ML13267A159
Jump to navigation
Jump to search
| ML13267A159 | |
| Person / Time | |
|---|---|
| Site: | Sequoyah  |
| Issue date: | 09/20/2013 |
| From: | Shea J W Tennessee Valley Authority |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| TAC MF0481, TAC MF0482 | |
| Download: ML13267A159 (54) | |
Text
Tennessee Valley Authority, 1101 Market Street, Chattanooga, Tennessee 37402September 20, 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 Regarding theReview of the Sequoyah Nuclear Plant, Units 1 and 2, License RenewalApplication, Set 11 (30-day), and Revised RAI Responses for B.1.14-1a,2.5-2a, 2.3.4.3-5a, 2.3.3.15-la, B.1.41-3b (TAC Nos. MF0481 and MF0482)References: 1. 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 ofthe Sequoyah Nuclear Plant, Units 1 and 2, License Renewal Application(TAC Nos. MF0481 and MF0482) -Set 11," dated August 22, 2013(ADAMS Accession No. ML 13224A126)3. Letter to NRC, "Response to NRC Request for Additional InformationRegarding the Review of the Sequoyah Nuclear Plant, Units 1 and 2,License Renewal Application, Sets 1, 6, 7, and Revised Responsesfor 1.4-2, 1.4-3 and 1.4-4 (TAC Nos. MF0481 and MF0482)," datedAugust 9, 2013 (ADAMS Accession No. ML 13225A387)4. Letter to NRC, "Response to NRC Request for Additional InformationRegarding the Review of the Sequoyah Nuclear Plant, Units 1 and 2,License Renewal Application, Set 4/Buried Piping, Set 8, and Set 9(TAC Nos. MF0481 and MF0482)," dated July 25, 2013 (ADAMSAccession No. ML 13213A026)Printed on recycled paper U.S. Nuclear Regulatory CommissionPage 2September 20, 20135. Letter to NRC, "Response to NRC Request for Additional InformationRegarding the Review of the Sequoyah Nuclear Plant, Units 1 and 2,License Renewal Application, Set 10 (30-day), B.1.9-1, B.1.4-4 RevisedRAI Responses, and Revision to LRA page 2.4-44 (TAC Nos. MF0481and MF0482)," dated September 3, 2013 (ADAMS Accession No. ML13252A036)By letter dated January 7, 2013 (Reference 1), Tennessee Valley Authority (TVA) submittedan application to the Nuclear Regulatory Commission (NRC) to renew the operating licensesfor the Sequoyah Nuclear Plant (SQN), Units 1 and 2. The request would extend thelicenses for an additional 20 years beyond the current expiration date.By Reference 2, the NRC forwarded a request for additional information (RAI) labeledSet 11. The required date for responding was within 30 days of the date stated in the RAI(i.e., no later than September 23, 2013). Enclosure 1 provides the RAI responses.In References 3, 4, and 5, TVA submitted responses that included RAIs B.1.14-1, 2.5-2,2.3.4.3-5, 2.3.3.15-1, and B.1.41-3a. In an August 23, 2013 telecom, Mr. Richard Plasse,the NRC License Renewal Project Manager, requested clarification for these RAIresponses. Enclosure 2 provides the requested clarification.Enclosure 3 is an updated list of the regulatory commitments for license renewal.Consistent 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 this20th day of September 2013.Respe y,J W. heaice resident, Nuclear Licensingnclosures:1. TVA Responses to NRC Request for Additional Information: Set 1.1 (30-day)2. Revised Responses for B.1.14-1a, 2.5-2a, 2.3.4.3-5a, 2.3.3.15-1a, and B.1.41-3b3. Regulatory Commitment List, Revision 7 /cc: See Page 3 U.S. Nuclear Regulatory CommissionPage 3September 20, 2013cc (Enclosures):NRC Regional Administrator- Region IINRC Senior Resident Inspector -Sequoyah Nuclear Plant ENCLOSURE 1Tennessee Valley AuthoritySequoyah Nuclear Plant, Units I and 2 License RenewalTVA Responses to NRC Request for Additional Information: Set 11 (30-day)
ENCLOSUREITennessee Valley AuthoritySequoyah Nuclear Plant, Units 1 and 2 License RenewalTVA Responses to NRC Request for Additional Information: Set 11 (30-day)RAI 4.1-4aBackground:By letter dated July 11, 2013, the applicant provided its responses to RAI 4.1-4, Parts a. and b.on whether the flaw analysis for the reactor coolant pump (RCP) casings at Sequoyah Units Iand 2 would need to be identified as a Time Limited Aging Analysis (TLAA) for the LicenseRenewal Application (LRA) in accordance with 10 CFR 54.21(c)(1) TLAA identificationrequirements.Issue:To resolve the RAI request, the applicant must demonstrate that the analysis does not conformto one or more of the six definition criteria that are used to define a plant analysis as a TLAA, asgiven in 10 CFR 54.3(a). In its response to RAI 4.1-4, Parts a. and b., the applicant relies on afuture licensing basis change that the applicant claims will be done during the Period ofExtended Operation (PEO) and uses this future licensing basis change in the PEO as the solebasis for concluding that the supporting flaw tolerance analysis for the RCP casings does notneed to be identified as a TLAA. This is not acceptable because the basis did not demonstratewhy the stated analysis is not in conformance with all six definition criteria for TLAAs in 10 CFR54.3(a) or why the analysis would not need to be identified pursuant to the TLAA identificationrequirement in 10 CFR 54.21(c)(1) and the six criteria for TLAAs in 10 CFR 54.3(a).Request:1. Clarify whether ASME Code Case N-481 and the supporting flaw tolerance evaluationfor the RCP casings are being relied upon in the current licensing basis (CLB) as thebasis for performing alternative visual examinations of the RCP casing welds, and if so,justify why the flaw tolerance analysis would not need to be identified as a TLAA for theLRA, as based on the CLB for the Sequoyah units at time of the LRA review. Respondto Part 2 of this request if this Code Case is still being relied upon for the CLB.2. Clarify how the flaw tolerance evaluation addressed potential drops in the fracturetoughness property of the CASS RCP casing material during the PEO, and justify whythe assessment of loss of fracture toughness in the evaluation would not need to bewithin the scope of a TLAA for the LRA.E-1 -1 of 17 TVA Response to RAI 4.1-4a1. Although ASME Code Case N-481 was credited in the Sequoyah Nuclear Plant (SQN)second Inservice Inspection. Interval (ISI), both SQN Units 1 and 2 are now in the third ISIinspection interval.ASME Code Case N-481 is not credited in the third interval for SQN Units 1 or 2. ASMECode Case N-481 and the supporting flaw tolerance evaluation for the reactor coolant pump(RCP) casings are not relied upon in the current licensing basis (CLB) as the basis forperforming alternative visual examinations of the RCP casing welds. The CLB for thecurrent ISI inspection interval for both SQN Units 1 and 2 is the 2001 Edition, 2003 Addendaof the ASME B&PV Code, Section Xl.2. Because ASME Code Case N-481 is not credited in SQN's third ISI inspection interval, thesupporting flaw tolerance evaluation for the RCP casings is not contained in the CLB and isnot relied upon in making a safety determination.E-1- 2of17 RAI 4.1-6aBackground:By letter dated July 11, 2013, the applicant provided its responses to RAI 4.1-6, Part a., onwhether the flaw for the boric acid injection tank (BIT) at Unit 2 would need to be identified as aTLAA for the LRA in accordance with 10 CFR 54.21(c)(1) TLAA identification requirements.Issue:The staff has determined that the applicant's response demonstrates that the flaw evaluation forthe Unit 2 BIT does not need to be identified as a TLAA because the analysis: (a) does notinvolve time-dependent assumptions defined by the current operating term, and (b) does notconform to the definition of a TLAA in 10 CFR 54.3(a). However, the staff noted that theapplicant does not identify cracking as an aging effect requiring management for the BIT in LRATable 3.3.2-1 [Sic, 3.2.2-1], and does not specifically credit augmented inspections under theapplicant's Inservice Inspection (ISI) Program (LRA AMP B. 1.16) to manage cracking that wasdetected in the Unit 2 BIT.Request:Identify the mechanism that initiated the flaw in the BIT bottom head-to-shell weld and identifywhether this mechanism was age-related.In addition, clarify whether the flaw in the BIT bottom head-to-shell weld could grow by an age-related growth mechanism, such as cyclical loading or one of the stress corrosion crackingmechanisms, regardless of the cause for initiation of the flaw in the BIT bottom head-to-lowershell weld.Justify why cracking (including crack growth) has not been listed in LRA Table 3.3.2-1 [Sic,3.2.2-1] as an aging effect requiring management for welds in the BIT and why the applicant'sISI Program (LRA AMP B. 1.17) has not been credited to manage cracking in the BITs.TVA Response to RAI 4.1-6aThe BIT is a carbon steel tank, clad on the internal surface with stainless steel. As documentedin the SQN corrective action program, the flaw that was identified by the site inspection islocated at the cladding to base metal interface, 2.1 inches below the exterior surface.Therefore, it is not exposed to the internal or external environments. Although a root causeanalysis was not performed to determine the cause of the flaw, TVA assessed that the flaw wasmost likely manufacturing-induced and not age-related based on the location of the flaw.Two augmented inspections have been performed that have identified no flaw growth.The subsequent crack growth analysis was performed as required by ASME Section Xl for flawsthat are detected during inspections. A carbon steel material exposed to temperatures belowthe fatigue threshold does not have an aging effect of cracking that requires management, sothere is no listing for cracking in LRA Table 3.2.2-1 (corrected number). The augmentedinspection is specific to the location of the manufacturing-induced flaw. The ISI programaugmented inspections of this flaw will continue during the period of extended operation (PEO).E-1- 3of17 RAI 4.1-11aBackground:By letter dated July 11, 2013, the applicant provided its responses to RAI 4.1-11, whichprovided the applicant's basis on why the exemption for use of ASME Code Case N-514 as thebasis for establishing the temperature enable settings for the low temperature overpressureprotection (L TOP) system does not need to be identified as an exemption for the LRA inaccordance with the requirements in 10 CFR 54.21(c)(2). In its response, the applicant statedthat ASME Code Case N-514 has been incorporated into ASME Section X1, Appendix G, andtherefore, this exemption will not be required when the pressure-temperature limits are updatedfor the PEO. The applicant stated that an LRA amendment is not needed with respect toidentifying this exemption as an exemption that meets the requirements in 10 CFR 54.2 1(c)(2).Issue:The staff does not find the applicant's response to RAI 4.1-11 to be acceptable because10 CFR 54.21(c)(2) requires regulatory exemptions to be identified in the LRA based on theCLB as it exists at the time of the NRC's LRA review, and not on future actions that may or maynot be implemented during the period of extended operation. The regulation requires theapplicant to identify any regulatory exemption that was previously granted under therequirements of 10 CFR 50.12 and whose basis for the exemption was based on a TLAA. Foreach exemption that does need to be identified for the LRA, the rule requires the applicant toprovide an evaluation in the LRA that justifies the continuation of the exemption during theperiod of extended operation.The Pressure Temperature Limits Report (PTLR) and WCAP-15293 for Unit I and PTLR andWCAP-15321 for Unit 2 refer to ASME Code Case N-514 in relationship to establishing theenable temperature for the L TOP system in each unit. However, the CLB for each unit stillcontains an exemption to use ASME Code Case N-514 for the pressure lift setpoints and enabletemperatures of the plant L TOP systems. As such, the exemption to use Code Case N-514may be based on a TLAA since the exemption allows the applicant to establish these setpointsbased on a mathematical function of the limiting adjusted reference temperature (RTNDT value)for the reactor vessel beltline materials. Therefore, the staff needs further justification why theexemption for use of ASME Code Case N-514 had not been identified as an exemption thatmeets the exemption identification criteria in 10 CFR 54.21(c) (2) and why this exemption hasnot been included in the LRA and dispositioned in accordance with the exemption requirementsin 10 CFR 54.21(c)(2).Request:1. Clarify whether the exemption for use of ASME Code Case N-514 had been granted inaccordance with the requirements in 10 CFR 50.12.2. Clarify whether the alternative bases in ASME Code Case N-514 were based on a TLAAand justify your bases for concluding that either the stated exemption is either based ona TLAA or is not based on a TLAA.E-1- 4of17
