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{{Adams
#REDIRECT [[CNL-13-105, Response to NRC Request for Additional Information Regarding Review of the License Renewal Application, Sets 10 (3.0.3-1, Requests 3, 4, 6), 12 (B.1.6-1b, B.1.6-2b), 16 (4.3.1-8a)]]
| number = ML13312A005
| issue date = 11/04/2013
| title = Sequoyah, Units 1 & 2 - Response to NRC Request for Additional Information Regarding Review of the License Renewal Application, Sets 10 (3.0.3-1, Requests 3, 4, 6), 12 (B.1.6-1b, B.1.6-2b), 16 (4.3.1-8a)
| author name = Shea J W
| author affiliation = Tennessee Valley Authority
| addressee name =
| addressee affiliation = NRC/Document Control Desk, NRC/NRR
| docket = 05000327, 05000328
| license number = DPR-077, DPR-079
| contact person =
| case reference number = CNL-13-105, TAC FM0481, TAC MF0482
| document type = Graphics incl Charts and Tables, Letter
| page count = 74
| project = TAC:FM0481, TAC:MF0482
| stage = Response to RAI
}}
 
=Text=
{{#Wiki_filter:Tennessee Valley Authority, 1101 Market Street, Chattanooga, Tennessee 37402CNL-13-105November 4, 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:References:Response to NRC Request for Additional Information Regarding theReview of the Sequoyah Nuclear Plant, Units I and 2, License RenewalApplication, Sets 10 (3.0.3-1, Requests 3, 4, 6), 12 (B.1.6-1b, B.1.6-2b), 16(4.3.1-8a) (TAC Nos. MF0481 and MF0482)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-Set 10," dated August 2, 2013 (ADAMS Accession No. ML13204A257)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 10 (B.1.23-2a), 11 (4.1-8a), and 12(30-day)," dated September 30, 2013 (ADAMS Accession No.ML13276A018)4. NRC Letter to TVA, "Requests for Additional Information for the Review ofthe Sequoyah Nuclear Plant, Units 1 and 2, License Renewal Application-Set 16," dated October 18, 2013 (ADAMS Accession No.ML13282A330)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.Printed on recycled paper U.S. Nuclear Regulatory CommissionPage 2November 4, 2013By Reference 2, the NRC forwarded a request for additional information (RAI) labeledSet 10, which included RAI 3.0.3-1, Requests: 3, 4 and 6 with a required response due dateno later than October 31, 2013. However, Mr. Richard Plasse, NRC Project Manager for theSQN License Renewal, has given a verbal extension for the response to November 4, 2013.Enclosure 1 provides the TVA responses.In Reference 3, TVA submitted responses that included RAIs B.1.6-1a, and B.1.6-2a. InanOctober 23, 2013 telecom, Mr. Plasse requested clarifications to these RAI responses.Enclosure I provides the requested clarifications.By Reference 4, the NRC forwarded an RAI labeled Set 16, which included RAI 4.3.1-8awith a required response due date no later than November 18, 2013. Enclosure 1 providesthe TVA response.Enclosure 2 is an updated list of the regulatory commitments for license renewal, whichsupersedes all previous versions.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 this4th day of November 2013.Res e ully,J W. heace esident, Nuclear LicensingEnclosures:1. TVA Responses to NRC Request for Additional Information: Sets 10 (3.0.3-1,Requests 3, 4, 6), 12 (B.1.6-lb, B.1.6-2b), 16 (4.3.1-8a)2. Regulatory Commitment List, Revision 11cc (Enclosures):NRC Regional Administrator -Region IINRC Senior Resident Inspector -Sequoyah Nuclear Plant ENCLOSURE1Tennessee Valley AuthoritySequoyah Nuclear Plant, Units I and 2 License RenewalTVA Responses to NRC Request for Additional Information:Sets 10 (3.0.3-1, Requests 3, 4, 6), 12 (B.1.6-1b, B.1.6-2b), 16 (4.3.1-8a)Set 10: RAI 3.0.3-1, Request 3Backgqround:Recent industry operating experience (OE) and questions raised during the staff's review ofseveral license renewal applications (LRAs) has resulted in the staff concluding that severalaging management programs (AMP) and aging management review (AMR) items in the LRAmay not or do not account for this OE.These issues are related to the following, as described in detail below:3. Loss of coating integrity for Service Level Ill and other coatings.Issue:3. Loss of coating integrity for Service Level Ill and Other coatingsIndustry OE indicates that degraded coatings have resulted in unanticipated or acceleratedcorrosion of the base metal and degraded performance of downstream equipment(e.g., reduction in flow, drop in pressure, reduction in heat transfer) due to flow blockage.Based on these industry OE examples, the staff has questions related to how the agingeffect, loss of coating integrity due to blistering, cracking, flaking, peeling, or physicaldamage, would be managed for Service Level Ill and other coatings.For purposes of this RAI:a. Service Level Ill coatings are those installed on the interior of in-scope piping, heatexchanges, and tanks which support functions identified under 10 CFR 54.4(a)(1)and (a) (2).b. "Other coatings," include coatings installed on the interior of in-scope piping, heatexchangers, and tanks whose failure could prevent satisfactory accomplishment ofany of the functions identified under 10 CFR 54.4(a)(3).c. The term "coating" includes inorganic (e.g., zinc-based) or organic (e.g., elastomericor polymeric) coatings, linings (e.g., rubber, cementitious), and concrete surfacesthat are designed to adhere to a component to protect its surface.d. The terms "paint" and "linings" should be considered as coatings.The staff does not consider a coating to be a component. A coating becomes an integralpart of an in-scope component, providing it protection from corrosion, just as the addition ofchromium to steel mitigates corrosion. Just as stainless steel introduces a new aging effect,cracking due to stress corrosion cracking (SCC), to which carbon steel is generally notsusceptible, the addition of a coating to a component introduces the potential forunanticipated or accelerated corrosion of the base metal and degraded performance ofdownstream equipment due to flow blockage. If coatings are installed, loss of coatingintegrity due to blistering, cracking, flaking, peeling, or physical damage must be managedregardless of whether the coatings are credited for aging.Request:3. Loss of coating integrity for Service Level Ill and Other coatingsE-1 -1 of 51
: a. State whether any in-scope components have internal Service Level Ill or Othercoatings.b. If coatings have been installed on the internal surfaces of in-scope components(i.e., piping, piping subcomponents, heat exchangers, and tanks), state how loss ofcoating integrity due to blistering, cracking, flaking, peeling, or physical damage willbe managed, including:i. For each installed coating application, whether installation records, if available,used to apply the coating included material manufacturer installationspecifications.ii. The inspection method.iii. The parameters to be inspected.iv. When inspections will commence and the frequency of subsequent inspections.Consider such factors as whether coatings can be verified to have beeninstalled to manufacturer specifications, prior inspection findings of acceptableor degraded coatings, and coating replacement history.v. The extent of inspections and the basis for the extent of inspections if it is not100 percent.vi. The training and qualification of individuals involved in coating inspections.vii. How trending of coating degradation will be conducted.viii. Acceptance criteria.ix. Corrective actions for coatings that do not meet acceptance criteria.x. The program(s) that will be augmented to include the above requirements.c. State how LRA Section 3 Table 2s, Appendix A, and Appendix B will be revised toaddress the program used to manage loss of coating integrity due to blistering,cracking, flaking, peeling, or physical damage.TVA Response to RAI 3.0.3-1. Request 3, Loss of Coating IntegrityDuring the individual plant assessment, applicable aging effects were considered for licenserenewal in-scope components regardless of whether preventive programs such as coating orwater chemistry programs were applied.The following components have the potential for degradation of coatings to affect the passivefunctions of downstream components (e.g., reduction in flow, drop in pressure, reduction in heattransfer) due to flow blockage and for components with a pressure boundary function that couldexperience accelerated corrosion due to coating degradation.E-1- 2of51 (3.a) Component (3.b.i) (3.b.i)with internal Service Coating Installation records, if available, used to apply theLevel III or Other InstallationCoating Records coating included material manufacturer installationAvailable specifications.PipingFire protection No N/Acarbon dioxideHigh pressure fire No N/AprotectionMakeup watertreatment plantHypochlorite No N/AThe coating (Belzona) was applied in accordance withEssential rawYes the coating manufacturer's specification or as directed bycooling water TVA Engineering.TanksHPFP water storage No N/AClear well No N/ALined per TVA Spec. Section 27 [see drawing 166365,contract 71 C30-92627-1]Cation No N/APotable water Yes AWWA D102-62T Standard for PaintingBulk chemical No N/Astorage tankCaustic batching No N/ACaskdecontamination No N/AcollectorMain feed pump No N/Aturbine oilGland seal water No N/AstorageSI pump lube oil No N/AreservoirsE-1- 3of51 (3.a) Component (3.b.i) (3.b.i)with internal Service Coating Intlai oLevel III or Other Installation Installation records, if available, used to apply theCoating Records coating included material manufacturer installationAvailable specifications.Pressurizer relief No N/AThe coating (Belzona) was applied in accordance withEDG 7 day storage Yes the coating manufacturer's specification or as directed byTVA Engineering.Heat ExchangersElectric board room The coating (Belzona) was applied in accordance withchiller packages Yes the coating manufacturer's specification or as directed by(A-A and B-B) TVA Engineering.Incore instrument The coating (Belzona) was applied in accordance withroom water chiller Yes the coating manufacturer's specification or as directed bypackage B TVA Engineering.b(ii). Visual inspections are used to assess coating condition.b(iii). The monitored parameter is the coated component surface condition.b(iv). Initial inspections will begin no later than the last scheduled refueling outage prior to theperiod of extended operation (PEO). Subsequent inspections will be performed based onthe initial inspection results. For example:i. If no peeling, delamination, blisters, or rusting are observed, and any cracking andflaking has been found acceptable, subsequent inspections will be performed atleast once every six years. If no indications are found during inspection of onetrain, the redundant train would not be inspected.ii. If the inspection results do not meet (i), but a coating specialist has determined thatno remediation is required, then subsequent inspections will be conducted everyother refueling outage.iii. If coating degradation is observed that required repair or replacement, or newlyinstalled coatings, subsequent inspections will occur during each of the next tworefueling outage intervals to establish a performance trend on the coating.Commitment #24.B has been added.b(v). The extent of inspections for coated tanks and heat exchangers is different than that forpiping. The visible portions of coated tanks and heat exchangers are inspected upondisassembly or entry. The inspection of coated piping is based on accessibility (i.e., theends of the piping and the length of available borescope equipment). A 20 percentsample of the pipe coating or a maximum of 25 locations will be inspected for eachcombination of coating type, material protected by the coating, and environment.b(vi). Coating inspections are performed by individuals certified to ANSI N45.2.6,"Qualifications of Inspection, Examination, and Testing Personnel for Nuclear PowerPlants." The subsequent evaluation of inspection findings is conducted by a nuclearcoatings subject matter expert qualified in accordance with ASTM D 7108-05, "StandardGuide for Establishing Qualifications for a Nuclear Coatings Specialist."b(vii). The Periodic Surveillance and Preventive Maintenance (PSPM) Program described inLRA B.1.31 is structured to maintain components in a manner that permits them toE-1 -4of51 perform their design function. The program establishes the frequency and types ofmaintenance to be performed on equipment commensurate with its importance to safety,effect on plant operation, and replacement cost, with consideration for the degree ofinherent reliability built into individual components. Relevant information about theequipment maintenance activity, including as-found conditions, is recorded andreviewed. The as-found conditions are trended and used to adjust the time intervalbetween preventive maintenance activities to ensure that the monitored components cancontinue to perform their design function until the next inspection. An individualknowledgeable and experienced in nuclear coatings work will prepare reports thatinclude 1) the location of all areas identified with deterioration, 2) a prioritization of therepair areas into areas that must be repaired before returning the system to service andareas where repair can be postponed to the next inspection, and 3) where available,photographs indexed to inspection locations.b(viii). The following acceptance criteria are utilized: Peeling and delamination are notpermitted. Cracking is not permitted if accompanied by delamination or loss of adhesion.Blisters are limited to intact blisters that are completely surrounded by sound coatingbonded to the surface.b(ix). Corrective actions for unacceptable inspection findings will be determined in accordancewith the SQN 10 CFR 50 Appendix B Corrective Action Program (CAP).b(x). The PSPM Program described in LRA B.1.31 is enhanced to include verification ofcoating integrity of selected piping, tanks and heat exchangers, coating acceptancecriteria, qualifications for personnel performing coating inspections and evaluatingcoating findings, and documentation of coating inspections.The Fire Water System Program described in LRA B. 1.13 is enhanced in the responseto SQN RAI 3.0.3-1 Request #4 to address the coatings in the fire water storage tanks.The Service Water Integrity Program described in LRA B.1.38 is enhanced to addresscoating acceptance criteria, qualifications for personnel performing coating inspectionsand evaluating coating findings, and documentation of coating inspections.c. Changes to LRA Section A.1.31, Periodic Surveillance and Preventive MaintenanceProgram, follow with additions underlined."The Periodic Surveillance and Preventive Maintenance (PSPM) Program managesfor specific components' aging effects not managed by other aging managementprograms, including loss of material, fouling, cracking, loss of coating integrity, andchange in material properties.Each inspection occurs at least once every five years, with the exception of coatinginspections for which frequency is based on coating condition. For each activity thatrefers to a representative sample, a representative sample is 20 percent of thepopulation (defined as components having the same material, environment, and agingeffect combination) with a maximum of 25 components.Credit for program activities has been taken in the aging management review ofsystems, structures and components as described below.Prior to the PEO, perform a visual inspection of a 20 percent sample of the followingcoated piping systems or a maximum of 25 locations for each combination of type ofcoating, material the coating is protecting, and environment. Visually inspect theE-1- 5of51 surface condition of the coated components to manage loss of coating integrity dueto cracking, debonding, delamination, peeling, flaking, and blistering.i. Fire protection carbon dioxide (galvanized piping)ii. High pressure fire protection (cement lined piping)iii. Makeup water treatment plant (where Saran and Polypropylene applied)iv. Hypochlorite (Polypropylene, Kynar, Teflon, and concrete)v. Essential raw cooling water (where Belzona applied)Prior to the PEO, perform a visual inspection of the following coated tanks and heatexchangers. Visually inspect the surface condition of the coated components tomanage loss of coating integrity due to cracking., debonding, delamination, peeling,flaking, and blistering.Tanksi. Clear well (where Epoxy-Phenolic coatinqgNisconsin protective coating PlastiteNo. 7155 or equal applied)ii. Caustic (where TVA specs -Section 27 applied (drawing 116365, contract71C30-92627-1))iii. Cation (where 3/16 inch of rubber applied)iv. Potable water (where AWWA D102-62T standard for painting Section 3.1 No.2, 3, or 4 applied)v. Bulk chemical (where rubber lining applied)vi. Caustic batching (where 3/16" rubber lined with chlorinated rubber compoundapplied)vii. Cask decontamination (where 2 coats Red Lead in oil, Fed SPEC TTP-85 TypeII applied)viii. Main feed pump turbine oil (where coating applied)ix. Gland seal water (where red oil based paint applied)x. Safety injection lube oil reservoir (where 0.006 inch plastic coating applied)xi. Pressurizer relief (where Ambercoat 55 applied)xii. EDG 7 day storace (where Belzona applied)E-1 -6 of 51 Heat Exchangersi. Electric board room chiller packages (where Belzona applied)ii. Incore instrument room water chiller package B (where Belzona applied)* Include the following loss of coating integrity acceptance criteria (1) peeling anddelamination are not permitted, (2) cracking is not permitted if accompanied bydelamination or loss of adhesion, and (3) blisters are limited to intact blisters that arecompletely surrounded by sound coating bonded to the surface.