on past satisfactory examination results, SQN has no plans to perform ultrasonictest (UT) examination of the SCV below the moisture barrier from the annulus area orfrom inside the SCV. Furthermore, SQN has no plans to remove concrete inside theSCV or the annulus outside the SCV to expose a portion of the embedded SCV or rebarin the concrete for examination. However, if future examinations identify moistureintrusion below the moisture barrier sealant in the inaccessible area of SCV embeddedin concrete, one or both of these examination techniques may be necessary forcompliance with 10 CFR 50.55a(b)(2)(ix), and would be performed if necessary.EL 679'-9atEXHIBIT ATYPICAL TEST CONNECTION DETAILE1-8 of 79 Commitment changesCommitment 35 is added.TVA will modify the configuration of the SQN Unit 1 test connection access boxes toprevent moisture intrusion to the leak test channels. Prior to installinq this modification,TVA will perform remote visual examinations inside the leak test channels by inserting aborescope video probe through the test connection tubing.Commitment is to be implemented before the PEO for SQN Unit 1.RAI B.1.6-2Back-ground:LRA Section B. 1.6 states that the applicant's Inservice Inspection -IWE program, withenhancement, is consistent with the program described in NUREG-1801 (GALL Report),Section XI.S1, ASME Section Xl, Subsection IWE. GALL Report AMP XI.S1 "scope ofprogram, "program element includes examinations of Class MC, steel containment pressure-retaining components and their integral attachments, metallic shell and penetration liners ofClass CC concrete containments and their integral attachments, containment hatches andairlocks, containment moisture barriers, containment pressure-retaining bolting, and metalcontainment surface areas, including welds and base metal. 10 CFR 50.55a imposes inserviceinspection (ISI) requirements per ASME Code, Section X1, Subsection IWE, which in ArticleIWE-2412, has specific recommendations for examination of welds that are added to theInspection Program during an inspection interval.Issue:During steam generator replacement (SGR) for Sequoyah Nuclear Plants (SQN), Units I and 2in 2004 and 2012 respectively, the steel containments dome were cut and full penetration weldswere added. The LRA section B. 1.6, "Containment Inservice Inspection -IWE," states that in2011, the program was revised to change the scope of examinations performed on thecontainment vessel dome cut welds, based on operating experience. However, the details ofthe change are not identified in the AMP. It is not clear whether the change satisfies therequirements of IWE-2412 for welds added during an inspection interval.Request:1. Describe the details of the change in scope of the examinations performed and will continueto be performed on the containment vessel dome cut welds during the period of extendedoperation.2. The response should include the operating experience across the fleet that was used toimplement a change in the scope and whether this change meets the requirements of IWE-2412.E1-9 of 79 RAI B.1.6-2 RESPONSE1. As described in LRA Section B.1.6, the scope of the SQN Containment Inservice Inspection-IWE Program includes the SCV and its integral attachments. Following steam generatorreplacement (SGR) activities, the ASME Code Section Xl required visual examinationfrequency'for the newly installed welds was established in accordance with IWE-2412(b)(2)for new items or welds added to the inspection program during the second period of aninterval. Neither the scope nor the frequency of this ASME Code Section Xl required visualexamination has been revised. The SQN ASME Code Section Xl Subsection IWE programincludes ongoing visual inspection of the full penetration SCV dome cut weld during thePEO.In addition to the ASME Code Section Xl required visual examinations, SQN elected toperform augmented volumetric examinations at the location of the full penetration weldswhere the SCV domes were cut. This voluntary volumetric examination is not required bythe ASME Code and changes to this examination do not represent a change in scope to therequirements established under IWE-2412. IWE-2412 is not applicable to the examinationfrequency for this owner-elected examination.2. A similar owner-elected augmented examination plan was performed at Tennessee ValleyAuthority Watts Bar Nuclear Plant. The volumetric examinations are strictly voluntaryexaminations beyond those required by the ASME Code and do not constitute a change inscope to the requirements established under IWE-2412. IWE-2412 is not applicable to theexamination frequency for this owner-elected examination.RAI B.1.7-1Background:The SQN, Units I and 2, LRA Section B. 1.7 Containment Leak Rate AMP states that theapplicant has implemented Option B for the 10 CFR Part 50 Appendix J for leak rate testing(LRTs) and it is consistent with no exceptions or enhancements with the GALL Report, Revision2, AMP Xl. S4. The GALL Report AMP Xl. S4, "10 CFR Part 50, Appendix J," "parametersmonitored or inspected, " program element states that parameters to be monitored includeleakage rates through containment shells, liners, and associated welds.10 CFR Part 50, Appendix J rule requires containment leak rate tests to "assure that (a) leakagethrough these containments or systems and components penetrating these containments doesnot exceed allowable leakage rates specified in the technical specifications and (b) integrity ofthe containment structure is maintained during its service life."Issue:The applicant in Section B. 1.7, "Containment Leak Rate, "AMP in the LRA states that theContainment Leak Rate Program detects degradation of the containment shell and liner andcomponents that may compromise the containment pressure boundary. The AMP also statesthat the parameters monitored are leakage rates of the steel containment vessel and associatedwelds, penetrations, fittings, and other access openings. However, during the audit the staffnoted that the applicant has issued a DCN 23160 that allows permanent sealing of the pressuretest piping that is connected to leak chase channels embedded in the concrete base slab.These leak chase channels were originally provided to test the leak tightness of the containmentbase slab liner plate full penetration welds. It is not clear how the applicant plans to monitorleakage rate through containment base slab liner plate and associated welds during the futureEl-10 of 79 ILRTs as recommended in GALL Report AMP, "10 CFR 50, Appendix J, " with the pressure testpiping, that is connected to the leak chase channels embedded in the concrete base slab,permanently sealed.Request.Describe how the GALL Report AMP, "10 CFR 50, Appendix J" recommendations will be met orjustify alternatives to the LRTs to assure the integrity of containment base slab liner plate weldsis maintained during the period of extended operation.RAI B.1.7-1 RESPONSEThe Sequoyah Nuclear Plant (SQN) containment base slab liner plate welds will be exposed topeak accident pressure during performance of periodic containment integrated leak rate tests(CILRT) in accordance with 10 CFR Part 50, the Appendix J during the PEO. Relative to thedesign modification sealing the pressure test piping, the design allows the leak test channels tobe vented to the containment atmosphere during performance of the CILRT. This assures thatthe containment base slab liner plate welds are exposed to peak accident pressure during eachCILRT.A vent path to the containment atmosphere through the pressure test piping will be created priorto conduct of the CILRT. Following completion of the CILRT, the vent path will then be sealedto prevent moisture intrusion during plant operation.The changes to Commitment 34, and LRA Sections A.1.7 and B.1.7 follow, with additionsunderlined and deletions lined through.LRA APPENDIX A CHANGES'A.1.7 Containment Leak Rate ProgramAdd the following to the end of Section A.1.7."The Containment Leak Rate Pro-gram will be enhanced as follows.* Revise Containment Leak Rate Program procedures to require venting the SCV bottomliner plate weld leak test channels to the containment atmosphere prior to the CILRT andresealing the vent path after the CILRT to prevent moisture intrusion during plantoperation."The enhancement will be implemented prior to the period of extended operation."LRA APPENDIX B CHANGESB.1.7 Containment Leak Rate ProgramNUREG-1801 Consistency:"The Containment Leak Rate Program, with enhancement, is will be consistent with theprogram described in NUREG-1801,Section XI.S4, 10 CFR Part 50, Appendix J.EnhancementsNGReEl-11 of 79 The followinq enhancement will be implemented prior to the period of extended operation."Elements Affected Enhancements1. Scope of Program Revise Containment Leak Rate Programprocedures to require venting the SCVbottom liner plate weld leak test channels tothe containment atmosphere prior to theCILRT and resealing the vent path after theCILRT to prevent moisture intrusion duringplant operation.Commitment changesCommitment 34 is added with additions shown as underlines."Revise Containment Leak Rate Program procedures to require venting the SCV bottomliner plate weld leak test channels to the containment atmosphere prior to the CILRT andresealing the vent path after the CILRT to prevent moisture intrusion during plantoperation.Commitment is to be implemented before the PEO for both units."RAI B.1.7-2Backqround:The SQN, Units 1 and 2, LRA B. 1.7 Containment Leak Rate program states that the applicanthas implemented Option B for the 10 CFR Part 50 Appendix J for LRTs and is consistent withno exceptions or enhancements with the GALL Report, Revision 2, AMP Xl. S4. The GALLReport AMP Xl. S4, "10 CFR Part 50, Appendix J," "scope of program," program element statesthat "the scope of the containment LRT program includes all containment boundary pressureretaining components."10 CFR Part 50, Appendix J, rule requires containment LRTs to assure that (a) leakage throughthe components penetrating the containment does not exceed allowable leakage rates specifiedin the technical specifications or associated bases; and (b) periodic surveillance of reactorcontainment penetrations and isolation valves is performed so that proper maintenance andrepairs are made during the service life of the containment, and systems and componentspenetrating primary containment. 10 CFR Part 54.21 (a) rule requires all containment boundarypressure-retaining components to be age managed.Issue:SQN, Units 1 and 2, final safety analysis report (FSAR) and Supplement I of the original safetyevaluation report (SER), indicate that a number of penetrations and valves are excluded fromlocal LRTs (LLRTs). It is not clear how the applicant will manage the aging effects for anycomponents that are not included in "its scope of program, " program element.E1-12 of 79 Request:1. For those components (valves, penetrations, and other components) that have beenexcluded from the Containment Leak Rate program, identify how aging effects will bemanaged during the period of extended operation.2. Indicate which AMPs and/or aging management review (AMR) line items will be used tomanage the aging effects for each of the exempted/excluded components, orjustify whyan AMP and/or AMR line item is not necessary for the period of extended operation.RAI B.1.7-2 RESPONSEThe components listed in the table below are exempted from 10 CFR Part 50, Appendix J TypeB and C testing. The components listed do not meet the criteria of 10 CFR 50, Appendix J, fordesignation as containment isolation valves that are required to be Type C tested, although theyare classified as containment isolation valves per General Design Criterion 55 or 56. During thePEO, the effects of aging on those components that have been exempted/excluded from 10CFR Part 50, Appendix J testing are managed by the aging management program identified inthe table below using the following notes. Components of the penetrations listed in the tablehave corresponding line items in the LRA tables, which list the identified aging managementprograms. The penetrations are tested under LRA Section A. 1.7, Containment Leak RateProgram.E1-13 of 79 Notes:1. External surface of carbon steel components have no aging effects requiring managementdue to the temperature being greater than 212'F2. External Surfaces Monitoring Program [B. 1.10] manages the effects of aging on externalsurfaces3. Water Chemistry Control -Primary and Secondary Program [B. 1.43] manages the effects ofaging on internal surfaces4. External surface of stainless steel components exposed to indoor air have no aging effectsrequiring management5. Service Water Integrity Program [B.1.38] manages the effects of aging on internal surfaces6. Flow Accelerated Corrosion Program [B.1.14] manages effects of aging on internal surfaces7. Inservice Inspection Program [B.1.16] manages effects of aging on external surfacesValves AgingPenetration Valves Unit 2 Equipment ID ManagementUnit 1,2 only Program3-280A SQN-1 (2)-VLV-003-0280A 2,33-609 SQN-1 (2)-VLV-003-0609 2,33-836 SQN-1 (2)-VLV-003-0836 2,33-510 SQN-1(2)-VLV-003-0510 2, 3X-12A 3-033 SQN-1 (2)-FCV-003-0033-A 2, 3SYSTEM 3 3-903 SQN-1(2)-VLV-003-0903 2, 3FEEDWATER -LOOP 1 3-857 SQN-1 (2)-VLV-003-0857 2, 3GENERAL COMMENTS: -THIS 3-904 SQN-1(2)-VLV-003-0904 2, 3LINE JOINS TO THE SECONDARY 3-877 SQN-1(2)-VLV-003-0877 2, 3SIDE OF THE STEAM 3-885 SQN-1 (2)-VLV-003-0885 2, 3GENERATOR (SG) INSIDE 3-873 SON-i (2)-VLV-003-0873 2,3CONTAINMENT AND IS 3-174 SQN-1-LV-003-0873 2,3CONSIDERED A CLOSED 3-174 SQN--LCV-003-0174 2, 3SYSTEM INSIDE CONTAINMENT. SQN-2-LCV-003-0174-B 2, 3THE ISOLATION VALVES WHICH 3-889 SQN-1/2-VLV-003-0889 2, 3EXIST OUTBOARD OF 3-832 SQN-1 (2)-VLV-003-0832 2, 3CONTAINMENT ARE NOT LEAK 3-853 SQN-1(2)-VLV-003-0853 2, 3RATE TESTED. 3-849 SQN-1(2)-VLV-003-0849 2,33-164 SQN-1 (2)-LCV-003-0164-A 2, 33-164A SQN-1 (2)-LCV-003-0164A 2,33-504 SQN-2-VLV-003-0504 2,33-505 SQN-2-VLV-003-0505 2, 3E1-14 of 79 X-12B 3-281A SQN-1 (2)-VLV-003-0281A 2, 3DESCRIPTION: SYSTEM 3 3-502 SQN-I (2)-VLV-003-0502 2, 3FEEDWATER -LOOP 2 3-503 SQN-I (2)-VLV-003-0503 2, 3THIS LINE JOINS TO THE 3-509 SQN-i (2)-VLV-003-0509 2, 3, 6SECONDARY SIDE OF THE SG 3-610 SQN-1 (2)-VLV-003-0610 2, 3INSIDE CONTAINMENT AND ISCONSIDERED A CLOSEDSYSTEM INSIDE CONTAINMENT.THE ISOLATION VALVES WHICH 3-047 SQN-1 (2)-FCV-003-0047-B 2, 3, 6EXIST OUTBOARD OFCONTAINMENT ARE NOT LEAKRATE TESTED.X-12C 3-282A SQN-1 (2)-VLV-003-0282A 2, 3DESCRIPTION: SYSTEM 3 3-500 SQN-I (2)-VLV-003-0500 2, 3FEEDWATER -LOOP 3 3-501 SQN-I (2-)VLV-003-0501 2, 3THIS LINE JOINS TO THE 3-508 SQN-I (2)-VLV-003-0508 2, 3, 6SECONDARY SIDE OF THE SG 3-611 SQN-1 (2)-VLV-003-0611 2, 3INSIDE CONTAINMENT AND ISCONSIDERED A CLOSEDSYSTEM INSIDE CONTAINMENT.THE ISOLATION VALVES WHICH 3-087 SQN-1(2)-FCV-003-0087-A 2, 3, 6EXIST OUTBOARD OFCONTAINMENT ARE NOT LEAKRATE TESTED.3-283A SQN-1 (2)-VLV-003-0283A 2,33-506 SQN-2-VLV-003-0506 2,33-507 SQN-2-VLV-003-0507 2,33-511 SQN-1 (2)-VLV-003-0511 2, 3,63-612 SQN-1 (2)-VLV-003-0612 2, 3, 6X-12D 3-100 SQN-1 (2)-FCV-003-0100-B 2, 3DESCRIPTION: SYSTEM 3 3-837 SQN-1 (2)-VLV-003-0837 2, 3, 6FEEDWATER -LOOP 4 3-833 SQN-1 (2)-VLV-003-0833 2, 3THIS LINE JOINS TO THE 3-858 SQN-1 (2)-VLV-003-0858 2, 3SECONDARY SIDE OF THE SG 3-850 SQN-1 (2)-VLV-003-0850 2, 3INSIDE CONTAINMENT AND IS 3-854 SQN-1 (2)-VLV-003-0854 2, 3CONSIDERED A CLOSED 3-171 SQN-1 (2)-LCV-003-0171-B 2, 3SYSTEM INSIDE CONTAINMENT. 3-171A SQN-1 (2)-LCV-003-0171A 2, 3THE ISOLATION VALVES WHICH 3-906 SQN-I (2-VLV-003-0906 2, 3EXIST OUTBOARD OF 3-890 SQN-1 (2)-VLV-003-0890 2, 3CONTAINMENT ARE NOT LEAK 3-886 SQN-1 (2)-VLV-003-0886 2, 3RATE TESTED. 3-175 SQN-I(2)LCV-003-0175-A 2,33-874 SQN-1 (2)-VLV-003-0874 2,33-907 SQN-1 (2)-VLV-003-0907 2,33-878 SQN-1 (2)-VLV-003-0878 2, 3X-13A 1-015 SQN-1 (2)-FCV-001-001 5-A 2, 3DESCRIPTION: SYSTEM 1 MAIN 1-536 SQN-1 (2)-VLV-001-0536 1, 3STEAM -LOOP 1 1-537 SQN-1 (2)-VLV-001-0537 1, 3THIS LINE JOINS TO THE 1-147 SQN-1(2)-FCV-001-0147-A 1, 3SECONDARY SIDE OF THE SG 1-004 SON-i (2)-FCV-001-0004-T 1, 3, 6INSIDE CONTAINMENT AND IS 1-623 SQN-1 (2)-VLV-001-0623 1,3,6CONSIDERED A CLOSED 1-926 SQN-1(2)-VLV-001-0926 1, 3SYSTEM INSIDE CONTAINMENT. 1-922 SQN-l(2)-VLV-001-0922 1, 3THE ISOLATION VALVES WHICH 1-005 SQN-I (2)-PCV-001-0005-A 1, 3EXIST OUTBOARD OF 1-619A SQN-1(2)-VLV-001-0619A 1, 3CONTAINMENT ARE NOT LEAK 1-619 SQN-1(2)-VLV-001-0619 1, 3E1-15 of 79 RATE TESTED. THE SAFETY 1-522 SQN-1(2)-VLV-001-0522 1, 3RELIEF. VALVES FORM PART OF 1-523 SQN-1 (2)-VLV-001-0523 1, 3THE OUTSIDE CONTAINMENT 1-524 SQN-1(2)-VLV-001-0524 1, 3BARRIER. 1-525 SQN-1 (2)-VLV-001-0525 1,31-526 SQN-1 (2)-VLV-001-0526 1,31-148 SQN-1(2)-FCV-001-0148-B 1, 3X-13B 1-534 SQN-1(2)-VLV-001-0534 1, 3DESCRIPTION: SYSTEM 1 MAIN 1-535 SQN-1(2)-VLV-001-0535 1, 3STEAM LOOP 2 -THIS LINE JOINS 1-011 SQN-1 (2)-FCV-001-0011-T 2,3,6TO THE SECONDARY SIDE OF 1-624 SQN-1 (2)-VLV-001-0624 1, 3,6THE SG INSIDE CONTAINMENT 1-927 SQN-1(2)-VLV-001-0927 1, 3AND IS CONSIDERED A CLOSED 1-923 SQN-1(2)-VLV-001-0923 1, 3SYSTEM INSIDE CONTAINMENT. 1-620 SQN-1 (2)-VLV-001-0620 1, 3THE ISOLATION VALVES WHICH 1-620A SQN-1(2)-VLV-001-0620A 1.3EXIST OUTBOARD OF 1-02 SQN-1(2)-VLV-001-0620A 1,3CONTAINMENT ARE NOT LEAK 1-012 SQN-1(2)-PCV-001-0012-B 1, 3RATE TESTED. THE SAFETY 1-517 SQN-1 (2)-VLV-001-0517 1,3RELIEF VALVES FORM PART OF 1-518 SQN-1(2)-VLV-001-0518 1,3THE OUTSIDE CONTAINMENT 1-519 SQN-1(2)-VLV-001-0519 1, 3BARRIER. 1-520 SQN-1 (2)-VLV-001-0520 1,31-521 SQN-1(2)-VLV-001-0521 1,3X-13C 1-149 SQN-1(2)-FCV-001-0149-A 1, 3DESCRIPTION: SYSTEM 1 MAIN 1-532 SQN-1 (2)-VLV-001-0532 1,3STEAM -LOOP 3 1-533 SQN-1(2)-VLV-001-0533 1, 3THIS LINE JOINS TO THE 1-022 SQN-1 (2)-FCV-001-0022-T 2, 3, 6SECONDARY SIDE OF THE SG 1-625 SQN-1 (2)-VLV-001-0625 1, 3, 6INSIDE CONTAINMENT AND IS 1-928 SQN-1(2)-VLV-001-0928 1,3CONSIDERED A CLOSED 1-924 SQN-1 (2)-VLV-001-0924 1, 3SYSTEM INSIDE CONTAINMENT. 1-023 SQN-1(2)-PCV-001-0023-A 1, 3THE ISOLATION VALVES WHICH 1-621 SQN-1 (2)-VLV-001-0621 1,3EXIST OUTBOARD OF 1-621A SQN-1 (2)-VLV-001-0621A 1, 3CONTAINMENT ARE NOT LEAK 1-512 SQN-1(2)-VLV-001-0512 1, 3RATE TESTED. THE SAFETY 1-513 SQN-1 (2)-VLV-001-0513 1, 3RELIEF VALVES FROM PART OF 1-514 SQN-1 (2)-VLV-001-0514 1,3THE OUTSIDE CONTAINMENT 1-515 SQN-1 (2)-VLV-001-0515 1, 3BARRIER. 1-516 SQN-1 (2)-VLV-001-0516 1,31-016 SQN-1(2)-FCV-001-0016-A 2, 3,X-13D 1-538 SQN-1 (2)-VLV-001 -0538 1, 3DESCRIPTION: SYSTEM 1 MAIN 1-539 SON-1 (2)-VLV-001-0539 1,3STEAM -LOOP 4 1-150 SQN-1-FCV-001-0150-B 1, 3THIS LINE JOINS TO THE 1-029 SQN-1 (2)-FCV-001-0029-T 2, 3, 6SECONDARY SIDE OF THE SG 1-626 SQN-1 (2)-VLV-001-0626 1, 3, 6INSIDE CONTAINMENT AND IS 1-929 SQN-1 (2)-VLV-001-0929 1,3CONSIDERED A CLOSED --________________CNIEEACLSD1-925 SQN-1 (2)-VLV-001-0925 1, 3SYSTEM INSIDE CONTAINMENT 1-925 SON-I (2)-VLV-001-0622 1,3THE ISOLATION VALVES WHICH 1-622 SQN-1 (2)-VLV-001-0622 1, 3EXIST OUTBOARD OF 1-622A SON-i(2)-VLV-001-0622A 1, 3CONTAINMENT ARE NOT LEAK 1-030 SQN-1 (2)-PCV-001-0030-A 1, 3RATE TESTED. THE SAFETY 1-527 SQN-1 (2)-VLV-001-0527 1, 3RELIEF VALVES FORM PART OF 1-528 SQN-1(2)-VLV-001-0528 1, 3THE OUTSIDE CONTAINMENT 1-529 SQN-1(2)-VLV-001-0529 1, 3BARRIER. 1-530 SQN-1 (2)-VLV-001-0530 1,31-531 SQN-1(2)-VLV-001-0531 1, 3E1-16 of 79 X-14ADESCRIPTION: SYSTEM 1 MAINSTEAM -SG BLOWDOWN LOOP 2THIS LINE'JOINS TO THESECONDARY SIDE OF THE SGINSIDE CONTAINMENT AND ISCONSIDERED A CLOSEDSYSTEM INSIDE CONTAINMENT.THE ISOLATION VALVES WHICHEXIST OUTBOARD OFCONTAINMENT ARE NOT LEAKRATE TESTED. SEEEXEMPTIONS. THE PIPINGOUTSIDE THE SHIELD BLDG ISJOINED BY A SAMPLING LINE.THIS LINE IS ISOLATED BY ASOLENOID GLOBE VALVE WITHPHASE A ISOLATION.1-806SON-1 (2)-VLV-001 -08061.31-806- -1-807 SQN-1 (2)-VLV-001 -0807 1,31-813 SQN-1(2)-VLV-001-0813 2, 3,61-182 SQN-1 (2)-FCV-001-0182-B 1, 3,61-821 SQN-1 (2)-VLV-001 -0821 1,31-817 SQN-1(2)-VLV-001-0817 1, 3, 643-058 SQN-1 (2)-FSV-043-0058-A 31-014 SQN-1(2)-FCV-001-0014-A 2, 3,61-825SQN-1 (2)-VLV-001 -08251,3X-14BDESCRIPTION: SYSTEM 1 MAINSG BLOWDOWN LOOP 4THIS LINE JOINS TO THESECONDARY SIDE OF THE SGINSIDE CONTAINMENT AND ISCONSIDERED A CLOSEDSYSTEM INSIDE CONTAINMENT.THE ISOLATION VALVES WHICHEXIST OUTBOARD OFCONTAINMENT ARE NOT LEAKRATE TESTED. SEEEXEMPTIONS. THE PIPINGOUTSIDE THE SHIELD BLDG ISJOINED BY A SAMPLING LINE.THIS LINE IS ISOLATED BY ASOLENOID GLOBE VALVE WITHPHASE A ISOLATION.1-810SQN-1 (2)-VLV-001-08101,31-811 SQN-1 (2)-VLV-001-0811 1,31-815 SQN-1 (2)-VLV-001-0815 1, 3,61-184 SQN-1 (2)-FCV-001-0184-B 1, 3,61-823 SQN-1(2)-VLV-001-0823 1, 343-064 SQN-1 (2)-FSV-043-0064-A 3,1-819 SQN-1(2)-VLV-001-0819 1, 3,61-032 SQN-1(2)-FCV-001-0032-A 1, 3,61-827SQN-1(2)-VLV-001-08271,3X-14CDESCRIPTION: SYSTEM 1 MAINSG BLOWDOWN LOOP 3THIS LINE JOINS TO THESECONDARY SIDE OF THE SGINSIDE CONTAINMENT AND ISCONSIDERED A CLOSEDSYSTEM INSIDE CONTAINMENT.THE ISOLATION VALVES WHICHEXIST OUTBOARD OFCONTAINMENT ARE NOT LEAKRATE TESTED. THE PIPINGOUTSIDE THE SHIELD BLDG ISJOINED BY A SAMPLING LINE.THIS LINE IS ISOLATED BY ASOLENOID GLOBE VALVE WITHPHASE A ISOLATION.1-808SQN-1 (2)-VLV-001 -08081,31-809 SQN-1 (2)-VLV-001 -0809 1,31-814 SQN-1 (2)-VLV-001-0814 1, 3,61-183 SQN-1(2)-FCV-001-0183-A 1, 3,61-822 SQN-1 (2)-VLV-001 -0822 1, 343-061 SQN-1 (2)-FSV-043-0061-B 3,1-818 SQN-1(2)-VLV-001-0818 1, 3,61-025 SQN-1(2)-FCV-001-0025-B 1, 3,61-826SQN-1 (2)-VLV-001 -08261,3E1-17 of 79 X-14DDESCRIPTION: SYSTEM 1 MAINSG BLOWDOWN LOOP 1THIS LINE JOINS TO THESECONDARY SIDE OF THE SGINSIDE CONTAINMENT AND ISCONSIDERED A CLOSEDSYSTEM INSIDE CONTAINMENT.THE ISOLATION VALVES WHICHEXIST OUTBOARD OFCONTAINMENT ARE NOT LEAKRATE TESTED. SEEEXEMPTIONS. -THE PIPINGOUTSIDE THE SHIELD BLDG ISJOINED BY A SAMPLING LINE.THIS LINE IS ISOLATED BY ASOLENOID GLOBE VALVE WITHPHASE A ISOLATION.1-804SQN-1 (2)-VLV-001-08041,31-805 SQN-1(2)-VLV-001 -0805 1,31-812 SQN-1 (2)-VLV-001-0812 1,31-181 SQN-1 (2)-FCV-001-0181-A 1,31-820 SQN-1 (2)-VLV-001-0820 1, 343-055 SQN- 1 (2)-FSV-043-0055-B 31-816 SQN-1 (2)-VLV-001-0816 1, 3,61-007 SQN-I(2)-FCV-001-0007-B 1, 3,61-824SQN-1(2)-VLV-001-08241,3X-16DESCRIPTION: SYSTEM 62 CVCS-NORMAL CHARGINGTHIS PENETRATION HAS AGUARANTEED 30-DAY WATERSUPPLY THAT WILL PROVIDE APRESSURE GREATER THAN 1.1TIMES THE MAXIMUM ACCIDENTPRESSURE. TVA IDENTIFIEDTHE AVAILABLE OUTBOARDAUTOMATIC ISOLATION VALVECLOSEST TO THE CONTAINMENTAS THE OUTBOARDCONTAINMENT ISOLATIONBARRIER. THIS VALVEAUTOMATICALLY CLOSES ON ASAFETY INJECTION SIGNAL. SEEEXEMPTIONS.62-545I SQN-1 (2)-FLG-062-05453,462-543 SQN-1(2)-VLV-062-0543 3, 462-544 SQN-1 (2)-FLG-062-0544 3, 462-709 SQN-1 (2)-VLV-062-0709 3, 462-090SQN-1-FCV-062-0090SQN-2-FCV-062-0090-A3,463-640SQN-1 (2)-VLV-063-06403,7X-17DESCRIPTION: SYSTEM 63 SISRHR HOT LEG INJECTION63-639 SQN-1 (2)-VLV-063-0639 3, 463-870 SQN-1(2)-VLV-063-0870 3, 463-871 SQN-1 (2)-VLV-063-0871 3, 463-158 SQN-1 (2)-FCV-063-0158 3, 463-642 SQN-1 (2)-VLV-063-0642 3, 463-643 SQN-1 (2)-VLV-063-0643 3, 763-846 SQN-1 (2)-VLV-063-0846 3, 463-172 SQN-i (2)-FCV-063-0172-B 3, 463-845 SQN-1 (2)-VLV-063-0845 3, 463-636 SQN-1(2)-VLV-063-0636 3, 463-637 SQN-1(2)-VLV-063-0637 3, 463-861 SQN-2-VLV-063-0861 3, 4X-19A 63-072 SQN-1 (2)-FCV-063-0072-A 3, 4DESCRIPTION: SYSTEM 63 SIS-63-593 SQN-1(2)-VLV-063-0593 3, 4SUMP SUCTION TO RHR PUMP 63-591 SQN-1 (2)-VLV-063-0591 3, 41,2A-A 63-595 SQN-1 (2)-VLV-063-0595 3, 4E1-18 of 79 X-19B 63-073 SQN-1 (2)-FCV-063-0073-A 3, 4DESCRIPTION: SYSTEM 63 SIS-63-592 SQN-1(2)-VLV-063-0592 3, 4SUMP SUCTION TO RHR PUMP 63-590 SQN-1 (2)-VLV-063-0590 3, 41,2B-B 63-594 SQN-1 (2)-VLV-063-0594 3,4X-20A 63-633 SQN-1 (2)-VLV-063-0633 3, 4DESCRIPTION: SYSTEM 63 SIS-63-661 SQN-1 (2)-VLV-063-0661 3, 4RHR PUMP DISCHARGE 63-667 SQN-1(2)-VLV-063-0667 3, 4TRAIN B 63-635 SQN-1(2)-VLV-063-0635 3, 463-412 SQN-1 (2)-VLV-063-0412 3, 463-112 SQN-1(2)-FCV-063-0112 3,463-833 SQN-1 (2)-VLV-063-0833 3, 463-834 SQN-1 (2)-VLV-063-0834 3, 463-835 SQN-1 (2)-VLV-063-0835 3, 463-094 SQN-1 (2)-FCV-063-0094-B 3, 463-631 SQN-1 (2)-VLV-063-0631 3, 463-414 SQN-2-VLV-063-0414 3, 463-632 SQN-1(2)-VLV-063-0632 3, 4X-20B 63-660 SQN-1 (2)-VLV-063-0660 3, 4DESCRIPTION: SYSTEM 63 SISRHR PUMP DISCHARGE TRAIN A 63-659 SQN-l(2)-VLV-063-0659 3, 463-634 SQN-1 (2)-VLV-063-0634 3, 463-413 SQN-1 (2)-VLV-063-0413 3, 463-111 SQN-1 (2)-FCV-063-01 11 3, 463-411 SQN-1 (2)-VLV-063-0411 3, 463-630 SQN-i (2)-VLV-063-0630 3, 463-093 SQN-1 (2)-FCV-063-0093-A 3, 463-415 SQN-2-VLV-063-0415 3, 463-547 SQN-1 (2)-VLV-063-0547 3, 463-549 SQN-1(2)-VLV-063-0549 3, 463-546 SQN-1 (2)-VLV-063-0546 3, 463-548 SQN-1 (2)-VLV-063-0548 3, 463-318A SQN-i (2)-VLV-063-0318A 363-318B SQN-1(2)-VLV-063-0318B 363-317A SQN-1 (2)-VLV-063-0317A 363-317B SQN-1 (2)-VLV-063-0317B 363-314A SQN-1 (2)-VLV-063-0314A 3DESCRIPTION: SYSTEM 63 SIS -63-314B SQN-1 (2)-VLV-063-0314B 3PUMP DISCHARGE TO HOT LEGS 63-313A SQN-1(2)-VLV-063-0313A 3TRAIN B 63-313B SQN-1(2)-VLV-063-0313B 363-862 SQN-1 (2)-VLV-063-0862 363-863 SQN-1 (2)-VLV-063-0863 363-650 SQN-1 (2)-VLV-063-0650 363-157 SQN-I (2)-FCV-063-157-B 363-649 SQN-1 (2)-VLV-063-0649 363-825 SQN-1 (2)-VLV-063-0825 363-167 SQN-1 (2)-FCV-063-0167 363-648 SQON-1 (2)-VLV-063-0648 363-860 SQN-2-VLV-063-0860 3EI-19 of 79 X-22DESCRIPTION: SYSTEM 63 SIS -INJECTION TANK CHARGINGPUMP DISCHARGE. THE FSV'SARE REQUIRED TO VENT THEBONNET AREA OF FCV-63-25AND 26, THUS ALLEVIATINGPRESSURE LOCKING CONCERNS(IN ACCORDANCE WITHREQUIREMENTS OF NRC GL 95-07). THE FSV'S HAVE NO EFFECTON THE CLOSING OF THE FCV'SOR THE CONTAINMENTISOLATION CAPABILITY OF THEFCV'S.163-174SQN-1 (2)-FCV-063-0174363-581 SQN-1 (2)-VLV-063-0581 3, 7FCV-63-26 SQN-1 (2)-FCV-063-0026-A 3FSV-63-25 SQN-i (2)-FSV-063-0025-B 3FCV-63-25 SQN-1 (2)-FCV-063-0025-B 3FSV-63-26 SQN-1 (2)-FSV-063-0026-A 363-816SQN-2-VLV-063-0816368-559SQN-1 (2)-VLV-068-05593X-24DESCRIPTION: SYSTEM 62, 63,68, 72 CVCS, SIS, RCS, CS -RELIEF VALVE DISCHARGE. THECONTAINMENT ISOLATIONPROVISIONS FOR THE RELIEFVALVE DISCHARGE LINE(DISCHARGING TO THEPRESSURIZER RELIEF TANK)CONSIST OF A CHECK VALVEINSIDE CONTAINMENT ANDPARALLEL RELIEF VALVESOUTSIDE CONTAINMENT SERVEAS THE OUTER ISOLATIONBARRIER. SEE EXEMPTIONS.68-560 SON-i (2)-VLV-068-0560 368-561 SQN-1 (2)-VLV-068-056i 372-517 SQN-1 (2)-VLV-072-0517 372-512 SQN-1 (2)-VLV-072-0512 372-518 SQN-1 (2)-VLV-072-0518 372-513 SQN-1 (2)-VLV-072-0513 362-505 SQON-1 (2)-VLV-062-0505 363-505 SQN-i(2)-VLV-063-0511 363-534 SQN-1 (2)-VLV-063-0534 363-535 SQN-1(2)-VLV-063-0535 363-536 SQN-1 (2)-VLV-063-0536 363-626 SQN-1 (2)-VLV-063-0626 363-627 SQN-1 (2)-VLV-063-0627 363-638SO N-i1 6363 SO____ N-1________________ _______________8X-25BDESCRIPTION: SYSTEM 30VENTILATION CONTAINMENTSENSORS 30-311/44 -THE DPSENSORS ARE CLOSEDSYSTEMS OUTSIDE OFCONTAINMENT THAT AREATTACHED DIRECTLY TOCONTAINMENT. NO ISOLATIONVALVES ARE EMPLOYED FORTHESE SENSORS AS THEY USE ADOUBLE DIAPHRAGM SYSTEMFOR DP MEASUREMENT. THEDIAPHRAGMS ARE QUALIFIEDFOR POST-LOCA USET 130-311 ZSQN-1 (2)-ISIV-030-031 1Z430-44Z _____SQN-1 (2)-ISIV-030-0044Z 43ý0-3ii1Y ___ _SON-i1 (2)-DR IV-030-031 1Y 430-44Y j ____SON-i (2)-DRIV-030-0044Y 4 ______30-311iX J ____SON-i (2)-DRIV-030-031 IX 14I 30-44XSQN-1 (2)-DRIV-030-0044X4u ___________ a __________ u JE1-20 of 79 X-27ADESCRIPTION: SYSTEM 30VENTILATION CONTAINMENTSENSOR 30-30C. THE DPSENSOR ARE CLOSED SYSTEMSOUTSIDE OF CONTAINMENTTHAT ARE ATTACHED DIRECTLYTO CONTAINMENT. NOISOLATION VALVES AREEMPLOYED FOR THESESENSORS AS THEY USE ADOUBLE DIAPHRAGM SYSTEMFOR DP MEASUREMENT. THEDIAPHRAGMS ARE QUALIFIEDFOR POST-LOCA USE.30-30CZSQ N-1 (2)-IS IV-030-0030CZ430-30CY I SQN-1 (2)-DRIV-030-0030CY 1430-30CXSQN-1 (2)-DRIV-030-0030CX4X-27BDESCRIPTION: SYSTEM 30VENTILATION CONTAINMENTSENSOR 30-42. THE DP SENSORARE CLOSED SYSTEMS OUTSIDEOF