- 3. Based on your responses to Parts I and 2 of this RAI, justify why the exemption to useASME Code Case N-514 for Units I and 2 would not need to be identified as anexemption for the LRA that meets the exemption identification requirements in 10 CFR54.21(c)(2).TVA Response to RAI 4.1 -11aResponse1. TVA confirms that the exemption for the use of ASME Code Case N-514 was granted inaccordance with the requirements in 10 CFR 50.12. See NRC to TVA Letter "NRCExemption for Use of ASME Code Case N-514," dated June 18, 1993.2. ASME Code Case N-514 provides a method for establishing low temperature overpressureprotection (LTOP) system setpoints based on pressure-temperature limit curves and thelimiting adjusted reference temperature (RTNDT value) for the reactor vessel beltlinematerials. Therefore, the exemption to use the code case involves the TLAA thatdetermines pressure-temperature limits and the limiting adjusted reference temperature(RTNDT value) for the reactor vessel beltline materials.3. As identified in Regulatory Guide 1.147, ASME Code Case N-514 was annulled on April 19,2002. To resolve the concerns identified in this RAI, the exemption to allow the use ofASME Code Case N-514 is identified in the below change to LRA Section 4.1.2.Changes to LRA Section 4.1.2 follow with additions underlined and deletions lined through."4.1.2 Identification of ExemptionsExemptions for SQN were identified through a review of the UFSAR, the operatinglicenses, the Technical Specifications, the NRC SERs, ASME Section Xl Programdocumentation, fire protection documents, NRC Agencywide Documents Access andManagement System (ADAMS) database, and docketed correspondence. N1eoXoMptionS that Aill remaine in eaffect1 for tho period -of extenAd-ed operation are- based onT-AA -One exemption has been identified that involves a TLAA. ASME Code Case N-514 provides a method for establishing LTOP system setpoints based on pressure-temperature limit curves and the limiting adiusted reference temperature (RTNDT value)for the reactor vessel beltline materials. For further information on how the LTOPsystem setpoint TLAA is evaluated, see LRA Section 4.2.5.See NRC to TVA Letter "NRC Exemption for Use of ASME Code Case N-514," datedJune 18, 1993."E-1- 5of17 RAI 4.6-1Background:Per SRP-LR Section 4.6.1.1.1 for a TLAA to be dispositioned in accordance with 10 CFR54.21(c)(1)(i), the existing analyses must be verified to be valid and bounding for the period ofextended operation. SRP-LR Section 4.6.3. 1.1 states that the existing analyses should beshown to be bounding even during the PEO.LRA section 4.6 states "Analyses were identified for bellows assemblies for the penetrationsthat stated they were qualified for 7000 cycles of the design displacements. The number ofdesign displacements expected to occur from either thermal changes or containmentpressurizations is much less than 7000. Therefore, the associated penetrations bellows arequalified for the PEO. The analysis remains valid for the PEO in accordance with 10 CFR54.21(c)(1)(i)."Issues:The staff reviewed the SQN UFSAR and was not able to find and verify the analyses used toestimate the number of displacements for bellows assemblies of the penetrations expected tooccur from thermal changes or containment pressurizations and project those analyses to theend of the PEO.Requests:To ensure "the estimated number of cycles" are within "the qualifying limit of 7000 cycles,"describe how the qualifying limit of 7000 cycles was determined, and provide the estimatednumber of cycles due to cyclic loading conditions (e.g., thermal, pressure, etc.) for thecontainment penetration bellows at the end of PEO.TVA Response to RAI 4.6-1The qualifying limit of 7000 cycles was a conservative assumption to bound the expectednumber of operating cycles with ample margin. Although the original containment penetrationflued heads and bellows did not have a specific fatigue analysis, analyses were identified forreplaced or repaired penetration bellows assemblies at penetrations 13C, 24, and 30. Theanalyses confirmed that these penetrations were qualified for 7000 cycles of the designdisplacements.Penetration 13C is the 32" main steam discharge line from steam generator #3. Displacementsof its bellows will occur due to the steam line and containment temperature increasing duringplant heatups.Penetrations 24 and 30 have bellows attached to the penetration sleeve to allow differentialexpansion between the containment vessel and the shield building. Displacements of thebellows for these penetrations will occur due to containment temperature increasing during plantheatups.E-1- 6of17 Also, the bellows will be displaced by loading experienced during containment integrated leakrate testing (CILRT). Therefore, the number of cycles expected for penetrations 13C, 24 and 30are calculated as follows using a 50% margin:(200 heat ups + 40 CILRT) x (1.5 (50% margin)) = 360 cycles.Note that the value of 200 heat ups is from SQN FSAR Table 5.2.1-1.The expected number of cycles, i.e., 360, is well below the 7000 cycles for which these bellowsare qualified.E-1- 7of17 RAI B. 1.40-laBackgqround:Based on its audit of the applicant's program basis document for the Structures MonitoringProgram, it is not clear that the preventive actions for storage, lubricants, and corrosion potentialdiscussed in Section 2 of the RCSC publication "Specification for Structural Joints Using ASTMA325 or A490 Bolts," will be used consistent with the recommendations in the GALL Report.Issue:The applicant's response to RAI B. 1.40-1 dated July 1, 2013 states that the StructuresMonitoring Program employs the preventive actions for storage, lubricants, and corrosionpotential. The program basis document stated that the preventive actions of Section 2 ofResearch Council for Structural Connections publication "Specification for Structural JointUsing ASTM A325 and A490 bolts" have been considered in existing plant procedures forASTM A325 and A490 bolting. However, during its audit, the staff found that the existingprocedures provided as part of the program basis document for the Structures MonitoringProgram did not include the preventive actions for storage, lubricants and corrosion potential.The staff has not been provided with sufficient information to verify that the preventive actionsprogram element of the Structures Monitoring Program is consistent with the GALL Report,without enhancement or exception, as claimed by the applicant in the LRA.Request:1. Describe the preventive actions for storage, lubricants, and corrosion potential employedby the Structures Monitoring Program.2. If the procedures describing these preventive actions were not referenced in theprogram basis document when audited, provide clarification and make revisions to theLRA and UFSAR supplement as necessary based on the response to #1.TVA Response to RAI B.1.40-1a1. The preventive actions for storage, lubricant, and corrosion employed in the StructuresMonitoring Program (SMP) are described in SQN procedures G29B-SO1, 4.M.1.1,Section 3.9.2; G29B-SO1, 4.M.4.4, Section 4.2; and NPG-SPP-04.3. They includeprovisions for storage, handling, and preserving safety-related and quality-relatedmaterials, including ASTM A325 and A490 bolting. Consistent with therecommendations of section 2.2 of the Research Council for Structural Connectionspublication, "Specification for Structural Joints Using ASTM A325 or A490 Bolts," theseprocedures provide for protected storage of bolts, nuts, washers and other fastenercomponents to ensure their conditions are maintained as near as possible to theas-manufactured conditions, including the manufacturer-applied coatings or lubricants,until they are installed. These procedures include provisions for storing the fastenercomponents in containers for protection from dirt and corrosion. The fasteners in thecontainers are within a protected compartment and are removed from protected storageonly as necessary. Procedures specify promptly returning unused fastener componentsE-1- 8of17 to protected storage. In summary, the fastener components are received, stored, andhandled so as to minimize the possibility of corrosion, contamination, entrance of foreignmaterials, deterioration, or physical damage.2. The procedures describing these preventive actions are not clearly identified in the SMPprogram basis document. However, as described in the response to RAI B.1.40-1a(1)above, the SMP follows the recommendations of the RCSC publication preventive actionsfor storage, lubricant, and corrosion potential. For clarification, TVA will revise the SMPprocedures to explicitly include these preventive actions in Commitment 31.L.The changes to LRA Sections A.1.40 and B.1.40 follow with additions underlined."A.1.40 Structures Monitoring Program_ Revise Structures Monitorinq Program procedures to include the following preventiveactions.* Specify protected storage requirements for high-strength fastener components(specifically ASTM A325 and A490 bolting.) Storage of these fastener components shallinclude: (1) maintaining fastener components in closed containers to protect from dirtand corrosion: (2) storage of the closed containers in a protected shelter: (3) removal offastener components from protected storage only as necessary: and (4) prompt return ofany unused fastener components to protected storage.B.1.40 Structures MonitoringEnhancements: The following enhancements will be implemented prior to the PEO.Elements Affected Enhancements2. Preventive Actions Specify protected storage requirements for high-strength fastener components (specifically ASTMA325 and A490 bolting). Storage of these fastener components shall include: (1) maintainingfastener components in closed containers to protect from dirt and corrosion: (2) storage of theclosed containers in a protected shelter; (3) removal of fastener components from protected storageonly as necessary: and (4) prompt return of any unused fastener components to protected storage."Commitment 31.L has been added as shown in the above with additions underlined.E-1- 9of17 RAI 3.1.2-4-1aBackground:By letter dated July 29, 2013, the applicant responded to RAI 3.1.2-4-1, and stated thatreduction of heat transfer is not an aging effect requiring management for steam generatortubes.Issue:The staff considers reduction of heat transfer in steam generator tubes to be an applicableaging effect requiring management. The staff notes that heat transfer is the intended functionfor the steam generator tubes, and without proper management, the intended function could becompromised.Request:Discuss how reduction of heat transfer will be managed for steam generator tubes. Revise theLRA as necessary, consistent with the response.TVA Response to RAI 3.1.2-4-1aThe Water Chemistry Control -Primary and Secondary Program will manage reduction of heattransfer (fouling) for the steam generator tubes.The change to LRA Section 3.1.2.1.4 follows with additions underlined.Aging Effects Requiring ManagementThe following aging effects associated with the steam generators require management.