* Ensure coating inspections are performed by individuals certified to ANSI N45.2.6,"Qualifications of Inspection, Examination, and Testing Personnel for Nuclear PowerPlants," and that subsequent evaluation of inspection findings is conducted by anuclear coatings subject matter expert qualified in accordance withASTM D 7108-05, "Standard Guide for Establishing Qualifications for a NuclearCoatings Specialist."* Ensure an individual knowledgeable and experienced in nuclear coatings work willprepare a coating report that includes a list of locations identified with coatingdeterioration including, where possible, photographs indexed to inspection location,and a prioritization of the repair areas into areas that must be repaired beforereturning the system to service and areas where coating repair can be postponed tothe next inspection.* Perform subsequent inspections of coatings based on the following.i. If no flaking, debonding, peeling, delamination, blisters, or rusting areobserved, and any cracking and flaking has been found acceptable,subsequent inspections will be performed at least once every six years. If thecoating is inspected on one train and no indications are found, the samecoating on the redundant train would not be inspected during that inspectioninterval.ii. If the inspection results do not meet (i), yet a coating specialist has determinedthat no remediation is required, then subsequent inspections will be conductedevery other refueling outage.iii. If coating degradation is observed that required newly installed coatings,subsequent inspections will occur during each of the next two refueling outageintervals to establish a performance trend on the coatinq."Commitment #24 will implement the intents made in the statements above and for LRASection B.1.31 changes stated below.Changes to LRA Section B.1.31, Periodic Surveillance and Preventive MaintenanceProgram (PSPM) follow with additions underlined."The Periodic Surveillance and Preventive Maintenance (PSPM) Program manages forspecific components' aging effects not managed by other aging managementprograms, including loss of material, fouling, cracking, loss of coating integrity, andchange in material properties.Initial coating inspections will begin no later than the last scheduled refueling outageprior to the PEO. Subsequent coating inspections will be performed based on thefollowing.E-1 -7 of 51 If no peeling, delamination, blisters, or rusting are observed, and any cracking andflaking has been found acceptable, subsequent inspections will be performed atleast once every six years. If the coatinq is inspected on one train and noindications are found, the same coatinq on the redundant train would not beinspected durinq that inspection interval.ii. If the inspection results do not meet (i), yet a coating specialist has determined thatno remediation is required, then subsequent inspections will be conducted everyother refueling outage.iii. If coating degradation is observed that required newly installed coatings,subsequent inspections will occur during each of the next two refueling outageintervals to establish a performance trend on the coating.4. Detection of Aging EffectsPreventive maintenance activities and periodic surveillances provide for periodiccomponent inspections to detect aging effects. Inspection intervals are establishedsuch that they provide timely detection of degradation prior to loss of intendedfunctions. Inspection intervals, sample sizes, and data collection methods aredependent on component material and environment and take into considerationindustry and plant specific operating experience and manufacturers' recommendations.Established techniques such as visual inspections are used. Each inspection occurs atleast once every five years, with the exception of coating inspections, for whichfrequency is based on coating condition. The selection of components to be inspectedwill focus on locations which are most susceptible to aging, where practical.Established inspection methods to detect aging effects include (1) visual inspectionsand manual flexing of elastomeric components and (2) visual inspections or other NDEtechniques for metallic components. Inspections are performed by personnel qualifiedto perform the inspections.6. Acceptance CriteriaPeriodic Surveillance and Preventive Maintenance Program acceptance criteria aredefined in specific inspection procedures. The procedures confirm that the structure orcomponent intended function(s) are maintained by verifying the absence of agingeffects or by comparing applicable parameters to limits established by plant designbasis.Acceptance criteria include (1) for elastomer components, no significant change inmaterial properties or cracking while visually observing and flexing components, aP4(2) for metallic components, no unacceptable loss of material such that componentwall thickness remains above the required minimum, and (3) for loss of coatingintegrity (a) no peeling or delamination, (b) no cracking if accompanied bydelamination or loss of adhesion, and (c) no blisters unless completely surrounded bysound coating bonded to the surface.E-1 -8 of 51 Element Affected Enhancement3. Parameters Prior to the PEO, Perform a visual inspection of a 20 percent sampleMonitored/Inspected of the following coated piping systems or a maximum of 25 locationsfor each combination of type of coating, material the coating is4. Detection of Aging protecting, and environment combination. Visually inspect theEffects surface condition of the coated components to manage loss ofcoating integrity due to cracking, debonding, delamination, peeling,flaking, and blistering.i. Fire protection carbon dioxide (galvanized piping)ii. High pressure fire protection (cement lined piping)iii. Makeup water treatment plant (where Saran andPolypropylene applied)iv. Hypochlorite (Polypropylene, Kynar, Teflon, and concrete)v. Essential raw cooling water (where Belzona applied)3. ParametersMonitored/Inspected4. Detection of AgingEffectsPrior to the PEO, perform a visual inspection of the following coatedtanks and heat exchanaers. Visually inspect the surface condition of......... f .... iv ............................the coated components to manaae loss of coatina intearitv due tocracking, debonding., delamination, peeling, flaking, and blistering.Tanksi. Clear well (where Epoxy-Phenolic coating/Wisconsinprotective coating Plastite No. 7155 or equal applied)ii. Caustic (where TVA specs -Section 27 applied, drawing166365: contract 71 C30-92627-1)Cation (where 3/16 inch of rubber applied)iii.iv.v.vi.Potable water (where AWWA D102-62T standard forpainting Section 3.1 No. 2. 3. or4 applied)Bulk chemical (where rubber linina aPPlied)Caustic batching (where 3/16" rubber lined with chlorinatedrubber compound applied)vii. Cask decontamination (where 2 coats Red Lead in oil , Fedviii.ix.X.xi.xii.SPEC TTP-85 Type II applied)Main feed pump turbine oil (where coating applied)Gland seal water (where red oil based paint applied)Safety injection lube oil reservoir (where 0.006 inch plasticcoating applied)Pressurizer relief (where Ambercoat 55 applied)EDG 7 day storage (where Belzona applied)Heat Exchangersi. Electric boaii. Incore instrLrd room chiller package (where Belzona applied)iment room water chiller package B (whereBelzona applied)E-1- 9of51
: 6. Acceptance Criteria Include the following acceptance criteria for loss of coating integqrity:(1) peeling and delamination are not permitted, (2) cracking is notpermitted if accompanied by delamination or loss of adhesion, and (3)blisters are limited to intact blisters that are completely surrounded bysound coating bonded to the surface.3. Parameters Ensure coating inspections are performed by individuals certified toMonitored/Inspected ANSI N45.2.6, "Qualifications of Inspection, Examination, and TestingPersonnel for Nuclear Power Plants," and that subsequent evaluation4. Detection of Aging of inspection findings is conducted by a nuclear coatings subiectEffects matter expert qualified in accordance with ASTM D 7108-05,"Standard Guide for Establishing Qualifications for a NuclearCoatings Specialist."5. Monitoring and Trending Ensure an individual knowledgeable and experienced in nuclearcoatings work will prepare a coating report that includes a list oflocations identified with coating deterioration including, wherepossible, photographs indexed to inspection location, and aprioritization of the repair areas into areas that must be repairedbefore returning the system to service and areas where coating repaircan be postponed to the next inspection.4. Detection of Aging Ensure coating inspections are performed by individuals certified toEffects ANSI N45.2.6, "Qualifications of Inspection, Examination, and TestingPersonnel for Nuclear Power Plants," and that subsequent evaluationof inspection findings is conducted by a nuclear coatings subjectmatter expert qualified in accordance with ASTM D 7108-05,"Standard Guide for Establishing Qualifications for a NuclearCoatings Specialist."3. Parameters Perform subsequent inspections of coatings based on the following.Monitored/Inspectedi. If no flaking, debonding, peeling, delamination, blisters, or4. Detection of Aging rusting are observed, and any cracking and flaking has beenEffects found acceptable, subsequent inspections will be performed atleast once every six years. If the coating is inspected on onetrain and no indications are found, the same coating on theredundant train would not be inspected during that inspectioninterval.ii. If the inspection results do not meet (i), but a coating specialisthas determined that no remediation is required, thensubsequent inspections will be conducted every other refuelingoutage.iii. If coating degradation is observed that required newly installedcoatings, subsequent inspections will occur during each of thenext two refueling outage intervals to establish a performancetrend on the coating.E-1- 10of51 Changes to LRA Section A.1.38, Service Water Integrity Program follow with additionsunderlined"The Service Water Integrity Program manages loss of material and fouling forcomponents fabricated from carbon steel, carbon steel clad with stainless steel, castiron, copper alloy, nickel alloy, or stainless steel exposed to ERCW as described in theSQN response to NRC GL 89-13. The program includes (a) surveillance and controltechniques to manage effects of biofouling, corrosion, erosion, coating failures, andsilting; (b) tests to verify heat transfer capability of heat exchangers important to safety;(c) system walkdowns to ensure compliance with the licensing basis; and (d) routineinspections and maintenance.The Service Water Integrity Program will be enhanced as follows.* Revise Service Water Integrity Program procedures to perform periodic visualinspections to manage loss of coating integrity due to cracking, debonding.,delamination, peeling, flaking, and blistering in heat exchangers credited in the NRCGeneric Letter (GL) 89-13 response. Include the following coating integrityacceptance criteria: (1) peeling and delamination are not permitted, (2) cracking isnot permitted if accompanied by delamination or loss of adhesion, and (3) blistersare limited to intact blisters that are completely surrounded by sound coating bondedto the surface.* Revise Service Water Integrity Program procedures to ensure coating inspectionsare performed by individuals certified to ANSI N45.2.6, "Qualifications of Inspection,Examination, and Testing Personnel for Nuclear Power Plants," and that subsequentevaluation of inspection findings is conducted by a nuclear coatings subject matterexpert qualified in accordance with ASTM D 7108-05, "Standard Guide forEstablishing Qualifications for a Nuclear Coatings Specialist."* Revise Service Water Integrity Program procedures to ensure an individualknowledgeable and experienced in nuclear coatings work will prepare a coatingreport that includes a list of locations identified with coating deterioration including,where possible, photographs indexed to inspection location, and a prioritization ofthe repair areas into areas that must be repaired before returning the system toservice and areas where coating repair can be Postponed to the next inspection."E-1 -11 of 51 Changes to LRA Section B.1.38, Service Water Integrity Program follow with additionsunderlined and deletions marked through."EnhancementsNoeThe followinq enhancement will be implemented prior to the PEO.Element Affected Enhancement3. Parameters Monitored/Inspected Revise Service Water Integrity Program procedures tomonitor the condition of coated surfaces in the heatexchangers credited in the response to NRC GenericLetter (GL) 89-13 response.4. Detection of aging Effect Revise the Service Water Integrity ProgramProcedures to perform periodic visual inspections tomanage loss of coating integrity due to cracking,debonding, delamination, peeling, flaking, andblistering in heat exchangers credited in the NRCGeneric Letter (GL)89-13 response.6. Acceptance Criteria Revise the Service Water Integrity ProgramProcedures to include the following coating integrityacceptance criteria: (1) peeling and delamination arenot permitted, (2) cracking is not permitted ifaccompanied by delamination or loss of adhesion, and(3) blisters are limited to intact blisters that arecompletely surrounded by sound coating bonded tothe surface.5. Monitoring and Trending Revise Service Water Integrity Program procedures toensure an individual knowledgeable and experiencedin nuclear coatings work will prepare a coating reportthat includes a list of locations identified with coatingdeterioration including, where possible, photographsindexed to inspection location, and a prioritization ofthe repair areas into areas that must be repairedbefore returning the system to service and areaswhere coating repair can be postponed to the nextinspection.Commitment #38 has been added.E-1- 12of51 Changes to LRA Table 3.3.2-1 follow with additions underlined.Table 3.3.2-3: Fire Protection C02 and RCP Oil Collection SystemComponent Aging Effect AgingType Intended Requiring Management NUREG-1801 Table 1Function Material Environment Management Program Item Item NotesPiping Pressure Metal with Treated Water Loss of coating Periodic Hboundary Service Level III Cit) integrity Surveillance andor other internal Preventivecoating MaintenanceProgramChanges to LRA Table 3.3.2-1 follow with additions underlined.Table 3.3.2-1: Fuel Oil SystemAging Effect AgingComponent Intended Requiring Management NUREG-1801 Table IType Function Material Environment Management Program Item Item NotesPi Pressure Metal with Fuel oil (int.) Loss of coatinq Periodic Hboundary Service Level III inteqritV Surveillance andor other internal Preventivecoating MaintenanceI ProgramE-1- 13 of 51 Changes to LRA Table 3.3.2-1 follow with additions underlined.Table 3.3.2-2: High Pressure Fire Protection -Water SystemAging Effect AgingComponent Intended Requiring Management NUREG-1801 Table 1Type Function Material Environment Management Program Item Item NotesTank Pressure Metal with Raw Water Ont.) Loss of coating Fire Water System Hboundary Service Level III integrity Pro ramor other internal__ oatingPi Pressure Metal with Raw Water Ont.) Loss of coatin Periodic Hboundary Service Level III integrity Surveillance andor other internal Preventivecoatinq MaintenanceProgramChanges to LRA Table 3.3.2-17-6 follow with additions underlined.Table 3.3.2-17-6: High Pressure Fire Protection -Water System, Nonsafety-Related Components Affecting Safety-relatedSystemsAging Effect AgingComponent Intended Requiring Management NUREG-1801 Table IType Function Material Environment Management Program Item Item NotesPressure Metal with Raw Water (int.) Loss of coating Periodic Hboundary Service Level III integrity Surveillance andor other internal Preventivecoating MaintenanceProgram,E-1- 14 of 51 Changes to LRA Table 3.3.2-17-7 follow with additions underlined.Table 3.3.2-17-7: Water treatment System and Makeup Water Treatment Plant, Nonsafety-Related Components AffectingSafety-related SystemsAging Effect AgingComponent Intended Requiring Management NUREG-1801 Table IType Function Material Environment Management Program Item Item NotesPi Pressure Metal with Treated Water Loss of coating Periodic Hboundary Service Level III it) integrity Surveillance andor other internal Preventivecoating MaintenanceProgramTank Pressure Metal with Treated Water Loss of coating Periodic --Hboundary Service Level III it. integrity Surveillance andor other internal Preventivecoating MaintenanceProgramrChanges to LRA Table 3.3.2-17-19 follow with additions underlined.Table 3.3.2-17-19: Hypochlorite System, Nonsafety-Related Components Affecting Safety-related SystemsAging Effect AgingComponent Intended Requiring Management NUREG-1801 Table IType Function Material Environment Management Program Item Item NotesP1iFi Pressure Metal with Treaded Water Loss of coating Periodic Hboundary Service Level III it. inte-nrity Surveillance andor other internal Preventivecoating MaintenanceProqram_Tank Pressure Metal with Treaded Water Loss of coating Periodic -Hboundary Service Level III int. integrity Surveillance andor other internal Preventivecoatin MaintenanceProgram_E-1- 15of51 Changes to LRA Table 3.3.2-17-23 follow with additions underlined.Table 3.3.2-17-23: Chemical and Volume Control System, Nonsafety-Related Components Affecting Safety-relatedSystemsAging Effect AgingComponent Intended Requiring