CONTAINMENT THAT AREATTACHED DIRECTLY TOCONTAINMENT. NO ISOLATIONVALVES ARE EMPLOYED FORTHESE SENSORS AS THEY USE ADOUBLE DIAPHRAGM SYSTEMFOR DP MEASUREMENT. THEDIAPHRAGMS ARE QUALIFIEDFOR POST-LOCA USE.I 30-42ZSQN-1 (2)-ISIV-030-0042Z430-42Y SQN-1 (2)-DRIV-030-0042Y 430-42XSQN-1 (2)-DRIV-030-0042X463-545SQN-1 (2)-VLV-063-05453,7X-32DESCRIPTION: SYSTEM 63 SISPUMP DISCHARGE TO HOT LEGSTRAIN A. THIS PENETRATIONHAS A GUARANTEED 30-DAYWATER SUPPLY THAT WILLPROVIDE A PRESSURE GREATERTHAN 1.1 TIMES THE MAXIMUMACCIDENT PRESSURE.63-543 SQN-1 (2)-VLV-063-0543 3, 763-542 SQN-1 (2)-VLV-063-0542 363-544 SQ N-1 (2)-VLV-063-0544 363-316A SQN-1(2)-VLV-063-0316A 363-316B SQN-1 (2)-VLV-063-0316B 363-315A SQN-1 (2)-VLV-063-315A 363-315B SQN-1(2)-VLV-063-315B 363-864 SQN-1 (2)-VLV-063-0864 363-865 SQN-1 (2)-VLV-063-0865 363-658 SQN-1 (2)-VLV-063-0658 363-657 SQN-1 (2)-VLV-063-0657 363-824 SQN-1 (2)-VLV-063-0824 363-823 SQN-1(2)-VLV-063-0823 363-541 SQN-1 (2)-VLV-063-0541 363-156 SQN-1 (2)-FCV-063-0156-A 363-312A SQN-1(2)-VLV-063-0312A 363-312B SQN-1 (2)-VLV-063-0312B 363-311 A SQN-1(2)-VLV-063-031 1A 363-311 B SQN-1 (2)-VLV-063-031 1B 363-021SQN-1 (2)-FCV-063-00213E1-21 of 79 63-557SQN- I (2)-VLV-063-05573,7X-33DESCRIPTION: SYSTEM 63 SISPUMP DISCHARGE COLD LEGINJECTIONTHIS PENETRATIONHAS A GUARANTEED 30-DAYWATER SUPPLY THAT WILLPROVIDE A PRESSUREGREATER THAN 1.1 TIMES THEMAXIMUM ACCIDENT PRESSURE-SEE EXEMPTIONS. VALVES 63-619A THRU 63-626A HAVEANOTHER DOWN STREAMNORMALLY CLOSED ISOLATIONVALVE63-556 SQN-1 (2)-VLV-063-0556 363-550 SQN-1 (2)-VLV-063-0550 363-022 SQN-1 (2)-FCV-063-0022-B 363-551 SQN-1 (2)-VLV-063-0551 3, 763-320A SQN-1 (2)-VLV-063-0320A 363-319a SQN-1 (2)-VLV-063-0319A 363-326A SQN-1 (2)-VLV-063-0326A 363-325A SQN-1 (2)-VLV-063-0325A 363-832 SQN-1 (2)-VLV-063-0832 363-831 SQN-1 (2)-VLV-063-0831 363-324A SQN-1 (2)-VLV-063-0324A 363-323A SQN-1 (2)-VLV-063-0323A 363-555 SQN-1(2)-VLV-063-0555 3, 763-656 SQON-1 (2)-VLV-063-0656 363-554 SQN-1 (2)-VLV-063-0554 363-553 SQN-1 (2)-VLV-063-0553 3, 763-552 SQN-1 (2)-VLV-063-0552 363-322A SQN-1 (2)-VLV-063-0322A 363-321A SQN-1(2)-VLV-063-0321A 363-653 SQN-1 (2)-VLV-063-0653 363-121 SQN-1 (2)-FCV-063-0121 363-836 SQN-1 (2)-VLV-063-0836 363-837 SQN-1 (2)-VLV-063-0837 363-655 SQN- I (2)-VLV-063-0655 363-654 SQN-1 (2)-VLV-063-0654 363-645SQN-1 (2)-VLV-063-064533-862SQN-1 (2)-VLV-003-08622.3X-40ADESCRIPTION: SYSTEM 3AUXILIARY FEEDWATER THISLINE JOINS TO THE SECONDARYSIDE OF THE SG INSIDECONTAINMENT AND ISCONSIDERED A CLOSEDSYSTEM INSIDE CONTAINMENT.THE ISOLATION VALVES WHICHEXIST OUTBOARD OFCONTAINMENT ARE NOT LEAKRATE TESTED. SEEEXEMPTIONS3-860 SQN- 1(2)-VLV-003-0860 2,33-925 SQN-1 (2)-VLV-003-0925 2, 33-351A SQN-1 (2)-VLV-003-0351A 2,33-351 B SQN-1 (2)-VLV-003-0351 B 2,33-922 SQN-1 (2)-VLV-003-0922 2,33-899 SON-1 (2)-VLV-003-0899 2,33-901 SQN-I(2)-VLV-003-0901 2,33-876 SQN-1 (2)-VLV-003-0876 2,33-884 SQN-l(2)-VLV-003-0884 2,33-872 SQN-1 (2)-VLV-003-0872 2,33-888 SQN-1(2)-VLV-003-0888 2, 3SQN-1-LCV-003-01733-173 SQN-2-LCV-003-0173-B 2,33-856 SQN-i (2)-VLV-003-0856 2,33-900 SQN-1 (2)-VLV-003-0900 2,33-835 SQN-1(2)-VLV-003-0835 2,33-844 SQN-1 (2)-VLV-003-0844 2,33-831 SQN-1 (2)-VLV-003-0831 2,33-848 SQN-l(2)-VLV-003-0848 2,33-852 SQN-1 (2)-VLV-003-0852 2, 33-156A SQN-1 (2)-LCV-003-0156A 2,33-156SQN-i (2)-LCV-003-0156-A2,3E1-22 of 79 13-861SON-1 (2)-VLV-003-08612.3X-40BDESCRIPTION: SYSTEM 3AUXILIARY FEEDWATER THISLINE JOINS TO THE SECONDARYSIDE OF THE SG INSIDECONTAINMENT AND ISCONSIDERED A CLOSEDSYSTEM INSIDE CONTAINMENT.THE ISOLATION VALVES WHICHEXIST OUTBOARD OFCONTAINMENT ARE NOT LEAKRATE TESTED.3-921 SQN-1(2)-VLV-003-0921 2,33-859 SQN-1 (2)-VLV-003-0859 2,33-924 SQN-1(2)-VLV-003-0924 2, 33-352A SQN-1 (2)-VLV-003-0352A 2, 33-352B SQN-I (2)-VLV-003-0352B 2,33-842 SQN-1 (2)-VLV-003-0842 2,33-897 SQN-1 (2)-VLV-003-0897 2,33-875 SQN-1 (2)-VLV-003-0875 2,33-883 SQN-1 (2)-VLV-003-0883 2,_33-871 SQN-1 (2)-VLV-003-0871 2,_33-887 SQN-1 (2)-VLV-003-0887 2,3SQN-1-LCV-003-01723-172 SQN-2-LCV-003-0172-A 2,_33-834 SQN-1 (2)-VLV-003-0834 2,33-855 SQN-I(2)-VLV-003-0855 2,33-896 SQN-1 (2)-VLV-003-0896 2,33-843 SQN-1 (2)-VLV-003-0843 2,33-830 SQN-1 (2)-VLV-003-0830 2,33-847 SQN-1(2)-VLV-003-0847 2,33-851 SQN-1 (2)-VLV-003-0851 2 33-148 SQN-1 (2)-LCV-003-0148-B 2, 33-148ASQN-1 (2)-LCV-003-0148A2,362-578SQN-1 (2)-VLV-062-05783X-43ADESCRIPTION: SYSTEM 62 CVCSTO REACTOR COOLANT PUMPSEALS LOOP #3. THISPENETRATION HAS AGUARANTEED 30-DAY WATERSUPPLY THAT WILL PROVIDE APRESSURE GREATER THAN 1.1TIMES THE MAXIMUM ACCIDENTPRESURE.62-567 SQN-1 (2)-VLV-062-0567 362-575 SQN-1 (2)-VLV-062-0575 362-563 SON-1 (2)-VLV-062-0563 362-571 SQN-1 (2)-VLV-062-0571 362-559 SAN-1 (2)-VLV-062-0559 362-555 SQN-1 (2)-VLV-062-0555 362-546 SQN-1 (2)-VLV-062-0546 362-549 SQN- I (2)-VLV-062-0549 362-550 SQN-1 (2)-VLV-062-0550 362-551 SQN-1 (2)-VLV-062-0551 362-552SQN-1 (2)-VLV-062-0552362-577SQN-i (2)-VLV-062-05773X-43BDESCRIPTION: SYSTEM 62 CVCSTO REACTOR COOLANT PUMPSEALS LOOP #2. THISPENETRATION HAS AGUARANTEED 30-DAY WATERSUPPLY THAT WILL PROVIDE APRESSURE GREATER THAN 1.1TIMES THE MAXIMUM ACCIDENTPRESURE.62-565 SQN-1 (2)-VLV-062-0565 362-561 SQN-1 (2)-VLV-062-0561 362-573 SQN-1 (2)-VLV-062-0573 362-569 SQN-1 (2)-VLV-062-0569 362-557 SQN-1 (2)-VLV-062-0557 3E1-23 of 79 62-579SQN-1 (2)-VLV-062-0579362-567 SQN-1 (2)-VLV-062-0567 3X-43CTHIS PENETRATION HAS AGUARNTEED 30 DAY WATERSUPPLY THAT WILL PROVDE APRESSURE GREATER THAN 1.1TIMES THE MAXIMUM ACCIDENTPRESSURE.62-574 SQN-1 (2)-VLV-062-0574 362-562 SQ N-1 (2)-VLV-062-0562 362-570 SQN-1 (2)-VLV-062-0570 362-558 SQN-1 (2)-VLV-062-0558 34 t 462-576SQN-I (2)-VLV-062-05763x-43DTHIS PENETRATION HAS AGUARNTEED 30 DAY WATERSUPPLY THAT WILL PROVDE APRESSURE GREATER THAN 1.1TIMES THE MAXIMUM ACCIDENTPRESSURE.62-584 _SQN-i (2)-VLV-062-0584 362-572 SQN-1 (2)-VLV-062-0572 362-560 SQN-1 (2)-VLV-062-0560 362-568 SQ N-1 (2)-VLV-062-0568 362-556 SQ N-1 (2)-VLV-062-0556 3X-85B 30-45Z SQN-1 (2)-ISIV-030-0045Z 4DESCRIPTION: SYSTEM 30 30-45Y SQN-1 (2)-DRIV-030-0045Y 4VENTILATION SYSTEMPRESSURE SENSOR 30-45X SQN-1 (2)-DRIV-030-0045X 4X-102 3-881 SQN-1(2)-VLV-003-0881 2, 3DESCRIPTION: SYSTEM 3 3-352A SQN-1 (2)-VLV-003-0352A 2, 3AUXILIARY FEEDWATER TESTLINE 3-921 SQN-l(2)-VLV-003-0921 2,3THIS LINE JOINS TO THE 3-352B SQN-1 (2)-VLV-003-0352B 2, 3SECONDARY SIDE OF THE SG 3-352C SQN-1(2)-VLV-003-0352C 2, 3INSIDE CONTAINMENT AND ISCONSIDERED A CLOSEDSYSTEM INSIDE CONTAINMENT.THE ISOLATION VALVES WHICH 3-972 SQN-2-VLV-003-0972 2, 3EXIST OUTBOARD OFCONTAINMENT ARE NOT LEAKRATE TESTED.X-104 DESCRIPTION: SYSTEM 3 3-862 SQN-1(2)-VLV-003-0862 2, 3AUXILIARY FEEDWATER TEST 3-922 SQN-1(2)-VLV-003-0922 2, 3LINE -THIS LINE JOINS TO THESECONDARY SIDE OF THE SG 3-351A SQN-1 (2)-VLV-003-0351A 2, 3INSIDE CONTAINMENT AND IS 3-351B SQN-1 (2)-VLV-003-0351B 2, 3CONSIDERED A CLOSED 3-351C SQN-1 (2)-VLV-003-0351C 2, 3SYSTEM INSIDE CONTAINMENT. 3-971 SQN-2-VLV-003-0971 2, 3THE ISOLATION VALVES WHICHEXIST OUTBOARD OFCONTAINMENT ARE NOT LEAK 3-970 SQN-2-VLV-003-0970 2, 3RATE I IIE1-24 of 79 X-107DESCRIPTION: SYSTEM 74 RHR -SUPPLY -THE SUCTION LINEFROM THE LOOP 4 HOT LEG TOTHE RHR PUMPS IS ISOLATED BYTWO MOTOR-OPERATED VALVESIN SERIES, WHICH ARE CLOSEDWITH POWER REMOVED WHILETHE PLANT IS AT POWER. THEVALVES ARE INTERLOCKED TOPREVENT OPENING WHEN THEREACTOR COOLANT SYSTEM(RCS) IS AT HIGH PRESSURE.BOTH VALVES ARE LOCKEDINSIDE CONTAINMENT. THISCONFIGURATION ISACCEPTABLE ON AN "OTHERDEFINED BASIS" INACCORDANCE WITH ANSISTANDARD N271-1976.THE RELIEF VALVE INSIDECONTAINMENT THATDISCHARGES TO THEPRESSURIZER RELIEF TANKINSIDE CONTAINMENT IS ALSOACCEPTABLE PER THE ANSISTANDARD. THE FR SHOWN ONTHE DRAWING INDICATESPIPING THAT HAS 3/8 FLOWRESTRICTORS INSTALLED.74-500SQN-1 (2)-VLV-074-05003,474-001 SQN-1(2)-FCV-074-0001-A 3, 4, 774-501 SQN-1(2)-VLV-074-0501 3, 474-549 SQN-1 (2)-VLV-074-0549 3, 474-502 SQN-i (2)-VLV-074-0502 3, 474-503 SQN-1 (2)-VLV-074-0503 3, 474-002 SQN-1(2)-FCV-074-0002-B 3, 4, 774-504 SQN-1 (2)-VLV-074-0504 374-505SQN-1 (2)-VLV-074-05053RAI B.1.11-1Backqround:The "scope of program" program element of GALL Report AMP X M1, "Fatigue Monitoring,"states that the program monitors and tracks the number of critical thermal and pressuretransients for the components that have been identified to have a fatigue time-limited aginganalysis (TLAA).Issue:The staff noted that updated FSAR (UFSAR) Table 5.2.1-1 includes 18,300 cycles of "Loadingand unloading power changes per unit at 5% per minute" and 2, 000 cycles of "Step loadincrease and decrease of 10% per unit". LRA Section 4.3.1.6 includes 15 cycles of designtensioning cycle limit for reactor coolant pump (RCP) hydraulic studs/nuts. LRA Section 4.3.2.3identifies the following five additional transients for the fatigue calculations for Chemical andVolume Control System (CVCS) Regenerative Heat Exchangers: (1) 2,000 cycles of "Stepchanges in letdown stream fluid temperature from 100°F to 5600F,;" (2) 24,000 cycles of "Stepchanges in letdown stream temperature from 400°F to 5600F;" (3) 200 cycles of "Changes inletdown stream temperature from 100°F to 560°F occurring over four hours;" (4) 200 cycles of"Changes in letdown stream fluid temperature from 560°F to 140°F occurring over 20 hours2.314815e-4 days <br />0.00556 hours <br />3.306878e-5 weeks <br />7.61e-6 months <br />;"and, (5) 200 cycles of "Pressurizations to respective design pressure and temperature."E1-25 of 79 The staff also noted that aforementioned eight transients were inputs to various metal fatigueTLAAs dispositioned in accordance with 10 CFR 54.21 (c)(1)(iii). However, these transientswere not included in LRA Tables 4.3-1 and 4.3-2 and it is not clear to the staff whether thesetransients are monitored by the applicant's Fatigue Monitoring program.Request:1. Clarify whether all these transients will be monitored as part of the Fatigue Monitoringprogram.2. If not, for each of the transients, justify why the transient would not need to be monitoredby the Fatigue Monitoring program during the period of extended operation.RAI B.1.11-1 RESPONSEThe 18,300 cycles of "Loading and unloading power changes per unit at 5% per minute" and2,000 cycles of "Step load increase and decrease of 10% per unit" were assumed in the designto allow the plants to be loaded and unloaded frequently to follow the grid load demand. SQNUnits 1 and 2 are base-loaded plants that do not perform frequent power changes. Thenumbers postulated and used in the analyses far exceed the number required for actual plantoperation through the PEO. Therefore, there is no need for monitoring these transients in theFatigue Monitoring Program.As described in LRA Section 4.3.1.6, 15 tensioning cycles were analyzed for the reactor coolantpump hydraulic tensioning nuts and studs. Reactor coolant pumps are rarely disassembledsuch that tensioning of the studs is necessary. For example, the one reactor coolant pump withhydraulically tensioned studs has not been disassembled since the studs were installed in 2005.Based on the plant operating history of infrequent disassembly of the reactor coolant pumps,there is no need for monitoring these cycles in the Fatigue Monitoring Program.The cycle limits of (1) 2,000 cycles of "Step changes in letdown stream fluid temperature from1 00°F to 560°F" and (2) 24,000 cycles of "Step changes in letdown stream temperature from400°F to 560°F" for the CVCS regenerative heat exchanger do not need to be monitored by theFatigue Monitoring Program because the letdown fluid temperature normally remains stable atSQN Units 1 and 2. Based on plant experience, the numbers of cycles postulated and used inthe analyses far exceed the numbers required for plant operation through the PEO. Amaximum of 90 cycles of each of these two transients are expected for plant operation throughthe PEO.The CVCS regenerative heat exchanger transient cycle limits (items (3) (4) (5) of the issuediscussion) designated for 200 cycles are provided to correspond to temperature and pressurechanges that occur in the heat exchanger during plant heatups and cooldowns. Plant heatupand cooldown transients are monitored as part of the Fatigue Monitoring Program described inLRA B.1.11 with a limit of 200 cycles as shown in LRA Tables 4.3-1 and 4.3-2. Also thisinformation is found in UFSAR Table 5.21-1.Ei-26 of 79 RAI B.1.11-2Background:Enhancement 3 of the Fatigue Monitoring program stated that "[fjatigue usage factors for theRCS limiting components will be determined to address the Cold Overpressure MitigationSystem (COMS) event (i.e., low temperature overpressurization event) and the effects of thestructural weld overlays." The applicant identifies that Enhancement 3 is included on the "scopeof program" program element of the AMP. The "scope of program" program element of GALLReport AMP X M1, "Fatigue Monitoring, " states that the program monitors and tracks thenumber of critical thermal and pressure transients for the components that have been identifiedto have a fatigue TLAA.Issue:The applicant has not identified the components that are within the scope of the statedenhancement. Furthermore, the staff noted that the effects of the structural weld overlays forfatigue usage factors may include, but are not limited to, the update or addition of componentsand transients to existing fatigue analyses. The staff seeks further clarifications on the impactsthat the presence of structural weld overlays will have on the following aspects of the program:(a) list of components, (b) design transients, (c) cycle counting activities, and, (d) cumulativeusage factor (CUF) analyses. Without such information, the staff cannot determine whether the"scope of program" element of the Fatigue Monitoring program, when enhanced, would beconsistent with that of GALL Report AMP X. M1.Request:1. Identify all plant systems and components that are within the scope of license renewalthat have been affected by or will be affected by occurrences of COMS events.a) With respect to these components, clarify and define what is meant by the statement:"[flatigue usage factors for the RCS limiting components will be determined toaddress the COMS event."2. Identify all systems and components that are within the scope of license renewal thathave been or will be subjected to structural weld overlay modifications.a) With respect to these components, identify and explain all impacts (effects) that thepresence of structural weld overlays will have on the scope of the Fatigue Monitoringprogram, including (but not limited to) impacts of the following aspects of the.program:1) list of components,2) design transients,3) cycle counting activities, and4) CUF analyses.3. In light of the responses that will be made to Parts (a) and (b), justify why the proposedenhancement, when implemented, provides assurance that the "scope of program"element of the Fatigue Monitoring program will be consistent with that in GALL ReportAMP X.M1, "Fatigue Monitoring. " Revise LRA Section A. 1.11 accordingly.E1-27 of 79 RAI B.1.11-2 RESPONSE1 The cold overpressure mitigation system (COMS) transient can affect reactor coolantsystem (RCS) pressure boundary components. The COMS transient was not one of theoriginal design transients used in the Class 1 fatigue analyses at SQN Units I and 2.This transient is postulating the inadvertent pressurization of the RCS when at lowtemperatures. The pressure is then reduced by operation of the power operated reliefvalve while conservatively assuming a temperature change during the transient. Duringpreparation of license renewal documentation, an addendum to the pressurizer stressanalysis that includes review of the COMS transient was identified; however, fatigueanalyses for other RCS pressure boundary components had not been reevaluated forpotential fatigue effect from the COMS transient. Enhancement 3 of the FatigueMonitoring Program will expand the review of the COMS transient to the fatigueanalyses for RCS pressure boundary components other than the pressurizer.a). The statement, "[flatigue usage factors for the RCS limiting components will bedetermined to address the COMS event" is in the enhancement to the FatigueMonitoring Program in LRA Section B. 1.11. This statement refers to the calculationof new fatigue cumulative usage factors (CUF) to determine the effects of the COMStransient. This includes a review of the RCS component stress analyses todetermine the changes in CUFs required due to the COMS transient effects on theRCS pressure boundary components.2 Structural weld overlays are installed at the following locations:* On four SQN-1 control rod drive mechanism (CRDM) lower canopy seal welds.(Unit 1 Core locations A-5, E-13, L-13 and J-1)* On SQN-1 and 2 pressurizer safety/relief, spray and surge nozzles.There are no plans to install additional structural weld overlays.a). The third enhancement identified for the Fatigue Monitoring Program in LRA B. 1.11(dealing with the effects of the structural weld overlays) will provide an evaluation ofthe effect of the structural weld overlays on the Class 1 fatigue analyses. No impactsto the scope of the Fatigue Monitoring Program are expected. This enhancement isnot expected to change the list of components, design transients, or cycle countingactivities. The revised analyses may cause a change to the calculated CUFs.3 Enhancements to the scope of program element of the Fatigue Monitoring Program willensure that the CUFs for the RCS pressure boundary components are adjusted asrequired to consider the effects of the COMS transient and structural weld overlays. Theenhancement does not add components or require tracking of additional plant transientsbut only ensures CUFs remain within the allowable limit as specified in the scope sectionof NUREG-1801 Revision 2,Section X.M1 Fatigue Monitoring. A change to thedescription of the enhancement in the Fatigue Monitoring Program is made for clarity.E1-28 of 79 Additions are underlined and deletions are lined through.LRA Section A.1.11 Fatigue Monitoring Program"Fatigue usage factors for the reactor coolant system pressure boundary lit-iigcomponents will be adiusted as necessary dete-MiPed to incorporate the effects of theCold Overpressure Mitigation System (COMS) event (i.e., low temperatureoverpressurization event) and the effects of structural weld overlays."LRA Section B.1.111. Scope of Program Fatigue usage factors for the RCS pressureboundary limiting components will be adiusted asnecessary deteFMOied to incorporate the effects ofthe Cold Overpressure Mitigation System (COMS)event (i.e., low temperature overpressurizationevent) and the effects of structural weld overlays.Commitment changes: Commitment 7.C is revised to reflect the changes shown above.RAI B.1.13-1Backqround:The program description of the Fire Water System program, LRA Section B. 1.13, states that theprogram manages loss of material and fouling for fire protection components that are tested inaccordance with the Fire Protection Report.During its review of the UFSAR, the staff noted that the two safety-related standby fire/floodmode pumps are used to provide makeup to the steam generators and reactor coolant systemduring a flooding event. Based on the staff's review of LRA Sections 2.3.3.2, 3.3, 3.4, and LRADrawing 1, 2-47W850-24, "Mechanical Flow Diagram Fire Protection, "it appears that the pumps,and suction and discharge piping of these pumps, are being age-managed by the Fire WaterSystem program.The "scope of program" program element in GALL Report AMP XI.M27 states, "[t]he AMPfocuses on managing loss of material due to corrosion, MIC, or biofouling of steel componentsin fire protection systems exposed to water."GALL Report Item VIII. G. SP-136 recommends GALL Report AMP XI. M38, "Inspection ofInternal Surfaces in Miscellaneous Piping and Ducting Components," to age-manage steelpiping exposed to raw water. GALL Report Table VIL El, "Chemical Volume and ControlSystem (PWR)," does not include steel piping exposed to a raw water environment.Issue:It is not clear to the staff that given the scope of inspections recommended in GALL Report AMPXI. M27, that the Fire Water System program is appropriate to manage the portion of a systemwhose intended functions as described in IOCFR 54.4 are to support auxiliary feedwater andreactor coolant system make-up.E1-29 of 79 Request:1. State whether the safety-related standby fire/flood mode pumps and associated suctionand discharge piping will be age-managed by the Fire Water System program.2. State why reasonable assurance can be established that the components will meet theirintended function consistent with the current licensing basis, or propose an alternativeaging management program if the components will be age-managed by the Fire WaterSystem program.a. In considering the response to question 2, review the changes to programs suchas GALL Report AMP XI. M38, "Inspection of Internal Surfaces in MiscellaneousPiping and Ducting Components," included in draft LR-ISG-2012-02, "AgingManagement of Internal Surfaces, Service Level III and Other Coatings,Atmospheric Storage Tanks, and Corrosion under Insulation."RAI B.1.13-1 Response:1. The Periodic Surveillance and Preventive Maintenance Program will be used to manageloss of material due to corrosion on the interior surfaces of the safety-related standbyfire/flood mode pumps and associated suction and discharge piping and pipingcomponents.2. The fire/flood mode pumps and associated piping were originally the main fire waterpumps. Design changes were implemented to supply the fire water system with potablewater. The function of the fire/flood mode pumps was changed to provide an assuredsource of water to the SGs in the event of a flood.The periodic fire/flood mode pump and piping component internal visual inspections forloss of material will be performed at once every five years. Based on the periodic visualinspection of the internals of the components associated with the fire/flood pumps everyfive years there is reasonable assurance that loss of material will be managed such thatthe fire/flood mode pumps and the associated components will perform their designbasis function consistent with the current licensing basis.The changes to LRA Sections A.1.31 and B.1.31 follow, with additions underlined anddeletions lined through.LRA Section A.1.31* Visually inspect the interior and exterior surface of the fire/flood mode carbonsteel pumps and piping and piping components exposed to raw water to manageloss of material.LRA Section B.1.31Fire/flood mode pumps Visually inspect the interior andexterior surface of the fire/floodmode carbon steel pumps andpiping and piping componentsexposed to raw water tomanage loss of material.E1-30 of 79 The changes to affected LRA Table 3.3.2-2 line items are with additions underlined and deletions lined through.Component Intended Aging Effect Aging NUREG- Table 1Type Function Material Environment Requiring Management 1801 Item NotesManagement Program ItemPipin Pressure Carbon Raw water Loss of Periodic VII.G.A- 3.3.1-64 Eboundary steel (int) material Surveillance 33andPreventiveMaintenancePump Pressure Carbon Raw water Loss of FI.e-WateF VII.G.A- 3.3.1-64 AECasing boundary Steel (ext) material System 33PeriodicSurveillanceandPreventiveMaintenancePump Pressure Carbon Raw water Loss of FRe-qatei VII.G.A- 3.3.1-64 AECasing boundary Steel (int) material System 33PeriodicSurveillanceandPreventiveMaintenanceE1-31 of 79 The Chanqe to LRA Table 3.3.1 is with additions underlined and deletions lined throuqh.ItemNumberComponentAging Effect/MechanismAging ManagementProgramsFurther EvaluationRecommendedDiscussion4 4 4 + *3.3.1-64Steel, copperalloy piping,pipingcomponents, andpiping elementsexposed to rawwaterLoss of materialdue to general,pitting, crevice, andmicrobiologicallyinfluencedcorrosion; foulingthat leads tocorrosionChapter XI.M27,"Fire Water System"NoConsictont ;Aith NUREG-4801. Loss of materialfor most steel andcopper alloy fireprotection systemcomponents exposed toraw water is managedby the Fire WaterSystem Program. ThePeriodic Surveillanceand PreventiveMaintenance Programmanages loss ofmaterial for the steelfire/flood mode pumpcasings and associatedpiping using periodicvisual inspections.E1-32 of 79 RAI B.1.13-2Background:LRA Section B. 1.13, Fire Water System, Enhancement No. 4, associated with the "detection ofaging effects" program element of the LRA AMP states, "[r]evise Fire Water System Programprocedures to consider implementing the flow testing requirements of NFPA 25 or justify whythe flow testing requirements of NFPA should not be implemented."GALL Report AMP Xl. M27 recommends that system flow testing be used to ensure thatcorrosion and biofouling are not occurring and that the system's intended function is maintained.Issue:It is not clear to the staff whether flow testing is or is not included in the program. The staffcannot complete its evaluation of the program until it understands the basis for not includingflow testing or flow testing is included in the program.Request:State the basis for why reasonable assurance, in the absence of flow testing, can beestablished that the fire water system components will be adequately age-managed to meettheir intended function consistent with the current licensing basis, or include flow testing inaccordance with NFPA 25, "Standard for the Inspection, Testing, and Maintenance of WaterBased Fire Protection Systems, " 2011 Edition.RAI B.1.13-2 RESPONSETVA revises the Fire Water System Program full flow testing to be in accordance with full flowtesting standards of NFPA-25 (2011).The changes to LRA Sections A.1.13, B.1.13 and Commitment 9.D follow, with additionsunderlined and deletions lined through."Revise the Fire Water System Program full flow testing to be in accordance with full flowtesting standards of NFPA-25 (2011).Revise FFre W"ater System Program procedures to consider implementing the flow testingof NE.PA 25 or justify why the flow testing of N'P, should nbe implemented."Commitment changes: Commitment 9.1) is revised to reflect the changes shown above.E1-33 of 79 RAI B.1.13-3Background:During the audit, the staff reviewed Problem Evaluation Report 690236 which stated that the firejockey pump is running continuously. During the audit, the applicant stated that the nominalflowrate of the fire jockey pump is 50 gallons per minute (gpm) and in the early 2000s, leakagewas identified as 13-18 gpm.The "detection of aging effects" program element of GALL Report AMP XI. M27 states that,"[c]ontinuous system pressure monitoring, system flow testing, and wall thickness evaluations ofpiping are effective means to ensure that corrosion and biofouling are not occurring and that thesystem's intended function is maintained." The "parameters monitored/inspected" programelement states, "the parameters monitored are the system's ability to maintain pressure. "Inaddition, the GALL Report AMP XI. M27 program description states, "these systems arenormally maintained at required operating pressure and monitored such that loss of systempressure is immediately detected and corrective actions initiated."Issue:The degraded system performance is inconsistent with the GALL Report AMP Xl. M27 programdescription, and the "detection of aging effects" and "parameters monitored/inspected" programelements in that the jockey pump run times cannot be used to monitor for further systemdegradation. It is not clear to the staff how the Fire Water System program will be adjustedduring the period of extended operation if the jockey pump is running continuously.Request:State how the Fire Water System program will be adjusted during the period of