* Cracking" Cracking -fatigue" Fouling* Loss of material* Loss of material -wear" Loss of preloadThe change to LRA Table 3.1.2-4 follows with additions underlined.Table 3.1.2-4: Steam GeneratorsAging Effect Aging NUREG TableComponent tntended Material Environment Requiring Management -1801 Table NotesType Function Management Program Item 1 ItemWater ChemistryHeat Nickel Treated Control -Tubes transfer alloy water (ext) Fouling Neae Primary and HSecondary NlneP,E-1- 10 of 17 RAI 3.5.2.2.1.3-01Background:In LRA Table 3.5.1, item 3.5.1-5, the applicant states that it will manage steel elements ofinaccessible areas of containments for loss of material due to general, pitting, and crevicecorrosion in accordance with the GALL Report recommendations. The GALL Report states thatadditional plant-specific activities are warranted if loss of material due to corrosion is significantfor inaccessible areas. According to the GALL Report, corrosion is not significant if the followingfour conditions are satisfied:1. The concrete that is in contact with the embedded containment steel met therequirements of ACI 318 or 349 or use the guidance of ACI 201.2R,2. The moisture barrier at the junction where the steel becomes embedded in concrete issubject to aging management activities in accordance with ASME Section XI, SubsectionIWE requirements,3. The concrete is monitored to ensure that it is free of penetrating cracks that provide apath for water seepage to the surface of the containment shell,4. Borated water spills and water ponding are cleaned up or diverted to a sump in a timelymanner.SRP-LR Section 3.5.2.2.1.3, which addresses loss of material due to general, pitting, andcrevice corrosion for steel elements of accessible and inaccessible areas of containments,recommends further evaluation if the four GALL Report conditions cannot be satisfied.Issue:LRA Section 3.5.2.2.1.3 contains the applicant's further evaluation discussion that considersloss of material due to general, pitting, and crevice corrosion. The staff reviewed Section3.5.2.2.1.3 and noted that it lacked information demonstrating that the GALL Reportrecommendations were satisfied. The staff noted that the applicant did not discuss conditionfour related to borated water spills and water ponding.Request:Discuss plant-specific operating experience related to water ponding on the containmentconcrete floor, including frequency and resulting corrective actions.TVA Response to RAI 3.5.2.2.1.3-01A review of the SQN operating experience, documented in the site corrective action program(CAP), was performed to identify instances of water ponding (standing water) on thecontainment concrete floor. The search, covering the last ten years of plant operation, identifiedone occurrence of water ponding on the containment concrete floor in 2004. The visible waterponding on the floor was attributed to a clogged floor drain. Corrective action included clean-upof the water and unclogging the floor drain.E-1 -11 of 17 Instances of water leakage from various systems have been noted during outage activities.These conditions were investigated, evaluated, and corrected. A review was also performed ofthe operating experience associated with the Boric Acid Corrosion Program, ContainmentInservice Inspection -IWE Program and the Structures Monitoring Program and there were noinstances documented of water ponding on the containment concrete floor from theseprograms.In addition to visually detecting water ponding (during refueling outages and reported throughCAP), water leakage (including borated water) that could cause water ponding is monitoredthrough system performance. System parameters are monitored and adverse operatingconditions (including system leakage) are noted, investigated, and areas cleaned up promptly.Additionally, the containment concrete floor slopes to floor drains minimizing locations wherewater could accumulate on the containment floor.E-1- 12of17 RAI B.1.17-laBackgqround:In its response of RAI B. 1.17-1 on July 1, 2013, the applicant stated "The configuration of thestrainer allows leak off water to flow down the strainer and onto the essential raw cooling water(ERCW) strainer support causing corrosion. Planned corrective actions include a designmodification of the strainer to prevent ERCW support from being continuously exposed to water,thus mitigating corrosion. The modification proposed to install a "catch container" to the ERCWstrainer to route the leak off water coming out of the top of the strainer to a floor drain." TheLRA states "The program was developed in accordance with ASME Section X1, 2001 Editionthrough the 2003 Addenda as approved by 10 CFR 50. 55a. "Accordingly the ERCW strainersupport components should satisfy the requirements Article IWF-3000, "Standards forExamination Evaluations," which may include examinations, corrective measures, evaluations,tests, etc., currently and during the period of extended operation. GALL Report AMP Xl. S3, inprogram element "acceptance criteria," refers to the acceptance standards of IWF-3400, andstates "other unacceptable conditions include [Ijoss of material due to corrosion or wear, whichreduces the load bearing capacity of the component support."Issue:In summary, the applicant will be implementing a corrective action of redirecting the leakingwater on the ERCW strainer support components to a floor drain, thus mitigating corrosion. It isnot clear how the corrosion process will be mitigated by restricting the leaking water on theERCW strainer support components only, and is expected to perform its intended functionduring the period of extended operation.Changing the degrading environment to a benign environment may not alleviate the initiatedcorrosion process of carbon steel supports subject to stresses under operating conditions. Theincubation-stage of corrosion process may have already been completed on some of thesupport components. Material-weakening stage (cracking) of the carbon steel supports andtheir components and attachment welds may already have been initiated with an eventualoutcome of a reduced load bearing capacity of the component support. It is not clear whetherthe LRA AMP In-service Inspection -IWF (ISI-IWF) Program will follow the recommendation ofthe GALL Report AMP Xl. S3, program element "acceptance criteria," which is based on therequirements of ASME Code Section X1, Article IWF-3400 during the period of extendedoperation.Request:Provide the results of the evaluations of the ERCW strainer support components per therequirements of ASME Code Section X1, Article IWF-3000 "Standards for ExaminationEvaluations."E-1- 13 of 17 TVA Response to RAI B.1.17-1aThe essential raw cooling water (ERCW) strainer (A-2A) support components are examinedunder the SQN Inservice Inspection (ISI)-IWF Program described in LRA Section B.1.17. Theexamination results are evaluated in accordance with ASME Code Section Xl, Article IWF-3000following the acceptance standards of Article IWF-3400.The condition of the ERCW strainer support components was evaluated during the last ISIexamination performed in 2008 and subsequently re-evaluated under the TVA corrective actionprogram in 2012. The evaluation performed concluded that the corrosion of the ERCW strainersupport components was surface corrosion only and that the observed surface corrosion hasinsignificant effect on the ability of the ERCW strainer support to perform its intended function.This conclusion is consistent with the evaluation documented in the 2008 ISI report that thecorrosion on the ERCW strainer support is surface corrosion that does not affect the structuralintegrity of the support.In addition, the 2012 SQN engineering review of the ERCW strainer support structuralcalculation concluded that there was no significant degradation attributable to the ERCWstrainer support corrosion. The review of the support and its associated qualifying calculationdetermined that the support capacity for the ERCW strainer had not been degraded. As aresult, compliance with IWF-3000, specifically the acceptance criteria of ASME Code Section XI,Article IWF-3400, "Acceptance Standards" was demonstrated.The SQN ISI-IWF Program will continue to ensure the ERCW strainer support components areinspected and the results are evaluated per ASME Code Section Xl, Article IWF-3000 followingthe acceptance criteria of ASME Code Section Xl, Article IWF-3400. This provides reasonableassurance that the support will remain capable of performing its intended function during thePEO.E-1- 14 of 17 RAI B.1.11-laBackground:In its July 1, 2013, response to request for additional information (RAI) B. 1.11-1, the applicantprovided its clarification on whether specific transients listed in RAI B. 1.1.11-1 will be monitoredas part of the Fatigue Monitoring program. The applicant stated the cycle limits of (1) 2, 000cycles of "Step changes in letdown stream fluid temperature from IO0°F to 560°F" and (2)24, 000 cycles of "Step changes in letdown stream temperature from 400°F to 560°F" for theChemical and Volume Control System (CVCS) regenerative heat exchangers will not bemonitored by the Fatigue Monitoring program.The applicant also stated that the 15 cycles of design tensioning cycle limit for the RCPhydraulic studs and nuts will not be monitored in the Fatigue Monitoring program. LRA Section4.3.1.6 states the Fatigue Monitoring Program will manage the effects of aging due to fatigue onthe RCP in accordance with 10 CFR 54.21(c)(1)(iii). The staff noted that the "parametersmonitored/inspected" program element of GALL Report AMP X. M1, "Fatigue Monitoring, " statesthat the program monitors all plant design transients that cause cyclic strains, which aresignificant contributors to the fatigue usage factor.Issue:In its justification for the two transients for the CVCS regenerative heat exchangers, theapplicant stated that the letdown fluid temperature normally remains stable for both units. Theapplicant further stated that a maximum of 90 cycles for each of the transients are expectedthrough the period of extended operation. The staff is unclear on how the applicant came tothese conclusions. The applicant did not explain how it determined that the letdown fluidtemperature normally remains stable or how it can confirm that the temperature during thetransient will remain stable for the period of extended operation. The staff is unclear if thetemperature stability is during normal operation or during the transient. Also, the applicant didnot provide an explanation based on its plant configuration and operational history to support itscalculation that 90 cycles is expected for each transient through the period of extendedoperation.In its justification, the applicant stated that the RCPs are rarely disassembled such thattensioning the studs and nuts is necessary. The applicant stated that only one RCP hasinstalled hydraulically tensioned studs in 2005, and the studs have not been disassembled sinceits installation. The applicant used this basis to state that the 15 cycles of design tensioningcycle limit for the RCP hydraulic studs and nuts will not need to be monitored. However, thestaff is unclear how the Fatigue Monitoring Program, in accordance with 10 CFR 54.21 (c)(1)(iii),will manage the effects of aging due to fatigue on the RCPs if this transient is not monitored.Request:1. Confirm whether the letdown fluid temperature normally remains stable during normaloperation or during the aforementioned transients.E-1- 15of17
- a. If the temperature is stable during normal operation, justify how the temperaturestability has any impact on fatigue usage accumulation during the transients -inlieu of a justification, monitor these transients as part of the Fatigue Monitoringprogram.b. If the temperature is stable during these transients.i. State the basis for the letdown fluid normally remaining stable duringthese transients at SQN Units 1 and 2.ii. Describe what measures will be taken to ensure letdown fluidtemperature will remain stable during these transients throughout theperiod of extended operation.2. Describe how a maximum of 90 cycles for each of the aforementioned transients wascalculated and justify that the calculations are consistent with plant configuration andoperational history.3. Describe and justify the programmatic elements of the Fatigue Monitoring Program thatwill manage the effects of aging due to fatigue on the RCPs, in accordance with 10 CFR54.21(c)(1)(iii), given that the 15 cycles of design tensioning cycle limit for the RCPhydraulic studs and nuts will not be monitored.4. If the Fatigue Monitoring Program will not be used, justify how the effects of aging due tofatigue will be managed for the RCPs in accordance with 10 CFR 54.21(c)(1)(iii). Revisethe LRA as necessary.TVA Response to RAI B.1.11-1a1. The source of the letdown fluid to the regenerative heat exchanger is the reactor coolantloop 3 crossover leg that is at the cold leg temperature of approximately 545°F. The reactorcoolant loop crossover leg and the letdown fluid temperatures remain within a narrow rangeduring normal plant operation.To confirm the stability of the CVCS regenerative heat exchanger letdown fluid temperature,two years of SQN temperature data for the regenerative heat exchanger inlet and outlettemperatures were reviewed for each unit. This data does not show frequent significanttemperature transients such as the 2,000 cycles of "Step changes in letdown stream fluidtemperature from 100°F to 560°F" or the 24,000 cycles of "Step changes in letdown streamtemperature from 400°F to 560°F" that were conservatively assumed in the design analysis.After initial heatup from refueling outages, one cycle approximating the 100°F to 560°F cyclewas observed on both Units over the two year period and two cycles approximating the400°F to 560°F cycle were observed on Unit 1 and five cycles approximating the 400°F to560OF cycle were observed on Unit 2 over the two year period.Based on the data reviewed, normal operating procedures do not result in a large number oftransients such as those used in the fatigue assessment of the heat exchangers. Noadditional measures are necessary to limit temperature transients throughout the PEO.E-1- 16 of 17