Management NUREG-1801 Table IType Function Material Environment Management Program Item Item NotesTank Pressure Metal with Treated Water Loss of coating Periodic Hboundary Service Level III it. nte lrit Surveillance andor other internal Preventivecoating MaintenanceProgramChanges to LRA Table 3.3.2-17-25 follow with additions underlined.Table 3.3.2-17-25: Essential Raw Cooling Water Systems, Nonsafety-Related Components Affecting Safety-relatedSystemsAging Effect AgingComponent Intended Requiring Management NUREG-1801 Table IType Function Material Environment Management Program Item Item NotesPPressure Metal with Raw water Ont.) Loss of coating Periodic --Hboundary Service Level III integrity Surveillance andor other internal Preventivecoatinq MaintenanceProgramE-1- 16of51 Changes to LRA Table 3.3.2-17-27 follow with additions underlined.Table 3.3.2-17-27: Waste Disposal Systems, Nonsafety-Related Components Affecting Safet -related SystemsAging Effect AgingComponent Intended Requiring Management NUREG-1801 Table IType Function Material Environment Management Program Item Item NotesTank Pressure Metal with Waste water Loss of coating Periodic _ -Hboundary Service Level III it. inte:rity Surveillance andor other internal Preventivecoating MaintenanceFProgramChanges to LRA Table 3.3.2-17-8 follow with additions underlined.Table 3.3.2-17-8: Potable (Treated Water) Water Distribution System, Nonsafety-Related Components Affecting Safety-Related SystemsAging Effect AgingComponent Intended Requiring Management NUREG-1801 Table 1Type Function Material Environment Management Program Item Item NotesTank Pressure Metal with Treated water Loss of coating Periodic Hboundary Service Level III int. integrity Surveillance andor other internal Preventivecoatin MaintenanceProgramChanges to LRA Table 3.2.2-1 follow with additions underlined.Table 3.2.2-1: Safety Injection SystemAging Effect AgingComponent Intended Requiring Management NUREG-1801 Table IType Function Material Environment Management Program Item Item NotesTank Pressure Metal with Lube oil Ont.) Loss of coating Periodic --Hboundary Service Level III intenrity Surveillance andor other internal Preventivecoating MaintenanceProgram_E-1- 17of51 Changes to LRA Table 3.3.2-17-3 follow with additions underlined.Table 3.3.2-17-3: Central Lubricating Oil System, Nonsafet -Related Components Affecting Safety-Related SystemsAging Effect AgingComponent Intended Requiring Management NUREG-1801 Table IType Function Material Environment Management Program Item Item NotesTank Pressure Metal with Lube oil (int.) Loss of coatinq Periodic --Hboundary Service Level III integrity Surveillance andor other internal Preventivecoating Maintenance_rogqramChanges to LRA Table 3.3.2-17-14 follow with additions underlined.Table 3.3.2-17-14: Gland Seal Water System, Nonsafety-Related Components Affecting Safety-Related SystemsAging Effect AgingComponent Intended Requiring Management NUREG-1801 Table IType Function Material Environment Management Program Item Item NotesTank Pressure Metal with Treated water Loss of coating Periodic --Hboundary Service Level III it.t inrt Surveillance andor other internal Preventivecoating Maintenance____ ____ __ _ ___ ___ ____ ___ ____ ____ ____ ___ ___ ____ ___Progqram_ _ _ _ _ __ _ _ _ _E-1- 18of51 Changes to LRA Table 3.1.2-5 follow with additions underlined.Table 3.1.2-5: Reactor Coolant System, Nonsafety-Related Components Affecting Safety-Related SystemsAging Effect AgingComponent Intended Requiring Management NUREG-1801 Table IType Function Material Environment Management Program Item Item NotesTank Pressure Metal with Treated borated Loss of coating Periodic Hboundary Service Level III water > 140OF integrity Surveillance andor other internal mt. Preventivecoating MaintenanceProgramChanges to LRA Table 3.3.2-6 follow with additions underlined.Table 3.3.2-6: Control Building HVAC SystemAging Effect AgingComponent Intended Requiring Management NUREG-1801 Table IType Function Material Environment Management Program Item Item NotesHeat Pressure Metal with Raw water Ont.) Loss of coating Service Water Hexchanger boundary Service Level III integrity Integrity Program(Channel or other internalHeadI__oatingChanges to LRA Table 3.3.2-5 follow with additions underlined.Table 3.3.2-5: Aux Building and Reactor Building Gas Treatment/Ventilation SystemAging Effect AgingComponent Intended Requiring Management NUREG-1801 Table IType. Function Material Environment Management Program Item Item NotesHeat Pressure Metal with Raw water (int.) Loss of coating Service Water Hexchanger boundary Service Level III integrity Integrity Programchannel head) or other internalcoatingE-1- 19of51 Set 10: RAI 3.0.3-1, Request 4Background:Recent industry operating experience (OE) and questions raised during the staff's review ofseveral license renewal applications (LRAs) has resulted in the staff concluding that severalaging management programs (AMP) and aging management review (AMR) items in the LRAmay not or do not account for this OE.These issues are related to the following, as described in detail below.'4. Managing aging effects of fire water system componentsIssue:4. Managing aging effects of fire water system componentsIndustry OE has indicated that flow blockages have occurred in dry sprinkler piping thatwould have resulted in failure of the sprinklers to deliver the required flow to combat a fire.This OE is described in NRC Information Notice (IN) 2013-06, Corrosion in Fire ProtectionPiping Due to Air and Water Interaction." The common cause is air and water interactionsleading to accelerated corrosion that occurred in normally dry fire water piping that had beensubject to inadvertent flow or flow tested, and which may not have been properly drained.As stated in IN 2013-06, had inspections been conducted to National Fire ProtectionAssociation (NFPA) 25 2011 Edition, "Standard for the Inspection, Testing, andMaintenance of Water-Based Fire Protection Systems," the obstructions may have beendetected. As such, in regard to the recommendations in GALL Report AMP X1. M27, "FireWater System," and GALL Report AMP XI.M29, the staff position is as follows:a. The tests and inspections listed in Table 4a, "Fire Water System Inspection andTesting Recommendations," of this RAI should be conducted.b. Wall thickness evaluations used as an alternative instead of flow tests or internalvisual examinations for managing flow blockage should not be credited for agingmanagement because external wall thickness measurements may not be capable ofidentifying when sufficient general corrosion has occurred such that the corrosionproducts cause flow blockage. The first enhancement associated with the "detectionof aging effects" program element of the Fire Water System Program states that,"[w]all thickness evaluations of fire protection piping using non-intrusive techniques(e.g., volumetric testing) to identify evidence of loss of material will be performedprior to the period of extended operation and periodically thereafter. Results of theinitial evaluations will be used to determine the appropriate inspection interval toensure aging effects are identified prior to loss of intended function." It is not clear tothe staff whether these volumetric examinations are in addition to periodic flow testsor internal examinations, or would replace this testing.c. If internal visual inspections detect surface irregularities because of corrosion,follow-up volumetric examinations are to be performed. These follow-up exams arenecessary to ensure that there is sufficient wall thickness in the vicinity of theirregularity.d. For portions of water-based fire protection system components that are periodicallysubjected to flow but designed to be normally dry, such as dry-pipe or preactionsprinkler system piping and valves, augmented inspections should be performed inthe portions of this piping that are not configured to completely drain. Theaugmented inspections should consist of internal visual examination or full flowtesting of the entire portion that is not configured to completely drain. Given theE-1- -20-of51 potential for accelerated corrosion in the portions of this piping that are notconfigured to completely drain, periodic wall thickness measurements should beconducted.e. The inspection requirements in NFPA 25 Chapter 9, "Water Storage Tanks," aredifferent than the recommendations in GALL Report AMP Xl.M29. For example,NFPA 25 states that external inspections are conducted quarterly and interiorinspections are conducted on a 3-year interval if the tank does not have internalcorrosion protection; otherwise, the inspections are conducted on a 5-year interval.In contrast, GALL Report AMP Xl. M29 recommends that external inspections occuron a refueling outage interval and internal inspections are conducted every 10 years.Fire water storage tanks should be inspected to the requirements of NFPA 25.Request:4. Managing aging effects of fire water system componentsa. State that inspections and testing of in-scope fire water system components will beconducted in accordance with Table 4a, or provide justification for any portions thatwill not be inspected or tested in this manner.b. State whether the enhancement to use wall thickness evaluations is in lieu ofconducting flow tests or internal visual examinations, and if it is, state the basis forwhy wall thickness measurements in the absence of flow testing or internal visualexaminations provide reasonable assurance that the intended functions of in-scopefire water system components will be maintained consistent with the CLB for thePEO.c. Add a requirement to the program to conduct follow-up volumetric examinations ifinternal visual inspections detect surface irregularities that could be indicative of wallloss below nominal pipe wall thickness, or state the basis for why visual inspectionsalone will provide reasonable assurance that the intended functions of in-scope firewater system components will be maintained consistent with the CLB for the PEO.d. For portions of water-based fire protection system components that are periodicallysubjected to flow but designed to be normally dry, such as dry-pipe or preactionsprinkler system piping and valves, but not configured to completely drain, state thefollowing:i. The inspection method to ensure that fouling is not occurring.ii. The parameters to be inspected.iii. When inspections will commence and the frequency of subsequent inspections.iv. The extent of inspections and the basis for the extent of inspections if it is not100 percent.v. Acceptance criteria.vi. How much of this piping will be periodically inspected for wall thickness and howoften the inspections will occur.e. Revise the Aboveground Metallic Tanks Program to not include the fire water storagetank and include this tank in the scope of the Fire Water System Program. Inaddition, state that the tank inspections will be in accordance with the inspectionsrequirements of NFPA 25. Alternatively, state why conducting inspections inaccordance with the Aboveground Metallic Tanks Program provides reasonableassurance that the intended functions of fire water storage tank will be maintainedconsistent with the CLB for the PEO.f. State how LRA Section 3 Table 2s and Appendices A. 1.13 and B. 1.13 will be revisedto address the above changes.E-1- -21-of51 Table 4a Fire Water System Inspection and Testing Recommendations"'2,5Description T NFPA 25 SectionSprinkler SystemsSprinkler inspections 5.2. 1.1Pipe and fitting inspections 5.2.2Hanger and seismic brace inspections 5.2.3Sprinkler testing 5.3Obstruction, internal inspection of piping 14.24 and 14.3Standpipe and Hose SystemsPiping inspections 6.2.1Flow tests 6.3.1Hydrostatic tests 6.3.2Private Fire Service MainsExposed piping 7.2.2.1Testing 7.3.1, 7.3.2, 7.3.3.1Fire PumpsSuction screens -7 8.3.3.7Water Storage TanksExterior Inspections 9.2.5.5Interior inspections 9.2.6 , 9.2.7Valves and System-Wide TestingMain drain test 13.2.5Preaction valves and deluge valves 13.4.3.2.2 -13.4.3.2.8Dry pipe valves and quick opening devices 13.4.4.2.2 -.13.4.4.2.3, 13.4.4.2.9Pressure reducing valves and relief valves 13.5.1.2, 13.5.2.2, 13.5.3.2, 13.5.4.3, 13.5.5.2Hose Valves 13.5.6.1.7Water Fixed Spray SystemsStrainers (annual and after each system actuation) 10.2.1.6, 10.2.1.7, 10.2.7Water supply 10.2.6.2System components (annual and after each 10.2.4system actuation)Operation Test (annual) 10.3.4, 10.3.5, 10.4.1Foam Water Sprinkler SystemsSystem piping and fittings 11.2.3. (1), (2)Water supply 11.2.6.2E-1- -22-of51 Strainers (quarterly) 11.2.7.1Storage tanks (external -quarterly) 11.2. 9. 5.1.2 (2)Operational Test Discharge Patterns (annually) 11.3.2.6, 11.3.2.7, 11.3.3Storage tanks (internal-lO years) 11.4.3, 11.4.4.2, 11.4.5, 11.4.6.4, 11.4.7.41. All terms and references are to NFPA 25 2011 Edition. The staff is referring to NFPA 25 2011Edition as a common reference for the description of the scope and periodicity of specificinspections and tests. It should not be inferred that the CLB needs to be revised to include all theinspection, testing and maintenance requirements of this document. The above inspections andtests are related to the management of applicable aging effects for passive long-lived in-scopecomponents in the fire water system. Inspections and tests not related to the above are to beconducted in accordance with the current licensing basis. If the current licensing basis states morefrequent inspections than required by NFPA 25, the current licensing basis should be met.2. A reference to a section includes all sub-bullets unless otherwise noted (e.g., a reference to 5.2.1.1includes 5.2.1.1.1 through 5.2.1.1.7).3. The alternative nondestructive examination methods permitted by 14.2.1. 1 are limited to those thatcan ensure that flow blockage will not occur.4. In regard to Section 9.2.6.4, the threshold for taking action required in Section 9.2.7 is as follows:pitting and general corrosion beyond nominal wall depth and any coating failure where bare metal isexposed. Blisters should be repaired. Adhesion testing should be performed in the vicinity ofblisters even though bare metal may not have been exposed.5. Items in areas that are inaccessible for safety considerations due to factors such as continuousprocess operations and energized electrical equipment shall be inspected during each scheduledshutdown but not more than every refueling outage interval.E-1- -23-of51 TVA Response to RAI 3.0.3-1. Request 4. Managing Aging Effects of Fire Water Systema. Table 4a was originally provided to TVA in the Set 10, August 2, 2013 RAI, and laterrevised via an e-mail from NRC Project Manager on 9/26/2013, ADAMS No.ML1 3270A037. With the incorporation of the enhancements listed in Response f. below,the inspections and testing of in-scope fire water system components will be conductedin accordance with relevant guidance of the NFPA 25 (2011 edition) sections listed inTable 4a with exceptions described below.Modified Table 4a Fire Water System Inspection and Testing Recommendationsl12,5Description I NFPA 25 SectionSprinkler SystemsSprinkler inspectionsa 1 5.2.1.1Sprinkler testing 1 5.3.1Standpipe and Hose SystemsFlow tests 16.3.1Private Fire Service MainsUnderground and exposed piping flow 7.3.1tests IHydrants 17.3.2Fire PumpsSuction screens 18.3.3.7Water Storaae TanksExterior inspections 19.2.5.5Interior inspections 19.2.64 ,9.2.7Valves and System-Wide TestinqMain drain test 1 13.2.5Deluge valves0 113.4.3.2.2 through 13.4.3.2.5Water spray Fixed SystemsStrainers (refueling outage interval and 10.2.1.6, 10.2.1.7. 10.2.7after each system actuation) .Operation test (refueling outage interval) 10.3.4.3Foam Water Sprinkler SystemsStrainers (refueling outage interval and 11.2.7.1after each system actuation) IOperational Test Dischar-ge Patterns I 11.3.2.6J ...Storagqe tanks (internal -10 years) J Visual inspection for internal corrosionObstruction InvestigationObstruction, internal inspection of 'iin 14.2 and 14.3E-1- -24-of51
