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#REDIRECT [[CNL-14-010, Response to NRC Request for Additional Information Regarding the Review of the Sequoyah Nuclear Plant, Units 1 and 2, License Renewal Application, 3.0.3-1 (Requests 3b, -3a, 4b, 6b); B.1.34-8; B.1.34-9; A.1-2; Tables 3.3.1, 3.3.2-11, and ]]
| number = ML14057A808
| issue date = 01/16/2014
| title = Response to NRC Request for Additional Information Regarding the Review of the Sequoyah Nuclear Plant, Units 1 and 2, License Renewal Application, 3.0.3-1 (Requests 3b, -3a, 4b, 6b); B.1.34-8; B.1.34-9; A.1-2; Tables 3.3.1, 3.3.2-11, and 3.
| 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-14-010, TAC MF0481, TAC MF0482
| package number = ML14058A131
| document type = Letter, Report, Miscellaneous
| page count = 83
| project = TAC:MF0481, TAC:MF0482
}}
 
=Text=
{{#Wiki_filter:L44 140116 001 b-7 AC4pWithhold from Public Disclosure in Accordance with 10 CFR 2.390. Uponremoval of Enclosure 2, this letter is uncontrolled.Tennessee Valley Authority, 1101 Market Street, Chattanooga, Tennessee 37402CNL-14-010January 16, 201410 CFR Part 54ATTN: Document Control DeskU.S. Nuclear Regulatory CommissionWashington, D.C. 20555-0001Sequoyah Nuclear Plant, Units 1 and 2Facility Operating License Nos. DPR-77 and DPR-79NRC Docket Nos. 50-327 and 50-328Subject: Response to NRC Request for Additional Information Regarding theReview of the Sequoyah Nuclear Plant, Units I and 2, License RenewalApplication, 3.0.3-1 (Requests 3b, -3a, 4b, 6b); B.1.34-8; B.1.34-9; A.1-2;Tables 3.3.1, 3.3.2-11, and 3.6.1 (TAC Nos. MF0481 and MF0482)References: 1. Letter to NRC, "Sequoyah Nuclear Plant, Units 1 and 2 LicenseRenewal," dated January 7, 2013 (ADAMS Accession No. ML13024A004)2. Letter to NRC, "Response to NRC Request for Additional InformationRegarding the Review of the Sequoyah Nuclear Plant, Units 1 and 2,License Renewal Application, B. 1.41-4b, 3.0.3-1 (Requests Ia, 3a, 4a,6a), B.1.23-2e, 3.4.2.1.1-2a, Tables (3.4.1, 3.4.2-3-5, 3.3.1, 3.3.2-11),LRA B. 1.14, MRP-1 39, LRA Appendices A and B Acceptance Criteria,"dated December 16, 2013 (ADAMS Accession No. ML13357A722)3. NRC to TVA, "Requests for Additional Information for the Review of theSequoyah Nuclear Plant, Units 1 and 2, License Renewal Application -Set 14," dated September 26, 2013 (ADAMS Accession No.ML13263A338)4. NRC to TVA, "Requests for Additional Information for the Review of theSequoyah Nuclear Plant, Units 1 and 2, License Renewal Application -Set 18," dated December 6, 2013 (ADAMS Accession No.ML13323A097)5. NRC to TVA, "Requests for Additional Information for the Review of theSequoyah Nuclear Plant, Units 1 and 2, License Renewal Application -Set 19," dated December 23, 2013 (ADAMS Accession No.MLI13353A538)Pdnted wn recycle pape U.S. Nuclear Regulatory CommissionPage 2January 16, 2014By letter dated January 7, 2013 (Reference 1), the Tennessee Valley Authority (TVA)submitted a License Renewal Application (LRA) to the Nuclear Regulatory Commission(NRC) to renew the operating licenses for the Sequoyah Nuclear Plant (SQN), Units 1 and2. The request would extend the licenses for an additional 20 years beyond the currentexpiration date.By Reference 2, TVA submitted responses to request for additional information (RAI) 3.0.3-1(Requests 3a, 4a, 6a) and Tables 3.3.1 and 3.3.2-11. In a December 17, 2013 telecom,Mr. Richard Plasse, NRC Project Manager for the SQN License Renewal, requestedclarifications to these RAI responses. Enclosure 1 provides the requested clarifications.By References 3, 4, and 5, the NRC forwarded RAI Sets 14, 18, and 19, respectively thatincluded RAIs B.1.34-8, B.1.34-9, 3.0.3-1-3a, and A. 1-2 with required response due datesno later than November 25, 2013 ( Set 14), January 6, 2014 (Set 18), and January 22, 2014(Set 19). Mr. Plasse has given a verbal extension to January 16, 2014, for the RAIresponses that were due prior to that time. Enclosures 1 and 2 provide TVA's responses.Enclosure 2 (RAI Response B.1.34-8) contains information which Westinghouse considersto be proprietary in nature. Pursuant to 10 CFR 2.390, "Public-inspections, exceptions,request for withholding," paragraph (a)(4), it is requested that Enclosure 2 