- 2. The 90 cycles in the original RAI response was estimated by assuming three occurrences ofeach cycle every two years for 60 years of operation. As discussed above, a review of plantdata has shown that the cycles that do occur are substantially fewer than the numbers oftransients assumed in the fatigue analysis.Additional details are provided below.2,000 cycles (100 to 560'F): This represents a letdown temperature step changetransient that was assumed to occur approximately one time per week during normalplant operation. The above-discussed observation of two years of SQN data from bothUnit 1 and Unit 2 indicates that this transient seldom occurs during normal plantoperation. TVA conservatively estimated the number of transients to be 1.5 per year for60 years or 90 cycles.The estimated number of cycles, 90, is far less than the 2,000 assumed cycles of a stepchange in temperature of this magnitude.* 24,000 cycles (400 to 560'F): This represents a letdown temperature step changetransient that was assumed to occur approximately two times per day during normal plantoperation. The above-discussed observation of two years of plant data from both Unit 1and Unit 2 indicates no more than five transients in temperature approximating a 160°Fstep change. Conservatively increasing the number of transients by a factor of two andapplying this to each heatup and cooldown cycle (200) gives a predicted number oftransients of 2,000.The estimated number of cycles, 2000, is far less than the 24,000 assumed cycles of astep change in temperature of 1600F.3. To resolve the concern in Request 3 of this RAI, the reactor coolant pump hydraulic studtensioning cycles will be added to the tracked transients in the Fatigue Monitoring Program.Changes to LRA Appendix A. 1. 11 and Appendix B. 1. 11 follow with additions underlined.The change to LRA Appendix A.1.11 follows:* Revise Fatigue Monitoring Program procedures to track the tensioning cycles for thereactor coolant Pump hydraulic studs.The change to LRA Appendix B.1.11 follows:Element Affected Enhancement1. Scope of Revise Fatigque Monitoring Program procedures to trackProgram the tensioning cycles for the reactor coolant pumphydraulic studs.4. The Fatigue Monitoring Program will be used as identified in the response to Request 3.Commitment 7.E is added as shown above.E-1- 17 of 17 ENCLOSURE 2Tennessee Valley AuthoritySequoyah Nuclear Plant, Units I and 2 License RenewalRevised Responses for B.1.14-1a, 2.5-2a, 2.3.4.3-5a, 2.3.3.15-1a, and B.I.41-3b ENCLOSURE2Tennessee Valley AuthoritySequoyah Nuclear Plant, Units I and 2 License RenewalRevised Responses for B.1.14-1a, 2.5-2a, 2.3.4.3-5a, 2.3.3.15-la, and B.l.41-3bRAI B.l.14-1aNRC requested clarification for the response to RAI B.1.14-1.The following response to RAI B.1.14-1a supersedes the response provided to the NRC onAugust 9, 2013, ADAMS No. ML1 3225A387, page 1 of 22 in Enclosure 3.Note: Revisions are in italics and underlined. The majority of the revisions are inserted tablesat the end of the revised B.1.14-1 response in Enclosure 2, pages 4 to 8.Revised TVA Response to RAI B.1.14-11. The Flow-Accelerated Corrosion (FAC) Program will be consistent with the programdescribed in NUREG-1801, AMP XI.M17 as revised by LR-ISG-2012-01.2. The new program enhancement added to LRA Sections A.1.14 and B.1.14 includes asusceptibility review in accordance LR-ISG-2012-01. The susceptibility review is designedto identify the appropriate component types, materials and mechanisms associated withnon-FAC erosion. Component types monitored for loss of material due to non-FAC erosionmechanisms are identified in the changes to LRA tables depicted below.The change to LRA Section A.1.14 follows with additions underlined and deletions linedthrough."A.1.14 Flow-Accelerated Corrosion ProgramThe Flow-Accelerated Corrosion (FAC) Program manages loss of material due to wallthinning caused by FAC for carbon steel piping and components by (a) performing ananalysis to determine systems subject to FAC and internal and ekternal eFrocin,(b) conducting appropriate analysis to predict wall thinning, (c) performing wall thicknessmeasurements based on wall thinning predictions, and (d) evaluating measurementresults to determine the remaining service life and the need for replacement or repair ofcomponents. Measurement results are also used to confirm predictions and to planlong-term corrective action. The program relies on implementation of guidelinespublished by EPRI in NSAC-202L, Rev. 3, and internal and external operatingexperience. The program uses a predictive code for portions of susceptible systems withdesign and operating conditions that are amenable to computer modeling. Inspectionsare performed using ultrasonic or other approved testing techniques capable ofdetermining wall thickness. Components predicted to reach the minimum allowed wallE2 -1 of 15 thickness before the next scheduled outage are isolated, repaired, replaced, orreevaluated under the corrective action program.Where applicable, the FAC Program also manages loss of material due to erosionmechanisms of cavitation, flashing, liquid droplet impingement and solid particle erosionfor any material in moving fluid environments.The Flow-Accelerated Corrosion Program will be enhanced as follows." Revise Flow-Accelerated Corrosion Program procedures to implement NSAC-202Lguidance for examination of components upstream of piping surfaces wheresignificant wear is detected.* Revise Flow-Accelerated Corrosion Program procedures to implement the guidancein LR-ISG-2012-01, which will include a susceptibility review based on internaloperating experience, external operating experience, EPRI TR-1 011231,Recommendations for Controlling Cavitation, Flashing, Liquid Droplet Impingement.and Solid Particle Erosion in Nuclear Power Plant Piping, and NUREG/CR-6031,Cavitation Guide for Control Valves."The change to LRA Section B.1.14 follows with additions underlined and deletions linedthrough."B.1.14 Flow-Accelerated Corrosion ProgramProgram DescriptionThe Flow-Accelerated Corrosion (FAC) Program manages loss of material due to wallthinning caused by FAC and erosion. The program manages loss of material due to wallthinning for carbon steel piping and components by (a) performing an analysis todetermine systems subject to FAC and internal aind nerinal eFrc.in, (b) conductingappropriate analysis to predict wall thinning, (c) performing wall thickness measurementsbased on wall thinning predictions, and (d) evaluating measurement results to determineremaining service life and the need for replacement or repair of components. Arepresentative sample of components is selected based on the most susceptiblelocations for wall thickness measurements at a frequency in accordance withNSAC-202L guidelines to ensure that degradation is identified and mitigated before thecomponent integrity is challenged. Measurement results are used to confirm predictionsand to plan long-term corrective action. In the event measurements of wall thinningexceed predictions, the extent of the wall thinning is determined as a part of the CAP.The program relies on implementation of guidelines published by EPRI in NSAC-202L,Rev. 3, and internal and external operating experience. The program uses a predictivecode for portions bf susceptible systems with design and operating conditions that areamenable to computer modeling. Inspections are performed using ultrasonic or otherapproved testing techniques capable of determining wall thickness. When fieldmeasurements show that the predictive code is not conservative, the model isrecalibrated. The model is also adjusted as a result of any power up-rates.E2 -2 of 15 Components predicted to reach the minimum allowed wall thickness before the nextscheduled outage are isolated, repaired, replaced, or reevaluated under the CAP.Where applicable the FAC Program also manages loss of material due to erosionmechanisms of cavitation, flashing, liquid droplet impingement and solid particle erosionfor any material in moving fluid environments.NUREG-1801 Consistency: The FAC Program, with enhancements, is consistent withthe program described in NUREG-1801,Section XI.M17, Flow-Accelerated Corrosion,as modified by LR-ISG-2012-01.Exceptions to NUREG-1801: None"Enhancements: The following enhancements will be implemented prior to the period ofextended operation.Element Affected Enhancement1. Scope of Program Revise FAC Program procedures to implementNSAC-202L guidance for examination of componentsupstream of piping surfaces where significant wear isdetected.1. Scope of Pro-gram Revise FAC Program procedures to implement theiguidance in LR-ISG-2012-01, which will include a3. Parameters Monitored/Inspected susceptibility review based on internal operating4. Detection of Aging Effects experience, external operating experience, EPRITR-1011231, Recommendations for Controlling5. Monitoringq and Trending Cavitation, Flashing, Liquid Droplet Impingement, and7. Corrective Action Solid Particle Erosion in Nuclear Power Plant Piping.,and NUREG/CR-6031, Cavitation Guide for ControlValves.Commitment #10 has been revised.E2 -3 of 15 The changes to LRA Table 3.3.2-17-4, Raw Cooling Water System, Nonsafety-Related Components Affecting Safety-RelatedSystems, follow with additions underlined.Component Intended Aging Effect Aging NUREG-cope Inten Materal Environment Requiring Management 1801 Item Table 1 Item NotesType Function Management ProgramPiDin Pressure Carbon Raw water (int) Loss of material due Flowboundary steel to erosion Accelerated HCorrosionPinin Pressure Coper Raw water (int) Loss of material due Flowboundary alloy to erosion Accelerated HCorrosionPressure Stainless Raw water (int) Loss of material due Flowboundary steel to erosion Accelerated HCorrosionThe changes to LRA Table 3.3.2-11, Essential Raw Cooling Water Systems, follow with additions underlined.Component Intended Aging Effect Aging NUREG-Material Environment Requiring Management 1801 Item Table 1 Item NotesType Function Management ProgramPi~in Pressure Carbon Raw water (int) Loss of material due Flowboundary steel to erosion Accelerated HCorrosionPipin Pressure Nickel alloy Raw water (int) Loss of material due Flowboundary to erosion Accelerated HCorrosionPinin Pressure Stainless Raw water (int) Loss of material due Flowboundary steel to erosion Accelerated HI I_ I I I CorrosionE2 -4 of 15 The changes to LRA Table 3.3.2-17-25, Essential Raw Cooling Water System, Nonsafety-Related Components Affecting Safety-Related Systems, follow with additions underlined.Component Intended Aging Effect Aging NUREG-cope Inten Material Environment Requiring Management 1801 Item Table I Item NotesType Function Management ProgramPiin Pressure Carbon Raw water (int) Loss of material due Flowboundary steel to erosion Accelerated HCorrosionBMW Pressure Stainless Raw water (int) Loss of material due Flowboundary steel to erosion Accelerated H1 1 1_ 1 CorrosionThe changes to LRA Table 3.3.2-2, High Pressure Fire Protection -Water System, follow with additions underlined.The changes to LRA Table 3.3.2-17-6, High Pressure Fire Protection System, Nonsafety-Related Components affecting Safety-Related Systems, follow with additions underlined.Component Intended Aging Effect Aging NUREG-TypeFu n Material Environment Requiring Management 1801 Item Table 1 Item NotesType Function Management ProgramPiin Pressure Carbon Raw water (int) Loss of material due Flowboundary steel to erosion Accelerated HCorrosionE2 -5 of 15 The changes to LRA Table 3.4.2-2, Main and Auxiliary Feedwater System, follow with additions underlined.Component Intended Aging Effect Aging NUREG-Material Environment Requiring Management 1801 Item Table 1 Item NotesType Function Management ProgramPiin Pressure Aluminum Treated water Loss of material due Flowint) to erosion Accelerated HCorrosionPining Pressure Carbon Treated water Loss of material due Flowboundary steel (int) to erosion Accelerated HCorrosionPinino Pressure Stainless Treated water Loss of material due Flowboundary steel (int) to erosion Accelerated HCorrosionThe changes to LRA Table 3.4.2-3-3, Main and Auxiliary Feedwater System, Nonsafety-Related Components affecting Safety-Related Systems, follow with additions underlined.Component Intended Aging Effect Aging NUREG-TypeMaterial Environment Requiring Management 1801 Item Table I Item NotesManagement ProgramPressure Carbon Treated water Loss of material due Flowboundary steel ) to erosion Accelerated HI _ CorrosionPressure Stainless Treated water Loss of material due Flowboundary steel >140°F (int) to erosion Accelerated HI_ CorrosionThe changes to LRA Table 3.4.2-3-2, Condensate System, Nonsafety-Related Components affecting Safety-Related Systems,follow with