: 1. All terms and references are to the 2011 Edition of NFPA 25. The NRC staff cites the 2011Edition of NFPA 25 for the description of the scope and periodicity of specific inspectionsand tests. This table specifies those inspections and tests that are related to age-managing applicable aging effects associated with loss of material and flow blockage forpassive long-lived in-scope components in the fire water system. Inspections and tests notrelated to the above should continue to be conducted in accordance with the plant's currentlicensing basis. If the current licensing basis specifies more frequent inspections thanrequired by NFPA 25 or this table, the plant's current licensing basis should be continue tobe met.2. A reference to a section includes all sub-bullets unless otherwise noted (e.g., a referenceto 5.2.1.1 includes 5.2.1.1.1 through 5.2.1.1.7).3. The alternative nondestructive examination methods permitted by 14.2.1.1 and 14.3.2.3are limited to those that can ensure that flow blockage will not occur.4. In regard to Section 9.2.6.4. the threshold for taking action required in Section 9.2.7 is asfollows: pitting and general corrosion to below nominal wall depth and any coating failure inwhich bare metal is exposed. Blisters should be repaired. Adhesion testing should beperformed in the vicinity of blisters even though bare metal might not have been exposed.Regardless of conditions observed on the internal surfaces of the tank, bottom-thicknessmeasurements should be taken on each tank during the first 10-year period of the PEO.5. Items in areas that are inaccessible because of safety considerations such as those raisedby continuous process operations, radiological dose, or ener-gized electrical equipmentshall be inspected during each scheduled shutdown but not more often than every refuelingoutage interval.6. Where the nature of the protected property is such that foam cannot be discharged, thenozzles or open sprinklers shall be inspected for correct orientation and the system testedwith air to ensure that the nozzles are not obstructed.Exceptions to the Modified Table 4a* Inspections specified in Sections 5.2.1.1, 5.2.2 and 5.2.3 are performed on an18-month basis versus an annual basis. The frequency of once every 18 months isappropriate based on the lack of past inspection findings and the need to performsome inspections during a refueling outage.* Sections 14.2.1 and 14.2.2: Section 14.2.1 specifies an inspection of piping andbranch line conditions every five years unless there are multiple wet pipe systems ina building. For multiple wet pipe systems in a building, Section 14.2.2 allows aninspection on every other wet pipe system every five years. The inspection consistsof opening a flushing connection at the end of one main and removing a sprinklertoward the end of one branch line for the purpose of inspecting for the presence offoreign material. SQN is taking the following exception to Sections 14.2.1 and14.2.2. SQN performs internal inspection of the high pressure fire water (HPFP)system strainers every 36 months. If foreign material is identified, the condition isentered into the CAP. In the last 10 years, only one incident of organic material(clam shells) was identified in the strainer. It was determined that the clam shellsentered the system before the HPFP system was switched from raw water to potablewater in 1998. SQN will perform a one-time visual inspection using the methodologydescribed in NFPA-25 Section 14.2.1 prior to the PEO to verify there are no foreignmaterials in the dry portions of the fire water system (i.e., those portions downstreamE-1- -25-of51 of deluge and preaction valves). Any additional inspections of the dry portion of thefire water system in accordance with NFPA-25, Sections 14.2.1 or 14.2.2 will bebased on the one-time inspection results. See the enhancement in Response f.below and Commitment #9.G.* Section 6.3.1 addresses conducting a flow test. SQN is taking an exception toconducting a flow test and a main drain test of each zone of the automatic standpipesystem. Every three years, the station tests the highest elevation areas in theERCW building to ensure sufficient pressure and flow at lower elevations. For thefire water hoses credited in the NRC-approved Fire Protection Report, the stationensures that the required minimum flow is established every three years. For otherfire water hose stations, open flow paths through each hose station is verified everyfive years. Additional flow testing of the automatic standpipe system is a risk-significant activity due to the potential for water contacting critical equipment in thearea. In addition, flowing water in the radiological areas may result in additionalradwaste. Any flow blockage or abnormal discharge identified during flow testing isidentified and entered into the CAP.Not performing flow testing in the radiological controlled area and areas that containcritical equipment required for normal and shutdown operations eliminates a risk-significant activity and the potential to create additional radwaste. Because thesystem is continuously pressurized with potable water, an open flow path is assuredwithout the need to perform additional flow testing.Section 7.3.1 addresses flow testing of underground and exposed piping. SQN istaking an exception to flow testing additional underground and exposed piping withinbuildings for the same reason stated in the exception to Section 6.3.1 above. Thestation performs testing to determine friction loss characteristics on most of theexterior fire water system piping. The tests assess the pressure loss of the variouspipe segments. The tests are performed every three years and the results aretrended. Based on ten years' of test results for underground piping and the use ofpotable water, there is reasonable assurance of an open flow path withoutperforming additional flow testing. In addition, hydrants are tested annually.Based on the current testing and trending, the addition of a risk-significant activity,and the production of additional radwaste in radiological controlled areas is notwarranted.Section 13.4.3.2.2 specifies full flow testing of deluge valves. SQN is taking anexception to performing deluge valve testing annually at full flow in indoor areascontaining equipment critical to the operation of the plant. Opening a deluge valveand allowing flow out of the open sprinkler heads in areas with critical equipment isconsidered a risk-significant activity. In addition, flow testing in the RCA would resultin additional radwaste.E-1- -26-of51 Based on the testing and trending, the additional deluge valve testing is notwarranted due to the addition of a risk-significant activity, the production of additionalradwaste in radiological controlled areas.b. The enhancement described in LRA Sections A.1.13 and B.1.13 allows the use of non-intrusive techniques (e.g., volumetric testing) in lieu of conducting flow testing or internalinspections to detect flow blockage. According to the NFPA-25 (2011) handbook, theuse of x-ray, ultra sound, and remote video techniques can be used in lieu of impairingthe system to conduct visual inspections. The use of these techniques providesreasonable assurance that the effects of aging will be managed such that the fire watersystem components will continue to perform their intended functions consistent with thecurrent licensing basis through the PEO.c. An enhancement to conduct follow-up volumetric examinations if internal visualinspections detect surface irregularities that could indicate wall thickness below nominalpipe wall thickness has been added to LRA Sections A.1.13 and B.1.13 as discussed inthe enhancement listed in Response f. below.d. The portions of the fire water system that are periodically subject to flow, but designed tobe normally dry, such as dry-pipe or preaction sprinkler system piping and valves, will beinspected prior to the PEO. See Commitment #9.G. For those piping sections wheredrainage is not occurring as expected, the following actions will be performed.i. A representative sample of components such as sprinkler heads or couplings willbe removed prior to the PEO and a visual internal inspection or non-intrusivetesting will be performed to verify there are no signs of abnormal corrosion (wallthickness loss) or blockage. Any signs of abnormal corrosion or blockage will beentered into the CAP.ii. The monitored parameter is the condition of the internal surface.iii. The inspections will be performed prior to the PEO. The frequency of subsequentinspections will be based on the results of the initial inspections.iv. A representative sample is defined as 20 percent of each population with the samematerial, environment, and aging effect combination with a maximum of 25inspections. The percentage inspected is the percent of total length of dry pipingthat may be periodically wetted or the percentage of the total number of discretelocations. This is consistent with representative samples for other agingmanagement programs.v. The acceptance criteria will be "no debris" (i.e., no corrosion products that couldimpede flow or cause downstream components to become clogged) and nosurface irregularities that could indicate wall loss to below nominal pipe wallthickness.vi. Wall thickness measurements will be performed if internal visual inspections detectsurface irregularities that could indicate wall loss to below nominal pipe wallthickness. See the enhancement in Response f. below.E-1- -27-of51
: e. The fire water tanks have been removed from the Above Ground Metallic Tanks Programand included in the Fire Water Systems Program. The fire water storage tanks will beinspected in accordance with NFPA-25 (2011 Ed.) requirements. See Commitment #9.J.f. The change to LRA Section A.1.1 follows with additions underlined."The Aboveground Metallic Tanks Program manages loss of material and cracking for theouter surfaces of the aboveground metallic tanks (excluding the fire water storage tanks)using periodic visual inspections on tanks within the scope of license renewal asdelineated in 10 CFR 54.4. For in-scope painted tanks, the program monitors the surfacecondition for blistering, flaking, cracking, peeling, discoloration, underlying rust, andphysical damage. For in-scope stainless steel tanks, the program will monitor surfacecondition to assure a clean, shiny surface with no visible leaks. The visible exteriorportions of the tanks will be inspected at least once every refueling cycle.This program also manages the bottom surfaces of aboveground metallic tanks, whichare constructed on a ring of concrete and oil-filled sand. The program requires ultrasonictesting (UT) of the tank bottoms to assess the thickness against the thickness specified inthe design specification. The UT testing of the tank bottoms will be performed at leastonce within the five years prior to the PEO and whenever the tanks are drained during thePEO.This program will be implemented prior to the PEO."The change to LRA Section B.1.1 follows with additions underlined."The Aboveground Metallic Tanks Program is a new program that will manage loss ofmaterial and cracking for the outer surfaces of the aboveground metallic tanks (excludinqthe fire water storage tanks) using periodic visual inspections on tanks within the scope ofthe program as delineated in 10 CFR 54.4. Preventive measures were applied duringconstruction, such as using the appropriate materials, protective coatings, and elevationas specified in design and installation specifications. For in-scope painted tanks, theprogram monitors the surface condition for blistering, flaking, cracking, peeling,discoloration, underlying-rust, and physical damage. For in-scope stainless steel tanks,the program will monitor surface condition to assure a clean, shiny surface with no visibleleaks. The visible exterior portions of the tanks will be inspected at least once everyrefueling cycle.This program will also manage the bottom surface of aboveground metallic tanks, whichare constructed on a ring of concrete and oil-filled sand. The program will requireultrasonic testing (UT) of the tank bottoms to assess the thickness against the thicknessspecified in the design specification. The UT testing of the tank bottoms will beperformed at least once within the five years prior to the period of extended operation andwhenever the tanks are drained during the period of extended operation.In accordance with installation and design specifications, the tanks do not employcaulking or sealant at the concrete/tank interface.This program will be implemented prior to the period of extended operation."E-1- -28-of51 The changes to LRA Section A.1.13 follow with additions underlined and deletions linedthrough."The Fire Water System Program manages loss of material and fouling forcomponents in fire protection systems (including the fire water storage tanks). Theprogram includes periodic flushing and system performance testing in accordance withthe applicable National Fire Protection Association (NFPA) commitments as describedin the Fire Protection Report. System pressure is monitored such that loss of pressureis immediately detected and corrective action initiated. Portions of the systemexposed to water are internally visually inspected. Sprinkler heads that have been inplace for 50 years are tested in accordance with NFPA 25 Section 5.3.1 if notreplaced."Revise Fire Water System Program procedures to ensure a representetPvesample-ef-sprinkler heads will-be are tested or ,epled before the end of the 50year heAd soernic life wnd. vals thoreattor teexten..ded perFid of ope-ration. in accordance with NFPA-25 (2011 Edition),Section 5.3.1. defines a representative sample of sprinklers to consist ofaminmu ...Of not leAs than fu'r sprinklers or one perent of the number o.sprinklers per individual sprinkler sample, Whichever is gr.eater. If the option torepiaco tne SpFRknios s chosen, all sprinkler: head-s that have- beenA in serVice brF50 years will be replaced.* Revise Fire Water System Program procedures to indelude-periodically remove arepresentative sample of components such as sprinkler heads or couplings priorto the PEO and perform a visual internal inspection of dry fire water systempiping in4emale for evidence of corrosion, and-loss of wall thickness, and foreignmaterial that may result in flow blockage using the methodology described inNFPA-25 Section 14.2.1. This includes those sections of dry piping described inNRC Information Notice (IN) 2013-06, where drainage is not occurring. Theacceptance criteria shall be "no debris" (i.e., no corrosion products that couldimpede flow or cause downstream components to become clogged). Anyadditional inspections in accordance with NFPA-25, Sections 14.2.1 or 14.2.2 willbe based on the initial inspection results.* Revise Fire Water System Program procedures to perform an obstructionevaluation in accordance with NFPA-25 (2011 Edition), Section 14.3.1." Revise Fire Water System Program procedures to conduct follow-up volumetricexaminations if internal visual inspections detect surface irregularities that couldbe indicative of wall loss below nominal pipe wall thickness.* Revise Fire Water System Program procedures to annually inspect the fire waterstorage tank exterior painted surface for signs of degradation. If degradation isidentified, conduct follow-up volumetric examinations to ensure wall thickness isegual to or exceeds nominal wall thickness.E-1- -29-of51 Revise Fire Water System Program procedures to include a fire water storagetank interior inspection every five years that includes inspections for signs ofpitting, spalling., rot, waste material and debris, and aquatic growth. Include inthe revision direction to perform fire water storage tank interior coating testing, ifany degradation is identified, in accordance with ASTM D 3359 or equivalent, adry film thickness test at random locations to determine overall coating thickness:and a wet sponge test to detect pinholes, cracks or other compromises of thecoating. If there is evidence of pitting or corrosion ensure the Fire Water SystemProgram procedures direct performance of an examination to determine wall andbottom thickness.Revise Fire Water System Program procedures based on the results of afeasibility study to perform the main drain tests in accordance with NFPA-25(2011 Edition) Section 13.2.5.Revise Fire Water System Program procedures to perform spray head dischargepattern tests from all open spray nozzles to ensure that patterns are not impededby plugged nozzles, to ensure that nozzles are correctly positioned, and toensure that obstructions do not prevent discharge patterns from wetting surfacesto be protected. Where the nature of the protected property is such that watercannot be dischar-ged, the nozzles shall be inspected for proper orientation andthe system tested with smoke or some other medium to ensure that the nozzlesare not obstructed.E-1- -30-of51 The changes to LRA Section B.1.13 follow with additions underlined and deletions linedthrough."The Fire Water System Program manages loss of material and fouling for fireprotection components (including the fire water storage tanks) that are tested inaccordance with the Fire Protection Report.Consistent with NFPA 25, the SQN program includes system performance testing inaccordance with the Fire Protection Report. This periodic full-flow testing includesmonitoring the pressure of tested pipe segments, which verifies that system pressureremains adequate for system intended functions. Results are trended. Periodicflushing is also performed in accordance with the Fire Protection Report.Wall thickness measurements are evaluated to ensure minimum wall thickness ismaintained. Wall thickness may be determined by non-intrusive measurement, suchas volumetric testing, or as an alternative to non-intrusive testing, by visuallymonitoring internal surface conditions upon each entry into the system for routine orcorrective maintenance. The use of internal visual inspections is acceptable wheninspections can be performed (based on past maintenance history) on a representativenumber of locations. These inspections will be performed before the period ofextended operation and at plant-specific intervals based on the initial test resultsduring the period of extended operation. Periodic visual inspections of fire watersystem internals will monitor surface condition for indications of loss of material.In addition, the water system pressure is continuously monitored such that loss ofpressure is immediately detected and corrective action initiated. If not replaced,sprinkler heads are tested before the end of 50-year sprinkler service life and every tenyears thereafter during the period of extended operation. General requirements of theprogram include testing and maintaining fire detectors and visually inspecting the firehydrants to detect signs of corrosion. Fire hydrant flow tests are performed annually toensure the fire hydrants can perform their intended function.Program acceptance criteria are (a) the water based fire protection system canmaintain required pressure, (b) no signs of unacceptable degradation are observedduring non-intrusive or visual inspections, (c) minimum design pipe and tank wallthickness is maintained, and (d) no biofouling exists in the sprinkler systems that couldcause corrosion in the sprinklers."E-1- -31-of51 Elements Affected EnhancementsElements AffectedEnhancements4. Detection of Aqing EffectRevise Fire Water System Program procedures toensure a re.presentative sample of sprinkler heads wil,be are tested or replaced before the end of the 50 yearsprinkler hedadn sewich ifeAn- -at ten year inteSealsthere-after during the o~dended period of operatieon. inaccordance with NFPA-25 (2011 Edition), Section53V I dlfi~ aI FeII IIII II I I iv I sample i e1 i pikl~ toI IIIVcns o mInimum not Ile es than.. folurl orone percent Of the num'Fber Of Sprinklres per individualsprinkler sample, WhicheVer is greater. If the option toreplace the sprinklers is chosen, all spFrikler heads thathave been in ceryice forF 50 years will be replaced-.4. Detection of Agin.q Effect Revise Fire Water Program procedures to perform anobstruction evaluation in accordance with NFPA-25(2011 Edition), Section 14.3.1.4. Detection of Aging Effect Revise Fire Water System Program procedures toperiodically remove a representative sample ofcomponents such as sprinkler heads or couplings priorto the PEO and perform a visual internal inspection ofdry fire water system piping itemals for evidence ofcorrosion, af,-loss of wall thickness, and foreignmaterial using the methodology described in NFPA-25Section 14.2.1. This includes those sections of drypiping described in NRC Information Notice (IN) 2013-06, where drainage is not occurring due to design. Theacceptance criteria shall be "no debris" (i.e., nocorrosion products that could impede flow or causedownstream components to become clogged). Anyadditional inspections in accordance with NFPA-25,Sections 14.2.1 or 14.2.2 will be based on the initialinspection results.4. Detection of Aging Effect Revise Fire Water System Program procedures toconduct follow-up volumetric examinations if internalvisual inspections detect surface irregularities that couldbe indicative of wall loss below nominal pipe wallthickness.E-1- -32-of51