be withheld frompublic disclosure. Enclosure 4 provides the affidavit supporting the request. Enclosure 1contains the non-proprietary and redacted B.1.34-8 RAI response, suitable for publicdisclosure.Enclosure 3 is an updated list of the regulatory commitments for license renewal thatsupersedes 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 this16th day of January 2014.Resp Ily,v.W phe~annsVic President, Nuclear LicensingEnclosurescc: See Page 3 U.S. Nuclear Regulatory CommissionPage 3January 16, 2014Enclosures1. TVA Response to NRC Request for Additional Information: 3.0.3-1 (Requests3b, -3a, 4b, 6b); B.1.34-8 (non-proprietary); B.1.34-9; A.1-2; Tables 3.3.1, 3.3.2-11;and 3.6.12. TVA Response to NRC Request for Additional Information: B.1.34-8 (Proprietary)3. Regulatory Commitment List, Revision 144. Westinghouse Affidavit for RAI Response B.1.34-8, [TVA-14-2, CAW-14-3884]cc (Enclosures):NRC Regional Administrator -Region IINRC Senior Resident Inspector -Sequoyah Nuclear Plant ENCLOSUREITennessee Valley AuthoritySequoyah Nuclear Plant, Units 1 and 2 License RenewalTVA Response to NRC Request for Additional Information:3.0.3-1 (Requests 3b, -3a, 4b, 6b); B.1.34-8 (non-proprietary); B.1.34-9; A.1-2;Tables 3.3.1, 3.3.2-11; and 3.6.1Set 10: RAI 3.0.3-1, Request 3bAs a result of a teleconference call, on December 17, 2013, with Mr. Richard Plasse, NRC, TVAprovides the following revision to the RAI Response 3.0.3-1 Request 3 (ADAMS Accession No.ML13312A005, November 4, 2013, Enclosure 1, pages E-1 -3,4,6 of 51).TVA is changing the scope or frequency of inspections of coatings for the componentsdiscussed below. License Renewal SRP, Section A.1.2.2 of Appendix A, states that the risksignificance of a structure or component can be considered in evaluating the robustness of anaging management program (AMP). The changes discussed below are appropriate based onthe low risk significance of coatings associated with the affected components.Tanks and Piping Containing LiquidsIn each of the cases below, the component is non-safety-related and remote from safety-related(SR) components and components that are credited to support station blackout (SBO) and fireprotection (FP). The components are accessible for observation during routine daily operatingactivities.A coating failure that could cause spraying safety-related component is highly unlikely. Inaddition, there are no possible detrimental downstream effects on SR components orcomponents credited to support SBO or FP. Therefore, the effects of aging on the componentslisted below will be adequately managed through the AMPs that do not include inspections ofinternal coatings.Tanks:Clear well tankCaustic tankCation tankPotable water tankBulk chemical storage tankCaustic batching tankMain feed pump turbine oil tankGland seal water storage tankE-1 -1 of 42 EDG 7-Day Fuel Oil Tanks Inspection FrequencyThe Sequoyah Nuclear Plant (SQN) Technical Specifications (TS) require that the EDG7-day fuel oil tanks are drained, any accumulation of sediment is removed, and inspectedevery ten-years versus the five-year coating inspection periodicity stated in TVA RAIResponse 3.0.3-1 Request 3.In 2001, Belzona coating was applied to some localized pitting in the EDG 7-day fuel oiltanks 2A-A and 2B-B. As a result, the EDG 7-day fuel oil tanks were included in the originalRAI response as having an applied coating.An appropriate opportunity for TVA performing the Belzona coating inspection is inconjunction with the EDG 7-day fuel oil tank inspection at the ten-year frequency required byTS Surveillance Requirement 4.8.1.1.2.f, instead of every five years as previously stated inthe TVA RAI response 3.0.3-1 Request 3.Technical Basis: The EDG 7-day fuel oil tanks are embedded in concrete and operated atatmospheric pressure. The Belzona coating was applied in small, localized spots on thebottom of the 2A-A and 2B-B EDG 7-day fuel oil tanks. According to the work order andengineering analyses, the two largest pits were 0.125 inches and 0.156 inches in depth. Atthe worst location, the tank wall was approximately twice the required minimum thickness.The potential for clogging downstream components was evaluated when the Belzona wasapplied