extendedoperation if the jockey pump is running continuously.RAI B.1.13-3 RESPONSENo changes to the Fire Water System Program are necessary during the PEO. The followingdiscussion demonstrates consistency of the SQN Fire Water System Program with the programelements discussed in this RAI.With regard to the fire jockey pump leakage, a corrective action plan has been developed underthe SQN corrective action program to identify and repair the leaks in the Fire Water System.The SQN Fire Water System remains capable of performing its license renewal intendedfunction.The "detection of aging effects" program element of NUREG-1801 AMP XI.M27 states that,"[c]ontinuous system pressure monitoring, system flow testing, and wall thickness evaluations ofpiping are effective means to ensure that corrosion and biofouling are not occurring and that thesystem's intended function is maintained."With respect to performance of the jockey fire pump, continuous system pressure monitoring isprovided regardless of whether the jockey pump is running continuously. If pressure decreasesbelow normal, low system pressure is immediately detected and corrective actions initiated.The "parameters monitored/inspected" program element of NUREG-1801, AMP XI.M27 states,"the parameters monitored are the system's ability to maintain pressure." Consistent with theXI.M27 parameters monitored/inspected, the SQN fire water system and associated proceduresE1-34 of 79 provide for maintaining the system's ability to maintain pressure. If the jockey pump is unable tomaintain pressure, low system pressure is immediately detected and corrective actions initiated.NUREG-1801 AMP XI.M27 program description states, "these systems are normally maintainedat required operating pressure and monitored such that loss of system pressure is immediatelydetected and corrective actions initiated." Consistent with the NUREG-1801 AMP XI.M27program description, the SQN fire water system is normally maintained at required operatingpressure and monitored such that loss of system pressure is immediately detected andcorrective actions initiated.The continuous monitoring of the system pressure ensures the system can perform its designbasis function as the jockey pump fulfills its function of maintaining normal system pressure.RAI B.I.17-1Background:The GALL Report recommends that the extent, frequency, and examination methods for Class1, 2, 3, and MC component supports and related hardware (Le., structural bolting, high strengthstructural bolting, support anchorage to the building structure, accessible sliding surfaces,constant and variable load spring hangers, guides, stops, and vibration isolation elements) to bebased on ASME Section Xl, Subsection IWF, per 10 CFR 50.55a imposed ISI requirements.There is a reasonable assurance that a properly implemented IWF inspection program will beeffective to detect, evaluate, or repair age-related degradation before there is a loss ofcomponent support intended function. The VT-3 examination method specified by the programcan reveal loss of material due to corrosion and wear, verification of clearances, settings,physical displacements, loose or missing parts, debris or dirt in accessible areas of the slidingsurfaces, or loss of integrity at bolted connections.Issue:As part of the audit, the staff performed a walkdown of the essential raw cooling water (ERCW)building. During the walkdown, the staff noted that one of the strainer's support is exposed tocontinuous leakage and has evidence of corrosion of bolts and support plates.Request:Describe the actions planned to be taken to ensure that corrosion is mitigated and that thedegradation of the strainer's support will not prevent it from performing its intended functionduring the period of extended operation.RAI B.1.17-1 RESPONSEThe observed exposure of the ERCW strainer support to continuous water leakage andevidence of corrosion on the support had been identified by SQN personnel under the plant'scorrective action program prior to the license renewal audit. The configuration of the strainerallows leak off water to flow down the strainer and onto the ERCW strainer support causingcorrosion. Planned corrective actions include a design modification of the strainer to preventERCW supports from being continuously exposed to water, thus mitigating corrosion. Themodification proposes to install a "catch container" to the ERCW strainer to route the leak offwater coming out of the top of the strainer to a floor drain. The SQN Inservice Inspection -IWFProgram ensures the ERCW strainer support remains capable of performing its intendedfunction during the PEO.E1-35 of 79 RAI B.1.17-2Background:LRA Section B. 1.17 states that the applicant's Inservice Inspection -IWF program, withenhancement, is consistent with the program described in NUREG-1801 (GALL Report),Section XI.S3, ASME Section XI, Subsection IWF. GALL Report AMP XI.S3, "monitoring andtrending, "program element, states that examinations of Class 1, 2, 3, and MC componentsupports and related hardware (i.e., structural bolting, high strength structural bolting, supportanchorage to the building structure, accessible sliding surfaces, constant and variable loadspring hangers, guides, stops, and vibration isolation elements) that reveal unacceptableconditions which exceed the acceptance criteria and require corrective measures are extendedto include additional examinations in accordance with ASME Code Section X1, Subsection IWF-2430.Issue:Upon review of plant-specific operating experience, the staff noted cases in which degradedconditions were found during IWF examinations of Class 1, 2, 3, and MC component supportsand related hardware. Engineering evaluation determined that the as-foundcomponent/hardware was acceptable-as-is, but the component/hardware was still re-worked toas-new condition. Since it was determined that the as-found condition did not affect thesupport's capability to perform its design function, the licensee did not apply ASME SectionsIWF-2420 and IWF-2430 for successive or additional examinations.The ASME Code, Section X1, Subsection IWF program requires the inspection of the samesample of the total population of component supports and related hardware at each inspectioninterval. The staff's concern with respect to aging management is that if IWF supports that arepart of the inspection sample are reworked to as-new condition, they are no longer typical of theother supports and related hardware in the population. Subsequent IWF inspections of thesame sample would not represent the age-related degradation of the rest of the population.Request:When corrective actions are not required per the ASME Code, Section IWF, acceptance criteria,but a support within the IWF inspection sample is repaired to as-new condition without anexpansion of the ISI sample population size, describe how the ASME Section X1, SubsectionIWF Program will be effective in managing aging of similar/adjacent Class 1, 2, 3, and MCcomponent supports and related hardware that are not included in the ISI Program samplepopulation.RAI B.1.17-2 RESPONSEThe SQN Inservice Inspection (ISI)-IWF Program will continue to be effective in managing agingof similar/adjacent Class 1, 2, 3, and MC component supports that are not included in theoriginal sample population by utilizing IWF-2430 to perform inspections of similar/adjacentsupports any time an unacceptable condition is evaluated and found to have the potential toadversely affect the design function of the subject support. When the identified condition isevaluated and found to be acceptable for service (i.e. have no adverse impact to the designfunction of the support) the program will be enhanced to require evaluation of the identifiedcondition against similar/adjacent supports, to ensure the condition would not adversely affectthe design function of similar/adjacent supports throughout the PEO. Because the ISI-IWFE1-36 of 79 Program was established based on inspecting a sample to infer the condition of the totalpopulation of like components, this enhancement will ensure any identified active degradationmechanism is considered, either by evaluation or inspection as appropriate, for thesimilar/adjacent supports, regardless of whether any elective corrective measures are taken torestore the subject support to its original design condition.Note the corrective measures referenced in the RAI, performed in response to the identifiedunacceptable conditions, did not restore the entire support to a "as-new condition," consideringall age-related degradation mechanisms potentially affecting the support's numerous basematerial structural product forms, welded connections, fasteners, protective coatings, springcans, clamps, etc., but only restored a single identified condition to the applicable owner'srequirement(s).The changes to Commitment 12.B, LRA Appendices A and B follow, additions are underlined.LRA Appendix A changesA.1.17 Inservice Inspection -IWFThe ISI-IWF Program will be enhanced as follows."Revise ISI -IWF Proqram procedures to include the following corrective action guidance.When an indication is identified on a component support exceeding the acceptance criteriaof IWF-3400, but an evaluation concludes the support is acceptable for service, theprogram shall require examination of additional similar/adiacent supports per IWF-2430unless the evaluation of the identified condition against similar/adiacent supports concludesthat it would not adversely affect the design function of similar/adjacent supports. Thisevaluation will be performed regardless of whether the program owner chooses to performcorrective measures to restore the component to its original design condition, per IWF-3112.3(b) or IWF-3122.3(b)."LRA Appendix B changesB.1.17 Inservice Inspection -IWFEnhancementsThe following enhancements will be implemented prior to the period of extended operation.Elements Affected Enhancements7. Corrective Revise ISI -IWF Program procedures to include the following correctiveActions action guidance.When an indication is identified on a component support exceeding theacceptance criteria of IWF-3400, but an evaluation concludes thesupport is acceptable for service, the program shall requireexamination of additional similar/adiacent supports per IWF-2430unless the evaluation of the identified condition against similar/adiacentsupports concludes that it would not adversely affect the designfunction of similar/adiacent supports. This evaluation will be performedregardless of whether the program owner chooses to performcorrective measures to restore the component to its original designcondition, per IWF-3112.3(b) or IWF-3122.3(b).E1-37 of 79 Commitment changes:Revise Commitment 12.B as shown below. Additions are underlined."Revise ISI -IWF Program procedures to include the following corrective action guidance.When an indication is identified on a component support exceeding the acceptance criteriaof IWF-3400, but an evaluation concludes the support is acceptable for service, the programshall require examination of additional similar/adiacent supports per IWF-2430 unless theevaluation of the identified condition against similar/adiacent supports concludes that itwould not adversely affect the design function of similar/adiacent supports. This evaluationwill be performed regardless of whether the program owner chooses to perform correctivemeasures to restore the component to its original design condition, per IWF-3112.3(b) orIWF-3122.3(b)."RAI B.1.19-1Background:The GALL AMP Xl. M38, "Inspection of Internal Surface in Miscellaneous Piping and DuctingComponents" states that this program is not intended for use on piping and ducts whererepetitive failures have occurred from loss of material that resulted in loss of intended function.AMP Xl. M38 further recommends using a plant-specific program if operating experienceindicates that there have been repetitive failures.During the audit, a review of the Operating Experience Summary and "operating experience",program element for the Internal Surfaces in Miscellaneous Piping and Ducting Componentsprogram was performed. The applicant stated that it would be inappropriate to manage agingeffects for these material-environment combinations in these systems:" copper-alloy -condensation, and carbon steel -waste water* ventilation, station drains, waste disposal, and diesel generatorsThe applicant further stated that the plant-specific Periodic Surveillance and PreventiveMaintenance Program would be used to manage the effects of aging for these systems.Issue:The following LRA tables contain material/environment/system combinations where repetitivefailures are known to occur, however those combinations are being age-managed by theInternal Surfaces in Miscellaneous Piping and Ducting Components program.3.3.2-4: carbon steel & waste water3.3.2-5: copper alloy & condensation3.3.2-8: carbon steel & waste water3.3.2-13: carbon steel & waste water3.3.2-15: carbon steel & waste waterE1-38 of 79 Request:Describe how the Inspection of Internal Surfaces of Miscellaneous Piping and DuctingComponents Program is adequate to monitor the material/environment and systemcombinations listed above, when operating experience indicates that a plant-specific programshould be used to monitor the aging effects of repetitive failures.RAI B.1.19-1 RESPONSEThe approach taken for the integrated plant assessment (IPA) for SQN license renewal is tocredit periodic inspections if repetitive loss of intended function has been observed. Becausethe Internal Surfaces in Miscellaneous Piping and Ducting Components Program includesinspections that are opportunistic, not periodic, this program was not used in the LRA formaterial/environment and system combinations when operating experience indicated there hadbeen repetitive failures. Use of this program in the tables listed above has been reviewed, andwith one exception as discussed below, has been found appropriate.The statement that lists these material-environment combinations for the specified systems is inthe LRA Section B.1.19, Internal Surfaces in Miscellaneous Piping and Ducting Components, inthe discussion of OE. The statement was based on a preliminary screening of OE that identifiedmiscellaneous heating, ventilation and air conditioning (HVAC); aux building and reactorbuilding gas treatment and ventilation; station drainage; waste disposal; and standby dieselgenerator systems as possibly experiencing repetitive failures, which would require for certaincomponents use of the Periodic Surveillance and Preventive Maintenance (PSPM) Programinstead of the Internal Surfaces in Miscellaneous Piping and Ducting Components Program.This determination was based. on identifying problem evaluation reports (PERs) involvingspecific component-environment combinations for each system. Further review duringdevelopment of the aging management review reports determined that these PERs were notindicative of repetitive losses of system intended function for the system components subject toaging management review that are represented by the tables listed above. Therefore, thestatement as written in LRA Section B. 1.19 is incorrect and is revised with additions underlinedand deletions lined through.In response to this RAI, the identified PERs were reevaluated to confirm the originalconclusions. Although this review confirmed that there have been no documented repetitivefailures resulting in loss of system intended function for the components represented in thetables listed above, a repetitive failure was identified for a specific set of components in thewaste disposal system that are subject to aging management review in accordance with 10 CFR54.4(a)(2) and represented by the component types listed in LRA Table 3.3.2-17-27.Thisoccurred in piping and valves associated with the cask decontamination collection tank (CDCT),as shown on LRA drawing LRA-1,2-47W30-2, locations A-F, 10-12. The CDCT is used duringoutages for water processing. As a result of this finding, the effects of aging on the affectedcomponents will now be managed by the PSPM Program rather than the Internal Surfaces inMiscellaneous Piping and Ducting Components Program. LRA Table 3.3.2-17-27 does notrequire revision because the component types affected (i.e., filter housing, piping, pump casing,tank, valve) are already represented by line items showing these component types made fromcarbon steel in a waste water environment with loss of material managed by the PSPMProgram. (These line items also represent abandoned equipment for which aging effects aremanaged by the PSPM Program.)E1-39 of 79 For LRA Table 3.3.2-4, no repetitive failures were identified for carbon steel in waste water inthe miscellaneous HVAC systems; therefore, use of the Internal Surfaces of MiscellaneousPiping and Ducting Components Program is appropriate.For LRA Table 3.3.2-5, no repetitive failures were identified for copper alloy exposed tocondensation in the aux building and reactor building gas treatment/ventilation system;therefore, use of the Internal Surfaces of Miscellaneous Piping and Ducting ComponentsProgram is appropriate.For LRA Table 3.3.2-8, no repetitive failures were identified for carbon steel in waste water inthe station drainage systems; therefore, use of the Internal Surfaces of Miscellaneous Pipingand Ducting Components Program is appropriate.For LRA Table 3.3.2-13, no repetitive failures were identified for carbon steel in waste water inthe waste disposal systems; therefore, use of the Internal Surfaces of Miscellaneous Piping andDucting Components Program is appropriate. However, repetitive failures were identified forcarbon steel components associated with the CDCT and exposed to waste water; therefore,aging effects for these components will be managed by the PSPM Program as shown in LRATable 3.3.2-17-27.For LRA Table 3.3.2-15, no repetitive failures were identified for carbon steel in waste water inthe standby diesel generator system; therefore, use of the Internal Surfaces of MiscellaneousPiping and Ducting Components Program is appropriate.Use of the Internal Surfaces of Miscellaneous Piping and Ducting Components Program isadequate to manage the effects of aging on the material/environment combinations in thesesystems as shown in LRA Tables 3.3.2-4, 3.3.2-5, 3.3.2-8, 3.3.2-13, and 3.3.2-15. Asdiscussed above, the PSPM program will be used for the CDCT components represented byline items in LRA Table 3.3.2-17-27.The change to LRA sections A.1.31, B.1.19, and B.1.31 follows, with additions underlined anddeletions lined through.LRA Section A.1.31, Periodic Surveillance and Preventive Maintenance Program, add thefollowing sub-bullet item under the bullet for "Nonsafety-related systems affecting safety-relatedsystems.") "Perform wall-thickness evaluations of carbon steel filter housings, piping, pumpcasings, tank, and valve bodies in the waste disposal system (System 077)associated with the cask decontamination collector tank (CDCT) to identify lossof material."LRA statement in Section B.1.19"A review of operating experience for plant systems with repetitive losses ofcomponent intended function due to aging effects was performed. The reviewfound no repetitive losses of system intended function with the specificexception of repetitive failures identified for components associated with theE1-40 of 79 cask decontamination collection tank (CDCT) in the waste disposal system.This tank is used for processing water during refueling outages. Aging effectsfor the carbon steel components associated with use of this tank will bemanaged by the plant-specific Periodic Surveillance and PreventiveMaintenance Program (Section B.1.31).MiscA!lfneous Piping and Ducting Components Program would be inappropriatefor managing aging effecnts for these material enVironmrent cobntosin thefollowing plant systems:--Comb~inations:copperaGlloy condeRnatin, and carbon steel waste wate.r.-Systems: ventilation, Astation- ddrain, waste disposal, and diesel generatorFs.Fknrr'.~nrn .k-~ ...I a ...* -~ .fl4.rnrj ~n ~ n ,n all..~ nnn a fir4Drn~ ,an*i~ an II A~, n+a n, nan* B PF J P g IIi-'rGram (sýectiOn 13.1.31) managaes the effectS of aging f9r thso materiai and-Ienvironment combinations in these systems."v vLRA Section B.1.31, Periodic Surveillance and Preventive Maintenance:Nonsafety-related Perform wall-thickness evaluations of a representativesystems affecting sample of carbon steel filter housings, piping., pump casings,safety-related tank, and valve bodies in the waste disposal system (Systemsystems (continued) 077) associated with the cask decontamination collector tank(CDCT) to identify loss of material.RAI B.1.21-1Background:In element 10 (operating experience) of the LRA AMP B. 1.21, Metal Enclosed Bus Inspection,the applicant states that the Metal Enclosed Bus (MEB) program is a new program for whichthere is no operating experience at SQN involving the aging effects managed by this program.In the GALL Report AMP XI.E4, it states that industry operating experience has shown thatfailures have occurred on MEBs caused by cracked insulation and moisture or debris buildupinternal to the MEB. During the audit on March 26, 2013, the staff became aware of a MEBfailure event in 2009 which resulted in the tripping of both units. In problem event report (PER)166884, the applicant states that the bus failed catastrophically on August 5, 2009. Theapplicant determined that the failure of the bus was caused by cracked Noryl insulation andmoisture intrusion inside the bus.Issue:Based on the MEB failure identified in PER 166884, the staff is concerned that SQN operatingexperience may not support the applicant's conclusion that LRA AMP B. 1.21 will be effective inmanaging the aging effect of MEBs for the period of extended operation.E1-41 of 79 Request:1. Describe corrective actions taken or planned to prevent recurrence of a MEB failurewithin the scope of license renewal.2. Revise element 10 of the LRA to incorporate lessons learned from this operatingexperience (OE) and explain why LRA AMP B. 1.21 will be effective in managing MEBaging effects.RAI B.1.21-1 RESPONSE1. The equipment failures associated with the SQN Units 1 and 2 automatic reactor trip onRCP bus undervoltage on March 26, 2009. The cause of the reactor trip was a phase-to-phase fault of a 6900V metal enclosed bus (MEB) due to cracked Noryl sleevinginsulation over a bus bar and water intrusion into the bus enclosure. Prior to the event,preventive maintenance tasks did not identify cracked sleeving or ensure the busenclosure was adequately sealed upon completion of the tasks.Corrective actions implemented to prevent recurrence of this event include the following.* Replaced the bus and bus enclosure that contained degraded Noryl insulation(sleeving), which were associated with transformers Common Station ServiceTransformer C, Cooling Tower Transformer (CTT) A and CTT B with an improveddesign that is more resistant to moisture intrusion." Revised preventive maintenance instructions for metal-enclosed bus (MEB) toincrease the inspection frequency, emphasize monitoring to identify crackedsleeving, reseal the bus duct after the inspection and enter deficiencies found intothe corrective action program. In addition, the instructions include direction to reviewOE relative to medium-voltage bus prior to performance of the preventivemaintenance task.These items have been effective to date for preventing reoccurrence of MEB failures atSQN.2. The proposed SQN Metal Enclosed Bus Inspection Program will provide an effectiveaging management program for the PEO because it is the same program described inNUREG-1801,Section XI.E4, which incorporates industry OE. The lessons learnedfrom the SQN OE with MEB failure are addressed by the SQN OE program.Specifically, consistent with NUREG-1801,Section XI.E4, Detection of Aging Effects, theSQN Metal Enclosed Bus Inspection Program provides for visual inspection of insulatingmaterial for signs of embrittlement and cracking. The program also includes inspectionof accessible elastomers (e.g., gaskets, boots, and sealants) for degradation that couldlead to a path for water intrusion into the bus.E1-42 of 79 To provide specific discussion of this SQN OE, the change to LRA Section B.1.21 follows, withadditions underlined and deletions lined through.B.1.21 METAL ENCLOSED BUS INSPECTIONOperatingi Experience"The Metal Enclosed Bus Inspection Program is a new program. Industry operating experienceand SQN operating experience will be considered in the implementation of this program. Plantoperating experience will be gained as the program is executed and will be factored into theprogram via the confirmation and corrective action elements of the SQN 10 CFR 50 AppendixB quality assurance program.iS no operating SQN has experienced metal enclosed bus failuresassociated with cracked Noryl insulation and moisture intrusion into the bus enclosure. Themost recent failure occurred in 2009. The failure resulted from degraded Noryl sleevinginsulation on bus bars coupled with water intrusion into the bus. Corrective actionsincluded replacing the degraded MEB and providing enhanced preventive maintenanceinstructions. The enhanced instructions are consistent with Metal Enclosed Bus InspectionProgram provisions to inspect bus insulation and bus enclosure seals and gaskets thatprevent moisture intrusion.Increased connection resistance, reduced insulation resistance, loss of material, hardening andloss of strength are at SQN iRn"olviRng the aging effects managed by this program. The pastMEB failures at SQN were the result of aging effects that the new Metal Enclosed BusInspection Program is designed to manage.The elements of the program inspections (e.g., the scope of the inspections and inspectiontechniques) are consistent with industry practice and have been used effectively at SQN inother programs. Accordingly, there is reasonable assurance that this new aging managementprogram will be effective during the period of extended operation.As discussed in element 10 to NUREG-1801,Section XI.E4, this program considers thetechnical information and industry operating experience provided in SAND 96-0344, IEEE Std.1205-2000, NRC IN 89-64, NRC IN 98-36, NRC IN 2000-14, and NRC IN 2007-01."RAI B.1.21-2Backgqround:During the review of a plant procedure, SQN-1-Bus-202-CC/CE, the staff identified an issue withverifying proper torque. Section 5. 