: 4. Detection of Aging Effect Revise Fire Water System Pro-gram procedures toannually inspect the fire water storage tank exteriorpainted surface for signs of degradation. If degradationis identified, conduct follow-up volumetric examinationsto ensure wall thickness is equal to or exceeds nominalwall thickness.4. Detection of Aging Effect Revise Fire Water System Program procedures toinclude a fire water storage tank interior inspectionevery five years that includes inspections for signs ofpitting, spalling, rot, waste material and debris, andaquatic growth. Include in the revision direction toperform fire water storage tank interior coating testing, ifany degradation is identified, in accordance with ASTMD 3359 or equivalent, a dry film thickness test atrandom locations to determine overall coatingthickness: and a wet sponge test to detect pinholes,cracks or other compromises of the coating.4. Detection of Aging Effect Revise Fire Water System Program procedures toperform a non-destructive examination to determinewall thickness whenever degradation is identified duringinternal tank inspections.4. Detection of Aging Effect Revise Fire Water System Program procedures basedon the results of a feasibility study to perform the maindrain tests in accordance with NFPA-25 (2011 Edition)Section 13.2.5.4. Detection of Agingq Effect Revise Fire Water System Program procedures toperform spray head dischar-ge pattern tests from allopen spray nozzles to ensure that patterns are notimpeded by plugged nozzles, to ensure that nozzles arecorrectly positioned, and to ensure that obstructions donot prevent discharge patterns from wetting surfaces tobe protected. Where the nature of the protectedproperty is such that water cannot be discharged, thenozzles shall be inspected for proper orientation and thesystem tested with smoke or some other medium toensure that the nozzles are not obstructed.E-1- -33-of51 The changes to affected LRA Table 3.3.2-2: High Pressure Fire Protection -Water System,line items and the corresponding Table 3.3.1 and 3.3.4 line items follow with additionsunderlined and deletions marked through.Component Intended Aging Effect Aging NUREG- Table 1Type Function Material Environment Requiring Management 1801 Item NotesTyeuntinManagement Program ItemTank Pressure Carbon Air-outdoor Loss of Abovegrond VII.HI.A- 3.3.1- Qboundary steel (ext.) material MetagiG 95 67 ETa, krs FireWaterSystemTank Pressure Carbon Concrete Loss of Abegroeund VIII.E.SP- 3.4.1.30 Gboundary steel (ext.) material MetalliG 115 ETaRks FireWaterSystemTank Pressure Carbon Soil (ext.) Loss of Abeg-eund VIII.E.SP- 3.4.1- Qboundary steel material Metallif 115 30 ETanks FireWaterSystemE-1- 34 of 51 3.3.1-67 Steel tanks exposed Loss of material Chapter XI.M29, No ConcGitent ''ith ,hUREG 1801. Loss of material for steel tanks,to air -outdoor due to general, "Aboveground except fire water storage tanks, exposed to outdoor air is managed by(external) pitting, and Metallic Tanks" the Aboveground Metallic Tanks Program. The Fire Water Systemcrevice Pro-gram manages loss of material for fire water storage tanks.corrosion3.4.1-30 Steel, stainless steel, Loss of material Chapter XI.M29, No Consistent with NUREG-1 801 for most components. Loss of materialaluminum tanks due to general, "Aboveground for steel tanks exposed to concrete or soil is managed by theexposed to soil or pitting, and Metallic Tanks" Aboveground Metallic Tanks Program. The Fire Water Systemconcrete, air -crevice Pro-gram manages loss of material for fire water storage tanksoutdoor (external) corrosion exposed to concrete or soil. Loss of material for stainless steel tanksexposed to outdoor air (applies to components in Table 3.2.2-1 only)is managed by the Aboveground Metallic Tanks Program. There areno aluminum or stainless steel tanks exposed to outdoor air in thesteam and power conversion systems in the scope of license renewal.Commitments #9.C, G -M have been changed.E-1 -35 of 51.
Set 10: RAI 3.0.3-1, Request 6Background:Recent industry operating experience (OE) and questions raised during the staff's review ofseveral license renewal applications (LRAs) has resulted in the staff concluding that severalaging management programs (AMP) and aging management review (AMR) items in the LRAmay not or do not account for this OE.These issues are related to the following, as described in detail below:6. Corrosion under insulationIssue:6. Corrosion under insulationDuring a recent license renewal AMP audit, the staff observed extensive general corrosion(i.e., extent of corrosion from a surface area but not depth of penetration perspective)underneath the insulation removed from an auxiliary feedwater (AFW) suction line. Theprocess fluid temperature was below the dew point for sufficient duration to accumulatecondensation on the external pipe surface. NACE, International (NACE), formerly known asNational Association of Corrosion Engineers, Standard SP0198-2010, "Control of Corrosionunder Thermal Insulation and Fireproofing Materials -A Systems Approach," categorizesthis as corrosion under insulation (CUI). In addition, during AMP audits the staff hasidentified gaps in the proposed aging management methods for insulated outdoor tanks andpiping surfaces. To date, these gaps have been associated with insufficient proposedexamination of the surfaces under insulation.The staff recommends periodic representative inspections of in-scope insulated componentswhere the process fluid temperature is below the dew point or where the component islocated outdoors. The timing, frequency, and extent of inspections should be as follows:a. Periodic inspections should be conducted during each 1 0-year period beginning5 years before the PEO.b. For a representative sample of outdoor components, except tanks, and any indoorcomponents operated below the dew point, remove the insulation and inspect aminimum of 20 percent of the in-scope piping length for each material type (i. e.,steel, stainless steel, copper alloy, aluminum), or for components where itsconfiguration does not conform to a 1-foot axial length determination (e.g., valve,accumulator), 20 percent of the surface area. Alternatively, remove the insulationand inspect any combination of a minimum of 25 1-foot axial length sections andcomponents for each material type. Inspections are conducted in each airenvironment (e.g., air-outdoor, moist air) where condensation or moisture on thesurfaces of the component could occur routinely or seasonally. In some instances,although indoor air is conditioned, significant moisture can accumulate underinsulation during high humidity seasons.c. For a representative sample of outdoor tanks and indoor tanks operated below thedew point, remove the insulation from either 25 1-square-foot sections or 20 percentof the surface area and inspect the exterior surface of the tank. Distribute thesample inspection points such that inspections occur on the tank dome, sides, nearthe bottom, at points where structural supports or instrument nozzles penetrate theinsulation, and where water collects such as on top of stiffening rings.E-1- 36 of 51
: d. Inspection locations should be based on the likelihood of CUI occurring (e.g.,alternate wetting and drying in environments where trace contaminants could bepresent, length of time the system operates below the dewpoint).e. Removal of tightly adhering insulation that is impermeable to moisture is not requiredunless there is evidence of damage to the moisture barrier. Given that the likelihoodof CUI is low for tightly adhering insulation, a minimal number of inspections of theexternal moisture barrier of this type of insulation, although not zero, should becredited toward the sample population.f. Subsequent inspections may consist of examination of the exterior surface of theinsulation for indications of damage to the jacketing or protective outer layer of theinsulation when the following conditions are verified in the initial inspection:i. No loss of material due to general, pitting or crevice corrosion, beyond thatwhich could have been present during initial construction.ii. No evidence of SCC.iii. No evidence of fatigue cracks.If the external visual inspections of the insulation reveal damage to the exterior surfaceof the insulation or there is evidence of water intrusion through the insulation (e.g., waterseepage through insulation seams/joints), periodic inspections under the insulationshould continue as described above.Request:6. Corrosion under insulationa. State how LRA Section 3 Table 2s and the appropriate AMPs and correspondingUpdated Final Safety Analysis Report (UFSAR) supplements will be revised toaddress the recommendations discussed above related to CUI for outdoor insulatedcomponents and indoor insulated components operated below the dew point.Alternatively, state and justify portions that will not be consistent with therecommendations related to CUI, aboveTVA Response to RAI 3.0.3-1 Request 6 -Corrosion under insulationThe response to Request 6.a. is provided by responding to Issues 6.a. through 6.f. andproviding a change to the LRA.During the PEO, there will be periodic representative inspections of the in-scope mechanicalcomponent surfaces under insulation and the insulation exterior surface. Insulated indoorcomponents (with process fluid temperature below the dew point) and outdoor components willbe inspected. SQN has procedural control over jacketing and insulation. The followingdiscusses the periodic representative inspections.a. SQN representative inspections are conducted during each 10-year period beginning5 years before the PEO.bl. For a representative sample of outdoor components, except tanks, and indoorcomponents, except tanks, identified with more than nominal degradation on theexterior of the component, insulation is removed for visual inspection of thecomponent surface. Inspections include a minimum of 20 percent of the in-scopepiping length for each material type (i.e., steel, stainless steel, copper alloy,aluminum). For components with a configuration which does not conform to a 1-footaxial length determination (e.g., valve, accumulator), 20 percent of the surface areais inspected. Inspected components are 20% of the population of each material typewith a maximum of 25. Alternatively, insulation is removed and a minimum of 25E-1- 37 of 51 inspections are performed that can be a combination of 1-foot axial length sectionsand individual components for each material type (e.g., steel, stainless steel, copperalloy, aluminum).b2. For a representative sample of indoor components, except tanks, operated below thedew point, which have not been identified with more than nominal degradation on theexterior of the component, the insulation exterior surface or jacketing is inspected.These visual inspections verify that the jacketing and insulation is in good condition.The number of representative jacketing inspections will be at least 50 during each10-year period.If the inspection determines there are gaps in the insulation or damage to thejacketing that would allow moisture to get behind the insulation, then removal of theinsulation is required to inspect the component surface for degradation.c. For a representative sample of indoor insulated tanks operated below the dew pointand all insulated outdoor tanks, insulation is removed from either 25 1-square-footsections or 20 percent of the surface area for inspections of the exterior surface ofeach tank. The sample inspection points are distributed so that inspections occur onthe tank dome, sides, near the bottom, at points where structural supports orinstrument nozzles penetrate the insulation, and where water collects (for exampleon top of stiffening rings).d. Inspection locations are based on the likelihood of corrosion under insulation (CUI).For example, CUI is more likely for components experiencing alternate wetting anddrying in environments where trace contaminants could be present and forcomponents that operate for long periods of time below the dew point.e. If tightly adhering insulation is installed, this insulation should be impermeable tomoisture and there should be no evidence of damage to the moisture barrier. Giventhat the likelihood of CUI is low for tightly adhering insulation, a small number ofinspections of the external moisture barrier of this type of insulation, although notzero, will be performed and credited toward the sample population.f. Subsequent inspections will consist of an examination of the exterior surface of theinsulation for indications of damage to the jacketing or protective outer layer of theinsulation, if the following conditions are verified in the initial inspection.* No loss of material due to general, pitting or crevice corrosion, beyond thatwhich could have been present during initial construction* No evidence of cracking" No evidence of crackingNominal degradation is defined as no loss of material due to general, pitting orcrevice corrosion, beyond that which could have been present during initialconstruction, and no evidence of cracking. If the external visual inspections of theinsulation reveal damage to the exterior surface of the insulation or there is evidenceof water intrusion through the insulation (e.g., water seepage through insulationseams/joints), periodic inspections under the insulation will continue as describedabove.Changes to LRA Section A.1.10, External Surfaces Monitoring Program follow with additionsunderlined and deletions lined through.E-1 -38 of 51 "The External Surfaces Monitoring Program manages aging effects of components fabricatedfrom metallic and polymeric materials through periodic visual inspection of external surfacesduring system inspections and walkdowns for evidence of leakage, loss of material (includingloss of material due to wear), cracking, and change in material properties. When appropriatefor the component and material, physical manipulation is used to augment visual inspectionsto confirm the absence of elastomer hardening and loss of strength. Inspections will beperformed by personal qualified through plant-specific programs, and deficiencies aredocumented and evaluated under the CAP. Surfaces that are not readily visible during plantoperations and refueling outages are inspected when they are made accessible and at suchintervals that would ensure the components' intended functions are maintained.For a representative sample of outdoor insulated components and indoor insulatedcomponents operated below the dew point, which have been identified with more thannominal degradation on the exterior of the component, insulation is removed for inspection ofthe component surface. For a representative sample of indoor insulated components operatedbelow the dew point, which have not been identified with more than nominal degradation onthe exterior of the component, the insulation exterior surface is inspected. These inspectionswill be conducted during each 10-year period beginninq 5 years before the PEO.The External Surfaces Monitoring Program will be enhanced as follows.Revise External Surfaces Monitoring Program procedures to clarify that periodicinspections of systems in scope and subject to aging management review for licenserenewal in accordance with 10 CFR 54.4(a)(1) and (a)(3) will be performed. Inspectionsshall include areas surrounding the subject systems to identify hazards to thosesystems. Inspections of nearby systems that could impact the subject systems willinclude SSCs that are in scope and subject to aging management review for licenserenewal in accordance with 10 CFR 54.4(a)(2).