and was determined to be of minimal concern. In the event the Belzona did detachitself from the tank surface, the Belzona's specific gravity is 2.5 to 3 times higher than thediesel fuel, which would cause the detached coating material to stay at or sink to the bottomof the tanks. Furthermore, the fuel fluid velocity during a fuel transfer operation is insufficientto transport the detached Belzona. In addition, there are two sets of suction lines from thetanks. The suction lines in the vicinity of the Belzona-applied area are approximately eightinches from the bottom of the tanks, further limiting the potential for fuel flow to entrainBelzona material, if any Belzona were to become detached from the tank wall. The othersuction lines are remote from the Belzona application sites.Belzona is a ceramic metal-based material that was installed per Belzona specifications andis a permanent repair for corrosion mitigation. TVA determined a ten-year inspectionfrequency to coincide with the TS-required ten-year inspection is sufficient. During the ten-year TS-required inspections, these tanks will undergo ultrasonic testing (UT) of the interiorsurface. The 2013 volumetric inspections identified an average wall measurement in eachtank greater than the 0.25 inch nominal wall thickness. The lowest wall thickness identifiedwas 0.24 inches. In the event of tank leakage, level instrumentation and alarm are providedto initiate tank refilling operations. Therefore, there is sufficient basis to extend the frequencyof the Belzona coating inspection (from five-year) on the EDG 7-day fuel oil tanks to matchthe ten-year TS Surveillance Requirement 4.8.1.1.2.f.Pipingi:Makeup water treatment plant pipingHypochlorite pipingFire Protection Carbon Dioxide PipingBecause C02 is a dry gas that cannot result in corrosion without the presence of moisture,inspection of the internal coating of this piping can be deleted from the Periodic Surveillanceand Preventive Maintenance Program.E-1 -2 of 42 Set 19: RAI 3.0.3-1-3a (Follow up to 3.0.3-1, Request 3):Background:As amended by letter dated November 4, 2013, [ADAMS Accession No. ML1 3312A005] LRASections A. 1.31 and B. 1.31, Periodic Surveillance and Preventive Maintenance Programprovide the following:Extent of inspection:Each inspection occurs at least once every 5 years, with the exception of coatinginspections for which frequency is based on coating condition. For each activity that refersto a representative sample, a representative sample is 20 percent of the population (definedas components having the same material, environment, and aging effect combination) with amaximum of 25 componentsPrior to the PEO, perform a visual inspection of a 20 percent sample of the following coatedpiping systems or a maximum of 25 locations for each combination of type of coating,material the coating is protecting, and environment. Visually inspect the surface condition ofthe coated components to manage loss of coating integrity due to cracking, debonding,delamination, peeling, flaking, and blistering.Acceptance criteria:For loss of coating integrity, the acceptance criteria include (1) peeling and delamination arenot permitted, (2) cracking is not permitted if accompanied by delamination or loss ofadhesion, and (3) blisters are limited to intact blisters that are completely surrounded bysound coating bonded to the surface. LRA Sections A. 1.38 and B. 1.38, Service WaterIntegrity Program, include the same proposed changes to the acceptance criteria for theprogram.Issue:The staff lacks sufficient information to conclude that the above proposed changes to the twoprograms will provide reasonable assurance that the effects of aging for internally coated inscope components will be adequately managed. Specifically:Extent of inspection:Although sampling 20 percent of a population with a maximum of 25 locations is consistentwith the representative sample size in several GALL Report AMPs (e.g., XI.M32, "One TimeInspection, "XI.M33, "Selective Leaching'), the staff notes that components within the scopeof these programs were generally procured, installed, and tested in accordance with industryconsensus documents (e.g., ASTM Standards, ASME Code Section