7. e of the procedure requires verifying bolts are properlytorqued. EPRI TR-104213, Bolted Joint Maintenance & Application Guide, states that boltsshould not be retorqued unless the joint requires service or the bolts are clearly loose. Verifyingthe torque is not recommended. The torque required to turn the fastener in the tighteningdirection (restart torque) is not a good indicator of the preload once the fastener is in service.Due to relaxation of the parts of the joint, the final loads are likely to be lower than the installloads. The GALL AMP XI.E4 recommends checking bus connections for increased resistanceby using thermography or by measuring connection resistance using a micro-ohmmeter.Issue:Re-torque is not recommended per industry guidance.E1-43 of 79 Request:Explain why procedure SQN-1-Bus-202-CC/CE requires the verification that bolts are properlytorqued versus the industry recommended practice not to retorque once the fastener is inservice.RAI B.1.21-2 RESPONSETVA has reevaluated the practice of retorquing to verify bolt torque on SQN MEB boltedconnections. A corrective action 702763-001 has been entered into the SQN corrective actionprogram to revise the applicable preventive maintenance procedure to eliminate the retorquingpractice and alternatively use connection resistance to evaluate MEB bolted connections. Thisrevision will make the SQN procedure consistent with the recommended industry practice.The practice of retorquing MEB connections is not part of the SQN Metal Enclosed BusInspection Program. Therefore, this change has no effect on the program description in LRASection B.1.21.RAI B.1.21-3Backqround:During the audit, the applicant indicated that it currently performs thermography of the MEBconnections with the MEB covers in place with the .bus fully loaded. The thermography test casewas not able to identify enough detail (distinction by temperature between component parts wasnot apparent) to consider this method effective. The staff noted that typically, infrared (IR)windows are installed on MEB covers for the purpose of thermography inspection.Issue:Without the installation of IR windows, the MEB cover may mask the temperature differencebetween the buses and will not be able to detect bus connection high resistance due to boltloosening.Request:If thermography is used, explain how this test will be effective to detect bus connection highresistance due to bolt loosening?RAI B.1.21-3 RESPONSEFor clarification, SQN preventive maintenance tasks do not specify thermography of MEBconnections with the MEB covers in place. When a new bus was placed in service, SQNperformed thermography one time with the MEB covers in place. The distinction by temperaturebetween component parts was determined inadequate to allow use of this method to assess theMEB conditions.Based on this experience, SQN will perform thermography of the MEB with the covers in placeonly if there is an IR window installed. Thermography will be an effective test to detect busconnection high resistance due to bolt loosening if the use is limited to MEB with IR windowsinstalled.E1-44 of 79 The change to LRA Section B.1.21 follows, with additions underlined and deletions linedthrough."Inspections of MEB will include the bus and bus connections, the bus enclosure assemblies,and the bus insulation and insulators. A sample of the accessible bolted connections will beinspected for loose connections. The bus enclosure assemblies will be inspected for loss ofmaterial and elastomer degradation. This program will be used instead of the StructuresMonitoring Program (SMP) for external surfaces of the bus enclosure assemblies. The businsulation or insulators will be inspected for degradation leading to reduced insulationresistance. These inspections will include visual inspections, as well as quantitativemeasurements, such as thermography or connection resistance measurements, as required.Thermography will be performed on bus connections with the MEB covers in place, only if thebus enclosure is equipped with an IR window to facilitate the inspection."The change to LRA Section A.1.21 follows, deletions are shown with strikethrough andadditions are underlined."MEB enclosure assemblies will be visually inspected internally for evidence of loss of material.Internal portions of the MEB enclosure assemblies will also be inspected for cracks, corrosion,foreign debris, excessive dust buildup, and evidence of water intrusion. MEB enclosureassembly external surfaces will be inspected for evidence of loss of material and hardeningand loss of strength (i.e., change in material properties) due to elastomer degradation. Businsulation or insulators will be visually inspected for signs of reduced insulation resistance dueto thermal/ thermoxidative degradation of organics/thermoplastics, radiation-induced oxidation,moisture/ debris intrusion, or ohmic heating, as indicated by embrittlement, cracking, chipping,melting, swelling, or discoloration, which may indicate overheating or aging degradation.Internal bus supports or insulators are visually inspected for structural integrity and signs ofcracks. A sample of accessible bolted connections will be inspected for increased connectionresistance at least once every ten years for loose connections using quantitativemeasurements such as thermography or connection resistance (micro-ohm) measurements.Twenty percent of the population with a maximum sample of 25 constitutes a representativesample size for accessible bolted connections. Otherwise, a technical justification of themethodology and sample size used for selecting components should be included as part of thesite documentation. The alternative to quant'tative measurements could be .used for accessibleMEB bolted connections covered with heat shrink tape or insulating boots. A sample ofaccessible bolted connections covered with heat shrink tape or insulating boots permanufacturer's recommendations can be inspected using the alternate qualitative methods. Ifthe alternate inspection method using visual is the only method performed, the visualinspection must be performed prior to the PEO and at least once every five years for insulationmaterial surface anomalies such as embrittlement, cracking, chipping, melting, discoloration,swelling, or surface contamination. Thermography will be performed on bus connections withthe MEB covers in place, only if the bus enclosure is equipped with an IR window to facilitatethe inspection."E1-45 of 79 RAI B.1.23-1Backgqround:LRA Section B. 1.23 and applicant's program basis document state that the Nickel AlloyInspection Program detects RCP boundary cracking and leakage due to primary water stresscorrosion cracking (PWSCC). LRA Section B. 1.23 states that the program uses the examinationand inspection requirements of 10 CFR 50.55a and industryguidelines (e.g., MRP- 139),consistent with GALL Report AMP Xl. 11 B, "Cracking of Nickel-Alloy Components and Loss ofMaterial Due to Boric Acid-Induced Corrosion in Reactor Coolant Pressure BoundaryComponents (PWRs only)."During the audit, the staff noted that evidence of borated-water leakage and corrosion wasidentified in the visual inspection of the Unit I reactor vessel bottom head and keyway areaduring the 2006 refueling outage. The applicant's plant event record related to this inspectionindicates that the affected components were the reactor vessel, vertical and horizontal sectionof mirror insulation surrounding the reactor vessel, thimble tubes and thimble tube supportstructure, and concrete wall surrounding the reactor pressure vessels.Issue:The LRA does not address which component was the source of the borated-water leakagediscussed above or whether the leakage resulted from aging-related degradation of reactorvessel and piping components. The staff also needs confirmation on whether the applicant tookadequate corrective action for the observed leakage.In addition, the staff needs to clarify how the applicant's program manages and resolves thesituation that borated-water leakage and associated corrosion products interfere with the visualexamination of the components within the scope of the program (e.g., the visual examination ofASME Code Cases N-770-1, N-729-1 and N-722-1).Request:1. Describe the source of the borated-water leakage that was observed during the 2006refueling outage for Unit 1.a) As part of the response, clarify whether the leakage resulted from aging-relateddegradation of reactor vessel and piping components.b) If so, identify the component and aging effect that induced the leakage.2. Clarify whether the applicant has cleaned the past borated-water leakage residues andcorrosion products. If not, justify why borated-water leakage residues and corrosionproducts left in service would not interfere with the visual examination that are includedin the program.3. Clarify how the program manages and resolves the situation that borated-water leakageand associated corrosion products interfere with the visual examination of thecomponents that are included in the scope of the program.E1-46 of 79 RAI B.1.23-1 RESPONSE1. The source of the leakage observed during the 2006 nickel alloy inspection wasrefueling water leaking past the refueling cavity seal over the Loop 2 cold leg nozzlearea. This seal and other removable reactor refueling cavity seals are installed duringrefueling prior to filling the refueling cavity. The leakage was due to a seal design thatwas not sufficiently robust, and was not attributed to age-related degradation of thereactor vessel or piping components. The seal design was changed to an improveddesign.2. Plant maintenance personnel removed the boric acid residue noted during the 2006nickel alloy inspection. The area below the reactor vessel was inspected after thecleaning with the result that the boric acid residue was removed. The inspection reportfor the 2006 nickel alloy inspection documented that "all penetrations were accessibleand there were no obstructions. The general overall condition of the penetrations andbare head surface was very good." The observation that there were no obstructions andthat the bare head surface condition was good is another indication that leakageresidues and corrosion products from the refueling cavity seal leakage had beenadequately removed.3. The Nickel Alloy Inspection Program resolves the situation of interferences with visualexaminations of program components by removing the interferences as necessary toallow effective examinations. Per industry guidance for an effective boric acid inspectionprogram for pressurized water reactors, "The disposition activity for an identified leakshould not be completed until boric acid cleanup is sufficient to ensure that the basemetal condition is adequately assessed." The implementing procedures for the NickelAlloy Inspection Program include provisions that implement industry guidance.RAI B.1.23-2Background:LRA Section B. 1.23 for the Nickel Alloy Inspection Program states that the program detects andmanages reactor coolant pressure boundary cracking and leakage due to primary water stresscorrosion cracking (PWSCC). The LRA also states that the program uses the examination andinspection requirements of 10 CFR 50.55a and industry guidelines (e.g., MRP-139), consistentwith GALL Report AMP X1, 11 B, "Cracking of Nickel-Alloy Components and Loss of MaterialDue to Boric Acid-Induced Corrosion in Reactor Coolant Pressure Boundary Components(PWRs only)."During the audit, the staff noted the following operating experience of the applicant. During thevolumetric examinations of the Unit I reactor vessel upper head penetration nozzles inaccordance with NRC Order EA-03-009, the applicant found wear indications on control roddrive mechanism (CRDM) penetration nozzles 1, 2, 3, 4 and 5.The applicant's plant event record regarding this operating experience also indicates that thesewear indications were due to the interaction between the inside surfaces of the CRDMpenetration nozzles and the centering pads of the CRDM thermal sleeves located inside thepenetration nozzles. The applicant's PER further indicates that the typical wear indication wasapproximately 0. 7 inches long in the axial direction and 360 degrees in circumference.E1-47 of 79 Issue:The LRA or applicant's program basis document does not describe how these wear indicationswill be monitored and managed to maintain the integrity of the CRDM penetration nozzles andto prevent potential reactor coolant pressure boundary leakage.Request:1. Provide the following baseline information related to the observed wear indications:a) The total number of the CRDM penetration nozzles for each unit, and the number of.CRDM penetration nozzles that have been found with wear in each unitb) Clarification on whether any of the wear indications are located in the RCP boundaryportions of the penetration nozzles.c) Clarification on whether all of the wear indications are located within the examinationvolumes that are inspected in the scope of the program (e.g., within the examinationvolume of the volumetric examination specified in ASME Code Case N-729-1).d) The maximum depth of the observed wear indications in each unit, and the nominalwall thickness of the CRDM penetration nozzlese) The acceptance criteria that were used to justify the continued service of thepenetration nozzles with the wear indications, and the technical basis of theacceptance criteria2. Clarify whether the other types of applicant's reactor vessels upper head penetrationnozzles (e.g., vent line nozzles) are susceptible to wear due to the interaction withpenetration thermal sleeves.a) If so, provide the baseline information, which is requested in Part I of this RAI, asapplied to the non-CRDM-type penetration nozzles3. Clarify why the LRA does not identify loss of material due to wear as an applicable agingeffect that should be managed for the CRDM penetration nozzles and other types ofreactor vessel upper head penetration nozzles.4. If loss of material due to wear is determined to be an applicable aging effect for thereactor vessel upper head penetration nozzles, describe the inspection method, scope,frequency, and acceptance criteria that will be used to detect and manage the agingeffect for the period of extended operation.a) In addition, describe the technical bases of the applicant's inspection approach andacceptance criteria5. Ensure that the LRA is consistent with the response, including program enhancementsand additional AMR items as necessary.RAI B.1.23-2 RESPONSE1.a) There are 78 CRDM head penetrations in each unit. Unit 1 and Unit 2 had areas ofthinning identified on the inside surface of the same five CRDM head penetration adaptersduring the reactor vessel head inspections in 2007. The five CRDM head adapters withobserved thinning are the only head adapters with weld examination volumes adjacent tothe wear pad locations. They are located at approximately top dead center of each reactorvessel head and have the greatest length of thermal sleeve exposed to fluid flow forces.E1-48 of 79 Consequently wear at these locations should be representative, if not bounding, of wearon other CRDM head adapters.1.b) The wear locations are in the reactor coolant pressure boundary (i.e., ASME Section IIIClass 1 pressure boundary).1.c) Seventy eight CRDMs, on each unit, have thermal sleeves with centering pads whereanalyzed wear could occur. Not all of the analyzed wear locations are within theexamination volume; however, the Code mandated examinations of the CRDMs include arepresentative number of wear locations that are inspected at a frequency in accordancewith Code Case N-729-1 and 10 CFR 50.55a.1.d) The observed depth of wear is equal to or less than 0.05 inches. The nominal CRDMhead adapter wall thickness is 0.625 inches.1 .e) The wear acceptance criteria is less than or equal to 0.05 inches. The technical basis forthe acceptance criteria is that 0.05 inches is the maximum credible amount of wear basedon the design features and with that amount of wear, the remaining CRDM head adapterwall thickness is sufficient to perform its design function. The maximum wear cannotexceed 0.05 inches because the thermal sleeve centering pads are designed to protrude amaximum of 0.1075 inches beyond the thermal sleeve tube outside diameter. Because thecentering pad will also wear due to the interaction with the CRDM head adapter andconsists of weaker material, the wear depth on the CRDM head adapter would not exceed0.05 inches.The technical basis considers reduced CRDM head adapter wall thickness due to wear,updated seismic loads, and updated loss of coolant accident loads. All of the stressintensity and fatigue usage factor limits used in the design of the Unit 1 and 2 CRDM headadapters as specified in the following ASME Code Editions remain satisfied with theincorporation of the reduced CRDM head adapter wall thickness." ASME Boiler and Pressure Vessel Code,Section III, Nuclear Vessels, 1968 Editionwith Addenda up to and including winter (1968)* ASME Boiler and Pressure Vessel Code,Section III -Division I, Appendix F, NuclearPower Plant Components, 1974 Edition2. There are five additional reactor pressure vessel head penetrations none of which have athermal sleeve. Therefore, they are not subject to wear due to interaction with a thermalsleeve.3. The LRA does not identify loss of material due to wear because during the integrated plantassessment (IPA), it was determined that the issue related to wear caused by the thermalsleeves on the CRDM head adapters had been analyzed and resolved. The locations ofthe CRDM thermal sleeve centering pads located outside the examination volume havenot been specifically inspected for head adaptor wear. However, the design of the thermalsleeve centering pads is identical on all CRDM penetrations and the worst case postulatedwear used in the analysis is bounding for all centering pads. The analysis demonstratesE1-49 of 79 that loss of material due to wear associated with the thermal sleeve centering pads is notan aging effect requiring management. Although inspections are not deemed necessary tomanage loss of material due to wear, the CRDMs with thermal sleeve centering padslocated within the examination volume are representative locations and are re-inspected atthe RPV head volumetric exam frequency based on Code Case N-729-1 and 10 CFR50.55a.4. For reasons provided above loss of material due to wear is not an aging effect requiringmanagement for the CRDM head adapters.5. The LRA is consistent with the response to this RAI. No additional line items arenecessary because loss of material due to wear is not an aging effect requiringmanagement for the CRDM head adapters.RAI B.1.25-1Backgqround:NUREG-1801, Revision 2, the GALL Report addresses inaccessible power cables in AMPXl.E3, "Inaccessible Power Cables Not Subject to 10 CFR 50.49 Environmental QualificationRequirements." The purpose of this AMP is to provide reasonable assurance that the intendedfunctions of inaccessible or underground power cables (400V to 35 kV), that are not subject toenvironmental qualification requirements of 10 CFR 50.49 and are exposed to wetting orsubmergence will be maintained consistent with the current licensing basis. The scope of theprogram applies to inaccessible (e.g. in conduit, duct bank, or direct buried installations) powercables within the scope of license renewal that are subject to significant moisture. Significantmoisture is defined as periodic exposures to moisture that last more than a few days (e.g., cablewetting or submergence in water). NUREG-1800, Revision 2, "Standard Review Plan for Reviewof License Renewal Applications for Nuclear Power Plants" (SRP), Table 3.0-1 providesguidance for FSAR supplements for aging management of applicable systems, including theGALL Report AMP XI.E3.Industry operating experience provided by NRC licensees in response to GL 2007-01 hasshown: (a) that there is an increasing trend of cable failures with length in service, (b) that thepresence of water/moisture or submerged conditions appears to be the predominant factorcontributing to inaccessible or underground power cable failure. The staff has determined,based on the review of the cable failure data, that an annual inspection of manholes and a cabletest frequency of at least every 6 years (with evaluation of inspection and test results todetermine the need for an increased inspection or test frequencies) is a conservative approachto ensure the operability of power cables and, therefore, should be considered.In addition, industry operating experience has shown that some NRC licensees haveexperienced cable manhole water intrusion events, such as flooding or heavy rain, that subjectscables within the scope of GALL Report, AMP XI.E3 to significant moisture. The staff hasdetermined that event driven inspections of cable manholes, in addition to the one year periodicinspection frequency, is a conservative approach and, therefore, should be considered. TheE1-50 of 79 GALL Report AMP XI.E3 states that periodic actions should be taken to prevent inaccessiblecables from being exposed to significant moisture. Examples of periodic actions are inspectingfor water collection in manholes and conduits and draining water as needed. The inspectionshould include direct observation that cables are not wetted or submerged, and cables/spicesand cable support structures are intact, and that dewatering/drainage systems (sump pumps)and associated alarms operate properly.Issue:During review of the applicant's operating experience, including work orders, PERs, andinspection reports, the staff identified unresolved cases of unacceptable levels of water inmanholes and hand-holes which could potentially expose in-scope power cables to significantmoisture.When a power cable is exposed to wet or submerged conditions for which it is not designed, anaging effect of reduced insulation resistance may result, causing a decrease in the dielectricstrength of the conductor insulation. This insulation degradation caused by wetting orsubmergence can potentially lead to failure of the cable's insulation system. Sequoyahinaccessible power cable operating history includes reference to PERs 432510,585074,589672,622595,432510, and letter dated March 12, 2013, to S.L. Harvey, "Response toCorporate Oversight-Level I Escalation letter (ERCW Duct bank dewatering efforts), " thatidentify unresolved concerns with standing water and timely dewatering of manholes. NRCIntegrated Inspection Report 05000327/2012002,05000328/2012002 identified a green findingfor the applicant's failure to meet the requirements of corrective action program procedure NPG-SPP-03.1.7, PER Actions, Revision 2. The finding involved the applicant's failure to ensure thatthe corrective action plan and associated actions addressed the required action and scheduleassociated with PER 432510. The issue was entered into the-applicant's corrective actionprogram as PERs 433761,432510, and 505259.The staff is concerned that the applicant's manhole inspections, including maintenance of sumppumps and cable support structures may not be adequate to prevent in-scope inaccessiblepower cables form being subjected to significant moisture. Additional information is requiredbefore a determination can be made regarding the sufficiency of LRA AMP B. 1.25 to detect andmanage the effects of aging.Request:1. Additional information is required that demonstrates proactive and satisfactory manhole,sump pump, and cable support structure inspection, maintenance and corrective actionsto prevent in-scope inaccessible power cables from being exposed to significantmoisture.a) Include a summary discussion of corrective actions and schedule for completion.2. Describe how plant specific and industry operating experience will be evaluated andincorporated into the GALL Report LRA AMP B. 1.25 to prevent exposure of in-scopeinaccessible power cables to significant moisture before and during the period ofextended operation.3. Describe inaccessible power cable testing, test frequencies and test applicability thatdemonstrate that in-scope inaccessible power cables, including inaccessible low voltagepower cable, will continue to perform their intended function before and during the periodof extended operation.E1-51 of 79 RAI B.1.25-1 RESPONSE1. During implementation of the new B.1.25 AMP, implementing documents will be modified ornew documents developed as necessary to achieve consistency with the AMP described inNUREG-1801,Section XI.E3.The AMP described in NUREG-1801 Section XI.E3 was developed based on the extensive OEreferenced in that section. Also as stated in LRA Section B.1.25, industry OE will be consideredin the implementation of this program and plant OE will be gained as the program is executedand will be factored into the program via the confirmation and corrective action elements of theSQN 10 CFR 50 Appendix B quality assurance program.The following summary discussion addresses the maintenance and corrective actionsassociated with SQN manholes, sump pumps and cable support structures to minimize theexposure of in-scope inaccessible power cables to significant moisture.As documented in the SQN corrective action program, there have been multiple instances ofwater in manholes at SQN. In 2012, a report was initiated in the correction action program todocument the trend of high levels of water in manholes that the work control process is notresolving in a timely manner. The NRC Integrated Inspection Report 05000327/2012002,05000328/2012002, dated April 30, 2012, identified a finding of very low safety significance(green) related to water in manholes. In response to the identified issues with untimely removalof water from manholes, the PM task instructions were revised to require water removal, iffound, from the manholes before the PM task could be closed. SQN experience since revisingthe PM instructions has been that the water, if any, has been removed within a week of initiatingthe PM activity.As a result of the negative OE with water in the manholes, a team of TVA personnel wasestablished in early 2013 to resolve the dewatering issues with safety-related manholes. Theteam is scheduling activities which will repair or replace sump pumps and discharge piping asnecessary to improve dewatering performance. In addition, TVA is issuing a modification toenhance the ability to remove water from manholes without having to remove the heavy missileshield manhole covers. The modification will enlarge the size of the openings in the covers ofmanholes.The cable support structure inspection is performed at least once every five years as part of theSQN SMP. The inspections described in NUREG-1801,Section XI.E3 will be implemented aspart of the new SQN Non-EQ Inaccessible Power Cables (400 V to 35 kV) Program described inLRA Section B. 1.25 prior to entering the PEO. During the PEO, the periodic inspections ofmanholes including cable support structures will be completed at least once every year(annually).2. The SQN Non-EQ Inaccessible Power Cables (400 V to 35 kV) Program is based on industryOE up to the time of Revision 2 of NUREG-1801. As stated in LRA Section B.1.25, industry OEwill be considered in the implementation of this program and plant OE will be gained as theprogram is executed and will be factored into the program via the confirmation and correctiveaction elements of the SQN 10 CFR 50 Appendix B quality assurance program. Detailsregarding how future industry OE is incorporated into the SQN aging management programsare provided in LRA Section B.0.4.E1-52 of 79 The SQN Non-EQ Inaccessible Power Cables (400 V to 35 kV) Program described in LRASection B.1.25, which is consistent with the AMP described in NUREG-1801,Section XI.E3without exception, provides the description of how plant-specific OE will be evaluated andincorporated into the AMP to minimize exposure of in-scope inaccessible power cables tosignificant moisture after this AMP is implemented."The program will include periodic inspections for water accumulation in manholes atleast once every year (annually). In addition to the periodic manhole inspections,manhole inspections for water after event-driven occurrences, such as flooding, will beperformed. Inspection frequency will be increased as necessary based on evaluation ofinspection results."3. The test frequencies and test applicability that demonstrate that in-scope inaccessible powercables, including inaccessible low-voltage power cables, will perform their intended functionafter the AMP is implemented are described in NUREG-1 801 Section XI.E3 as referenced inLRA Section B.1.25.The SQN Non-EQ Inaccessible Power Cables (400 V to 35 kV) Program