additions underlined.Component Intended Aging Effect Aging NUREG-TypeFu n Material Environment Requiring Management 1801 Item Table I Item NotesType Function Management ProgramPressure Carbon Treated water Loss of material due Flowboundary steel Ainta to erosion Accelerated HI_ I_ ICorrosionPressure Stainless Treated water Loss of material due Flowboundary steel >140°F (int) to erosion Accelerated HI_ CorrosionE2 -6 of 15 The changes to LRA Table 3.4.2-3-4, Extraction Steam System, Nonsafety-Related Components affecting Safety-Related Systems,follow with additions underlined.Component Intended Aging Effect Aging NUREG-TypeMateal Environment Requiring Management 1801 Item Table I Item NotesManagement ProgramP-ing Pressure Carbon Steam (int) Loss of material due Flowboundary steel to erosion Accelerated HCorrosionSPressure Stainless Steam (int) Loss of material due Flowboundary steel to erosion Accelerated HI_ I CorrosionThe changes to LRA Table 3.4.2-3-5, Heater Drains and Vents System, Nonsafety-Related Components affecting Safety-RelatedSystems, follow with additions underlined.Component Intended Aging Effect Aging NUREG-Type Function Material Environment Requiring Management 1801 Item Table I Item NotesManagement ProgramBýPi Pressure Carbon steel Steam (int) Loss of material due Flowboundary to erosion Accelerated HCorrosionPipin Pressure Carbon steel Treated water Loss of material due Flowboundary Aint) to erosion Accelerated HCorrosionPipin Pressure Stainless Steam (int) Loss of material due Flowboundary steel to erosion Accelerated HI__II_ ,_CorrosionPipin Pressure Stainless Treated water Loss of material due Flowboundary steel >140°F (int) to erosion Accelerated HCorrosionE2 -7 of 15 The changes to LRA Table 3.4.2-3-9, Condenser Circulating Water System, Nonsafety-Related Components affecting Safety-Related Systems, follow with additions underlined.Component Intended. Aging Effect Aging NUREG-Material Environment Requiring Management 1801 item Table I Item NotesType Function Management ProgramBiQ( Pressure Carbon Raw water (int) Loss of material due Flowboundary steel to erosion Accelerated HCorrosionnPin Pressure Copper Raw water (int) Loss of material due Flowboundary Alloy >15% to erosion AcceleratedZN or >8% Corrosion HAlPiDin Pressure Stainless Raw water (int) Loss of material due Flowboundary steel to erosion Accelerated HCorrosionE2 -8 of 15 RAI 2.5-2aNRC requested clarification for the response to RAI 2.5-2.The following response to RAI 2.5.2a supersedes the response provided to the NRC on July 25,2013, ADAMS No. ML13213A026, page 18 of 65 in Enclosure 3. In particular, LRATables 2.5-1 and 3.6-2 have been revised and added to this response.Note: Revisions are in italics with additions underlined and deletions lined through.Revised TVA Response to RAI 2.5-210 CFR 54.4(b) states, "[t]he intended functions that these systems, structures, andcomponents must be shown to fulfill in §54.21 are those functions that are the bases forincluding them within the scope of license renewal as specified in paragraphs (a)(1)-(3) of thissection." LRA Section 2.5 identifies the commodity group "insulated cables and connections" assubject to aging management review because it fulfills the intended function "conductselectricity." LRA Tables 2.5.1 and 3.6-2 identify that the intended function for non-environmentalqualification (EQ) electrical cables and connections (includes non-EQ electrical andinstrumentation and control penetration conductors and connections), non-EQ electrical cablesand connections used in instruments circuits, and fuse holders is to conduct electricity.Electrical insulated cables and connections have two sub-components: the insulation materialand the conducting material. The cable or connection component performs the license renewalintended function of "conducts electricity," which provides electrical connections to specifiedsections of an electrical circuit to deliver voltage, current or signals. This license renewalintended function applies to the conducting material sub-component.Aging effects requiring management for cables and connections involve the insulation materialsub-component. The insulated cable line items in Chapter VI of NUREG-1801 use the term"insulation material for electrical cables and connections." Therefore, to facilitate comparison tothe aging management review results of NUREG-1 801, the insulation sub-component materialwas identified in LRA Table 2.5-1 and Table 3.6-2. The license renewal intended function of thecables and connections commodity group is "conducts electricity." However, to clarify the agingmanagement of the cables and connections commodity group, the intended function of theinsulation material is changed to "Insulation." Accordingly, LRA Table 2.5-1 and LRATable 3.6-2 are changed to show the intended function "insulation."E2 -9 of 15 The changes to LRA Table 2.5-1 follow with additions underlined and deletions lined through.Structure and/or Component/Commodity Intended Function1Cable connections (metallic parts) Conducts electricityInsulation material for electrical cables and connections eloctricit,(including terminal blocks, fuse holders, etc.) not subject to Insulation10 CFR 50.49 EQ requirements (includes non-EQ electrical andI&C penetration conductors and connections)Insulation material for electrical cables not subject to 10 CFR ,,,.,dwR 9.."r"..,50.49 EQ requirements used in instrumentation circuits InsulationFuse holders (not part of active equipment): insulation material C.ndu"tS .,..tr"c.t,InsulationFuse holders (not part of active equipment): metallic clamps Conducts electricityHigh voltage insulators (high voltage insulators for SBO Insulationrecovery)Conductor insulation for inaccessible power cables (400 V to on.duc" 35 kV) not subject to 10 CFR 50.49 EQ requirements InsulationMetal enclosed bus: bus/connections Conducts electricityMetal enclosed bus: enclosure assemblies Conducts electricityMetal enclosed bus: external surface of enclosure assemblies Conducts electricityMetal enclosed bus: insulation; insulators Insulation161-kV oil-filled cable Conducts electricityInsulation161-kV oil-filled cable: reservoir tanks Insulation161-kV oil-filled cable: tubing, valves, instruments InsulationSwitchyard bus and connections (switchyard bus for SBO Conducts electricityrecovery)Transmission conductors (transmission conductors for SBO Conducts electricityrecovery)Transmission connectors (transmission connectors for SBO Conducts electricityrecovery)E2 -10 of 15 The changes to LRA Table 3.6-2 follow with additions underlined and deletions lined through.Table 3.6.2: Electrical ComponentsComponent Aging Effect AgingIntended Requiring Management NUREG- Table 1Component Type Function Material Environment Management Program 1801 Item Item NotesInsulation material 4E Insulation Heat, moisture, Reduced Non-EQ VI.A.LP-33 3.6.1-8 Afor electrical cables IN material -or radiation insulation Insulatedand connections various and air resistance (IR) Cables and(including terminal organic Connectionsblocks, fuse holders, polymersetc.) not subject to10 CFR 50.49 EQrequirements(includes non-EQelectrical and I&Cpenetrationconductors andconnections)Insulation material CE Insulation Heat, moisture, Reduced Non-EQ VI.A.LP-34 3.6.1-9 Afor electrical cables IN material -or radiation insulation Instrumentationot subject to 10 various and air resistance (IR) n Circuits TestCFR 50.49 EQ organic Reviewrequirements used in polymersinstrumentationcircuitsFuse holders (not CE Insulation Air- indoor None None VI.A.LP-24 3.6.1-21 Apart of active IN material -controlled orequipment): various uncontrolledinsulation material organicpolymersConductor insulation for rE Insulation Significant Reduced Non-EQ VI.A.LP-35 3.6.1-10inaccessible power IN material -moisture insulation Inaccessiblecables (400 V to 35 kV) various resistance (IR) Power Cablesnot subject to 10 CFR organic (400 V to 35 kV)50.49 EQ requirements polymersE2 -11 of 15 RAI 2.3.4.3-5aNRC requested clarification for the response to RAI 2.3.4.3-5a.The response to RAI 2.3.4.3-5a provides clarification to the response to RAI 2.3.4.3-5 providedto the NRC on July 25, 2013, ADAMS No. ML13213A026, page 62 of 65 in Enclosure 3.RAI 2.3.4.3-5Background:License renewal drawings LRA-1-47W857-1 and LRA-2-47W857-1, coordinates G-1/2, G-3,G-5, G-6, G-8, G-10, B-1/2, B-3, B-5, B-6, B-8 and B-IO, depict condenser circulating waterstrainer housings "1A3", "1A4", "1B3", "1B4", "1C3", "1C4", "IA 1' "1A2", "IB 1' "1B2", "1C1","1C2", "2A3", "2A4", "2B3", "2B4", "2C3", "2C4", "2A 1 ", "2A2", "2B 1 ", "2B2", "2C 1" and "2C2" asnot being within the scope of license renewal for 10 CFR 54.4(a)(2).Issue:LRA Table 2.3.4-3-9 lists the strainer housings component types as being subject to an AMRwith the intended function of pressure boundary.Request:The staff requests the applicant to provide the basis for not including the strainer housing withinthe scope of license renewal.TVA Response to RAI 2.3.4.3-5Drawings LRA-1-47W857-1 and LRA-2-47W857-1 at coordinates G-1/2, G-3, G-5, G-6, G-8,G-10 show the condenser circulating water (CCW) inlets, which do not have strainer housings.Locations B-1/2, B-3, B-5, B-6, B-8 and B-10 depict CCW strainer housings that are locatedwithin the CCW outlet piping. The strainer housings are represented by two horizontal parallellines within the CCW piping. Because the strainer housings are enclosed, they do not meet thespatial interaction criteria associated with 10 CFR 54.4(a)(2) and are not subject to agingmanagement review.NRC Follow-up RAI 2.3.4.3-5aIn its response letter, dated July 25, 2013, the applicant stated that license renewal drawingsLRA-1-47W857-1 and LRA-2-47W857-1, coordinates G-1/2, G-3, G-5, G-6, G-8, and G-10,depict the condenser circulating water inlets, which do not have strainer housings. The applicantalso stated that license renewal drawings LRA-1-47W857-1 and LRA-2-47W857-1, coordinatesB-1/2, B-3, B-5, B-6, B-8, and B-1O, depict condenser circulating water strainer housings thatare located within the condenser circulating water outlet piping. The applicant described thestrainer housings as being enclosed, which would not meet the spatial interaction criteriaassociated with 10 CFR 54.4(a)(2), and are not subject to AMR. However, the applicant did notclarify whether the condenser circulating water inlets at coordinates G-1/2, G-3, G-5, G-6, G-8,and G-1O would be subject to AMR for spatial interaction or any other intended function.E2 -12 of 15 The staff requests that the applicant to provide the scoping classification of the condensercirculating water inlets on license renewal drawings LRA-1-47W857-1 and LRA-2-47W857-1, atcoordinates G- 1/2, G-3, G-5, G-6, G-8, and G- 10, and discuss if the water inlets are subject toAMR.TVA Response to RAI 2.3.4.3-5aLRA drawings LRA-1-47W857-1 and LRA-2-47W857-1 depict the condenser tube cleaningsystem. The components highlighted on these drawings are those in the condenser tubecleaning system that are subject to aging management review. LRA drawings LRA-1-47W831-1-1 and LRA-2-47W831-1-1 show the CCW system. As indicated by the highlighting inlocations B-H, 6, the CCW inlets (as well as the outlets) are subject to aging managementreview based on the criterion of 10 CFR 54.4(a)(2) for spatial interaction.The line items for strainer housings listed in LRA Table 2.3.4-3-9 represent several otherstrainers in the CCW system (system code 27), e.g., those represented on drawing LRA-1,2-47W832-1 as squares or rectangles with diagonal lines.E2 -13 of 15 RAI 2.3.3.15-1aNRC requested clarification for the response to RAI 2.3.3.15-1a.Background:In its response letter, dated July 25, 2013, RAI 2.3.3.15-1, the applicant stated that thecompressor housings meets the criterion of 10 CFR 54.4(a)(2) for structural support. Theapplicant also amended LRA Table 3.3.2-17-30 as part of its RAI response to include all of thenecessary systems, structures and components subject to AMR. Based on the 10 CFR54.4(a)(2) criterion, the compressor housing should also be included as a component type inLRA Table 2.3.3-15. However, the applicant did not provide any information in its RAI responseabout its exclusion of the compressor housing from LRA Table 2.3.3-15.Request:The staff requests that the applicant clarifies whether the compressor housing will be includedas a new component type or if the component is already included as part of an existingcomponent type in LRA Table 2.3.3-15.The following response supersedes the response provided to the NRC on July 25, 2013,ADAMS No. ML13213A026, page 39 of 65 in Enclosure 3.Note: Revisions are in italics and underlined.TVA ResDonse to