III). However, internalpiping coatings, even when installed in accordance with manufacturer's recommendations,did not have the benefit of being procured, installed, and tested in accordance with industryconsensus documents that cover the same level of detail as covered in those associatedwith power piping or nuclear construction codes. Consequently, the staff considers that therepresentative sample size to manage loss of coating integrity for piping internal coatingsshould be greater than the representative sample size for other GALL Report AMPs. Inaddition, while components are discreet objects, locations on a surface need to include anarea to be adequately defined. Finally, the proposed changes to the programs do notinclude criteria for location selection.The staff has concluded that:1. The appropriate sample size for piping is either 73 piping segments (1 foot long), or50 percent of the total length of each coating type, substrate material, and environmentE-1 -3 of 42 combination. The inspection surface includes the entire inside surface of the 1 foot sample.If geometric limitations impede movement of remote or robotic inspection tools, the numberof inspection segments should be increased in order to cover an equivalent area of73 1- foot sections.2. Inspection location selection should be based on an evaluation of the effect of a coatingfailure on the in-scope component's intended function, potential problems identified duringprior inspections, and known service life history.Acceptance criteria:The acceptance criteria do not include any specificity related to the use of additional inspectiontechniques to determine the extent of delamination, peeling, or blisters when detected. Thestaff has concluded that when these conditions are detected, (a) followup physical testingshould be performed where physically possible (i.e., sufficient room to conduct testing), (b) thetest should consist of destructive or nondestructive adhesion testing using ASTM Internationalstandards endorsed in Regulatory Guide 1.54, and (c) a minimum number of sample pointsshould be specified (e.g., three or more). In addition, if coatings are credited for corrosionprevention, the component's base material in the vicinity of delamination, peeling, or blisterswhere base metal has been exposed should be inspected to determine if unanticipatedcorrosion has occurred.Request:Extent of inspection:1. In light of the above discussion, provide information to demonstrate that a sampleconsisting of either 20 percent of the total length for each combination of coating type,substrate material, and environment, or a maximum of 25 locations will provide reasonableassurance that the effects of aging for internally coated in scope piping will be adequatelymanaged. Alternatively, revise the LRA to reflect the staff's above recommended samplesize.2. Specify the minimum surface area that will be inspected when the sample is based on anumber of locations and not on a percentage of the total coating length.3. State the basis for sample selection.Acceptance criteria:4. When delamination, peeling, or blisters are detected, state what additional inspectiontechniques will be used to demonstrate that adjacent areas are completely surrounded bysound coatings bonded to the substrate.TVA Response to RAI 3.0.3-1-3a1. The extent of inspection of coated piping is based on accessibility (i.e., the ends of thepiping and the length of available borescope equipment). The sample size is an areaequivalent to the entire inside surface of 73 piping segments (1 foot long) or 50% of thetotal length of each coating type, substrate material, and environment combination. TheLRA Sections A.1.31 & B.1.31 are revised below to reflect the NRC-recommendedsample size.2. The inspection surface includes the entire inside surface of each 1-foot sample. Ifgeometric limitations impede movement of remote or robotic inspection tools, the number ofinspection segments will be increased in order to cover an area equivalent to the area ofE-1 -4 of 42 73 1-foot piping segments. The LRA Sections A.1.31 & B.1.31 are revised below to reflectthe NRC minimum inspection surface area.3. Inspection location selection will be based on an evaluation of the effect of