described in LRASection B.1.25 is consistent with the aging management program described in NUREG-1801,Section XI.E3 without exception. The aging effects requiring management at SQN are the sameas the aging effects identified in NUREG-1801,Section XI.E3. The inaccessible power cabletesting will include one or more proven, commercially available tests for detecting deteriorationof the insulation system due to wetting or submergence for inaccessible power cables (400 V to35 kV) included in this program, such as dielectric loss (dissipation factor/power factor), ACvoltage withstand, partial discharge, step voltage, time domain reflectometry, insulationresistance and polarization index, line resonance analysis, or other testing that is state-of-the-artat the time the tests are performed. Inaccessible power (400 V to 35 kV) cables will be tested atleast once every six years to provide an indication of the condition of the cable insulationproperties. Test frequencies are adjusted based on test results and OE.The Non-EQ Inaccessible Power Cables (400 V to 35 kV) Program will be effective at managingthe effects of aging since it will incorporate proven power cable testing techniques at thefrequencies recommended in NUREG-1801,Section XI.E3. Application of specific testingtechniques will vary depending on cable voltage level, but the specific techniques will be thoseproven effective for the cable voltage level.RAI A.1.25-1Background:LRA FSAR Supplement Section A. 1.25 does not include the test techniques consistent withSRP Table 3.0-1, as follows: 'The applicant can assess the condition of the cable insulation withreasonable confidence using one or more of the following techniques: Dielectric loss(Dissipation Factor/Power Factor), AC Voltage withstand, Partial Discharge, Step Voltage, TimeDomain Reflectometry, Insulation Resistance and Polarization Index, Line Resonance Analysis,or other testing that is state-of-the-art at the time the tests are performed. One or more tests areused to determine the condition of the cables so they will continue to meet their intendedfunction during the period of extended operation."E1-53 of 79 Issue:In the absence of these testing techniques in the applicant's program description, this makesthe FSAR Supplement inconsistent with the basis document SQN-RPT-10-LRD04 and theGALL Report, AMP XI.E3, Program Description and Detection of Aging Effects which list thespecific tests.Request:Provide an adequate program description in the FSAR Supplement consistent with the GALLReport AMP XI.E3 and SRP Table 3.0-1 including the test techniques.RAI A.1.25-1 RESPONSETo be consistent with the SQN basis document SQN-RPT-1 0-LRD04, NUREG-1 801, SectionXI.E3, and NUREG-1 800, Table 3.0-1, the change to LRA Section A.1.25 follows with additionsunderlined. This markup applies to both RAI A. 1.25-1 and RAI A. 1.25-2, which affect thissection.A.1.25 Non-EQ Inaccessible Power Cables (400 V to 35 kV) Program"The Non-EQ Inaccessible Power Cables (400 V to 35 kV) Program manages the aging effectof reduced insulation resistance on the inaccessible power (400 V to 35 kV) cable systems thathave a license renewal intended function. The program includes periodic actions to preventinaccessible cables from being exposed to significant moisture. Significant moisture is definedas periodic exposures to moisture that last more than a few days (e.g., cable wetting orsubmergence in water). In this program, inaccessible power (400 V to 35 kV) cables exposedto significant moisture are tested at least once every six years to provide an indication of thecondition of the cable insulation properties. Test frequencies are adjusted based on test resultsand operating experience. The specific type of test performed is a proven test for detectingdeterioration of the cable insulation. One or more proven, commercially available teststechniques will be used for detecting deterioration of the insulation system due to wetting orsubmergence for inaccessible power cables (400 V to 35 kV) included in this program, such asdielectric loss (dissipation factor/power factor), AC voltage withstand, partial discharge, stepvoltage, time domain reflectometry, insulation resistance and polarization index, line resonanceanalysis, or other testing that is state-of-the-art at the time the tests are performed. Theprogram includes periodic inspections for water accumulation in manholes at least once everyyear (annually). The inspections will include direct observation that cables are not wetted orsubmerged, that cables, splices and cable support structures are intact, and dewateringsystems (i.e., sump pumps) and associated alarms, if applicable, operate properly. In addition,operation of dewatering systems will be inspected and operation verified prior to any known orpredicted flooding events. In addition to the periodic manhole inspections, manholeinspections for water after event-driven occurrences, such as flooding, will be performed.Inspection frequency will be increased as necessary based on evaluation of inspection results."RAI A.1.25-2Backqround:LRA FSAR Supplement Section A. 1.25 does not provide periodic inspection specifics consistentwith SRP Table 3.0-1 as follows: "the applicant shall include periodic inspection specifics asfollows: The inspection should include direct observation that cables are not wetted orE1-54 of 79 submerged, that cables/splices and cable support structures are intact, anddewatering/drainage systems (i.e., sump pumps) and associated alarms operate properly. Inaddition, operation of dewatering devices should be inspected and operation verified prior to anyknown or predicted heavy rain or flooding events."Issue:In the absence of these specifics for periodic inspection, the FSAR Supplement is inconsistentwith the basis document SQN-RPT-I O-LRD04 and GALL Report AMP XI.E3, PreventiveActions, which list the periodic inspection specifics.Request:Provide an adequate program description in the FSAR Supplement consistent with GALLReport AMP XI.E3 and SRP Table 3.0-1, including inspection specifics.RAI A.1.25-2 RESPONSEThe change to LRA Section A.1.25 is shown in the response to RAI A.1.25-1. The revision addsspecific information regarding the inspections of cables and cable support structures andregarding the verification of proper operation of manhole dewatering systems periodically and inconjunction with observed and predicted flooding. The markup for RAI A. 1.25-1 includes thechanges for RAI A.1.25-2 for consistency and clarity because both RAIs affect the same LRAsection. Additions are underlined.RAI B.1.26-1Backqround:SRP Table 3. 0-1, FSAR Supplement for Aging Management of Applicable Systems under AMPXl. E2 states that in the case where cables are not part of the calibration or surveillanceprogram, a proven test (such as insulation resistance tests, time domain reflectometry tests, orother test judged to be effective) for detecting deterioration of insulation system are performed.LRA Section A. 1.26 states that for sensitive instrumentation circuit cables that are disconnectedduring instrumentation calibrations, testing will be performed using a proven method fordetecting deterioration for the insulation.Issue:The applicant does not identify the type of tests that can be used in the FSAR Supplement. Inthe absence of these testing techniques, the UFSAR Supplement is inconsistent with GALLReport AMP XI.E2 and SRP Table 3.0-1 which provides guidance on the specific tests.Request:"Provide a list of proven test that will be performed for detecting deterioration of insulationsystem for instrumentation cables. Revise the LRA Section A. 1.26 to be consistent with SRPTable 3.0-1.RAI B.1.26-1 RESPONSEConsistent with NUREG-1801,Section XI.E2 and NUREG-1800, Table 3.0-1, tests proveneffective for detecting deterioration of insulation systems include insulation resistance tests andtime domain reflectometry. The change to LRA Section A. 1.26 follows, additions areunderlined.E1-55 of 79 A.1.26 Non-EQ Instrumentation Circuits Test Review Program"For sensitive instrumentation circuit cables that are disconnected during instrumentcalibrations, testing using a proven method for detecting deterioration for the insulationsystem (such as insulation resistance tests or time domain reflectometrv) will occur at leastonce every ten years, with the first test occurring before the period of extended operation.Applicable industry standards and guidance documents are used to delineate the program."RAI B.1.30-01Backqround:LRA Sections B. 1.30 and A. 1.30 do not provide the number of in-scope small-bore piping weldsfor its two units. The GALL Report AMP, "detection of aging effects" program elementrecommends that if an applicant's units have not experienced a failure of its ASME Code ClassI piping, and it has extensive operating history (>30 years) at the time of submitting theapplication, the inspection sample size should be at least 3% of the weld population or amaximum of 10 welds of each weld type for each operating unit.In addition, the "detection of aging effects" program element of the GALL AMP recommendsthat for socket welds, opportunistic destructive examination can be performed in lieu ofvolumetric examination. Because more information can be obtained from a destructiveexamination than from a nondestructive examination, the applicant may take credit for eachweld destructively examined equivalent to having volumetrically examined two socket welds.Issue:It is not clear to the staff how the inspection sample size would be calculated, since the totalpopulation of Class I butt welds and socket welds for each unit within scope of the program arenot provided in the applicant's LRA. In addition, it is not clear to the staff if the applicant will useopportunistic destructive examination for butt welds, and how it will be credited when they areperformed in lieu of volumetric examinations.Request:1. Provide the type and number of in-scope small-bore piping welds for each of the units.2. In addition, clarify if opportunistic destructive examinations will be used for butt welds,and how they will be credited.3. Amend LRA Sections B. 1.30 and A. 1.30 accordingly, to include the total population forboth units, and to clearly state how opportunistic destructive examination will becredited, if they are performed in lieu of volumetric examinations for butt welds and/orsocket welds.E1-56 of 79 RAI B.1.30-01 RESPONSE1. There are 585 ASME Class 1 small-bore socket welds and 133 ASME Class 1 small-bore butt welds in Unit 1. There are 563 ASME Class 1 small-bore socket welds and 129ASME Class 1 small-bore butt welds in Unit 2.2. Only volumetric examinations will be credited for butt welds.3. The change to the second paragraph of LRA Section B.1.30 follows, with additionsunderlined and deletions lined through."Since SQN has an extensive operating history (>30 years of operating experience),this program provides a one-time volumetric or opportunistic destructive inspection ofa three po.....t sample or. ..mimum f ten ASME Class 1 piping b'utt weld, locGati'onand a threo percent sample or a maximum.. of te.n.ASME Clar- Ir, socket weld locationsthat are susceptible to cracking in each unit. There are 585 ASME Class 1 small-boresocket welds and 133 ASME Class 1 small-bore butt welds in Unit 1. There are 563ASME Class 1 small-bore socket welds and 129 ASME Class 1 small-bore butt weldsin Unit 2. The program also includes a volumetric inspection of four ASME Class 1small-bore butt welds for Unit 1 and four ASME Class 1 small-bore butt welds in Unit2. Volumetric examinations are performed using a demonstrated technique that iscapable of detecting the aging effects in the volume of interest. In the event theopportunity arises to perform a destructive examination of an ASME Class 1 small-bore socket weld that meets the susceptibility criteria, then the program takes creditfor two volumetric examinations. The program includes pipes, fittings, branchconnections, and full and partial penetration welds."The change to the second paragraph of LRA Section A.1.30 follows, with additionsunderlined.The program provides a one-time volumetric or opportunistic destructive inspection ofa three percent sample or maximum of ten ASME Class 1 piping butt weld locationsand a three percent sample or a maximum of ten ASME Class 1 socket weld locationsthat are susceptible to cracking. Volumetric examinations are performed using ademonstrated technique that is capable of detecting the aging effects in the volume ofinterest. In the event the opportunity arises to perform a destructive examination of anASME Class I small-bore socket weld that meets the susceptibility criteria, then theprogram takes credit for two. volumetric examinations. The program includes pipes,fittings, branch connections, and full and partial penetration welds.RAI B.1.35-1Background:The "Detection of Aging Effects" program element of GALL Report AMP XI.M31 states, in part,that.E1-57 of 79

1. the withdrawal schedule shall be submitted as part of a license renewal application forNRC review and approval in accordance with 10 CFR Part 50, Appendix H, and2. the program withdraws one capsule at an outage in which the capsule receives aneutron fluence of between one and two times the peak reactor vessel wall neutronfluence at the end of the period of extended operation (PEO) and tests the capsule inaccordance with ASTM E 185-82.Issue:The applicant's program, as modified by the enhancements, includes:1. an enhancement to the "Detection of Aging Effects" program element that has a generaldiscussion of a change to be made to the capsule withdrawal schedule, but no specifics,and2. an enhancement to the "Monitoring and Trending" program element for withdrawal andtesting of a standby capsule to cover the peak fluence expected at the end of the periodof extended operationDuring the audit, the staff noted that by letter dated January 10, 2013, the applicant submitted tothe NRC its proposed changes to the surveillance capsule withdrawal schedule that doesdemonstrate that a capsule will be withdrawn and tested at a fast neutron fluence level betweenone and two times the peak neutron fluence for the PEO. However, the LRA with itsenhancements does not include specific discussion of items I and 2 shown above from GALLReport AMP XI.M31.Request:1. The staff requests that the applicant include a specific reference to the January 10,2013, submittal.2. Clarify whether these proposed changes to the capsule schedule are consistent withGALL Report AMP XI.M31.RAI B.1.35-1 RESPONSE1. The changes to Commitment #28.B, LRA Sections A.1.35 and B.1.35 follows, to includea specific reference to the January 10, 2013 submittal to the NRC. Deletions are shownwith strikethrough and additions are shown with underline."Revise Reactor Vessel Surveillance Program procedures to incorporatedeveIop anNRC-approved schedule for capsule withdrawals to meet ASTM-E185-82requirements, including the possibility of operation beyond 60 years (refer to the TVALetter to NRC, "Sequoyah Reactor Pressure Vessel Surveillance Capsule WithdrawalSchedule Revision Due to License Renewal Amendment," dated January 10, 2013,ML 13032A251))."2. The proposed changes to the capsule withdrawal schedule are consistent with GALLReport AMP XI.M31.E1-58 of 79 RAI B.1.40-1Background:GALL Report AMP Xl. S6, "Structures Monitoring, " program element "preventive action, " statesthat if the structural bolting consists of ASTM A325, ASTM F1852, and/or ASTM A490 bolts, thepreventive actions for storage, lubricants, and stress corrosion cracking potential discussed inSection 2 of the Research Council for Structural Connections (RCSC) publication "Specificationfor Structural Joints Using ASTM A325 or A490 Bolts, "need to be used.Issue:SQN LRA states that the Structures Monitoring program, with enhancements, will be consistentwith the program described in GALL Report AMP XI.S6, "Structures Monitoring." While auditingthe program basis documentation, the staff noted that the "preventive action" program elementof the LRA AMP states that the preventive actions of Section 2 of RCSC have been consideredin the existing procedures for ASTM A325 and A490 bolting. It is not clear that the preventiveactions for storage, lubricants, and corrosion potential are being used as recommended in theGALL Report.Request:1. Clarify that the preventive actions for storage, lubricants, and corrosion potentialdescribed in Section 2 of RCSC, "Specification for Structural Joints Using ASTM A325or A490 Bolts," will be used or describe alternate methods used, if any.2. Provide justification for their use and any deviations from Section 2 of RCSC.RAI B.1.40-1 RESPONSE1. The SQN SMP employs the preventive actions for storage, lubricants, and corrosion potentialdescribed in Section 2 of Research Council on Structural Connections (RCSC),"Specification for Structural Joints Using ASTM A325 or A 490 Bolts." No alternate methodsare used.2. The SQN SMP does not use alternate methods.RAI B.1.40-2Background:GALL Report AMP X1. S6, "Structures Monitoring, "program element "detection of aging effects,"states that inspector qualifications should be consistent with industry guidelines and standards.The GALL Report further states that qualifications of inspection and evaluation personnelspecified in ACI 349.3R are acceptable for license renewal.Issue:SQN LRA states that the Structures Monitoring program, with enhancements, will be consistentwith the program described in GALL Report AMP X1. S6, "Structures Monitoring." While auditingthe program basis documentation, the staff noted that the "detection of aging effects" programelement of the LRA AMP states that the inspection and evaluation personnel qualifications areconsistent with industry guidelines and standards and guidance for implementing 10 CFR 50.65and meet the intent of ACI 349.3R; however, the qualifications of personnel described in theplant procedures do not align with those described in ACI 349.3R.E1-59 of 79 Request:1. Describe the qualifications of personnel performing the evaluations, i.e., responsibleengineer, and qualifications of personnel performing the inspections or testing.2. If the qualifications of personnel are not consistent with those recommended in Chapter 7 ofACI 349.3R, describe and provide justification for deviations thereofRAI B.1.40-2 RESPONSE1. The qualifications of personnel performing the inspections or testing and the qualifications ofpersonnel performing the evaluations, i.e., responsible engineer under the SQN SMP are asfollows.I. Inspector shall have the following minimum qualifications:a. Suitably knowledgeable or trainedb. Three years structural design/analysis/field evaluation experiencec. Approved by Site Lead Civil EngineerI1. Responsible Engineer shall have the following minimum qualifications:a. Knowledgeable or trained in the design, evaluation, and performance requirementsof structuresb. Degreed Civil/Structural Engineer or equivalentc. Five years structural design/analysis/field evaluation experienced. Approved by the Site Lead Civil Engineer2. The qualifications of personnel performing the inspections or testing and the qualifications ofpersonnel performing the evaluations, i.e., responsible engineer as recommended inChapter 7 of ACI 349.3R are as follows.I. Personnel performing the inspections or testing at the plant, under the direction of theresponsible engineer, should meet one of the following qualifications, or equivalent.a. Civil/structural engineering graduate (four-year) of an accredited college or universitywho has over one year experience in the evaluation of in-service concrete structuresor quality assurance related to concrete structuresb. Personnel possessing a Level I or Level II Concrete Inspector certification from theplant owner, using internal methods, ACI or other authorized testing organizations forconducting qualification testingc. Personnel meeting the requirements for Level I or Level II Concrete Inspector, asdefined in ASME B&PVC,Section III, Division 2, Appendix VII (American ConcreteInstitute 359) Code requirementsII. Responsible engineer should possess one of the following sets of qualifications.a. Registered professional engineer, knowledgeable in the design, evaluation, and in-service inspection of concrete structures and performance requirements of nuclearsafety-related structuresb. Civil/structural engineering graduate of an accredited college or university who hassuccessfully completed the experience, training, and testing requirements of the ACILevel III Concrete Inspector Program and is knowledgeable of the performancerequirements of nuclear safety-related structuresE1-60 of 79 The qualification of the personnel involved with overseeing inspections and evaluation ofstructures and structural components within the scope of the SQN SMP meet the intent ofthe recommendations of Chapter 7 of ACI 349.3R to ensure program activities areconducted by qualified personnel.For clarification, the enhancement to Detection of Aging Effects for the SQN SMP will berevised to ensure qualifications of personnel performing the inspection or testing andevaluation of structures and structural components within the scope of the SQN SMP areconsistent with the guidance in Chapter 7 of ACI 349.3R.The changes to Commitment 31 .J, LRA Appendices A and B follow, with additions underlined.LRA APPENDIX A CHANGESA.1.40 Structures Monitoring Program"Revise Structures Monitoring Program procedures to include the following for detectionof aging effects:* Qualifications of personnel conducting the inspections or testing and evaluation ofstructures and structural components meet the guidance in Chapter 7 of ACI349.3R."LRA APPENDIX B CHANGESB.1.40 Structures MonitoringEnhancementsThe following enhancements will be implemented prior to the period of extended operation.Elements Affected Enhancements4. Detection of Aging Effects Revise Structures Monitoring Programprocedures to include the following for detectionof aging effects.Qualifications of personnel conducting theinspections or testing and evaluation ofstructures and structural components meetthe guidance in Chapter 7 of ACI 349.3R.Commitment changesCommitment 31.J is added with additions underlined."Revise Structures Monitoring Progqram procedures to clarify that detection of agingeffects will include the following.Qualifications of personnel conducting the inspections or testing and evaluation ofstructures and structural components meet the guidance in Chapter 7 of ACI349.3R."E1-61 of 79 RAI B.1.40-3Background:GALL Report AMP Xl. S6, "Structures Monitoring, " program element "acceptance criteria, "statesthat the Structures Monitoring program calls for inspection results to be evaluated by qualifiedengineering personnel, based on acceptance criteria selected for each structure/aging effect toensure that the need for corrective actions is identified before loss of intended functions. Thecriteria are derived from design bases codes and standards that include ACI 349.3R, ACI 318,ANSI/ASCE 11, or the relevant AISC specifications, as applicable, and consider industry andplant operating experience. The GALL Report further states that applicants who are notcommitted to use ACI 349.3R and elect to use plant-specific criteria for concrete structuresshould describe the criteria and provide a technical basis for deviations from those in ACI349.3R.Issue:SQN LRA states that the Structures Monitoring program, with enhancements, will be consistentwith the program described in GALL Report AMP Xl. S6, "Structures Monitoring." While auditingthe program basis documentation, the staff noted that the "acceptance criteria" programelement of the LRA AMP states that the program will be enhanced to prescribe acceptancecriteria considering information provided in industry codes, standards, and guidelines includingNEI 96-03, ACI 201.1 R-92, ANSI/ASCE 11-99, and ACI 349.3R," however, the acceptancecriteria defined in procedures are qualitative and determine conditions as "acceptable,""acceptable with deficiencies, "or "unacceptable." It is not clear how the qualitative acceptancecriteria listed in the applicant's audited procedures will be aligned with the quantitative criteriadescribed in Chapter 5 of A Cl 349.3R, during the period of extended operation.Request:1. Clarify how the qualitative acceptance criteria align with the quantitative acceptancecriteria of ACI 349.3R.2. If not committed to follow ACI 349.3R acceptance criteria and elect to use plant-specificcriteria, describe and provide a technical basis for each deviation.RAI B.1.40-3 RESPONSE1. As stated in the SQN LRA Appendix B.1.40, the SMP acceptance criteria withenhancements will be consistent with the recommendations of Element 6 in GALLReport AMP XI.S6, "Structures Monitoring" which includes following the guidance of ACI349.3R. The SQN program specifies evaluation of inspection results by qualifiedengineering personnel based on acceptance criteria selected for each structure/agingeffect to ensure that the need for corrective actions is identified before loss of intendedfunction. The criteria are derived from design basis codes and standards that includeACI 349.3R, ACI 318, ANSI/ASCE 11, or the relevant AISC specifications, as applicable,and consider industry and plant OE."The enhancement to the SQN SMP acceptance criteria, shown in LRA Appendix B.1.40,specifies including acceptance criteria in SQN SMP considering information provided inindustry (design basis) codes, standards, and guidelines including NEI 96-03, ACI201.1R-92, ANSI/ASCE 11-99 and ACI 349.3R-02. The enhancement reads "Verifyacceptance criteria in SMP procedures is based on information provided in industryE1-62 of 79 codes, standards, and guidelines including NEI 96-03, ACI 201.1R-92, ANSI/ASCE 11-99 and ACI 349.3R-02. Industry and plant-specific OE will also be considered in thedevelopment of the acceptance criteria." The purpose of the enhancement is to align thequalitative acceptance criteria of the SQN SMP with the quantitative acceptance criteriaof ACI 349.3R and other industry (design basis) codes and standards. To clarify thisalignment, the enhancement to the SQN SMP will be revised as shown below.2. With the revised wording of the enhancement as discussed in response 1), the SQNSMP acceptance criteria is consistent with the ACI 349.3R acceptance criteria andadditional industry codes and standards. The SQN SMP acceptance criteria do not electto use plant-specific criteria, therefore no technical basis for deviations is necessary.The changes to Commitment 31.1, LRA Appendices A and B follow, with additions underlinedand deletions lined through.LRA APPENDIX A CHANGESA.1.40 Structures Monitoring ProgramVerify acceptancoe in Revise Structures Monitoring Program procedures to prescribequantitative acceptance criteria is based on the quantitative acceptance criteria of ACl 349.3Rand information provided in industry codes, standards, and guidelines including NEI 96 03,20-.R 92, .A.S!/ASCE I 99, and A.Cd 3g9.3R 02-ACI 318, ANSI/ASCE 11 and relevant AISCspecifications. Industry and plant-specific operating experience will also be considered in thedevelopment of the acceptance criteria.LRA APPENDIX B CHANGESB.1.40 Structures MonitoringEnhancementsThe following enhancements will be implemented prior to the period of extended operation.Elements Affected Enhancements6. Acceptance Criteria Verify aGccGeptai;e criteria in ReviseStructures Monitoring Program proceduresto prescribe quantitative acceptance criteriais based on the quantitative acceptancecriteria of ACI 349.3R and informationprovided in industry codes, standards, andguidelines including NEI 96-03, A.l 201.!R92, AN.S!.ASCE 11 -99, aFd AGI 34,9.3R 02ACl 318, ANSI/ASCE 11 and relevant AISCspecifications. Industry and plant-specificoperating experience will also be consideredin the development of the acceptancecriteria.Commitment changesE1-63 of 79 Revise Commitment 31.1 with additions underlined and deletions lined through."Verify acceptanGc crit9ria in Revise Structures Monitoring Program procedures to prescribequantitative acceptance criteria is based on the quantitative acceptance criteria of ACI349.3R and information provided in industry codes, standards, and guidelines including NE&96 03, ACI 201.1R 92, ANSI/ASCE 11 99, aRd ,AC 349.3R 02 ACI 318, ANSI/ASCE 11 andrelevant AISC specifications. Industry and plant-specific operating experience will also beconsidered in the development of the acceptance criteria."RAI B.1.40-4Backqround:A review of the Structures Monitoring AMP plant operating experience has shown that theTurbine Building at SQN has been experiencing groundwater infiltration through degradedexpansion/isolation joints for at least 16 years. During a walkdown of the Turbine Building, thestaff observed dampness and water in-leakage through degraded expansion/isolation joints andcracks in exterior walls. In addition, the staff noted the presence of concrete leaching, spalling,and rust colored stains on the walls. In some areas, groundwater was seeping through cracks inthe basement floor. Audited "Maintenance Rule Structural Inspection" Revisions 0 and 7,indicate that this groundwater in-leakage and the resulting aging effects continue to be an issue.The staff also noted a large diagonal crack on the north wall extending upward and eastwardapproximately 6 feet, which appeared to be much greater than 40 mils.Issue:Concrete exposed to groundwater in-leakage over a period of time can lead to corrosion ofrebars, concrete cracking, loss of material (spalling, scaling), aggregate reactions, and leachingresulting in increased porosity and permeability and loss of strength. As stated in ACI 349.3R,for concrete "if this leaching progresses without mitigation, the leaching process can produce aloss of mechanical properties, such as compressive strength and modulus of elasticity. "ACI349.3R also states that "leaching is a concern for potentially increasing the exposure of steelreinforcement to corrosion cell formation."For observed concrete surface conditions that exceed the acceptance limits provided in Section5.2 of A Cl 349.3R (e.g., cracks widths greater than 40 mils), conditions should be consideredunacceptable and need further technical evaluation. Cracks of this size expose rebar tocorrosion and concrete to further deterioration that may affect the structural integrity of affectedstructures.LRA Sections 3.5.2.2.1.9, 3.5.2.2.2.1.4, and 3.5.2.2.2.3.3, address leaching in inaccessibleareas of concrete and state that increase in porosity and permeability due to leaching is not anapplicable aging effect requiring management. Based on the observed leaching and waterinfiltration in accessible areas of concrete, the staff does not understand how this conclusionwas reached.Request:1. In areas susceptible to moisture or groundwater infiltration, describe and provide thetechnical basis for actions that have been and will be taken to assure that reinforcedconcrete walls and floor retain their strength and durability, and that there is no activecorrosion of the rebar taking place. Ensure that the response includes an explanation ofhow this will be accomplished for inaccessible concrete areas susceptible to moisture orgroundwater infiltration.E1-64 of 79