RAI 2.3.3.15-1aUpon further review, the air compressor housing meets the criterion of 10 CFR 54.4(a)(2) forstructural support of the hydraulic unloader and the %-inch line from the hydraulic unloader tothe high pressure tank.Changes to LRA Table 2.3.3-17-30, "Standby Diesel Generator System, Nonsafety-RelatedComponents Affectinq Safety-Related Systems, Components Subiect to Aging ManagementReview" follow with additions underlined.COmpressOr housing Pressure boundaryChanges to LRA Table 3.3.2-17-30, "Standby Diesel Generator System, Nonsafety-RelatedComponents Affecting Safety-Related Systems, Summary of Aging Management Evaluation"follow with additions underlined.Compressor Pressure Carbon Air- indoor Loss of External VII.L.A- 3.3.1- Ahousing boundary steel (ext) material Surfaces 77 78MonitoringCompressor Pressure Carbon Condensation Loss of Compressed VII.D.A- 3.3.1- Ahoui boundary steel (int) material Air Monitoring 26 55ITub___ Pressure Copper Condensation Loss of Compressed IVII.D.AP 3.3.1- CTI I boundary Uo (int) material Air Monitoring 1-240E2 -14 of 15 RAI B.1.41-3bNRC requested clarification for the first sentence of the last paragraph of the response toRAI B. 1.41-3a.The following response supersedes the response provided to the NRC on September 3, 2013,page 19 of 23 in the Enclosure-1.Note: Revisions are in italics and underlined.Revised TVA Response to RAI B.1.41-3aAs recommended in NUREG-1801,Section XI.M12, all components determined to be potentiallysusceptible to thermal aging embrittlement are within the scope of this program.Use of a flaw tolerance evaluation is the preferred approach to demonstrate that potentiallysusceptible components have adequate toughness.In the event that a volumetric inspection method becomes qualified for this application, TVAmay use this approach to perform inspections for some or all potentially susceptiblecomponents in lieu of the flaw tolerance evaluation.For each of the components selected for the inspection ogtion, the limiting portions of thecomponent from the standpoint of applied stress, operating time and environmentalconsiderations will be included, as recommended by NUREG-1801,Section XI.M12.E2 -15 of 15 ENCLOSURE 3Tennessee Valley AuthoritySequoyah Nuclear Plant, Units I and 2 License RenewalRegulatory Commitment List, Revision 7 ENCLOSURE3Tennessee Valley AuthoritySequoyah Nuclear Plant, Units I and 2 License RenewalRegulatory Commitment List, Revision 7Commitments 7.E and 31.L have been added. Additions are underlined.LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE IAUDITITEMImplement the Aboveground Metallic Tanks Program as described QN1: Prior to 09/17/20 B.1.1in LRA Section B.1.1 QN2: Prior to 09/15/212 A. Revise Bolting Integrity Program procedures to ensure the QN1: Prior to 09/17/20 B.1.2actual yield strength of replacement or newly procured bolts will be QN2: Prior to 09/15/21less than 150 ksiB. Revise Bolting Integrity Program procedures to include theadditional guidance and recommendations of EPRI NP-5769 forreplacement of ASME pressure-retaining bolts and the guidanceprovided in EPRI TR-104213 for the replacement of otherpressure-retaining bolts.C. Revise Bolting Integrity Program procedures to specify acorrosion inspection and a check-off for the transfer tube isolationvalve flange bolts.D. Revise Bolting Integrity Program procedures to visually inspect arepresentative sample of normally submerged ERCW system bolts atleast once every 5 years. (See Set 10 (30-day), Enclosure 1, B.1.2-2a)3 A. Implement the Buried and Underground Piping and Tanks SQN1: Prior to 09/17/20 B.1.4Inspection Program as described in LRA Section B. 1.4. SQN2: Prior to 09/15/21B. Cathodic protection will be provided based on the guidance ofNUREG-1801, section XI.M41, as modified by LR-ISG-2011-03.E-3- lof16 LRANo. OMMIMENTIMPLEMENTATION SECTIONSCHEDULE I AUDITITEM4 A. Revise Compressed Air Monitoring Program procedures to QNI: Prior to 09/17/20 B.1.5include the standby diesel generator (DG) starting air subsystem. SQN2: Prior to 09/15/21B. Revise Compressed Air Monitoring Program procedures toinclude maintaining moisture and other contaminants below specifiedlimits in the standby DG starting air subsystem.C. Revise Compressed Air Monitoring Program procedures to applya consideration of the guidance of ASME OM-S/G-1998, Part 17;EPRI NP-7079; and EPRI TR-108147 to the limits specified for the airsystem contaminantsD. Revise Compressed Air Monitoring Program procedures tomaintain moisture, particulate size, and particulate quantity belowacceptable limits in the standby DG starting air subsystem to mitigateloss of material.E. Revise Compressed Air Monitoring Program procedures toinclude periodic and opportunistic visual inspections of surfaceconditions consistent with frequencies described in ASMEO/M-SG-1 998, Part 17 of accessible internal surfaces such ascompressors, dryers, after-coolers, and filter boxes of the followingcompressed air systems:* Diesel starting air subsystem* Auxiliary controlled air subsystem* Nonsafety-related controlled air subsystemF. Revise Compressed Air Monitoring Program procedures tomonitor and trend moisture content in the standby DG starting airsubsystem.G. Revise Compressed Air Monitoring Program procedures toinclude consideration of the guidance for acceptance criteria inASME OM-S/G-1998, Part 17, EPRI NP-7079; andEPRI TR-108147.E-3- 2of16 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE /AUDITITEM5 A. Revise Diesel Fuel Monitoring Program procedures to monitor SQN1: Prior to 09/17/20 B.1.8and trend sediment and particulates in the standby DG day tanks. SQN2: Prior to 09/15/21B. Revise Diesel Fuel Monitoring Program procedures to monitor andtrend levels of microbiological organisms in the seven-day storagetanks.C. Revise Diesel Fuel Monitoring Program procedures to include aten-year periodic cleaning and internal visual inspection of thestandby DG diesel fuel oil day tanks and high pressure fire protection(HPFP) diesel fuel oil storage tank. These cleanings and internalinspections will be performed at least once during the ten-year periodprior to the period of extended operation and at succeeding ten-yearintervals. If visual inspection is not possible, a volumetric inspectionwill be performed.D. Revise Diesel Fuel Monitoring Program procedures to include avolumetric examination of affected areas of the diesel fuel oil tanks, ifevidence of degradation is observed during visual inspection. Thescope of this enhancement includes the standby DG seven-day fueloil storage tanks, standby DG fuel oil day tanks, and HPFP diesel fueloil storage tank and is applicable to the inspections performed duringthe ten-year period prior to the period of extended operation andsucceeding ten-year intervals.6 A. Revise External Surfaces Monitoring Program procedures to SQN1: Prior to 09/17/20 B.1.10clarify that periodic inspections of systems in scope and subject to SQN2: Prior to 09/15/21aging management review for license renewal in accordance with 10CFR 54.4(a)(1) and (a)(3) will be performed. Inspections shallinclude areas surrounding the subject systems to identify hazards tothose systems. Inspections of nearby systems that could impact thesubject systems will include SSCs that are in scope and subject toaging management review for license renewal in accordance with 10CFR 54.4(a)(2).B. Revise External Surfaces Monitoring Program procedures toinclude instructions to look for the following related to metalliccomponents:* Corrosion and material wastage (loss of material).* Leakage from or onto external surfaces loss of material)." Worn, flaking, or oxide-coated surfaces (loss of material)." Corrosion stains on thermal insulation (loss of material)." Protective coating degradation (cracking, flaking, and blistering)." Leakage for detection of cracks on the external surfaces ofstainless steel components exposed to an air environmentcontaining halides.C. Revise External Surfaces Monitoring Program procedures toinclude instructions for monitoring aging effects for flexiblepolymeric components, including manual or physical manipulationsof the material, with a sample size for manipulation of at least tenE-3- 3of16 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE I AUDITITEM(6) percent of the available surface area. The inspection parameters forpolymers shall include the following:" Surface cracking, crazing, scuffing, dimensional changes(e.g., ballooning and necking) -)." Discoloration.* Exposure of internal reinforcement for reinforcedelastomers (loss of material).* Hardening as evidenced by loss of suppleness duringmanipulation where the component and material can bemanipulated.D. Revise External Surfaces Monitoring Program procedures toensure surfaces that are insulated will be inspected when the externalsurface is exposed (i.e., during maintenance) at such intervals thatwould ensure that the components' intended function is maintained.E. Revise External Surfaces Monitoring Program procedures toinclude acceptance criteria. Examples include the following:* Stainless steel should have a clean shiny surface with nodiscoloration." Other metals should not have any abnormal surfaceindications." Flexible polymers should have a uniform surface texture andcolor with no cracks and no unanticipated dimensionalchange, no abnormal surface with the material in an as-newcondition with respect to hardness, flexibility, physicaldimensions, and color." Rigid polymers should have no erosion, cracking, checking orchalks.E-3- 4of16 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE IAUDITITEM7 A. Revise Fatigue Monitoring Program procedures to monitor and SQNI: Prior to 09/17/20 B.1.11track critical thermal and pressure transients for components that SQN2: Prior to 09/15/21have been identified to have a fatigue Time Limited Aging Analysis.B. Fatigue usage calculations that consider the effects of the reactorwater environment will be developed for a set of sample reactorcoolant system (RCS) components. This sample set will include thelocations identified in NUREG/CR-6260 and additional plant-specificcomponent locations in the reactor coolant pressure boundary if theyare found to be more limiting than those considered in NUREG/CR-6260. In addition, fatigue usage calculations for reactor vesselinternals (lower core plate and control rod drive (CRD) guide tubepins) will be evaluated for the effects of the reactor waterenvironment. Fen factors will be determined as described in Section4.3.3.C. Fatigue usage factors for the RCS pressure boundarycomponents will be adjusted as necessary-to incorporate the effectsof the Cold Overpressure Mitigation System (COMS) event (i.e., lowtemperature overpressurization event) and the effects of structuralweld overlays.D. Revise Fatigue Monitoring Program procedures to provideupdates of the fatigue usage calculations on an as-needed basis if anallowable cycle limit is approached, or in a case where a transientdefinition has been changed, unanticipated new thermal events arediscovered, or the geometry of components have been modified.E. Revise Fatigue Monitoring Program procedures to track thetensioning cycles for the reactor coolant pump hydraulic studs.8 A. Revise Fire Protection Program procedures to include an SQN1: Prior to 09/17/20 B.1.12inspection of fire barrier walls, ceilings, and floors for any signs of SQN2: Prior to 09/15/21degradation such as cracking, spalling, or loss of material caused byfreeze thaw, chemical attack, or reaction with aggregates.B. Revise Fire Protection Program procedures to provide acceptancecriteria of no significant indications of concrete cracking, spalling, andloss of material of fire barrier walls, ceilings, and floors and in otherfire barrier materials.9 A. Revise Fire Water System Program procedures to include periodic SQN1: Prior to 09/17/20 B.1.13visual inspection of fire water system internals for evidence of SQN2: Prior to 09/15/21corrosion and loss of wall thickness.B. Revise Fire Water System Program procedures to include one ofthe following options:* Wall thickness evaluations of fire protection piping using non-intrusive techniques (e.g., volumetric testing) to identify evidenceof loss of material will be performed prior to the period ofextended operation and periodically thereafter. Results of theE-3- 5of16 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE I AUDITITEM(9) initial evaluations will be used to determine the appropriateinspection interval to ensure aging effects are identified prior toloss of intended function.A visual inspection of the internal surface of fire protection pipingwill be performed upon each entry into the system for