* Revise External Surfaces Monitoring Program procedures to include instructions to lookfor the following related to metallic components:, 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 of stainless steelcomponents exposed to an air environment containing halides.Revise External Surfaces Monitoring Program procedures to include instructions formonitoring aging effects for flexible polymeric components through physicalmanipulations of the material, with a sample size for manipulation of at least ten percentof the available surface area. The inspection parameters for polymers shall include thefollowing:, Surface cracking, crazing, scuffing, dimensional changes (e.g., ballooning andnecking)., Discoloration., Exposure of internal reinforcement for reinforced elastomers (loss of material).E-1- 39 of 51 Hardening as evidenced by loss of suppleness during manipulation where thecomponent and material can be manipulated.R 1E, W -er-al s Mo.. Program procedures to ens.ure surfaces that areinute ,l ill ., be inspected thAe- etrnal sur.Gface i 8eXPosed (i.e., duingm.ain.t9eRanc) at such that w-ould en.ure that the components' intendd functioni aie Revise External Surfaces Monitoring Program procedures to specify thefollowing for insulated components., Periodic representative inspections are conducted during each 10-year periodbeginning 5 years before the PEO.For a representative sample of outdoor components, except tanks, and indoorcomponents, except tanks, identified with more than nominal degradation on theexterior of the component, insulation is removed for visual inspection of thecomponent surface. Inspections include a minimum of 20 percent of the in-scopepiping length for each material type (e.g., steel, stainless steel, copper alloy,aluminum). For components with a configuration which does not conform to a 1-footaxial length determination (e.g., valve, accumulator), 20 percent of the surface areais inspected. Inspected components are 20% of the population of each material typewith a maximum of 25. Alternatively, insulation is removed and componentinspections performed for any combination of a minimum of 25 1-foot axial lengthsections and individual components for each material type (e.g., steel, stainlesssteel, copper alloy, aluminum.)For a representative sample of indoor components, except tanks, operated below thedew point, which have not been identified with more than nominal degradation on theexterior of the component, the insulation exterior surface or iacketing is inspected.These visual inspections verify that the iacketing and insulation is in good condition.The number of representative iacketing inspections will be at least 50 during each10-year period.If the inspection determines there are gaps in the insulation or damage to theiacketing that would allow moisture to get behind the insulation, then removal of theinsulation is required to inspect the component surface for degradation.For a representative sample of indoor insulated tanks operated below the dew pointand all insulated outdoor tanks, insulation is removed from either 25 1 -square footsections or 20 percent of the surface area for inspections of the exterior surface ofeach tank. The sample inspection points are distributed so that inspections occur onthe tank dome, sides, near the bottom, at points where structural supports orinstrument nozzles penetrate the insulation, and where water collects (for exampleon top of stiffening rings).Inspection locations are based on the likelihood of corrosion under insulation (CUI).For example, CUI is more likely for components experiencing alternate wetting anddrying in environments where trace contaminants could be present and forcomponents that operate for long periods of time below the dew point.If tightly adhering insulation is installed, this insulation should be impermeable tomoisture and there should be no evidence of damage to the moisture barrier. Giventhat the likelihood of CUI is low for tightly adhering insulation, a minimal number ofinspections of the external moisture barrier of this type of insulation, although notzero, will be credited toward the sample population.E-1 -40 of 51 Subsequent inspections will consist of an examination of the exterior surface of theinsulation for indications of damage to the iacketing or protective outer layer of theinsulation, if the following conditions are verified in the initial inspection.0 No loss of material due to general, pitting or crevice corrosion, beyond that whichcould have been present during initial construction* No evidence of crackingNominal degradation is defined as no loss of material due to general, pitting, orcrevice corrosion, beyond that which could have been present during initialconstruction, and no evidence of cracking. If the external visual inspections of theinsulation reveal damage to the exterior surface of the insulation or there is evidenceof water intrusion through the insulation (e.g. water seepage through insulationseams/joints), periodic inspections under the insulation will continue as describedabove.Revise External Surfaces Monitoring Program procedures to include acceptance criteria.Examples include the following:o Stainless steel should have a clean shiny surface with no discoloration.Other metals should not have any abnormal surface indications.Flexible polymers should have a uniform surface texture and color with no cracksand no unanticipated dimensional change, no abnormal surface with the material inan as-new condition with respect to hardness, flexibility, physical dimensions, andcolor.Rigid polymers should have no erosion, cracking, checking or chalks.Enhancements will be implemented prior to the period of extended operation."Changes to LRA Section B.1.10, External Surfaces Monitoring Program follow with additionsunderlined and deletions lined through."For polymeric materials, the visual inspection will include 100 percent of the accessiblecomponents. The sample size of polymeric components that receive physical manipulation isat least ten percent of the available surface area. Acceptance criteria are defined to ensurethat the need for corrective action is identified before a loss of intended function(s). Forstainless steel a clean shiny surface is expected. For flexible polymers a uniform surfacetexture (no cracks) and no change in material properties (e.g., hardness, flexibility, physicaldimensions, color unchanged from when the material was new) are expected. For rigidpolymers no surface changes affecting performance such as erosion, cracking, crazing,checking, and chalking are expected. The acceptance standards include design standards,procedural requirements, current licensing basis, industry codes or standards, andengineering evaluations.For a representative sample of outdoor insulated components and indoor insulatedcomponents operated below the dew point, which have been identified with more thannominal degradation on the exterior of the component, insulation is removed for inspection ofthe component surface. For a representative sample of indoor insulated components operatedbelow the dew point, which have not been identified with more than nominal degradation onthe exterior of the component, the insulation exterior surface is inspected. These inspectionswill be conducted during each 10-year period beginning 5 years before the PEO.E-1 -41 of 51 NUREG-1801 ConsistencyThe External Surfaces Monitoring Program, with enhancements, will be consistent with theprogram described in NUREG-1801, Section XI.M36, External Surfaces Monitoring ofMechanical Components.Exceptions to NUREG-1801NoneEnhancementsThe following enhancements will be implemented prior to the period of extended operation.Element Affected Enhancement1. Scope of Program Revise External Surfaces Monitoring Program procedures to clarify that periodic inspections ofsystems in scope and subject to aging management review for license renewal in accordancewith 10 CFR 54.4(a)(1) and (a)(3) will be performed. Inspections shall include areas surroundingthe subject systems to identify hazards to those systems. Inspections of nearby systems thatcould impact the subject systems will include SSCs that are in scope and subject to agingmanagement review for license renewal in accordance with 10 CFR 54.4(a)(2).3. Parameters Revise External Surfaces Monitoring Program procedures to include instructions to look for theMonitored or following related to metallic components:Inspected 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 of stainless steel componentsexposed to an air environment containing halides.3. Parameters Revise External Surfaces Monitoring Program procedures to include instructions for monitoringMonitored or aging effects for flexible polymeric components, including manual or physical manipulations ofInspected the material, with a sample size for manipulation of at least ten percent of the available surfacearea. The inspection parameters for polymers shall include the following:" Surface cracking, crazing, scuffing, dimensional changes (e.g., ballooning and necking)." Discoloration.* Exposure of internal reinforcement for reinforced elastomers (loss of material).* Hardening as evidenced by loss of suppleness during manipulation where the componentand material can be manipulated.4.Detection of Aging Revise Eixternal Surfacesr Monitoring Prog~ram proceduresA_ to ensuire suirfaceis that AreinuteEffects ;-ill be inspected when the exterpnl surface is exposed (i.e., during maintenance) at suchinteral's that would ensuthr t the components' inten-ded fu--nction is maintained Revise ExternalSurfaces Monitoring Program procedures to specify the following for insulated components:" Periodic representative inspections are conducted during each 10-year period beginning 5years before the PEO." For a representative sample of outdoor components, except tanks, and indoor components,except tanks, identified with more than nominal degradation on the exterior of thecomponent, insulation is removed for visual inspection of the component surface. Inspectionsinclude a minimum of 20 percent of the in-scope piping length for each material type (e.g.,steel, stainless steel, copper alloy, aluminum). For components with a configuration whichdoes not conform to a 1-foot axial length determination (e.g., valve, accumulator), 20 percentof the surface area is inspected. Inspected components are 20% of the population of eachE-1 -42 of 51 material type with a maximum of 25. Alternatively, insulation is removed and a minimum of 25inspections are performed that can be a combination of 1-foot axial lenoqth sections andindividual components for each material type (e.g., steel, stainless steel, copper alloy,aluminum)4. (continue) For a representative sample of indoor components, except tanks, operated below the dewpoint, which have not been identified with more than nominal degradation on the exterior ofthe piping component, the insulation exterior surface or iacketing is inspected. These visualinspections verify that the iacketing and insulation is in good condition. The number ofrepresentative iacketing inspections will be at least 50 during each 10-year period.If the inspection determines there are gaps in the insulation or damage to the iacketing thatwould allow moisture to get behind the insulation, then removal of the insulation is required toinspect the component surface for degradation." For a representative sample of indoor insulated tanks operated below the dew point and allinsulated outdoor tanks, insulation is removed from either 25 1-square foot sections or 20percent of the surface area for inspections of the exterior surface of each tank. The sampleinspection points are distributed so that inspections occur on the tank dome, sides, near thebottom, at points where structural supports or instrument nozzles penetrate the insulation,and where water collects (for example on top of stiffening rings)." Inspection locations are based on the likelihood of corrosion under insulation (CUI). Forexample, CUI is more likely for components experiencing alternate wetting and drying inenvironments where trace contaminants could be present and for components that operatefor long periods of time below the dew point." If tightly adhering insulation is installed, this insulation should be impermeable to moisture andthere should be no evidence of damage to the moisture barrier. Given that the likelihood ofCUI is low for tightly adhering insulation, a minimal number of inspections of the externalmoisture barrier of this type of insulation, although not zero, will be credited toward thesample population." Subsequent inspections will consist of an examination of the exterior surface of the insulationfor indications of damage to the iacketing or protective outer layer of the insulation, if thefollowing conditions are verified in the initial inspection." No loss of material due to general, pitting or crevice corrosion, beyond that which couldhave been present during initial construction" No evidence of crackingNominal degradation is defined as no loss of material due to general, pitting, or crevicecorrosion, beyond that which could have been present during initial construction, and noevidence of cracking. If the external visual inspections of the insulation reveal damage to theexterior surface of the insulation or there is evidence of water intrusion through the insulation(e.g. water seepage through insulation seams/ioints), periodic inspections under the insulationwill continue as described above.6. Acceptance Revise External Surfaces Monitoring Program procedures to include acceptance criteria.Criteria Examples include the following:Stainless steel should have a clean shiny surface with no discoloration.E-1 -43 of 51
" Other metals should not have any abnormal surface indications." Flexible polymers should have a uniform surface texture and color with no cracks and nounanticipated dimensional change, no abnormal surface with the material in an as-newcondition with respect to hardness, flexibility, physical dimensions, and color.I Rigid polymers should have no erosion, cracking, checking or chalks.The changes to LRA table line items follow with additions underlined.At the end of LRA Table 3.2.1 Engineered Safety Features, in Notes for Table 3.2.2-1 throughTable 3.2.2-5-3, add the following plant specific note 204."204. Program provisions for outdoor insulated components or for indoor insulated componentsthat operate below the dew point apply..Table 3.2.2-1:Safety Injection System Summary of Aging Management EvaluationPiaing Pressure Stainless Condensation Loss of External Surfaces H. 204boundary steel (ext) material MonitoringPiping Pressure Stainless Condensation Cracking External Surfaces .. .H, 204boundary steel (ext) MonitoringTank Pressure Stainless Condensation Loss of External Surfaces -- -204boundary steel (ext) material MonitoringTank Pressure Stainless Condensation Cracking External Surfaces --H204boundary steel (ext) MonitoringE-1 -44 of 51 At the end of LRA Table 3.3.1 Auxiliary Systems, in Notes for Table 3.3.2-1 through Table3.3.2-17-32, add the following plant specific note 313."313. Program provisions for outdoor insulated components or for indoor insulated componentsthat operate below the dew point apply.Table 3.3.2-2: High Pressure Fire Protection -Water System Summary of Aging ManagementEvaluationEjiin Pressure Carbon Condensation Loss of External --boundary steel (ext) material Surfaces 313MonitoringTable 3.3.2-4: Miscellaneous Heating, Ventilating and Air Conditioning Systems Summary ofAging Management EvaluationEipiM Pressure Carbon Condensation Loss of External -Hboundary steel (ext) material Surfaces 313MonitorinqTank Pressure Carbon Condensation Loss of External .boundary steel (ext) material Surfaces 313MonitoringTable 3.3.2-6: Control Building HVAC System Summary of Aging Management EvaluationEigin Pressure Carbon Condensation Loss of External .H,boundary steel (ext) material Surfaces 313MonitoringEipjag Pressure Copper Condensation Loss of External H,boundary alloy (ext) material Surfaces 313MonitoringIE-1- 45 of 51 Table 3.3.2-11: Essential Raw Cooling Water Systems Summary of Aging ManagementEvaluationEjljn Pressure Carbon Condensation Loss of External H_,boundary steel (ext) material Surfaces 313MonitoringEipiM Pressure Nickel Condensation Loss of Externalboundary alloy (ext) material Surfaces 313MonitoringEipln Pressure Stainless Condensation Loss of External _H.,boundary steel (ext) material Surfaces 313MonitorinqTable 3.3.2-17-4: Raw Cooling Water System, Nonsafety-Related Components AffectingSafety-Related Systems Summary of Aging Management Evaluationjj Pressure Carbon Condensation Loss of External --boundary steel (ext) material Surfaces 313MonitoringEi2ýM Pressure Coppe Condensation Loss of External -boundary alloy (ext) material Surfaces 313MonitoringPressure Stainless Condensation Loss of External .. .Hboundary steel (ext) material Surfaces 313MonitoringTable 3.3.2-17-5: Raw Service Water System, Nonsafety-Related Components AffectingSafety-Related Systems Summary of Aging Management EvaluationF Pressure Carbon Condensation Loss of External 13boundary steel (ext) material Surfaces 313MonitoringE-1- 46 of 51 Table 3.3.2-17-16: Layup Water Treatment System, Nonsafety-Related Components AffectingSafety-Related Systems Summary of Aging Management EvaluationEjljn Pressure Carbon Condensation Loss of External ..