2. For the diagonal crack on the north wall of the Turbine Building as described above,provide a summary of any evaluation that may have been performed documenting theacceptability of the crack. Describe and justify any actions that will be taken todemonstrate that for this and other similar cracks, the effects of aging will be adequatelymanaged, during the period of extended operation.RAI B.1.40-4 RESPONSE1. During the baseline SQN SMP inspections performed in 1996 and 1997, minor ground waterin-leakage was observed and documented in several of the SQN Category I structures. Thetechnical evaluation of the observed in-leakage concluded that the condition would not affectthe intended functions of the affected structural elements. Additionally, SQN initiatedmaintenance activities to reduce the in-leakage.The baseline SQN SMP inspections of the turbine building, a non-Category I structure,noted in-leakage in the basement floor slab at EL 662.5' and significant in-leakage for thenorth and south perimeter walls above floor EL 662.5' and floor EL 685'. The technicalevaluation of the in-leakage concluded that the condition would not affect the intendedfunction of the structure elements. Leak repairs were initiated to stop the in-leakage withsome success. Additionally, the SQN SMP includes ongoing periodic inspections of theconditions noted. The turbine building is the most significant of the SQN structures withinthe scope of the SMP due to the constant moisture in-leakage over large areas of thestructure. The affected turbine building areas continue to be periodically monitored andevaluated under the SMP. Subsequent SMP inspections performed of the turbine buildingin 2002 and 2007 noted a decrease in the amount of in-leakage that was attributed to theinjection of sealant material into the leaking construction joints and cracks following thebaseline inspections.The inspections of the non-Category I turbine building under the enhanced SQN SMPprovides the basis to ensure that the reinforced concrete walls and floor slabs aremaintaining their strength and durability and no active corrosion of the reinforcement steel isoccurring. The SMP provides for future assessment against the evaluation criteria andacceptance criteria of ACI 349.3R and determination of appropriate corrective measures ifacceptance criteria are not met. Concrete areas within the scope of license renewal that aresusceptible to moisture or groundwater infiltration are below-grade exterior walls and floorsof SQN structures. The interior surfaces of these concrete walls and floors are locatedwithin accessible areas in the structures and are inspected and monitored under the SMP asdiscussed above. Additionally, opportunistic inspections of the normally inaccessibleexterior surfaces will be conducted when they become accessible due to required plantactivities.2. The diagonal crack on the north wall of the turbine building was observed during thebaseline SMP inspections performed in 1996 and 1997. The observed degradation wasevaluated within the SQN SMP. The technical evaluation of the crack concluded that thestructural capability of the turbine building north wall was not unacceptably impaired and thatthe wall would continue to perform its design function. The SQN SMP includes ongoinginspections of this conditions.The aging effects of turbine building and other structures within the SMP are managed byroutine inspections. As indicated in LRA Appendix B.1.40, the SQN SMP continues toinspect and evaluate the condition of structures during the PEO. Also, as provided inCommitment 31.F, the SMP will be enhanced to include acceptance criteria that are basedE1-65 of 79 on ACI 349.3R. The diagonal crack on the north wall of the turbine building and similarcracks observed during SMP inspections during the PEO will be evaluated in accordancewith quantitative acceptance criteria in ACI 349.3R. Conducting the periodic inspections ofstructures in accordance with the enhanced SQN SMP ensures that the effects of aging areadequately managed during the PEO.RAI B.1.40-5Background:During a walkdown of the spent fuel pool, the staff noted concrete leaching on the outersurfaces of the spent fuel pool walls. The staff also noted that one of the open tell tale drainswas not collecting borated water leakage, which may indicate that the leak chase channel isclogged or blocked.Issue:Concrete leaching of the spent fuel pool walls, is indicative of leakage originating from the spentfuel pool. If the leak chase channels are clogged or blocked, borated water leakage couldaccumulate in the channels, behind the liner, and eventually migrate through the concrete,possibly causing degradation of the leak chase system, concrete, and reinforcing steel.Request:1. Indicate whether the concrete leaching is active, and explain how the borated waterleakage may have affected the condition of the concrete and rebar, by describing whatsteps have been taken, or will be taken, to ensure that there would be no loss of strengthfor the concrete, no bond deterioration between rebar and concrete, and no activecorrosion of steel rebars and embedded leak chase channels, during the period ofextended operation.2. Discuss actions that have been or will be taken to ensure the leak chase system(channels, tubes, trenches, valve bodies, etc) remains free and clear so that it caneffectively prevent borated-water from seeping into and thus contributing to the aging ofthe reinforced concrete.RAI B.1.40-5 RESPONSE1. The concrete leaching observed on the spent fuel pool walls noted during a plant walk downby NRC staff and SQN personnel in March 2013 is not active.A SQN system engineer observed the leakage indication in early 2012 and photographedthe as-found condition. A more recent walk down was performed in May of 2013 and theleakage indication was again documented with photographs. The observed leakage areaappeared dry when observed in May 2013. The photographs from 2013 were very similar tothe 2012 photographs. The indication observed during the most recent walk down was verysimilar to the two sets of photographs. Documentation from the SQN SMP inspections ofthe structure (auxiliary building) did not identify degradation for this area. After the plantwalk down by NRC staff and SQN personnel in March 2013, a search of the SQN correctiveE1-66 of 79 action program database found no entries documenting this condition. Since the March2013 walk down, the leakage indication has been documented in the SQN corrective actionprogram.While filling the fuel transfer canal in December 2011, several thousand gallons of waterspilled over into the surrounding heating ventilation and air conditioning (HVAC) duct systemembedded in the concrete around the fuel transfer canal. This water was outside of the leakchase system of the spent fuel pool liner and fuel transfer canal liner drainage system. Thewater spilled out of the HVAC system onto lower floor elevations and was collected in floordrains. One embedded drain line is located within the wall of the spent fuel pool and fueltransfer canal foundation in the area where the noted concrete leaching was observedapproximately five months after the water spill. The concrete leaching was assumed to be aresult of the water spill into the duct work servicing the fuel transfer canal in 2011. Samplesof the residue material were collected for testing of various parameters including boron,chlorides, pH and iron. The sample results include some levels of boron which wouldindicate that the water source that caused the leaching was spent fuel pool water. Itappears that this was an isolated event that resulted in the observed concrete leachingindication. Additionally the residue material was white indicating no active corrosion of thereinforcement steel.The reinforced concrete foundation of the spent fuel pool, cask area and fuel transfer canalis approximately 67 feet by 55 feet in plan with a height of approximately 16 feet that isconstructed of multiple horizontal construction pours. There are no vertical constructionjoints in the concrete pours. The leak is inactive and was determined not to affect thestructural integrity of the concrete to perform its license renewal intended functions.Monitoring of this area has shown that the leaching indication was an isolated condition andthat there is no ongoing leakage. The SMP provides for continued monitoring to confirmthis. The continued monitoring of this area within the SMP during the PEO ensures thatthere will be no loss of strength for the concrete, no bond deterioration between rebar andconcrete, and no active corrosion of reinforcement steel and embedded leak chasechannels.2. The SQN operations personnel conduct routine rounds which include observation of the tell-tale drains from the leak chase channels of the spent fuel pool, cask area and the fueltransfer canal. Operations personnel observations of leakage from the tell-tale drains aretypically documented in either the SQN work order process or the corrective action program.A review of work order and corrective action document databases identified multipleinstances where leakage has been noted from the tell-tale drains over the years indicatingthey are performing their intended function and are not clogged or obstructed.Additionally, the historical trend of the rate of make-up water for the spent fuel pool has notshown any significant change that would indicate loss of pool water resulting from a leak inthe spent fuel pool or cask area liner plates. These actions indicate that the leak chasesystem (channels, tubes, trenches, valve bodies, etc.) remains free and clear.E1-67 of 79 RAI B.1.41-1Backqround:LRA Section B. 1.41 describes the applicant's Thermal Aging Embrittlement of Cast AusteniticStainless Steel (CASS) Program. The LRA states that this program is a new program tomanage cracking and reduction in fracture toughness due to thermal aging embrittlement inCASS piping and piping components, consistent with GALL Report AMP X1. M12, "ThermalAging Embrittlement of Cast Austenitic Stainless Steel Program (CASS)."The "scope of program" program element of GALL Report AMP XI. M12 states that in thesusceptibility screening method, ferrite content is calculated by using the Hull's equivalent factor(described in NUREG/CR-4513, Revision 1) or a staff-approved method for calculating deltaferrite in CASS materials.Issue:During the audit, the staff noted that the applicant's program basis document does not clearlyaddress whether the applicant's screening method for susceptibility to thermal agingembrittlement uses the Hull's equivalent factor, as described in NUREG/CR-4513, Revision 1, ora staff-approved method.Request:1. Clarify whether the applicant's screening method for susceptibility to thermal agingembrittlement uses the Hull's equivalent factor, as described in NUREG/CR-4513,Revision 1, or an alternative staff-approved method to determine the ferrite contents ofthe CASS piping components.2. If an alternative method will be used to determine the ferrite contents, identify thespecific alternative method and clarify whether the alternative method has beenapproved for use by the NRC.a) In addition, provide the applicant's technical basis of the alternative method toconfirm the adequacy of the method.RAI B.1.41-1 RESPONSE1. The screening method for susceptibility to thermal aging embrittlement will use the Hull'sequivalent factor, as described in NUREG/CR-4513, Revision 1. For clarification, thechanges to LRA Sections A. 1.41, B. 1.41 and 3.1.2.2.6 follow, with additions underlinedand deletions lined through.LRA Section A.1.41"The Thermal Aging Embrittlement of Cast Austenitic Stainless Steel Programmanages the aging effects of cracking and reduction in fracture toughness in castaustenitic stainless steel (CASS) components. The program consists of adetermination of the susceptibility of CASS piping, piping components, and pipingelements and the pressurizer spray head and regenerative heat exchanger shell tothermal aging embrittlement based on Hull's equivalent factor, as described inNUREG/CR-4513, Revision 1 cGactng m.ethod, molybdenu--m content, and perceferiite. For potentially susceptible components, aging management is accomplishedthrough qualified visual inspections, such as enhanced visualv9lUFA:t- examination,qualified ultrasonic testing methodology, or component-specific flaw toleranceE1-68 of 79 evaluation in accordance with ASME Section Xl code, 2001 Edition 2003 addendum.Applicable industry standards and guidance documents are used to delineate theprogram.This program will be implemented prior to the period of extended operation."LRA Section B.1.41"The Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) Programis a new program that manages the aging effects of cracking and reduction in fracturetoughness in CASS. The program consists of a determination of the susceptibility ofCASS piping, piping components, and piping elements and the pressurizer sprayhead and regenerative heat exchanger shell to thermal aging embrittlement based onHull's equivalent factor, as described in NUREG/CR-4513, Revision 1 Ga~tiaRMetmolybdenum content, and percnt forrite. For potentially susceptible components,aging management is accomplished through qualified visual inspections, such asenhanced visualvelumetme examination, qualified ultrasonic testing methodology, orcomponent-specific flaw tolerance evaluation in accordance with ASME Section Xlcode, 2001 Edition 2003 addendum. Applicable industry standards and guidancedocuments are used to delineate the program.This program will be implemented prior to the period of extended operation."LRA Section 3.1.2.2.6"Susceptibility to thermal aging embrittlement will be evaluated in the Thermal AgingEmbrittlement of CASS Program. Aging management for components that aredetermined to be susceptible to thermal aging embrittlement is accomplished usingeither enhanced VelumetFiG visual examinations or component specific flaw toleranceevaluations. Additional inspection or evaluations are not required for components thatare determined not to be susceptible to thermal aging embrittlement."2. No alternative approach for determining ferrite content has been proposed.RAI B.1.41-2Background:LRA Section A. 1.41 describes the applicant's UFSAR supplement for the Thermal AgingEmbrittlement of Cast Austenitic Stainless Steel (CASS) Program. In addition, LRA SectionB. 1.41 states that this AMP is a new program to manage cracking and reduction in fracturetoughness in CASS piping and piping components, consistent with GALL Report AMP XI.M12,"Thermal Aging Embrittlement of Cast Austenitic Stainless Steel Program (CASS)."The UFSAR supplement in LRA Section A. 1.41 states that for potentially susceptiblecomponents, aging management is accomplished through qualified visual inspections, such asenhanced volumetric examination, qualified ultrasonic testing methodology, or componentspecific flaw tolerance evaluation.E1-69 of 79 Issue:The staff noted that the UFSAR supplement description, "qualified visual inspections, such asenhanced volumetric examination, " needs to state "qualified visual inspections, such asenhanced visual examination, "in order to be consistent with GALL Report AMP X1. M12.The staff also noted that LRA Sections B. 1.41 (program description) and 3.1.2.2.6 need to berevised in a similar manner to correctly identify the inspection methods used in the program,consistent with GALL Report AMP X1. M12.Request:If claiming consistency with the GALL Report for this program, ensure that LRA Sections A. 1.41,B. 1.41, and 3.1.2.2.6 correctly identify the inspection methods used in the program, consistentwith GALL Report AMP XI.M12.RAI B.1.41-2 RESPONSELRA Sections A.1.41, B.1.41 and 3.1.2.2.6 inadvertently identified the wrong inspection method(i.e., enhanced volumetric examination) instead of the correct method of "enhanced visualexamination." The changes to LRA sections A. 1.41, B. 1.41 and 3.1.2.2.6 to change"volumetric" to "visual", are already shown in the response to RAI B.1.41-1.RAI B.1.41-3Background:LRA Section B. 1.41 describes the applicant's Thermal Aging Embrittlement of Cast AusteniticStainless Steel (CASS) Program, The LRA states that this program is a new program tomanage cracking and reduction in fracture toughness due to thermal aging embrittlement inCASS piping and piping components, consistent with GALL Report AMP Xl. M12, "ThermalAging Embrittlement of Cast Austenitic Stainless Steel Program (CASS)."GALL Report AMP XI. M12 states that for "potentially susceptible" piping components, agingmanagement is accomplished through either (a) qualified visual inspections, such as enhancedvisual examination; (b) a qualified ultrasonic testing (UT) methodology; or (c) a componentspecific flaw tolerance evaluation. The GALL Report also indicates that if the inspection option isused, the scope of the inspection should cover those portions of the components determined tobe limiting from the standpoint of applied stress, operating time, and environmentalconsiderations.Issue:The LRA does not address the scope of inspection for potentially susceptible CASScomponents, which the applicant's program uses when the inspection option is selected foraging management (e.g., what percent of the potentially susceptible components includingwelds is to be inspected in the applicant's aging management program).Request:1. Describe the scope of inspection that will be used when the inspection option is selectedfor aging management (e.g., what percent of the potentially susceptible componentsincluding welds is to be inspected in the aging management program).E1-70 of 79

2. In addition, provide the technical basis for the applicant's inspection scope in order todemonstrate the adequacy of the inspections for aging management.RAI B.1.41-3 RESPONSE1. As described in LRA Section B.1.41, the Thermal Aging Embrittlement of Cast AusteniticStainless Steel (CASS) Program is a new program and the scope of the programinspections is specified in NUREG -1801, XI.M12. The Inservice Inspection Programdescribed in LRA Section B. 1.16 manages the effects of aging on welds associated withASME Class 1, 2 and 3 components.When the inspection option is selected for aging management of cast austenitic stainlesssteel components, the scope of the inspection is in accordance with NUREG-1801,Section XI.M12, Detection of Aging Effects. Rather that specifying a percentage ofcomponents to inspect, NUREG-1 801,Section XI.M12 recommends that the scope ofthe inspection covers those portions of the components determined to be limiting fromthe standpoint of applied stress, operating time and environmental considerations.2. The technical basis for the scope of the program is that it is consistent with the NRCstaff's recommendations in NUREG-1801, XI.M12.RAI E-1Background:In the LRA Appendix B. 1.21, B. 1.24, B. 1.25, B. 1.26 and B. 1.27, under element 10 (operatingexperience), the applicant states that these AMPs are new programs and that industry operatingexperience will be considered in the implementation of this program. The applicant also statedthat plant operating experience will be gained as the program is executed and will be factoredinto the program via the confirmation and corrective action elements of the SQN 10 CFR 50Appendix B quality assurance program. The applicant further stated in LRA B. 1.21, that there isno operating experience at SQN involving the aging effects managed by these programs. Theapplicant concluded that there is reasonable assurance that these new AMPs will be effectiveduring the period of extended operation.SRP-LR Section A. 1.2.3.1 0 states that for new AMPs that have yet to be implemented at anapplicant's facility, the programs have not yet generated any operating experience. However,there may be other relevant plant-specific operating experience at the plant that is relevant tothe AMP's program elements even though the operating experience was not identified as aresult of implementation of the new program. Thus, for new programs, an applicant may need toconsider the impact of relevant operating experience that results from the past implementationof its existing AMPs that are existing programs and the impact of relevant generic operatingexperience on developing the program elements.Therefore, operating experience applicable to a new program should be discussed. In theLicense Renewal Interim Staff Guidance (LR-ISG) 2011-05, the staff stated that it intends for theEl-71 of 79 ongoing review of operating experience to inform every AMP, regardless of the AMP'simplementation schedule. The staff noted that there were instances of operating experiencesrelating to electrical AMPs which were not discussed in the operating experience programelement. For example, a MEB failed in August 2009 which resulted in the tripping of both units.The failure of the bus was caused by cracked Noryl insulation and moisture intrusion inside theMEB. This represents plant specific operating experience directly applicable to the agingmechanisms and effects relating to the MEB program AMP.Issue:Operating experience from existing plant programs relevant to LRA Appendix B, AMPS B. 1.21,B. 1.24, B. 1.25, B. 1.26 and B. 1.27 are not provided in the LRA. For new AMPs, applicable plantspecific and generic OE should be considered on an ongoing review basis to ensure theeffectiveness of the new AMP' program elements.Request:The operating experience being considered should include plant-specific DE at the plant that isrelevant to the AMP's program elements even though the DE was not identified as a result ofimplementation of the program.1. Describe relevant plant specific OE and lessons learned, as discussed above, for eachelectrical AMP.2. Identify areas where the aging management program was enhanced.3. Revise the LRA Appendix B operating experience elements, as appropriateRAI E-1 RESPONSETo support the SQN LRA, a review was performed to determine if there are aging effectsrequiring management not identified by the industry guidance documents for implementing thelicense renewal rule. The basis for this approach was that if an aging effect was identified inindustry guidance documents, then it would be addressed in such documents as NUREG-1801,Generic Aging Lessons Learned Report. Aging effects requiring management that were notidentified in industry guidance documents would require plant-specific activities for theirmanagement. This review included an assessment of ten years of SQN OE, from 2001 through2010. The review did not identify plant-specific or new industry OE different from the industryOE addressed in NUREG-1801 electrical aging management programs. The review concludedthat the NUREG-1 801 electrical AMPS were applicable to SQN and that no changes toNUREG-1 801 electrical AMPs were necessary. The details related to site-specific OE areprovided in the following discussion for each AMP.LRA B.1.21, Metal Enclosed Bus Inspection ProgramRAI Item 1:The following summary discussion addresses the results of the OE review for electricalcommodities that are included in the Metal Enclosed Bus Inspection Program.E1-72 of 79 On 03/26/09, SQN Units 1 and 2 experienced an automatic reactor trip on RCP busundervoltage. A loss of common station service transformer (CSST) C caused a loss of powerto the 1 B, 2B, 1D, and 2D unit boards. CSST C was lost due to the 161 kV breakers trippingdue to the differential relay actuation on the CSST D which experienced a secondary side busphase-to-phase fault. The phase-to-phase fault was due to cracked Noryl sleeving insulationover the bus bar and water intrusion into the bus enclosure. The failed MEB is similar to otherMEB at SQN that is within the scope of license renewal. Actions in response to lessons learnedfrom the review of this OE included