routine orcorrective maintenance. These inspections will be capable ofevaluating (1) wall thickness to ensure against catastrophicfailure and (2) the inner diameter of the piping as it applies to thedesign flow of the fire protection system. Maintenance historyshall be used to demonstrate that such inspections have beenperformed on a representative number of locations prior to theperiod of extended operation. A representative number is 20%of the population (defined as locations having the same material,environment, and aging effect combination) with a maximum of25 locations. Additional inspections will be performed as neededto obtain this representative sample prior to the period ofextended operation and periodically during the period ofextended operation based on the findings from the inspectionsperformed prior to the period of extended operation.C, Revise Fire Water System Program procedures to ensure arepresentative sample of sprinkler heads will be tested or replacedbefore the end of the 50-year sprinkler head service life and at ten-year intervals thereafter during the extended period of operation.NFPA-25 defines a representative sample of sprinklers to consist of aminimum of not less than four sprinklers or one percent of the numberof sprinklers per individual sprinkler sample, whichever is greater. Ifthe option to replace the sprinklers is chosen, all sprinkler heads thathave been in service for 50 years will be replaced.D, Revise the Fire Water System Program full flow testing to be inaccordance with full flow testing standards of NFPA-25 (2011).E. Revise Fire Water System Program procedures to includeacceptance criteria for periodic visual inspection of fire water systeminternals for corrosion, minimum wall thickness, and the absence ofbiofouling in the sprinkler system that could cause corrosion in thesprinklers.10 A, Revise Flow Accelerated Corrosion (FAC) Program procedures SQNI: Prior to 09/17/20 B.1.14to implement NSAC-202L guidance for examination of components SQN2: Prior to 09/15/21upstream of piping surfaces where significant wear is detected.B, Revise FAC Program procedures to implement the guidance inLR-ISG-2012-01, which will include a susceptibility review based oninternal operating experience, external operating experience, EPRITR-1 011231, Recommendations for Controlling Cavitation, Flashing,Liquid Droplet Impingement, and Solid Particle Erosion in NuclearPower Plant Piping, and NUREG/CR-6031, Cavitation Guide forControl Valves. (TVA Response to Set 6.60day RAI B. 1.14-1 andI B, 1.38-1) 1E-3- 6of16 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE I AUDITITEM11 Revise Flux Thimble Tube Inspection Program procedures to SQN1: Prior to 09/17/20 B.1.15include a requirement to address if the predictive trending projects SQN2: Prior to 09/15/21that a tube will exceed 80% wall wear prior to the next plannedinspection, then initiate a Service Request (SR) to define actions (i.e.,plugging, repositioning, replacement, evaluations, etc.) required toensure that the projected wall wear does not exceed 80%. If anytube is found to be >80% through wall wear, then initiate a ServiceRequest (SR) to evaluate the predictive methodology used andmodify as required to define corrective actions (i.e., plugging,I repositioning, replacement, etc).12 A. Revise Inservice Inspection-IWF Program procedures to clarify SQN1: Prior to 09/17/20 B.1.17that detection of aging effects will include monitoring anchor bolts for SQN2: Prior to 09/15/21loss of material, loose or missing nuts, and cracking of concretearound the anchor bolts.B. Revise ISI -IWF Program procedures to include the followingcorrective action guidance.When a component support is found with minor age-relateddegradation, but still is evaluated as "acceptable for continuedservice" as defined in IWF-3400, the program owner may chooseto repair the degraded component. If the component is repaired,the program owner will substitute a randomly selected componentthat is more representative of the general population forsubsequent inspections.13 Inspection of Overhead Heavy Load and Light Load (Related to SQN1: Prior to 09/17/20 B.1.18Refueling) Handling Systems: SQN2: Prior to 09/15/21A. Revise program procedures to specify the inspection scope willinclude monitoring of rails in the rail system for wear; monitoringstructural components of the bridge, trolley and hoists for the agingeffect of deformation, cracking, and loss of material due to corrosion;and monitoring structural connections/bolting for loose or missingbolts, nuts, pins or rivets and any other conditions indicative of loss ofbolting integrity.B. Revise program procedures to include the inspection andinspection frequency requirements of ASME B30.2.C. Revise program procedures to clarify that the acceptance criteriawill include requirements for evaluation in accordance with ASMEB30.2 of significant loss of material for structural components andstructural bolts and significant wear of rail in the rail system.D. Revise program procedures to clarify that the acceptance criteriaand maintenance and repair activities use the guidance provided inASME B30.214 Implement the Internal Surfaces in Miscellaneous Piping and QN1: Prior to 09/17/20 B.1.19Ducting Components Program as described in LRA Section B. 1.19. QN2: Prior to 09/15/21E-3- 7of16 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE / AUDITITEM15 Implement the Metal Enclosed Bus Inspection Program as SQN1: Priorto 09/17/20 B.1.21described in LRA Section B.1.21. 3QN2: Prior to 09/15/2116 A. Revise Neutron Absorbing Material Monitoring Program 3QN1: Prior to 09/17/20 B.1.22procedures to perform blackness testing of the Boral coupons within 3QN2: Prior to 09/15/21the ten years prior to the period of extended operation and at leastevery ten years thereafter based on initial testing to determinepossible changes in boron-10 areal density.B. Revise Neutron Absorbing Material Monitoring Programprocedures to relate physical measurements of Boral coupons to theneed to perform additional testing.C. Revise Neutron Absorbing Material Monitoring Programprocedures to perform trending of coupon testing results to determinethe rate of degradation and to take action as needed to maintain theintended function of the Boral.17 Implement the Non-EQ Cable Connections Program as described QN1: Prior to 09/17/20 B.1.24in LRA Section B.1.24 QN2: Prior to 09/15/2118 Implement the Non-EQ Inaccessible Power Cable (400 V to 35 kV) QNI: Prior to 09/17/20 B.1.25Program as described in LRA Section B. 1.25 SQN2: Prior to 09/15/2119 Implement the Non-EQ Instrumentation Circuits Test Review SQN1: Prior to 09/17/20 B.1.26Program as described in LRA Section B.1.26. SQN2: Prior to 09/15/2120 Implement the Non-EQ Insulated Cables and Connections QNI: Prior to 09/17/20 B.1.27Program as described in LRA Section B.1.27 QN2: Prior to 09/15/2121 A. Revise Oil Analysis Program procedures to monitor and QN1: Prior to 09/17/20 B.1.28maintain contaminants in the 161-kV oil filled cable system within SQN2: Prior to 09/15/21acceptable limits through periodic sampling in accordance withindustry standards, manufacturer's recommendations and plant-specific operating experience.B. Revise Oil Analysis Program procedures to trend oil contaminantlevels and initiate a problem evaluation report if contaminants exceedalert levels or limits in the 161 -kV oil-filled cable system.22 Implement the One-Time Inspection Program as described in LRA 3QN1: Prior to 09/17/20 B.1.29Section B.1.29. SQN2: Prior to 09/15/2123 Implement the One-Time Inspection -Small Bore Piping Program SQN1: Prior to 09/17/20 B.1.30as described in LRA Section B.1.30 SQN2: Prior to 09/15/2124 Revise Periodic Surveillance and Preventive Maintenance SQN1: Prior to 09/17/20 B.1.31Program procedures as necessary to include all activities described SQN2: Prior to 09/15/21in the table provided in the LRA Section B. 1.31 program description.E-3- 8of16 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE / AUDITITEM25 A. Revise Protective Coating Program procedures to clarify that SQN1: Prior to 09/17/20 B.1.32detection of aging effects will include inspection of coatings near SQN2: Prior to 09/15/21sumps or screens associated with the emergency core coolingsystem.B. Revise Protective Coating Program procedures to clarify thatinstruments and equipment needed for inspection may include, butnot be limited to, flashlights, spotlights, marker pen, mirror, measuringtape, magnifier, binoculars, camera with or without wide-angle lens,and self-sealing polyethylene sample bags.C. Revise Protective Coating Program procedures to clarify that thelast two performance monitoring reports pertaining to the coatingsystems will be reviewed prior to the inspection or monitoringprocess.26 A. Revise Reactor Head Closure Studs Program procedures to SQN1: Prior to 09/17/20 B.1.33ensure that replacement studs are fabricated from bolting material SQN2: Prior to 09/15/21with actual measured yield strength less than 150 ksi.B. Revise Reactor Head Closure Studs Program procedures toexclude the use of molybdenum disulfide (MoS2) on the reactorvessel closure studs and to refer to Reg. Guide 1.65, Revl.27 A. Revise Reactor Vessel Internals Program procedures to take SQN1: Priorto 09/17/20 B.1.34physical measurements of the Type 304 stainless steel hold-downsprings in Unit 1 at each refueling outage to ensure preload is SQN2: Not Applicableadequate for continued operation.B. Revise Reactor Vessel Internals Program procedures to includepreload acceptance criteria for the Type 304 stainless steelhold-down springs in Unit 1.28 A. Revise Reactor Vessel Surveillance Program procedures to SQNI: Prior to 09/17/20 B.1.35consider the area outside the beltline such as nozzles, penetrations SQN2: Prior to 09/15/21and discontinuities to determine if more restrictive pressure-temperature limits are required than would be determined by justconsidering the reactor vessel beltline materials.B. Revise Reactor Vessel Surveillance Program procedures toincorporate an NRC-approved schedule for capsule withdrawals tomeet ASTM-E1 85-82 requirements, including the possibility ofoperation beyond 60 years (refer to the TVA Letter to NRC,"Sequoyah Reactor Pressure Vessel Surveillance CapsuleWithdrawal Schedule Revision Due to License RenewalAmendment," dated January 10, 2013, ML13032A251.)C. Revise Reactor Vessel Surveillance Program procedures towithdraw and test a standby capsule to cover the peak fluenceexpected at the end of the period of extended operation.E-3- 9of16 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE / AUDITITEM29 Implement the Selective Leaching Program as described in LRA SQN1: Prior to 09/17/20 B.1.37Section B.1.37. QN2: Prior to 09/15/2130 Revise Steam Generator Intearitv Proaram Drocedures to ensure SQN1: Prior to 09/17/20 B.1.39w_that corrosion resistant materials are used for replacement steamgenerator tube plugs.SQN2: Prior to 09/15/21-4 131A. Revise Structures Monitoring Program procedures to includethe following in-scope structures:* 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) pump house and waterstorage tanks' foundations* Radiation monitoring station (or particulate iodine and noble gasstation) Units 1 & 2" Service building* Skimmer wall (Cell No. 12)* Transformer and switchyard support structures and foundationsB. Revise Structures Monitoring Program procedures to specify thefollowing list of in-scope structures are included in the RG 1.127,Inspection of Water-Control Structures Associated with NuclearPower Plants Program (Section B.1.36):* Condenser cooling water (CCW) pumping station (also known asintake pumping station) 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 and underwater damC. Revise Structures Monitoring Program procedures to include thefollowing in-scope structural components and commodities:" Anchor bolts* Anchorage/embedments (e.g., plates, channels, unistrut, angles,other structural shapes)* Beams, columns and base plates (steel)SQN1: Prior to 09/17/20SQN2: Prior to 09/15/210SBeams, columns, floor slabs and interior walls (concrete)Beams, columns, floor slabs and interior walls (reactor cavityand primary shield walls; pressurizer and reactor coolant pumpcompartments; refueling canal, steam generator compartments;crane wall and missile shield slabs and barriers)Building concrete at locations of expansion and grouted anchors;grout pads for support base platesCable trayCable tunnelCanal gate bulkheadCompressible joints and seals0000E-3- 10of16 LRAI IMPLEMENTATION SECTIONNO MSCHEDULE / AUDITITEM(31) 9 Concrete cover for the rock walls of approach channel* Concrete shield blocks* Conduit0 Control rod drive missile shield* Control room ceiling support system* Curbs* Discharge box and foundation* Doors (including air locks and bulkhead doors)0 Duct banks0 Earthen embankment0 Equipment pads/foundations* Explosion bolts (E. G. Smith aluminum bolts)* Exterior above and below grade; foundation (concrete)* Exterior concrete slabs (missile barrier) and concrete caps* Exterior walls: above and below grade (concrete)* Foundations: building, electrical components, switchyard,transformers, circuit breakers, tanks, etc.