-boundary steel (ext) material Surfaces 313Monitorinqgpj Pressure Stainless Condensation Loss of External Hboundary steel (ext) material Surfaces 313MonitoringPressure Stainless Condensation Cracking External H.. IIboundary steel (ext) Surfaces 313MonitoringTable 3.3.2-17-22: Ice Condenser System, Nonsafety-Related Components Affecting Safety-Related Systems Summary of Aging Management EvaluationPipingPressureboundaryCarbonsteelCondensation(ext)Loss ofmaterialExternalSurfacesMonitorin~qt t I.EjjLMPressureboundaryStainlesssteelCondensation(ext)Loss ofmaterialExternalSurfacesMonitoringTank Pressure Carbon Condensation Loss of Externalboundary steel (ext) material SurfacesMonitoringAt the end of LRA Table 3.4.1 Steam and Power Conversion Systems, in Notes for Table3.4.2-1 through 3.4.2-3-10, add the following plant specific note 404."404. Program provisions for outdoor insulated components or for indoor insulatedcomponents that operate below the dew point apply.Table 3.4.2-1: Main Steam System Summary of Aging Management EvaluationPipin Pressure Carbon Condensation Loss of External Surfaces ..-boundary steel (ext) material Monitoring 404Eign Pressure Stainless Condensation Loss of External Surfaces -boundary steel (ext) material Monitoring 404Pn Pressure Stainless Condensation Cracking External Surfaces -- -Hboundary steel (ext) Monitoring 404E-1 -47 of 51 Table 3.4.2-2: Main and Auxiliary Feedwater System Summary of Aging ManagementEvaluation.in Pressure Carbon Condensation Loss of External .Hboundary steel (ext) material Surfaces 404MonitoringPressure Aluminum Condensation Loss of External .. .H,boundary (ext) material Surfaces 404MonitoringPipinq Pressure Stainless Condensation Loss of External .Hboundary steel (ext) material Surfaces 404MonitoringEigtg Pressure Stainless Condensation Cracking External .Hboundary steel (ext) Surfaces 404MonitoringTable 3.4.2-3-9: Condenser Circulating Water System, Nonsafety-Related ComponentsAffecting Safety-Related Systems Summary of Aging Management EvaluationPig Pressure Carbon Condensation Loss of Externalboundary steel (ext) material Surfaces 404MonitoringPipin Pressure Copper Condensation Loss of External H,boundary alloy > (ext) material Surfaces 40415% Zn Monitoringor > 8%AlPiping Pressure Stainless Condensation Loss of External .Hboundary steel (ext) material Surfaces 404MonitoringCommitments # 6.D and F have been revised.E-1- 48 of 51 Set 12: RAI B.1.6-1b and B.1.6-2bIn a NRC telecom with TVA on October 23, 2013, the NRC requested clarifications for RAIB. 1.6-la and B. 1.6-2a responses. TVA supplements these two responses as follow withadditions underlined and deletions lined through.1. B.1.6-1b: Regarding RAI B.1.6-1a, from ML13276A018, page E-2 -42 of 46, Set 12.30d,TVA has added the following two sentences on this page as Commitment #35.B."To monitor the condition of the access boxes and associated materials, perform visualexaminations of all accessible surfaces, including the access box surfaces, cover plate,welds, and gasket sealing surfaces of the access boxes on each unit every other refuelingoutage with the gasketed access box lid removed."2. B.l.6-2b: Regarding RAI B. 1.6-2a, from ML1 3276A01 8, page E-2 -45 of 46,Set 12.30d, TVA supplements RAI B.1.6-2a, Response 1.b as follows."l.b. As discussed in RAI B.1.6-2a Response 1.a, the volumetric examination is solely anowner-elected examination and is not an examination required by ASME Code Section XI.Although the examinations are performed at the Article IWE-2412 examination frequency,the ASME Code is not the basis for this examination and the examination frequency maybe modified during the PEO. Volumetric examinations will continue once every five yearsat the frequency determined by SON engineeg until the coatings where the SCV domeswere cut are reinstalled for the units.Commitment #35.C: Continue volumetric examinations where the SCV domes were cut atthe frequency of once every five years until the coatings are reinstalled at these locations."E-1 -49 of 51 RAI 4.3.1-8aBackground:In its September 30, 2013, response to RAI 4.3.1-8, the applicant stated that the pressurizersurge nozzle-to-safe end welds for the units were originally included in the cumulative usagefactor (CUF) analyses for the pressurizer surge nozzles; however, the applicant stated that thedesign of the welds has been modified to include a full structural weld overlay (SWOL). Theapplicant also stated that, as identified in LRA Section 4.3.1.3, the current design basis of thepressurizer surge nozzles and their nozzle-to-safe end weld relies on a flaw evaluation that isused to establish the inservice inspection (ISI) frequency for the components.Issue:The response to RAI 4.3.1-8 may be inconsistent with LRA Section 4.3.1.3 Specifically, LRASection 4.3.1.3, identifies that the flaw evaluation for the nickel alloy pressurizer surgenozzle-to-safe end weld was performed to assess postulated cracking that could be initiated andgrown by a stress corrosion cracking (SCC) mechanism, and not by a metal fatigue mechanism.As a result, the response to RAI 4.3.1-8 will only provide a valid basis for concluding that thewelds would not need to be evaluated for environmentally-assisted fatigue if it is demonstratedthat the flaw evaluation of the pressurizer surge nozzle-to-safe end welds also included anevaluation of crack initiation and growth that is induced by a thermally-induced metal fatiguemechanism.Thus, it is not evident whether flaw growth by a thermally-induced metal fatigue mechanism wasincluded as part of the basis for establishing the inspection frequency that is used to schedulethe inspections of the pressurizer spray nozzle-to-safe end weld under the applicant's ISIProgram or Nickel Alloy Inspection Program.Request:Identify whether the flaw evaluation that was performed on the SWOL-modified pressurizersurge nozzle designs included an assessment of cracking that would be induced and grown bya thermally-induced metal fatigue mechanism (i.e., in addition to an assessment of cracking thatis initiated and grown by SCC).1. If it is determined that the flaw evaluation did include an assessment of both SCC andfatigue, identify the inspection frequency that is currently applicable to the ISI inspectionsunder the applicant's ISI Program or Nickel Alloy Inspection Program. In addition, identifywhich of the cracking mechanisms was determined to be limiting for establishment of theinspection frequency.2. If it is determined that the flaw growth analysis does not include an assessment of crackingthat could be initiated and grown by fatigue, identify design basis CUF values that areapplicable to the pressurizer surge nozzle-to-safe end weld locations for Units 1 and 2 andjustify why the CUF values for these Nickel alloy nozzle-to-safe end weld would not need tobe adjusted for environmentally-assisted fatigue, as performed in accordance with therecommended guidance for performing environmentally-assisted fatigue analyses for Nickelalloy components in SRP-LR Section 4.3. Justify your responses to this request.E-1- 50 of 51 TVA Response to RAI 4.3.1-8a:The evaluation that was performed for the pressurizer surge nozzle SWOL considered theeffects of thermally induced metal fatigue and the potential for stress corrosion cracking. TheSWOL places compressive load on the original weld that reduces the potential for stresscorrosion cracking in the original weld. The weld overlay material, Alloy 52/52M, is a nickel-based alloy that is highly resistant to stress corrosion cracking. If a flaw were to extend beyondthe portion of the nozzle wall with compressive stresses and has a crack tip stress intensity thatexceeded the value for PWSCC growth in the 82/182 material, then PWSCC could cause thecrack to grow until the weld overlay material (52/52M) is reached. From that time on, fatiguecrack growth could cause the crack to grow into the weld overlay material.1. The evaluation of cracking of the original material identifies that PWSCC is possible if a flawis large enough to cause the remaining area to exceed 10 KSI of tensile stress afterapplication of operating pressure and loads. The analysis of the overlay material considerscrack growth rate due to fatigue. The analysis determined that even with a postulated crackof 80% thru the original wall thickness, the remaining life would still be approximately 39years for an axial flaw and 31 years for a radial flaw. The surge nozzle weld overlayinspection frequency for SQN units 1 and 2 is once every fourth refueling outage.2. The full structural weld overlay analysis at the nickel alloy nozzle-to-safe end weld location isa flaw growth analysis that includes consideration of PWSCC and crack growth due tofatigue. Because there is no design basis fatigue analysis that determined a CUF for thenickel alloy nozzle-to-safe end weld, adjustment for environmentally assisted fatigue is notnecessary at this locationE-1 -51 of 51 ENCLOSURE2Tennessee Valley AuthoritySequoyah Nuclear Plant, Units 1 and 2 License RenewalRegulatory Commitment List, Revision 11Commitments 6.D & F, 9.C,G to M, 24.B, 35.B & C, and 38 have been revised with additionsunderlined and deletions lined through.This Commitment Revision supersedes all previous versions. The latest revision will be included in theLRA Appendix A. before the SQN LRA SER is issued.LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE I AUDITITEMImplement the Aboveground Metallic Tanks Program as described SQNI: Prior to 09/17/20 B.1.1in LRA Section B.1.1 SQN2: Prior to 09/15/212 A. Revise Bolting Integrity Program procedures to ensure the SQNI: Prior to 09/17/20 B.1.2actual yield strength of replacement or newly procured bolts will be SQN2: 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 SQNI: 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-2- 1 of 21 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE IAUDITITEM4 A. Revise Compressed Air Monitoring Program procedures to SQNI: 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-1 08147 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-1998, 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-1 998, Part 17, EPRI NP-7079; andEPRI TR-108147.-~ I -IE-2 -2 of 21 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 (PEO) and at succeedingten-year intervals. If visual inspection is not possible, a volumetricinspection will 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 PEO and succeeding ten-yearintervals.6 A. Revise External Surfaces Monitoring Program procedures to B.A,B,C,E: B.1.10clarify that periodic inspections of systems in scope and subject to SQN1: Prior to 09/17/20aging management review for license renewal in accordance with 10 SQN2: Prior to 09/15/21CFR 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-2 -3 of 21 LRANo COMMITMENT IMPLEMENTATION SECTIONSCHEDULE /AUDIT__ ITEM(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 reinforced elastomers(loss of material).* Hardening as evidenced by loss of suppleness duringmanipulation where the component and material can bemanipulated.D. Revise External Surifaces Monitoring Program procedures toensure surfaces that -;FAr i*nsulatdA Will be inApected when the externalsJufarce is expesed (i.e., during maintenance) at such inter.al thatwould ensure that th components' intended function is maintained.Revise External Surfaces Monitoring Program procedures to specifythe followinq for insulated components.* Periodic representative inspections are conducted during each .D:10-year period beginning 5 years before the PEO. SQN1: Prior to 09/17/15* For a representative sample of outdoor components, except SQN2: Prior to 09/15/16tanks, and indoor components, except tanks, identified withmore than nominal degradation on the exterior of thecomponent, insulation is removed for visual inspection of thecomponent surface. Inspections include a minimum of 20percent of the in-scope piping length for each material type (e.g.,steel, stainless steel, copper alloy, aluminum). For componentswith a configuration which does not conform to a 1-foot axiallength determination (e.g., valve, accumulator), 20 percent of thesurface area is inspected. Inspected components are 20% of thepopulation of each material type with a maximum of 25.Alternatively, insulation is removed and component inspectionsperformed for any combination of a minimum of 25 1-foot axiallength sections and individual components for each material type(e.g., steel, stainless steel, copper alloy, aluminum.)* For a representative sample of indoor components, excepttanks, operated below the dew point, which have not beenidentified with more than nominal degradation on the exterior ofthe component, the insulation exterior surface or iacketing isinspected. These visual inspections verify that the jacketing andinsulation is in good condition. The number of representativeMacketing inspections will be at least 50 during each 10-yearperiod.If the inspection determines there are gaps in the insulation ordamage to the jacketing that would allow moisture to get behindthe insulation, then removal of the insulation is required toinspect the component surface for degradation.* For a representative sample of indoor insulated tanks operatedbelow the dew point and all insulated outdoor tanks, insulation isremoved from either 25 1-square foot sections or 20 percent ofthe surface area for inspections of the exterior surface of eachtank. The sample inspection points are distributed so that-~ 1 1E-2- 4of21 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE /AUDIT, ITEM(6) inspections occur on the tank dome, sides, near the bottom, atpoints where structural supports or instrument nozzles penetratethe insulation, and where water collects (for example on top ofstiffening rings).* Inspection locations are based on the likelihood of corrosionunder insulation (CUI). For example, CUI is more likely forcomponents experiencing alternate wetting and drying inenvironments where trace contaminants could be present andfor components that operate for long periods of time below thedew point.* If tightly adhering insulation is installed, this insulation should beimpermeable to moisture and there should be no evidence ofdamage to the moisture barrier. Given that the likelihood of CUIis low for tightly adhering insulation, a minimal number ofinspections of the external moisture barrier of this type ofinsulation, although not zero, will be credited toward the samplepopulation.* Subsequent inspections will consist of an examination of theexterior surface of the insulation for indications of damage to theiacketing or protective outer layer of the insulation, if thefollowing conditions are verified in the initial inspection." No loss of material due to general, pitting or crevicecorrosion, beyond that which could have been present duringinitial construction" No evidence of crackingNominal degradation is defined as no loss of material due togeneral, pitting, or crevice corrosion, beyond that which couldhave been present during initial construction, and no evidence ofcracking. If the external visual inspections of the insulationreveal damage to the exterior surface of the insulation or there isevidence of water intrusion through the insulation (e.g. waterseepage through insulation seams/ioints), periodic inspectionsunder the insulation will continue as described above. [RAI3.0.3-1 Request 61E. 