revision of preventive maintenance instructions to increasethe inspection frequency, emphasize the visual inspection to identify cracked sleeving, resealthe bus enclosure after the inspection, and require entries into the corrective action program fordeficiencies discovered during inspections.RAI Item 2:The lessons learned from the MEB OE were evaluated during preparation of the SQN LRA.The evaluation found that the Metal Enclosed Bus Inspection Program described in the LRAincludes activities that are consistent with the lessons learned from the SQN OE. Therefore,changes to this program were not warranted.RAI Item 3:The change to LRA Section B.1.21 is shown in the response to RAI B.1.21-1.LRA B.1.24, Non-EQ Cable Connections ProgramRAI Item 1:The following summary discussion addresses the results of the OE review for electricalcommodities that are included in the Non-EQ Cable Connections Program.On 8/30/00 vital battery IV had a loose connection which was detected during the recharge ofvital battery IV following its discharge test. The condition was detected through the smell anddiscoloration of the insulator due to the heat that was produced during the high current flow (175amp draw) of the battery recharge. The charger was removed from service and the looseconnection tightened. This OE involved a loose connection that caused the associated agingeffect of increased connection resistance. Increased connection resistance and the associatedstressors are addressed in the SQN LRA. Lessons learned from review of this OE were thatexisting maintenance practices, specifically the battery charger PM, are effective at identifyingcable connection issues before connection failure.RAI Item 2:The Non-EQ Cable Connections Program described in the LRA includes activities that areconsistent with the lessons learned from the SQN OE. The one-time test discussed in the Non-EQ Cable Connections Program provides additional confirmation to support industry OE thatshows that electrical connections have experienced a low number of failures, and that existinginstallation and maintenance practices are effective. There have been limited numbers of age-related failures of cable connections reported at SQN. Therefore, changes to this program werenot warranted.E1-73 of 79 RAI Item 3:The change to LRA Section B. 1.24 follows, deletions are shown with strikethrough and additionsare underlined.B.1.24 NON-EQ CABLE CONNECTIONSOperating Experience"The Non-EQ Cable Connections Program is a new program. Industry operating experienceand SQN operating experience will be considered in the implementation of this program.Plant operating experience will be gained as the program is executed and will be factoredinto the program via the confirmation and corrective action elements of the SQN 10 CFR 50Appendix B quality assurance program.On 8/30/00 vital battery IV had a loose connection which was detected during the recharge ofvital battery IV following its discharge test. Thermography verified no heating under loadafter maintenance. This operating experience involved a loose connection that caused theassociated aging effect of increased connection resistance, which is addressed in the SQNLRA.This one-time inspection ensures that a potential aging effect (increased connectionresistance) does not require a periodic aging management program. No site-specificoperating experience was identified to indicate a need for a periodic aging managementprogram, and this one-time inspection will confirm this for SQN. The elements of the programinspections (e.g., the scope of the inspections and inspection techniques) are consistent withindustry practice and have been used effectively at SQN in other programs.As discussed in element 10 to NUREG-1 801,.Section XI.E6, this program considers the technicalinformation and industry operating experience provided in NUREG/CR-5643, SAND96-0344,IEEE Std. 1205-2000, EPRI 109619, EPRI 104213, NEI White Paper on AMP XI.E6, FinalLicense Renewal Interim Staff Guidance LR-ISG-2007-02, Staff Response to the NEI WhitePaper on AMP XI.E6, Licensee Event Report (LER) 3612007005, LER 3612007006 and LER3612008006. Accordingly, there is reasonable assurance that this new aging managementprogram will be effective during the period of extended operation.The process for review of future plant-specific and industry operating experience for agingmanagement programs is discussed in Section 8.0.4."LRA B.1.25, Non-EQ Inaccessible Power Cables (400 V to 35 kV) ProgramRAI Item 1:The following summary discussion addresses the results of the OE review the failure of cablesthat are included in the Non-EQ Inaccessible Power Cables (400 V to 35 kV) Program.The 5/4/2007 SQN response to GL 2007-01 identified two in-service failures of undergroundsafety-related power cables. One of these failures was the 2002 in-service failure of a 6.9 kvERCW supply pump circuit that was attributed to water treeing of the underground cable and theother failure was due to a manufacturing defect. SQN also reported 14 test failures. Thesewere failures to meet withstand testing acceptance criteria, which was either DC hipot or ACVLF withstand testing. The testing failures occurred during assessment of the condition ofmedium-voltage underground safety-related cables following the discovery of water treeing thatcaused the failed cable in 2002. These medium-voltage cable circuits are now subject toretesting at intervals dictated by the results of the "tan delta" assessments.E1-74 of 79 The following summary discussion addresses the maintenance and corrective actionsassociated with SQN manholes, sump pumps and cable support structures to minimize theexposure of in-scope inaccessible power cables to significant moisture.As documented in the SQN corrective action program, there have been multiple instances ofwater in manholes at SQN. In 2012, a report was initiated in the correction action program todocument the trend of high levels of water in manholes that the work control process is notresolving in a timely manner. The NRC, in an inspection report dated 4/30/2012, identified afinding of very low safety significance (green) related to water in manholes. In response to theidentified issues with untimely removal of water from manholes, the PM task instructions wererevised to require water removal, if found, from the manholes before the PM task could beclosed. SQN experience since revising the PM instructions has been that the water, if any, hasbeen removed within a week of initiating the PM activity.As a result of the negative OE with water in the manholes, a team of TVA personnel wasestablished in early 2013 to resolve the dewatering issues with safety-related manholes. Theteam is scheduling activities which will effect repair or replacement of sump pumps dischargepiping as necessary to improve dewatering performance. In addition, TVA is issuing amodification to enlarge the size of the openings in the covers of manholes thereby enhancingthe ability to remove water from manholes without having to remove the heavy missile shieldmanhole covers.An inspection of cable support structures is scheduled for completion in 2014. This inspection isperformed at least once every five years as part of the SQN SMP. The inspections described inNUREG-1801,Section XI.E3 will be implemented as part of the new SQN Non-EQ InaccessiblePower Cables (400 V to 35 kV) Program described in LRA Section B.1.25 prior to entering thePEO. During the PEO, the periodic inspections of manholes including cable support structureswill be completed at least once every year (annually).RAI Item 2:The lessons learned from the underground cable OE were evaluated during preparation of theSQN LRA. The evaluation found that the Non-EQ Inaccessible Power Cables (400 V to 35 kV)Program described in the LRA includes activities that are consistent with the lessons learnedfrom the SQN OE. Therefore, changes to this program were not warranted.Plant-specific OE such as water in manholes and testing results will be factored into theprogram to change inspection or test frequencies as described in B. 1.25 and A. 1.25. The AMPis based on OE up to time Revision 2 of NUREG-1801 was issued. As stated in LRA SectionB.1.25, industry OE will be considered in the implementation of this program and plant OE willbe gained as the program is executed and will be factored into the program via the confirmationand corrective action elements of the SQN 10 CFR 50 Appendix B quality assurance program.The process for review of future plant-specific and industry OE for aging management programsis discussed in Section B.0.4.RAI Item 3:The change to LRA Section B. 1.25 follows, deletions are shown with strikethrough and additionsare underlined.E1-75 of 79 B.1.25 NON-EQ INACCESSIBLE POWER CABLES (400 V TO 35 KV)Operating Experience"The Non-EQ Inaccessible Power Cables (400 V to 35 kV) Program is a new program. Industryoperating experience and SQN operating experience will be considered in the implementationof this program. Plant operating experience will be gained as the program is executed and willbe factored into the program via the confirmation and corrective action elements of the SQN 10CFR 50 Appendix B quality assurance program.The 5/4/2007 SQN response to GL 2007-01 identified two in-service failures of undergroundsafety-related power cables. One of these failures was the 2002 in-service failure of a 6.9 kvERCW supply pump circuit that was attributed to water treeing of the underground cable andthe other failure was due to a manufacturing defect. SQN also reported 14 test failures. Thesewere failures to meet withstand testing acceptance criteria, which was either DC hipot or ACVLF withstand testing. The testing failures occurred during assessment of the condition ofmedium-voltage underground safety-related cables following the discovery of water treeing thatcaused the failed cable in 2002. These medium-voltage cable circuits are now subwect toretesting at intervals dictated by the results of the "tan delta" assessments. A review of plant-specific operating experience identified no age -elated underground cable failures since theresponse to GL 2007-01, nor any aging mechanisms not considered in NUREG-1801.Although sump pumps are installed in some manholes at SQN, unacceptable amounts ofwaterhave been found in some of them. This condition was documented in 2011,. and-2012,and 2013.As documented in the SQN corrective action program, there have been multiple instances ofwater in manholes at SQN. In 2012, a report was initiated in the correction action program todocument the trend of high levels of water in manholes that the work control process is notresolving in a timely manner. The NRC, in an inspection report dated 4/30/2012, identified afinding of very low safety significance (green) related to water in manholes. In response to theidentified issues with untimely removal of water from manholes, the PM task instructions wererevised to require water removal, if found, from the manholes before the PM task could beclosed. SQN experience since revising the PM instructions has been that the water, if any, hasbeen removed within a week of initiating the PM activity.As a result of the negative operating experience with water in the manholes, a team of TVApersonnel was established in early 2013 to resolve the dewatering issues with safety-relatedmanholes. The team is scheduling activities which will effect repair or replacement of sumppumps and discharge piping as necessary to improve dewatering performance. In addition,TVA is issuing a modification to enlarqe the size of the openings in the covers of manholesthereby enhancing the ability to remove water from manholes without having to remove theheavy missile shield manhole covers.The resultant corrective actions are expected to improve the capability to prevent wateraccumulation in manholes.Proven, commercially available tests will be used for cable testing. As discussed in element 10to NUREG-1 801,Section XI.E3, this program considers the technical information and industryoperating experience provided in NUREG/CR-5643; IEEE Std. 1205-2000; SAND96-0344;EPRI 109619; EPRI 103834-P1-2; NRC IN 2002-12; NRC GL 2007-01; NRC GL 2007-01Summary Report; NRC Inspection Procedure, Attachment 71111.06, Flood ProtectionMeasures; NRC Inspection Procedure, Attachment 71111.01, Adverse Weather Protection; RG1.211 ,Rev. 0; DG-1240; and NUREG/CR-7000. Accordingly, there is reasonable assurancethat this new aging management program will be effective during the period of extendedoperation.E1-76 of 79 The process for review of future plant-specific and industry operating experience for agingmanagement programs is discussed in Section B.O.4."LRA B.1.26, Non-EQ Instrumentation Circuits Test Review ProgramRAI Item 1:The assessment of ten years of SQN OE performed to support the SQN LRA did not identifyaging effects for the electrical commodities covered by the Non-EQ Instrumentation CircuitsTest Review Program.The aging effects applicable to SQN insulation materials are taken from the DOE Cable AMG,which is based on a comprehensive review of industry OE through 1996. The EPRI electricalhandbook incorporated these results and consolidated the passive electrical commodity agingeffects into one concise document. The aging management review utilized guidance from theindustry documents and considered lessons learned from previous LRAs (LRAs), includingassociated RAIs.The OE review is the examination of industry data and plant-specific data relative to the aging ofpassive electrical commodities included in the aging management review. The purpose of thereview is to validate aging effects requiring management. This review did not identify plant-specific or new industry OE different from the industry OE cited in NUREG-1801,Section XI.E2and concludes the aging effects identified and discussed in NUREG-1801,Section XI.E2 arebounding for SQN.RAI Item 2:The lessons learned from the sensitive instrumentation cable and connection OE wereevaluated during preparation of the SQN LRA. The evaluation found that the Non-EQInstrumentation Circuits Test Review Program described in the LRA includes activities that areconsistent with the lessons learned from industry OE. Therefore, changes to this program werenot warranted.During implementation of the new B. 1.26 AMP, inspection activities will be modified or newactivities developed as necessary to achieve consistency with the B. 1.26 AMP andconsequently with the AMP described in NUREG-1801,Section XI.E2. The industry agingeffect OE discussed above is addressed by the Non-EQ Instrumentation Circuits Test ReviewProgram, so an enhancement to this program is not warranted.RAI Item 3:The change to LRA Section B.1.26 follows, deletions are shown with strikethrough and additionsare underlined.B.1.26 NON-EQ INSTRUMENTATION CIRCUITS TEST REVIEWOperating- Experience"The Non-EQ Instrumentation Circuits Test Review Program is a new program. Industryoperating experience and SQN operating experience will be considered in the implementationof this program. Plant operating experience will be gained as the program is executed and willbe factored into the program via the confirmation and corrective action elements of the SQN 10CFR 50 Appendix B quality assurance program.E1-77 of 79 The assessment of ten years of SQN operating experience performed to support the SQN LRAdid not identify aging effects for the electrical commodities covered by the Non-EQInstrumentation Circuits Test Review Program.As stated in NUREG-1801, Revision 2,Section XI.E2, industry operating experience hasidentified a case where a change in temperature across a high-range radiation monitor cable incontainment resulted in substantial change in the reading of the monitor. Changes ininstrument calibration can be caused by degradation of the circuit cable and are a possibleindication of electrical cable degradation. The vast majority of industry operating experienceregarding neutron flux instrumentation circuits is related to cable/connector issues insidecontainment near the reactor vessel. There is no operating experience at SQN involving age-related failures of neutron monitoring and high range radiation monitoring system cables andconnections, and no aging mechanisms not considered in NUREG-1801 have been identified.Accordingly, there is reasonable assurance that this new aging management program will beeffective during the period of extended operation.As discussed in element 10 to NUREG-1 801,Section XI.E2, this program considers thetechnical information and industry operating experience provided in NUREG/CR-5643, IEEEStd. 1205-2000, SAND96-0344, EPRI TR-109619, NRC IN 97-45, and NRC IN 97-45,Supplement 1.The process for review of future plant-specific and industry operating experience for agingmanagement programs is discussed in Section B.0.4."LRA B.1.27, Non-EQ Insulated Cables and Connections ProgramRAI Item 1:The following summary discussion addresses the results of the OE review for electricalcommodities that are included in the Non-EQ Insulated Cables and Connections Program.Cables associated with a fire detection panel experienced outer insulation breaking down due tohigh localized temperatures caused by a nearby main steam line. The breakdown of the outerjacket due to excess heat allowed the exuding of the cable plasticizer.Cables associated with a 120V AC vital instrument power board experienced outer insulationbreaking down due to high localized temperatures. The breakdown of the outer jacket due toexcess heat allowed the exuding of the cable plasticizer.The cable jacket and insulation on a thermocouple cable located underneath the hot leg 1nozzle cover in the reactor cavity was degraded to the point that the cable jacket and insulationfell off due to heat and/or radiation exposure when the cable was removed.Mirror insulation was left off hot piping near conduit containing field cables for RTDs. Themissing insulation caused a cable temperature higher than the cable temperature rating. ThisOE is for an EQ cable, but it is applicable to other cables.The above conditions are examples of adverse local environments associated with heat. TheSQN Non-EQ Insulated Cables and Connections Program addresses identification andevaluation of adverse local environments caused by high local temperatures.Motor leads for a HDTP motor have deteriorated (spongy insulation). This problem was causedby prolonged exposure to oil and the normal internal motor temperatures. Replacement leadsshould have insulation material with good resistance to degradation from oil saturation. This isbecause of the history of these motors misting oil into the motor housing. This is an example ofan adverse environment associated with exposure to contaminants, which is this case is oil. Thestressors of adverse environments and the associated aging effect of reduced insulationE1-78 of 79 resistance are addressed in the SQN LRA and the Non-EQ Insulated Cables and ConnectionsProgram.RAI Item 2:The lessons learned from the insulated cable and connection OE were evaluated duringpreparation of the SQN LRA. The evaluation found that the Non-EQ Insulated Cables andConnections Program described in the LRA includes activities that are consistent with thelessons learned from the SQN OE. Therefore, changes to this program were not warranted.RAI Item 3:The change to LRA Section B.1.27 follows, deletions are shown with strikethrough and additionsare underlined.B.1.27 NON-EQ INSULATED CABLES AND CONNECTIONSOperating Experience"The Non-EQ Insulated Cables and Connections Program is a new program. Industry operatingexperience and SQN operating experience will be considered in the implementation of thisprogram. Plant operating experience will be gained as the program is executed and will befactored into the program via the confirmation and corrective action elements of the SQN 10CFR 50 Appendix B quality assurance program.SQN has experienced cable iacket and insulation degradation as a result of adverse localizedenvironments from thermal stress and moisture. These issues were discovered duringmaintenance and plant walkdowns. No failures of circuit function were identified from thereview of SQN operating experience. The SQN Non-EQ Insulated Cables and ConnectionsProgram addresses identification and evaluation of adverse local environments.As stated in NUREG-1801, Revision 2,Section XI.E1, industry operating experience hasshown that adverse localized environments caused by heat/radiation/moisture for electricalcables and connections may exist near steam generators, pressurizers, or hot process pipes,such as feedwater lines. In this industry experience, such adverse localized environments havecaused degradation of insulating materials on electrical cables and connections that is visuallyobservable, such as color changes or surface cracking. These visual indications can indicatecable degradation. The examination techniques used in this program to detect aging effectsare proven industry techniques that have been effectively used at SQN in other programs.Accordingly, there is reasonable assurance that this new aging management program willbeeffective during the period of extended operation.As discussed in element 10 to NUREG-1 801,Section XI.El, this program considers thetechnical information and industry operating experience provided in NUREG/CR-5643, IEEEStd. 1205-2000, SAND96-0344, and EPRI TR-109619.The process for review of future plant-specific and industry operating experience for agingmanagement programs is discussed in Section B.0.4."E1-79 of 79 ENCLOSURE2Tennessee Valley AuthoritySequoyah Nuclear Plant, Units I and 2 License RenewalRegulatory Commitment List, Revision 3I. Commitments 2.C, 7.C, 9.D, 12.B, 28.B, 31.1, 31.J have been revised.II. Commitments 34 and 35 are new.RELATEDIMPLMENTTIONLRANo. COMMITMENT IMPLEMENTATION SOURCE SECTION /SCHEDULESETOAUDIT ITEMImplement the Aboveground Metallic Tanks SQN1: Prior to 09/17/20 B. 1.1Program as described in LRA Section B.1.1 3QN2: Prior to 09/15/212 A. Revise Bolting Integrity Program procedures 3QNI: Prior to 09/17/20 B.1.2to ensure the actual yield strength of replacement or 3QN2: Prior to 09/15/21newly procured bolts will be less than 150 ksiB. Revise Bolting Integrity Program procedures toinclude the additional guidance andrecommendations of EPRI NP-5769 for replacementof ASME pressure-retaining bolts and the guidanceprovided in EPRI TR-1 04213 for the replacement ofother pressure-retaining bolts.C. Revise Bolting Integrity Program procedures tospecify a corrosion inspection and a check-off forthe transfer tube isolation valve flange bolts.3 Implement the Buried and Underground Piping QN1: Prior to 09/17/20 B.1.4and Tanks Inspection Program as described in QN2: Prior to 09/15/21LRA Section B.1.4.E2-1 of 17 RELATEDCOMMITMENT IMPLEMENTATION SOURCE LRASCHEDULE SECTIONAUDIT ITEM4 A. Revise Compressed Air Monitoring Program SQN1: Prior to 09/17/20 B.1.5procedures to include the standby diesel generator SQN2: Prior to 09/15/21(DG) starting air subsystem.B. Revise Compressed Air Monitoring Programprocedures to include maintaining moisture andother contaminants below specified limits in thestandby DG starting air subsystemC. Revise Compressed Air Monitoring Programprocedures to apply a consideration of the guidanceof ASME OM-S/G-1998, Part 17; EPRI NP-7079;and EPRI TR-108147 to the limits specified for theair system contaminantsD. Revise Compressed Air Monitoring Programprocedures to maintain moisture, particulate size,and particulate quantity below acceptable limits inthe standby DG starting air subsystem to mitigateloss of material.E. Revise Compressed Air Monitoring Programprocedures to include periodic and opportunisticvisual inspections of surface conditions consistentwith frequencies described in ASME O/M-SG-1998, Part 17 of accessible internal surfaces suchas compressors, dryers, after-coolers, and filterboxes of the following compressed air systems:* Diesel starting air subsystem* Auxiliary controlled air subsystem* Nonsafety-related controlled air subsystemF. Revise Compressed Air Monitoring Programprocedures to monitor and trend moisture content inthe standby DG starting air subsystem.G. Revise Compressed Air Monitoring Programprocedures to include consideration of the guidancefor acceptance criteria in ASME OM-S/G-1 998, Part17, EPRI NP-7079; and EPRI TR-108147.E2-2 of 17 RELATEDNo. COMMITMENT IMPLEMENTATION SOURCE LRASCHEDULE SECTIONAUDIT ITEM5 A. Revise Diesel Fuel Monitoring Program SQN1: Prior to 09/17/20 B.1.8procedures to monitor and trend sediment and SQN2: Prior to 09/15/21particulates in the standby DG day tanks.B. Revise Diesel Fuel Monitoring Programprocedures to monitor and trend levels ofmicrobiological organisms in the seven-day storagetanks.C. Revise Diesel Fuel Monitoring Programprocedures to include a ten-year periodic cleaningand internal visual inspection of the standby DGdiesel fuel oil day tanks and high pressure fireprotection (HPFP) diesel fuel oil storage tank. Thesecleanings and internal inspections will be performedat least once during the ten-year period prior to theperiod of extended operation and at succeeding ten-year intervals. If visual inspection is not possible, avolumetric inspection will be performed.D. Revise Diesel Fuel Monitoring Programprocedures to include a volumetric examination ofaffected areas of the diesel fuel oil tanks, if evidenceof degradation is observed during visual inspection.The scope of this enhancement includes thestandby DG seven-day fuel oil storage tanks,standby DG fuel oil day tanks, and HPFP diesel fueloil storage tank and is applicable to the inspectionsperformed during the ten-year period prior to theperiod of extended operation and succeeding ten-year intervals.6 A. Revise External Surfaces Monitoring Program SQN1: Prior to 09/17/20 B.1.10procedures to clarify that periodic inspections of SQN2: Prior to 09/15/21systems in scope and subject to aging managementreview for license renewal in accordance with 10CFR 54.4(a)(1) and (a)(3) will be performed.Inspections shall include areas surrounding thesubject systems to identify hazards to thosesystems. Inspections of nearby systems that couldimpact the subject systems will include SSCs thatare in scope and subject to aging managementreview for license renewal in accordance with 10CFR 54.4(a)(2).B. Revise External Surfaces Monitoring Programprocedures to include instructions to look for thefollowing related to metallic components:" Corrosion and material wastage (loss ofmaterial)." Leakage from or onto external surfaces lossof material).E2-3 of 17 RELATEDIMPLMENTTIONLRANo. COMMITMENT IMPLEMENTATION SOURCE SECTION IAUDIT ITEM6