* Ice baskets0 Ice baskets lattice support frames* Ice condenser support floor (concrete)* Insulation (fiberglass, calcium silicate)0 Intermediate deck and top deck of ice condenser* Kick plates and curbs (steel -inside steel containment vessel)* Lower inlet doors (inside steel containment vessel)* Lower support structure structural steel: beams, columns,plates (inside steel containment vessel)* Manholes and handholes* Manways, hatches, manhole covers, and hatch covers(concrete)* Manways, hatches, manhole covers, and hatch covers (steel)* Masonry walls* Metal siding* Miscellaneous steel (decking, grating, handrails, ladders,platforms, enclosure plates, stairs, vents and louvers, framingsteel, etc.)* Missile barriers/shields (concrete)* Missile barriers/shields (steel)* Monorails* Penetration seals0 Penetration seals (steel end caps)0 Penetration sleeves (mechanical and electrical not penetratingprimary containment boundary)* Personnel access doors, equipment access floor hatch andescape hatches* Piles* Pipe tunnel0 Precast bulkheads* Pressure relief or blowout panels* Racks, panels, cabinets and enclosures for electricalE-3- 11of16 LRANo. COMMITMENT IMPLEMENTATION SECTIONNO MSCHEDULE I AUDITITEM(31)00000S000000000SS00000equipment and instrumentationRiprapRock embankmentRoof or floor deckingRoof membranesRoof slabsRWST rainwater diversion skirtRWST storage basinSeals and gaskets (doors, manways and hatches)Seismic/expansion jointShield building concrete foundation, wall, tension ring beamand dome: interior, exterior above and below gradeSteel liner plateSteel sheet pilesStructural boltingSumps (concrete)Sumps (steel)Sump liners (steel)Sump screensSupport members; welds; bolted connections; supportanchorages to building structure (e.g., non-ASME piping andcomponents supports, conduit supports, cable tray supports,HVAC duct supports, instrument tubing supports, tube tracksupports, pipe whip restraints, jet impingement shields,masonry walls, racks, panels, cabinets and enclosures forelectrical equipment and instrumentation)Support pedestals (concrete)Transmission, angle and pull-off towersTrash racksTrash racks associated structural support framingTraveling screen casing and associated structural supportframingTrenches (concrete)Tube trackTurning vanesVibration isolators00D. Revise Structures Monitoring Program procedures to includeperiodic sampling and chemical analysis of ground water chemistryfor pH, chlorides, and sulfates on a frequency of at least every fiveyears.E. Revise Masonry Wall Program procedures to specify masonrywalls located in the following in-scope structures are in the scope ofthe Masonry Wall Program:* Auxiliary building" Reactor building Units 1 & 2* Control bay" ERCW pumping station" HPFP pump house" Turbine buildingE-3- 12 of 16 LRANo. COMMITMENT IMPLEMENTATION SECTIONNMSCHEDULE IAUDITITEM(31) F. Revise Structures Monitoring Program procedures to include thefollowing parameters to be monitored or inspected:* Requirements for concrete structures based on ACI 349-3Rand ASCE 11 and include monitoring the surface condition forloss of material, loss of bond, increase in porosity andpermeability, loss of strength, and reduction in concrete anchorcapacity due to local concrete degradation.* Loose or missing nuts for structural bolting." Monitoring gaps between the structural steel supports andmasonry walls that could potentially affect wall qualification.G. Revise Structures Monitoring Program procedures to include thefollowing components to be monitored for the associated parameters:* Anchors/fasteners (nuts and bolts) will be monitored for looseor missing nuts and/or bolts, and cracking of concrete aroundthe anchor bolts.* Elastomeric vibration isolators and structural sealants will bemonitored for cracking, loss of material, loss of sealing, andchange in material properties (e.g., hardening).* Monitor the surface condition of insulation (fiberglass, calciumsilicate) to identify exposure to moisture that can cause loss ofinsulation effectiveness.H. Revise Structures Monitoring Program procedures to include thefollowing for detection of aging effects:* Inspection of structural bolting for loose or missing nuts." Inspection of anchor bolts for loose or missing nuts and/orbolts, and cracking of concrete around the anchor bolts.* Inspection of elastomeric material for cracking, loss of material,loss of sealing, and change in material properties (e.g.,hardening), and supplement inspection by feel or touch todetect hardening if the intended function of the elastomericmaterial is suspect. Include instructions to augment the visualexamination of elastomeric material with physical manipulationof at least ten percent of available surface area.* Opportunistic inspections when normally inaccessible areas(e.g., high radiation areas, below grade concrete walls orfoundations, buried or submerged structures) becomeaccessible due to required plant activities. Additionally,inspections will be performed of inaccessible areas inenvironments where observed conditions in accessible areasexposed to the same environment indicate that significantdegradation is occurring.* Inspection of submerged structures at least once every fiveyears.Inspections of water control structures should be conductedunder the direction of qualified personnel experienced in theinvestigation, design, construction, and operation of thesetypes of facilities." Inspections of water control structures shall be performed onan interval not to exceed five years.E-3- 13 of 16 LRAN.COMMITMENT IMPLEMENTATION SECTIONSCHEDULE / AUDITITEM(31)
- Perform special inspections of water control structuresimmediately (within 30 days) following the occurrence ofsignificant natural phenomena, such as large floods,earthquakes, hurricanes, tornadoes, and intense local rainfalls.* Insulation (fiberglass, calcium silicate) will be monitored forloss of material and change in material properties due topotential exposure to moisture that can cause loss of insulationeffectiveness.I. Revise Structures Monitoring Program procedures to prescribequantitative acceptance criteria is based on the quantitativeacceptance criteria of ACI 349.3R and information provided inindustry codes, standards, and guidelines including ACI 318,ANSI/ASCE 11 and relevant AISC specifications. Industry andplant-specific operating experience will also be considered in thedevelopment of the acceptance criteria.J. Revise Structures Monitoring Program procedures to clarify thatdetection of aging effects will include the following.Qualifications of personnel conducting the inspections or testing andevaluation of structures and structural components meet theguidance in Chapter 7 of ACI 349.3R.K. Revise Structures Monitoring Program procedures to include thefollowing acceptance criteria for insulation (calcium silicate andfiberglass)* No moisture or surface irregularities that indicate exposure tomoisture.L. Revise Structures Monitoring Program procedures to include thefollowing preventive actions.Specify protected storage requirements for high-strength fastenercomponents (specifically ASTM A325 and A490 bolting).Storage of these fastener components shall include:1) maintaining fastener components in closed containers to protectfrom dirt and corrosion:(2) storage of the closed containers in a protected shelter:(3) removal of fastener components from protected storage only asnecessary: and(4) prompt return of any unused fastener components to protectedstorage.32 Implement the Thermal Aging Embrittlement of Cast Austenitic QNI: Prior to 09/17/20 B.1.41Stainless Steel (CASS) as described in LRA Section B.1.41 QN2: Prior to 09/15/2133 A. Revise Water Chemistry Control -Closed Treated Water QN1: Prior to 09/17/20 B.1.42Systems Program procedures to provide a corrosion inhibitor for the QN2: Prior to 09/15/21following chilled water subsystems in accordance with industryguidelines and vendor recommendations:" Auxiliary building cooling" Incore Chiller 1A, 1B, 2A, & 2B* 6.9 kV Shutdown Board Room A & BE-3- 14 of 16 m LRAI IMPLEMENTATION SECTIONNo. COMMITMENT I SCHEDULE / AUDITITEM___________________________I_________IE(33) B. Revise Water Chemistry Control -Closed Treated WaterSystems Program procedures to conduct inspections whenever aboundary is opened for the following systems:* Standby diesel generator jacket water subsystem* Component cooling system* Glycol cooling loop system* High pressure fire protection diesel jacket water system" Chilled water portion of miscellaneous HVAC systems (i.e.,auxiliary building, Incore Chiller 1A, 1B, 2A, & 2B, and 6.9 kVShutdown Board Room A & B)C. Revise Water Chemistry Control-Closed Treated Water SystemsProgram procedures to state these inspections will be conducted inaccordance with applicable ASME Code requirements, industrystandards, or other plant-specific inspection and personnelqualification procedures that are capable of detecting corrosion orcracking.D. Revise Water Chemistry Control -Closed Treated WaterSystems Program procedures to perform sampling and analysis ofthe glycol cooling system per industry standards and in no casegreater than quarterly unless justified with an additional analysis.E. Revise Water Chemistry Control -Closed Treated WaterSystems Program procedures to inspect a representative sample ofpiping and components at a frequency of once every ten years forthe following systems:" Standby diesel generator jacket water subsystem* Component cooling system* Glycol cooling loop system* High pressure fire protection diesel jacket water system* Chilled water portion of miscellaneous HVAC systems (i.e.,auxiliary building, Incore Chiller 1A, 1B, 2A, & 2B, and 6.9 kVShutdown Board Room A & B)F. Components inspected will be those with the highest likelihoodof corrosion or cracking. A representative sample is 20% of thepopulation (defined as components having the same material,environment, and aging effect combination) with a maximum of 25components. These inspections will be in accordance withapplicable ASME Code requirements, industry standards, or otherplant-specific inspection and personnel qualification procedures thatensure the capability of detecting corrosion or cracking.34 Revise Containment Leak Rate Program procedures to require SQN1: Prior to 09/17/20 B. 1.7venting the SCV bottom liner plate weld leak test channels to the SQN2: Prior to 09/15/21containment atmosphere prior to the CILRT and resealing the ventpath after the CILRT to prevent moisture intrusion during plantoperation. IE-3- 15 of 16 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE /AUDITITEM35 Modify the configuration of the SQN Unit 1 test connection access SQNI: Prior to 09/17/20 B.1.6boxes to prevent moisture intrusion to the leak test channels. Prior toinstalling this modification, TVA will perform remote visual SQN2: Not Applicableexaminations inside the leak test channels by inserting a borescopevideo probe through the test connection tubing.36 Revise Inservice Inspection Program procedures to include a SQNI: Prior to 09/17/20 B.1.16supplemental inspection of Class 1 CASS piping components that SQN2: Prior to 09/15/21do not meet the materials selection criteria of NUREG-0313,Revision 2 with regard to ferrite and carbon content. An inspectiontechniques qualified by ASME or EPRI will be used to monitorcracking.Inspections will be conducted on a sampling basis. The extent ofsampling will be based on the established method of inspection andindustry operating experience and practices when the program isimplemented, and will include components determined to be limitingfrom the standpoint of applied stress, operating time andenvironmental considerations.37 TVA will implement the Operating Experience for the AMPs in No later than the B.0.4accordance with the WVA response to the RAI B.0.4-1 on scheduled issue date of:he renewed operatingJuly 29, 2013 letter to the NRC. (See Set 7.30day RAI B.0.4-1 icenses for SQN Units 1Response, EDMS # L44130725002) 2.The above table identifies the 37 SQN NRC LR commitments. Any other statements in this letterare provided for information purposes and are not considered to be regulatory commitments.E-3- 16of16