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-2 -5 of 21 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE / AUDITITEM(6) F. For a representative sample of outdoor insulated components andindoor insulated components operated below the dew point, whichhave been identified with more than nominal deqradation on theexterior of the component, insulation is removed for inspection of thecomponent surface. For a representative sample of indoor insulatedcomponents operated below the dew point, which have not been S.F:identified with more than nominal degradation on the exterior of the SQN1: Prior to 09/17/15component, the insulation exterior surface is inspected. These SQN2: Prior to 09/15/16inspections will be conducted during each 10-year period beginning 5years before the PEO. [RAI 3.0.3-1 Request 617 A. Revise Fatigue Monitoring Program procedures to monitor and SQN1: Priorto 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 and cycle-based fatiguewaiver evaluations on an as-needed basis if an allowable cycle limit isapproached, or in a case where a transient definition has beenchanged, unanticipated new thermal events are discovered, or thegeometry of components have been modified.E. Revise Fatigue Monitoring Program procedures to track thetensioning cycles for the reactor coolant pump hydraulic studs.E-2- 6 of 21 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE I AUDITITEM8 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.9Implement the Fire Water System Proaram as described in LRASection B.1.13.A. Revise Fire Water System Program procedures to include periodicvisual inspection of fire water system internals for evidence ofcorrosion 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 PEO andperiodically thereafter. Results of the initial evaluations will beused to determine the appropriate inspection interval to ensureaging effects are identified prior to loss 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 thePEO. A representative number is 20% of the population(defined as locations having the same material, environment,and aging effect combination) with a maximum of 25 locations.Additional inspections will be performed as needed to obtain thisrepresentative sample prior to the PEO and periodically duringthe PEO based on the findings from the inspections performedprior to the PEO.C. Revise Fire Water System Progjram procedures to ensure asprinkler heads are tested in accordance with NFPA-25 (2011SQN1: Prior to 09/17/203QN2: Prior to 09/15/21B.1.13Edition), Section 5.3.1 [RAI 3.0.3-1 Request 41 Revis-e Fire WaterSystem; Program proce-duresAF- to ens-ure a representative sam~ploosprinkler heads Will be tested or replaced befor tho end of the 50year sprinkler head szerice life and at ten year nevl theireafeduigte extended poriod of operation. N.'FPA :25 definer, arepresentative sample of sprinklerS to consist of a Minimum ofnoless than fouri sprinklers Or one percent of the number of sprinklersper individual sprinkler sample, Whichever is greater. If th opio toreplace the sprFinklers is, chosen, all sprinkler heads. that have been inRpfric for fin voears luill be r-Anl;1ed-Iw r ...E-2- 7of21 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE / AUDITITEM(9) 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.F. Prior to the PEO, SQN will select an inspection method (ormethods) that will provide suitable indication of piping wall thicknessfor a representative sample of buried piping locations to supplementthe existing inspection locations for high pressure fire protectionsystem 26 and essential raw cooling water system 67. [RAI 3.0.3-1,request 5a, Set 10.30, 9/3/13]G. Revise Fire Water System Program procedures to-periodicallyremove a representative sample of components such as sprinklerheads or couplings prior to the PEO and perform a visual internalinspection of dry fire water system piping for evidence of corrosion,loss of wall thickness, and foreign material that may result in flowblockage using the methodology described in NFPA-25 Section14.2.1. This includes those sections of dry piping described in NRCInformation Notice (IN) 2013-06, where drainage is not occurring.The acceptance criteria shall be "no debris" (i.e., no corrosionproducts that could impede flow or cause downstream components tobecome clogged). Any additional inspections in accordance withNFPA-25, Sections 14.2.1 or 14.2.2 will be based on the initialinspection results.H. Revise Fire Water System Program procedures to perform anobstruction evaluation in accordance with NFPA-25 (2011 Edition),Section 14.3.1.I. Revise Fire Water System Program procedures to conductfollow-up volumetric examinations if internal visual inspections detectsurface irregularities that could be indicative of wall loss belownominal pipe wall thickness.J. Revise Fire Water System Program procedures to annuallyinspect the fire water storage tank exterior painted surface for signsof degradation. If degradation is identified, conduct follow-upvolumetric examinations to ensure wall thickness is equal to orexceeds nominal wall thickness.The fire water storage tanks will be inspected in accordance withNFPA-25 (2011 Edition) requirements.K. Revise Fire Water System Program procedures to include a firewater storage tank interior inspection every five years that includesinspections for signs of pitting, spalling., rot, waste material anddebris, and aauatic arowth. Include in the revision direction toI IE-2 -8 of 21 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE I AUDITITEM(9) perform fire water storage tank interior coating testing, if anydegradation is identified, in accordance with ASTM D 3359 orequivalent, a dry film thickness test at random locations to determineoverall coating thickness: and a wet sponge test to detect pinholes,cracks or other compromises of the coating. If there is evidence ofpitting or corrosion ensure the Fire Water System Programprocedures direct performance of an examination to determine walland bottom thickness.L. Revise Fire Water System Program procedures based on theresults of a feasibility study to perform the main drain tests inaccordance with NFPA-25 (2011 Edition) Section 13.2.5.M. Revise Fire Water System Program procedures to perform sprayhead discharge pattern tests from all open spray nozzles to ensurethat patterns are not impeded by plugged nozzles, to ensure thatnozzles are correctly positioned, and to ensure that obstructions donot prevent discharge patterns from wetting surfaces to be protected.Where the nature of the Protected property is such that water cannotbe discharged, the nozzles shall be inspected for proper orientationand the system tested with smoke or some other medium to ensurethat the nozzles are not obstructed. fRAI 3.0.3-1. Request 4, forCommitments 9.C,G to M110 A. Revise Flow Accelerated Corrosion (FAC) Program procedures SQN1: 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.11 Revise Flux Thimble Tube Inspection Program procedures to SQNI: 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). IIE-2- 9of21 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE / AUDITITEM12 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 3QN1: Prior to 09/17/20 B.1.19Ducting Components Program as described in LRA Section B.1.19. 3QN2: Prior to 09/15/2115 Implement the Metal Enclosed Bus Inspection Program as 3QN1: Prior to 09/17/20 B.1.21described in LRA Section B.1.21. SQN2: Prior to 09/15/2116 A. Revise Neutron Absorbing Material Monitoring Program SQNI: Prior to 09/17/20 B.1.22procedures to perform blackness testing of the Boral coupons within SQN2: Prior to 09/15/21the ten years prior to the PEO and at least every ten years thereafterbased on initial testing to determine possible changes in boron-10areal density.E-2- 10 of 21 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE I AUDITITEM(16) 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 SQNI: Prior to 09/17/20 B.1.24in LRA Section B.1.24 SQN2: Prior to 09/15/2118 Implement the Non-EQ Inaccessible Power Cable (400 V to 35 kV) SQN1: Prior to 09/17/20 B.1.25Program as described in LRA Section B.1.25 SQN2: Prior to 09/15/21A. TVA response to RAI B.1.25.1a1. Repair the manhole sump pump and discharge piping 18.A.1: Sept 2015deficiencies associated with the accumulation of water in sevenmanholes/handholes that are scheduled for correction and/ormitigation by September 2015. (HH3, HH2B, HH52B, HH55A2,MH7B, MH10A and MH32B as identified on October 1, 2013) 18.A2 & 4: Sept 20142. Grade the ground surface around Manhole 31 to direct runoffaway from the manhole. The re-grading is scheduled forcompletion by September 2014.3. Prior to the PEO, the license renewal commitment for the Non-EQ 18.A.3:Inaccessible Power Cables (400 V to 35 kV) Program will QN1: Prior to 09/17/20establish diagnostic testing activities on all inaccessible power SQN2: Prior to 09/15/21cables in the 400 V to 35kV range that are in the scope of licenserenewal and subject to aging management review.4. Revise the manhole inspection procedures to specify themaximum allowable water level to preclude cable submergence inthe manhole. If the inspection identifies submergence ofinaccessible power cable for more than a few days, the conditionwill be documented and evaluated in the SQN corrective actionprogram. The evaluation will consider results of the most recentdiagnostic testing, insulation type, submergence level, voltagelevel, energization cycle (usage), and various other inputs todetermine whether the cables remain capable of performing theirintended current licensing basis function.19 Implement the Non-EQ Instrumentation Circuits Test Review QN1: Prior to 09/17/20 B.1.26Program as described in LRA Section B.1.26. QN2: 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 09/15/21E-2- 11 of 21 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE I AUDITITEM21 A. Revise Oil Analysis Program procedures to monitor and SQN1: 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 SQN1: 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 SQNI: Prior to 09/17/20 B.1.30as described in LRA Section B.1.30 SQN2: Prior to 09/15/2124 A. 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.B. RAI 3.0.3-1, Request 3, Loss of Coating Integrity: 24.BFor in-scope components that have internal Service Level Ill or Other SQN1: RFO Prior tocoatings, initial inspections will begin no later than the last scheduled 09/17/20refueling outage prior to the period of extended operation (PEO).Subsequent inspections will be performed based on the initial SQN2: RFO Prior toinspection results. )9/15/2125 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 monitoringI process.26 A. Revise Reactor Head Closure Studs Program procedures to SQNI: 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, Revi.E-2- 12 of 21 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE / AUDITITEM27 A. Revise Reactor Vessel Internals Program procedures to take SQN1: Prior to 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 SQN1: 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-E185-82 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 PEO.29 Implement the Selective Leaching Program as described in LRA SQN1: Prior to 09/17/20 B.1.37Section B.1.37. SQN2: Prior to 09/15/2130 Revise Steam Generator Integrity Program procedures to ensure SQNI: Prior to 09/17/20 B.1.39that corrosion resistant materials are used for replacement steam SQN2: Prior to 09/15/21generator tube plugs.31 A. Revise Structures Monitoring Program procedures to include SQN1: Prior to 09/17/20 B.1.40the following in-scope structures: SQN2: Prior to 09/15/21* 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 NuclearE-2- 13 of 21 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE / AUDITITEM(31) Power 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)* Beams, 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 plates* Cable tray* Cable tunnel* Canal gate bulkhead* Compressible joints and seals* Concrete cover for the rock walls of approach channel* Concrete shield blocks* Conduit* Control rod drive missile shield* Control room ceiling support system* Curbs* Discharge box and foundation* Doors (including air locks and bulkhead doors)* Duct banks" Earthen embankment" 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 baskets* Ice baskets lattice support frames* Ice condenser support floor (concrete)" Insulation (fiberglass, calcium silicate)" Intermediate deck and top deck of ice condenser" Kick plates and curbs (steel -inside steel containment vessel)E-2- 14 of 21 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE /AUDITITEM(31) e Lower inlet doors (inside steel containment vessel)* Lower support structure structural steel: beams, columns,plates (inside steel containment vessel)* Manholes and handholesa 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.)0 Missile barriers/shields (concrete)* Missile barriers/shields (steel)* Monorails* Penetration seals* Penetration seals (steel end caps)* Penetration sleeves (mechanical and electrical not penetratingprimary containment boundary)* Personnel access doors, equipment access floor hatch andescape hatches* Piles* Pipe tunnel* Precast bulkheads* Pressure relief or blowout panels* Racks, panels, cabinets and enclosures for electricalequipment and instrumentation* Riprap* Rock embankment* Roof or floor decking* Roof membranes* Roof slabs* RWST rainwater diversion skirt* RWST storage basin* Seals and gaskets (doors, manways and hatches)* Seismic/expansion joint0 Shield building concrete foundation, wall, tension ring beamand dome: interior, exterior above and below grade0 Steel liner plate0 Steel sheet piles0 Structural bolting* Sumps (concrete)0 Sumps (steel)* Sump liners (steel)* Sump screens* Support 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 trackE-2- 15 of 21 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE /AUDITITEM(31) supports, 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 towers* Trash racks* Trash racks associated structural support framing* Traveling screen casing and associated structural supportframing* Trenches (concrete)* Tube track" Turning vanes* Vibration isolatorsD. 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 buildingF. 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.E-2- 16of21 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE I AUDITITEM(31) 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.* 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.E-2- 17 of 21 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE IAUDITITEM(31) 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; and4. Prompt return of any unused fastener components to protectedstorage.M. TVA Response to RAI B.1.40-4a (Turbine Building wall crack)1. SQN will map and trend the crack in the condenser pit north wall.2. SQN will test water inleakage samples from the turbine buildingcondenser pit walls and floor slab for minerals and iron content toassess the effect of the water inleakage on the concrete and thereinforcing steel.3. SQN will test concrete core samples removed from the turbinebuilding condenser pit north wall with a minimum of one coresample in the area of the crack. The core samples will be testedfor compressive strength and modulus of elasticity and subjectedto petrographic examination.4. The results of the tests and SMP inspections will be used todetermine further corrective actions, if necessary.5. Commitment #31.M will be implemented before the PEO for SQNUnits 1 and 2.32 Implement the Thermal Aging Embrittlement of Cast Austenitic QN1: 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 & BB. 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 systemE-2- 18 of 21 LRACOMMITMENT IMPLEMENTATION SECTIONSCHEDULE / AUDITITEM(33)
* High pressure fire protection diesel jacket water system0 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 SQNI: 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. I IE-2- 19 of 21 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE IAUDITITEM35 A, From B.1.6-1 Response: Modify the configuration of the SQN Unit 35.A: B. 1.61 test connection access boxes to prevent moisture intrusion to the SQN1: Prior to 09/17/20leak test channels. Prior to installing this modification, TVA will SQN2: Not Applicableperform remote visual examinations inside the leak test channels byinserting a borescope video probe through the test connection tubing.B., From B. 1.6-1b Response: To monitor the condition of the access 35. B & C:boxes and associated materials, perform visual examinations of all SQN1: Prior to 09/17/20accessible surfaces, including the access box surfaces, cover plate. SQN2: Prior to 09/15/21welds, and gasket sealing surfaces of the access boxes on each unitevery other refueling outage with the gasketed access box lidremoved. [RAI B.1.6-lblC. From B.1.6-2b Response: Continue volumetric examinationswhere the SCV domes were cut at the frequency of once every fiveyears until the coatings are reinstalled at these locations. [RAI B. 1.6-2b136 Revise Inservice Inspection Program procedures to include a QN1: 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 and1 environmental considerations.E-2- 20 of 21 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE AUDITITEM37 TVA will implement the Operating Experience for the AMPs in o later than the B.0.4accordance with the TVA response to the RAI B.0.4-1 on cheduled issue date ofJuly 29, 2013 letter to the NRC. (See Set 7.30day RAI B.0.4-1 he renewed operatingResponse, ML13213A027); and icenses for SQN Units 1Oct 16, 2013 2013 letter to the NRC. (See Set 13.30d RAIs B.0.4-1a & 2. (Currently Februaryand A.l-la Response) 2015)" Revise OE Program Procedure to include current and futurerevisions to NUREG-1801, "Generic Aging Lessons Learned(GALL) Report," as a source of industry OE, and unanticipatedage-related degradation or impacts to aging managementactivities as a screening attribute.* Revise the CAP Procedure to provide a screening process ofcorrective action documents for aging management items, theassignment of aging corrective actions to appropriate AMPowners, and consideration of the aging management trend code.* Revise AMP procedures as needed to provide for review andevaluation by AMP owners of data from inspections, tests,analyses or AMP OEs." Revise the OE Program Procedure to provide guidance forreporting plant-specific OE on unanticipated age-relateddegradation or impact to aging management activities to theTVA fleet and/or INPO." Revise the OE, CAP, Initial and Continuing Engineering SupportPersonnel Training to address age-related topics, theunanticipated degradation or impacts to the aging managementactivities; including periodic refresher/update training andprovisions to accommodate the turnover of plant personnel, andrecent AMP-related OE from INPO, the NRC, Scientech, andnuclear industry-initiated guidance documents and standards."" A comprehensive and holistic AMP training topic list will bedeveloped before the date the SQN renewed operating license isscheduled to be issued.* TVA AMP OE Process, AMP adverse trending & evaluation inCAP, AMP Initial and Refresher Training will be fullyimplemented by the date the SQN renewed operating license isscheduled to be issued.381 Implement the Service Water Program as described in LRA Section SQN1: Prior to 09/17/20 B.1.38B.1.38. (RAI 3.0.3-1, Request 3) SQN2: Prior to 09/15/21The above table identifies the 3._8 SQN NRC LR commitments. Any other statements in this letterare provided for information purposes and are not considered to be regulatory commitments.This Commitment Revision supersedes all previous versions.E-2- 21 of 21
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