• Worn, flaking, or oxide-coated surfaces(cont.) (loss of material)." Corrosion stains on thermal insulation (lossof material)." Protective coating degradation (cracking,flaking, and blistering)." Leakage for detection of cracks on theexternal surfaces of stainless steelcomponents exposed to an air environmentcontaining halides.C. Revise External Surfaces Monitoring Programprocedures to include instructions for monitoringaging effects for flexible polymeric components,including manual or physical manipulations of thematerial, with a sample size for manipulation of atleast ten percent of the available surface area.The inspection parameters for polymers shallinclude the following:* Surface cracking, crazing, scuffing,dimensional changes (e.g., ballooning andnecking) -).* Discoloration.* Exposure of internal reinforcement forreinforced elastomers (loss of material).* Hardening as evidenced by loss ofsuppleness during manipulation where thecomponent and material can bemanipulated.D. Revise External Surfaces Monitoring Programprocedures to ensure surfaces that are insulated willbe inspected when the external surface is exposed(i.e., during maintenance) at such intervals thatwould ensure that the components' intendedfunction is maintained.E. Revise External Surfaces Monitoring Programprocedures to include acceptance criteria. Examplesinclude the following:* Stainless steel should have a clean shinysurface with no discoloration." Other metals should not have any abnormalsurface indications." Flexible polymers should have a uniformsurface texture and color with no cracks andno unanticipated dimensional change, noabnormal surface with the material in an as-new condition with respect to hardness,flexibility, physical dimensions, and color.* Rigid polymers should have no erosion,cracking, checking or chalks.E2-4 of 17 RELATEDIMPLMENTTIONLRANo. COMMITMENT IMPLEMENTATION SOURCE SECTION /SCHEDULESETOAUDIT ITEM7 A. Revise Fatigue Monitoring Program SQN1: Prior to 09/17/20 B.1.11procedures to monitor and track critical thermal and SQN2: Prior to 09/15/21pressure transients for components that have beenidentified to have a fatigue Time Limited AgingAnalysis.B. Fatigue usage calculations that consider theeffects of the reactor water environment will bedeveloped for a set of sample reactor coolantsystem (RCS) components. This sample set willinclude the locations identified in NUREG/CR-6260and additional plant-specific component locations inthe reactor coolant pressure boundary if they arefound to be more limiting than those considered inNUREG/CR-6260. In addition, fatigue usagecalculations for reactor vessel internals (lower coreplate and control rod drive (CRD) guide tube pins)will be evaluated for the effects of the reactor waterenvironment. Fen factors will be determined asdescribed in Section 4.3.3.C. Fatigue usage factors for the RCS pressureboundary iffiti components will be adjusted asnecessary determined to incorporate the effects ofthe Cold Overpressure Mitigation System (COMS)event (i.e., low temperature overpressurizationevent) and the effects of structural weld overlays.D. Revise Fatigue Monitoring Program proceduresto provide updates of the fatigue usage calculationson an as-needed basis if an allowable cycle limit isapproached, or in a case where a transientdefinition has been changed, unanticipated newthermal events are discovered, or the geometry ofcomponents have been modified.8 A. Revise Fire Protection Program procedures to SQN1: Prior to 09/17/20 B. 1.12include an inspection of fire barrier walls, ceilings, SQN2: Prior to 09/15/21and floors for any signs of degradation such ascracking, spalling, or loss of material caused byfreeze thaw, chemical attack, or reaction withaggregates.B. Revise Fire Protection Program procedures toprovide acceptance criteria of no significantindications of concrete cracking, spalling, and lossof material of fire barrier walls, ceilings, and floorsand in other fire barrier materials.E2-5 of 17 RELATEDNo. COMMITMENT IMPLEMENTATION SOURCE LRASCHEDULE SECTIONAUDIT ITEM9 A. Revise Fire Water System Program procedures QN1: Prior to 09/17/20 B.1.13to include periodic visual inspection of fire water SQN2: Prior to 09/15/21system internals for evidence of corrosion and lossof wall thickness.B. Revise Fire Water System Program proceduresto include one of the following options:* Wall thickness evaluations of fire protectionpiping using non-intrusive techniques (e.g.,volumetric testing) to identify evidence ofloss of material will be performed prior tothe period of extended operation andperiodically thereafter. Results of the initialevaluations will be used to determine theappropriate inspection interval to ensureaging effects are identified prior to loss ofintended function." A visual inspection of the internal surface offire protection piping will be performed uponeach entry into the system for routine orcorrective maintenance. These inspectionswill be capable of evaluating (1) wallthickness to ensure against catastrophicfailure and (2) the inner diameter of thepiping as it applies to the design flow of thefire protection system. Maintenance historyshall be used to demonstrate that suchinspections have been performed on arepresentative number of locations prior tothe period of extended operation. Arepresentative number is 20% of thepopulation (defined as locations having thesame material, environment, and agingeffect combination) with a maximum of 25locations. Additional inspections will beperformed as needed to obtain thisrepresentative sample prior to the period ofextended operation and periodically duringthe period of extended operation based onthe findings from the inspections performedprior to the period of extended operation.C. Revise Fire Water System Program proceduresto ensure a representative sample of sprinklerheads will be tested or replaced before the end ofthe 50-year sprinkler head service life and at ten-year intervals thereafter during the extended periodof operation. NFPA-25 defines a representativesample of sprinklers to consist of a minimum of notless than four sprinklers or one percent of thenumber of sprinklers per individual sprinkler sample,I U U IE2-6 of 17 RELATEDIMPLMENTTIONLRANo. COMMITMENT IMPLEMENTATION SOURCE SECTION ISCHEDULESETOAUDIT ITEM9 whichever is greater. If the option to replace the(cont.) sprinklers is chosen, all sprinkler heads that havebeen in service for 50 years will be replaced.D. Revise the Fire Water System Program full flowtesting to be in accordance with full flow testingstandards of NFPA-25 (2011).Reveso Fire Water System Programn procedu res toconsider implementing the flow testing requirementsof NFPA 25 or justifn why the flo-- testingreuiremnts of NEPPA should not be ipeetdE. Revise Fire Water System Program proceduresto include acceptance criteria for periodic visualinspection of fire water system internals forcorrosion, minimum wall thickness, and the absenceof biofouling in the sprinkler system that could causecorrosion in the sprinklers.10 Revise Flow Accelerated Corrosion Program SQNI: Prior to 09/17/20 B.1.14procedures to implement NSAC-202L guidance for SQN2: Prior to 09/15/21examination of components upstream of pipingsurfaces where significant wear is detected.11 Revise Flux Thimble Tube Inspection Program SQN1: Prior to 09/17/20 B.1.15procedures to include a requirement to address if SQN2: Prior to 09/15/21the predictive trending projects that a tube willexceed 80% wall wear prior to the next plannedinspection, then initiate a Service Request (SR) todefine actions (i.e., plugging, repositioning,replacement, evaluations, etc.) required to ensurethat the projected wall wear does not exceed 80%.If any tube is found to be >80% through wall wear,then initiate a Service Request (SR) to evaluate thepredictive methodology used and modify as requiredto define corrective actions (i.e., plugging,I repositioning, replacement, etc).E2-7 of 17 RELATEDIMPLMENTTIONLRANo. COMMITMENT IMPLEMENTATION SOURCE SECTION ISCHEDULESETOAUDIT ITEM12 A. Revise Inservice Inspection-IWF Program SQN1: Prior to 09/17/20 B.1.17procedures to clarify that detection of aging effects SQN2: Prior to 09/15/21will include monitoring anchor bolts for loss ofmaterial, loose or missing nuts, and cracking ofconcrete around the anchor bolts.B. Revise ISI -IWF Program procedures to includethe following corrective action guidance.When a component support is found with minorage-related degradation, but still is evaluated as'acceptable for continued service" as defined inIWF-3400, the program owner may choose torepair the degraded component. If thecomponent is repaired, the program owner willsubstitute a randomly selected component that ismore representative of the general population forsubsequent inspections.13 Inspection of Overhead Heavy Load and Light SQNI: Prior to 09/17/20 B.1.18Load (Related to Refueling) Handling Systems: SQN2: Prior to 09/15/21A. Revise program procedures to specify theinspection scope will include monitoring of rails inthe rail system for wear; monitoring structuralcomponents of the bridge, trolley and hoists for theaging effect of deformation, cracking, and loss ofmaterial due to corrosion; and monitoring structuralconnections/bolting for loose or missing bolts, nuts,pins or rivets and any other conditions indicative ofloss of bolting integrity.B. Revise program procedures to include theinspection and inspection frequency requirements ofASME B30.2.C. Revise program procedures to clarify that theacceptance criteria will include requirements forevaluation in accordance with ASME B30.2 ofsignificant loss of material for structural componentsand structural bolts and significant wear of rail in therail system.D. Revise program procedures to clarify that theacceptance criteria and maintenance and repairactivities use the guidance provided in ASME B30.214 Implement the Internal Surfaceis in Miscellaneous SQNI: Prior to 09/17/20 B.1.19Piping and Ducting Components Program as SQN2: Prior to 09/15/21described in LRA Section B.1.19.E2-8 of 17 RELATEDNo. COMMITMENT IMPLEMENTATION SOURCE LRASCHEDULE SECTION IAUDIT ITEM15 Implement the Metal Enclosed Bus Inspection SQN1: Prior to 09/17/20 B.1.21Program as described in LRA Section B.1.21. 3QN2: Prior to 09/15/2116 A. Revise Neutron Absorbing Material 3QNI: Prior to 09/17/20 B.1.22Monitoring Program procedures to perform 3QN2: Prior to 09/15/21blackness testing of the Boral coupons within theten years prior to the period of extended operationand at least every ten years thereafter based oninitial testing to determine possible changes inboron-10 areal density.B. Revise Neutron Absorbing Material MonitoringProgram procedures to relate physicalmeasurements of Boral coupons to the need toperform additional testing.C. Revise Neutron Absorbing Material MonitoringProgram procedures to perform trending of coupontesting results to determine the rate of degradationand to take action as needed to maintain theintended function of the Boral.17 Implement the Non-EQ Cable Connections 3QN1: Prior to 09/17/20 B.1.24Program as described in LRA Section B.1.24 3QN2: Prior to 09/15/2118 Implement the Non-EQ Inaccessible Power Cable 3QNI: Prior to 09/17/20 B.1.25(400 V to 35 kV) Program as described in LRA SQN2: Prior to 09/15/21Section B.1.2519 Implement the Non-EQ Instrumentation Circuits SQN1: Prior to 09/17/20 B.1.26Test Review Program as described in LRA Section SQN2: Prior to 09/15/21B.1.26.20 Implement the Non-EQ Insulated Cables and SQN 1: Prior to 09/17/20 B.1.27Connections Program as described in LRA SQN2: Prior to 09/15/21Section B.1.2721 A. Revise Oil Analysis Program procedures to QN1: Prior to 09/17/20 B.1.28monitor and maintain contaminants in the 161-kV oil SQN2: Prior to 09/15/21filled cable system within acceptable limits throughperiodic sampling in accordance with industrystandards, manufacturer's recommendations andplant-specific operating experience.B. Revise Oil Analysis Program procedures to trendoil contaminant levels and initiate a problemevaluation report if contaminants exceed alertlevels or limits in the 161-kV oil-filled cable system.22 Implement the One-Time Inspection Program as QN1: Prior to 09/17/20 B.1.29described in LRA Section B.1.29. QN2: Prior to 09/15/21E2-9 of 17 RELATEDIMPLMENTTIONLRANo. COMMITMENT IMPLEMENTATION SOURCE SECTION ISCHEDULESETOAUDIT ITEM23 Implement the One-Time Inspection -Small Bore SQN1: Prior to 09/17/20 B.1.30Piping Program as described in LRA Section SQN2: Prior to 09/15/21B.1.3024 Revise Periodic Surveillance and Preventive SQN1: Prior to 09/17/20 B.1.31Maintenance Program procedures as necessary to SQN2: Prior to 09/15/21include all activities described in the table providedin the LRA Section B.1.31 program description.25 A. Revise Protective Coating Program SQN1: Prior to 09/17/20 B.1.32procedures to clarify that detection of aging effects SQN2: Prior to 09/15/21will include inspection of coatings near sumps orscreens associated with the emergency core coolingsystem.B. Revise Protective Coating Program proceduresto clarify that instruments and equipment needed forinspection may include, but not be limited to,flashlights, spotlights, marker pen, mirror,measuring tape, magnifier, binoculars, camera withor without wide-angle lens, and self-sealingpolyethylene sample bags.C. Revise Protective Coating Program proceduresto clarify that the last two performance monitoringreports pertaining to the coating systems will bereviewed prior to the inspection or monitoringprocess.26 A. Revise Reactor Head Closure Studs Program OQNI: Prior to 09/17/20 B.1.33procedures to ensure that replacement studs are SQN2: Prior to 09/15/21fabricated from bolting material with actualmeasured yield strength less than 150 ksi.B. Revise Reactor Head Closure Studs Programprocedures to exclude the use of molybdenumdisulfide (MoS2) on the reactor vessel closure studsand to refer to Reg. Guide 1.65, Revl.27 A. Revise Reactor Vessel Internals Program SQN1: Prior to 09/17/20 B.1.34procedures to take physical measurements of theType 304 stainless steel hold-down springs in Unit 1 SQN2: Not Applicableat each refueling outage to ensure preload isadequate for continued operation.B. Revise Reactor Vessel Internals Programprocedures to include preload acceptance criteriafor the Type 304 stainless steel hold-down springsin Unit 1.E2-10 of 17 RELATEDIMPLMENTTIONLRANo. COMMITMENT IMPLEMENTATION SOURCE SECTION ISCHEDULESETOAUDIT ITEM28 A. Revise Reactor Vessel Surveillance Program SQN1: Prior to 09/17/20 B. 1.35procedures to consider the area outside the beltline SQN2: Prior to 09/15/21such as nozzles, penetrations and discontinuities todetermine if more restrictive pressure-temperaturelimits are required than would be determined by justconsidering the reactor vessel beltline materials.B. Revise Reactor Vessel Surveillance Programprocedures to incorporatedevelep an NRC-approved schedule for capsule withdrawals to meetASTM-E185-82 requirements, including thepossibility of operation beyond 60 years(refer to theTVA Letter to NRC, "Sequoyah Reactor PressureVessel Surveillance Capsule Withdrawal ScheduleRevision Due to License Renewal Amendment,"dated January 10, 2013, ML13032A251.)C. Revise Reactor Vessel Surveillance Programprocedures to withdraw and test a standby capsuleto cover the peak fluence expected at the end of theperiod of extended operation.29 Implement the Selective Leaching Program as QN1: Prior to 09/17/20 B.1.37described in LRA Section B.1.37. QN2: Prior to 09/15/2130 Revise Steam Generator Integrity Program QN1: Prior to 09/17/20 B.1.39procedures to ensure that corrosion resistant QN2: Prior to 09/15/21materials are used for replacement steam generatortube plugs.31 A. Revise Structures Monitoring Program SQNI: Prior to 09/17/20 B.1.40procedures to include the following in-scope SQN2: Prior to 09/15/21structures:* Carbon dioxide building* Condensate storage tanks' (CSTs)foundations and pipe trench* East steam valve room Units 1 & 2* Essential raw cooling water (ERCW)pumping station* High pressure fire protection (HPFP) pumphouse and water storage tanks' foundations* Radiation monitoring station (or particulateiodine and noble gas station) Units 1 & 2* Service building* Skimmer wall (Cell No. 12)* Transformer and switchyard supportstructures and foundationsB. Revise Structures Monitoring Programprocedures to specify the following list of in-scopestructures are included in the RG 1.127, Inspection 1E2-11 of 17 RELATEDNo. COMMITMENT IMPLEMENTATION SOURCE LRASCHEDULE SECTIONIAUDIT ITEM31 of Water-Control Structures Associated with Nuclear(cont.) Power Plants Program (Section B.1.36):* Condenser cooling water (CCW) pumpingstation (also known as intake pumpingstation) and retaining walls* CCW pumping station intake channel* ERCW discharge box* ERCW protective dike* ERCW pumping station and access cells* Skimmer wall, skimmer wall Dike A andunderwater damC. Revise Structures Monitoring Programprocedures to include the following in-scopestructural components and commodities:* Anchor bolts* Anchorage/embedments (e.g., plates,channels, unistrut, angles, other structuralshapes)* Beams, columns and base plates (steel)* Beams, columns, floor slabs and interiorwalls (concrete)* Beams, columns, floor slabs and interiorwalls (reactor cavity and primary shieldwalls; pressurizer and reactor coolant pumpcompartments; refueling canal, steamgenerator compartments; crane wall andmissile shield slabs and barriers)* Building concrete at locations of expansionand grouted anchors; grout pads for supportbase plates* Cable trayo Cable tunnel* Canal gate bulkhead* Compressible joints and seals* Concrete cover for the rock walls ofapproach channel* Concrete shield blocks* Conduit* Control rod drive missile shield* Control room ceiling support system* Curbs* Discharge box and foundation* Doors (including air locks and bulkheaddoors)* Duct banks* Earthen embankment* Equipment pads/foundations* Explosion bolts (E. G. Smith aluminumbolts)E2-12 of 17 RELATEDTIMPLEMENTATION LRASCHEDULE ISECTIONAUDIT ITEM31 0 Exterior above and below grade;(cont.) foundation (concrete)* Exterior concrete slabs (missile barrier)and concrete caps* Exterior walls: above and below grade(concrete)* Foundations: building, electricalcomponents, switchyard, transformers,circuit breakers, tanks, etc.* Ice baskets* Ice baskets lattice support frames* Ice condenser support floor (concrete)* Intermediate deck and top deck of icecondenser* Kick plates and curbs (steel -inside steelcontainment vessel)* Lower inlet doors (inside steel containmentvessel)* Lower support structure structural steel:beams, columns, plates (inside steelcontainment vessel)* Manholes and handholes* Manways, hatches, manhole covers, andhatch covers (concrete)* Manways, hatches, manhole covers, andhatch covers (steel)* Masonry walls* Metal siding* Miscellaneous steel (decking, grating,handrails, ladders, platforms, enclosureplates, stairs, vents and louvers, framingsteel, etc.)* Missile barriers/shields (concrete)* Missile barriers/shields (steel)* Monorails* Penetration seals* Penetration seals (steel end caps)* Penetration sleeves (mechanical andelectrical not penetrating primarycontainment boundary)* Personnel access doors, equipmentaccess floor hatch and escape hatches* Piles* Pipe tunnel* Precast bulkheads* Pressure relief or blowout panels* Racks, panels, cabinets and enclosuresfor electrical equipment andinstrumentation* RiprapE2-13 of 17 RELATEDNo. COMMITMENT IMPLEMENTATION SOURCE SECTION IAUDIT ITEM31

• Rock embankment(cont.)

• Roof or floor decking* Roof membranes* Roof slabs* RWST rainwater diversion skirt* RWST storage basin* Seals and gaskets (doors, manways andhatches)* Seismic/expansion joint* Shield building concrete foundation, wall,tension ring beam and dome: interior,exterior above and below grade* Steel liner plate* Steel sheet piles* Structural bolting* Sumps (concrete)* Sumps (steel)* Sump liners (steel)* Sump screens* Support members; welds; boltedconnections; support anchorages tobuilding structure (e.g., non-ASME pipingand components supports, conduitsupports, cable tray supports, HVAC ductsupports, instrument tubing supports, tubetrack supports, pipe whip restraints, jetimpingement shields, masonry walls,racks, panels, cabinets and enclosures forelectrical equipment and instrumentation)* Support pedestals (concrete)* Transmission, angle and pull-off towers* Trash racks* Trash racks associated structural supportframing* Traveling screen casing and associatedstructural support framing* Trenches (concrete)* Tube track* Turning vanes* Vibration isolatorsD. Revise Structures Monitoring Programprocedures to include periodic sampling andchemical analysis of ground water chemistry for pH,chlorides, and sulfates on a frequency of at leastevery five years.E. Revise Masonry Wall Program procedures tospecify masonry walls located in the following in-scope structures are in the scope of the MasonryWall Program:* Auxiliary buildingE2-14 of 17 RELATEDTIMPLEMENTATION ITRANo. COMITMENTSCHEDULE SORE SECTION/AUDIT ITEM31

• Reactor building Units 1 & 2(cont.)

• Control bay* ERCW pumping station* HPFP pump house* Turbine buildingF. Revise Structures Monitoring Programprocedures to include the following parameters tobe monitored or inspected:* Requirements for concrete structuresbased on ACI 349-3R and ASCE 11 andinclude monitoring the surface conditionfor loss of material, loss of bond, increasein porosity and permeability, loss ofstrength, and reduction in concrete anchorcapacity due to local concretedegradation.* Loose or missing nuts for structuralbolting." Monitoring gaps between the structuralsteel supports and masonry walls thatcould potentially affect wall qualification.G. Revise Structures Monitoring Programprocedures to include the following components tobe monitored for the associated parameters:" Anchors/fasteners (nuts and bolts) will bemonitored for loose or missing nuts and/orbolts, and cracking of concrete around theanchor bolts.* Elastomeric vibration isolators andstructural sealants will be monit6red forcracking, loss of material, loss of sealing,and change in material properties (e.g.,hardening).H. Revise Structures Monitoring Programprocedures to include the following for detection ofaging effects:* Inspection of structural bolting for loose ormissing nuts.* Inspection of anchor bolts for loose ormissing nuts and/or bolts, and cracking ofconcrete around the anchor bolts.* Inspection of elastomeric material forcracking, loss of material, loss of sealing,and change in material properties (e.g.,hardening), and supplement inspection byfeel or touch to detect hardening if theintended function of the elastomericmaterial is suspect. Include instructions toaugment the visual examination ofelastomeric material with physicalE2-15 of 17 RELATEDIMLMNA IO LRANo. COMMITMENT IMPLEMENTATION SOURCE SECTION IAUDIT ITEM31 manipulation of at least ten percent of(cont.) available surface area.* Opportunistic inspections when normallyinaccessible areas (e.g., high radiationareas, below grade concrete walls orfoundations, buried or submergedstructures) become accessible due torequired plant activities. Additionally,inspections will be performed ofinaccessible areas in environments whereobserved conditions in accessible areasexposed to the same environment indicatethat significant degradation is occurring.* Inspection of submerged structures atleast once every five years.Inspections of water control structuresshould be conducted under the direction ofqualified personnel experienced in theinvestigation, design, construction, andoperation of these types of facilities.* Inspections of water control structuresshall be performed on an interval not toexceed five years.* Perform special inspections of watercontrol structures immediately (within 30days) following the occurrence ofsignificant natural phenomena, such aslarge floods, earthquakes, hurricanes,tornadoes, and intense local rainfalls.I. Verify acceptance riteria i Revise StructuresMonitoring Program procedures to prescribequantitative acceptance criteria is based on thequantitative acceptance criteria of ACI 349.3R andinformation provided in industry codes, standards,and guidelines including NEI 96 03, Al 201.!R 92,,A,.hSI/ASCE 11-99, and AC 3"19.3R 02 ACI1318,ANSI/ASCE 11 and relevant AISC specifications.Industry and plant-specific operating experience willalso be considered in the development of theacceptance criteria.J. Revise Structures Monitoring Programprocedures to clarify that detection of aging effectswill include the following.Qualifications of personnel conducting theinspections or testing and evaluation of structuresand structural components meet the guidance inChaDter 7 of ACI 349.3R.& I I IE2-16 of 17 RELATEDIMPLMENTTIONLRANo. COMMITMENT IMPLEMENTATION SOURCE SECTION ISCHEDULESETOAUDIT ITEM32 Implement the Thermal Aging Embrittlement of SQN1: Prior to 09/17/20 B.1.41Cast Austenitic Stainless Steel (CASS) as SQN2: Prior to 09/15/21described in LRA Section B.1.4133A. Revise Water Chemistry Control -ClosedTreated Water Systems Program procedures toprovide a corrosion inhibitor for the following chilledwater subsystems in accordance with industryguidelines and vendor recommendations:* Auxiliary building cooling* Incore Chiller 1A, 1B, 2A, & 2B* 6.9 kV Shutdown Board Room A & BB. Revise Water Chemistry Control -ClosedTreated Water Systems Program procedures toconduct inspections whenever a boundary isopened for the following systems:* Standby diesel generator jacket watersubsystem* Component cooling system* Glycol cooling loop system* High pressure fire protection diesel jacketwater system* Chilled water portion of miscellaneousHVAC systems (i.e., auxiliary building,Incore Chiller 1A, 1B, 2A, & 2B, and 6.9kV Shutdown Board Room A & B)C. Revise Water Chemistry Control-ClosedTreated Water Systems Program procedures tostate these inspections will be conducted inaccordance with applicable ASME Coderequirements, industry standards, or other plant-specific inspection and personnel qualificationprocedures that are capable of detecting corrosionor cracking.D. Revise Water Chemistry Control -ClosedTreated Water Systems Program procedures toperform sampling and analysis of the glycolcooling system per industry standards and in nocase greater than quarterly unless justified with anadditional analysis.E. Revise Water Chemistry Control -ClosedTreated Water Systems Program procedures toinspect a representative sample of piping andcomponents at a frequency of once every tenyears for the following systems:* Standby diesel generator jacket watersubsystem* Component cooling system3QN1: Prior to 09/17/203QN2: Prior to 09/15/21B.1.42E2-17 of 17 RELATEDIMPLMENTTIONLIRANo. COMMITMENT IMPLEMENTATION SOURCE SECTION ISCHEDULESETOAUDIT ITEM33 0 Glycol cooling loop system(cont.) 0 High pressure fire protection diesel jacketwater system0 Chilled water portion of miscellaneousHVAC systems (i.e., auxiliary building,Incore Chiller 1A, 1B, 2A, & 2B, and 6.9kV Shutdown Board Room A & B)F. Components inspected will be those with thehighest likelihood of corrosion or cracking. Arepresentative sample is 20% of the population(defined as components having the same material,environment, and aging effect combination) with amaximum of 25 components. These inspectionswill be in accordance with applicable ASME Coderequirements, industry standards, or other plant-specific inspection and personnel qualificationprocedures that ensure the capability of detectingcorrosion or cracking.34 Revise Containment Leak Rate Program SQNI: Prior to 09/17/20 B.1.7procedures to require venting the SCV bottom liner SQN2: Prior to 09/15/21plate weld leak test channels to the containmentatmosphere prior to the CILRT and resealing thevent path after the CILRT to prevent moistureintrusion during plant operation.35 Modify the configuration of the SQN Unit 1 test SQNI: Prior to 09/17/20 B.1.6connection access boxes to prevent moistureintrusion to the leak test channels. Prior to installing SQN2: Not Applicablethis modification, TVA will perform remote visualexaminations inside the leak test channels byinserting a borescope video probe through the testconnection tubing.The above table identifies the 35 SQN NRC LR commitments. Any other statements inthis letter are provided for information purposes and are not considered to be regulatorycommitments.E2-18 of 17