a coating failureon component intended functions, potential problems identified during prior inspections,and service life history.4. When delamination, peeling, or blisters are detected, follow-up physical testing will beperformed where physically possible (i.e., sufficient room to conduct testing) on at leastthree locations. The testing will consist of destructive or nondestructive adhesion testingusing ASTM International standards endorsed in Regulatory Guide 1.54. In addition, ifcoatings are credited for corrosion prevention, the base material (in the vicinity ofdelamination, peeling, or blisters where base metal has been exposed) will be inspected todetermine if corrosion has occurred.Changes to LRA Sections A.1.31, Periodic Surveillance and Preventive Maintenance Program,follow with additions underlined and deletions lined through.The Periodic Surveillance and Preventive Maintenance (PSPM) Program manages forspecific components' aging effects not managed by other aging management programs,including loss of material, fouling, cracking, loss of coating integrity, and change in materialproperties.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 that refersto a representative sample, with the exception of coating inspection activities related topipig, a representative sample is 20% of the population (defined as components having thesame material, environment, and aging effect combination) with a maximum of25 components. For coated piping, a representative sample is 50% of in-scope coatedpiping systems or an area equivalent to the entire interior surface of 73 1-foot pipingsegments for each combination of type of coating, substrate material, and environment.Credit for program activities has been taken in the aging management review of systems,structures and components as described below.Prior to the PEO, perform a visual inspection of a 2050% sample of the coated Piping ineach of the following coated piping systems or an area equivalent to the entire insidesurface of a maximum of 25 73 1-foot onatieon; piping segments for each combination oftype of coating, substrate material the ,cating is protecting, and environment. Inspectionlocation selection will be based on an evaluation of the effect of a coating failure oncomponent intended function, potential problems identified during prior inspections, andservice life history. Visually inspect the surface condition of the coated components tomanage loss of coating integrity due to cracking, debonding, delamination, peeling,flaking, and blistering. In addition, if coatings are credited for corrosion prevention, thebase material (in the vicinity of delamination, peeling, or blisters where base metal hasbeen exposed) will be inspected to determine if corrosion has occurred. Commitment#24.D.1 is added.Piping:i.Fire protection carbon dioxide (galvanized piping)ii. High pressure fire protection (cement-lined piping)in.Makeup water treatment plant (where Saran andl applie\d)IV. HYPOchlGorIito (Ply I-1I nlr, Teflon, and Goncrete)v. Essential raw cooling water (where Belzona applied)E-1 -5 of 42 Prior to the PEO, perform a visual inspection of the following coated tanks and heatexchangers. Visually inspect the surface condition of the coated components to manageloss of coating integrity due to cracking, debonding, delamination, peeling, flaking, andblistering. Commitment #24.E is added.Tanksi. lear well (where Epox' Phenolic coatingANOGiScOns protectiVe coating PlastiteNo. 7155 or equal appliedl)ii. Cautic (where TVA specS Scctio 27 applied (drawing 116365, contrc71C30 926274-))ii. ation (Whore 3/16 inch of rubber applied).Potable wateFr A\AAIA D102 62T- tandard for painting Section 3.1 No. 2,3 4 applied)BulR--k chemical (whe-re rubber lining applied)1A. batching (where 316" rubber lined with hl.r;-iated rubber applied)vii. Cask decontamination collector (where 2 coats Red Lead in oil, Fed SPEC TTP-85 Type II applied)4iii. Main feed pump turbine oil (where coating applied);v -Gla'nd seal water (where red hil 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 fuel oil storage(where Belzona applied)xiii. Condensate storage tanksHeat 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. If delamination,peeling, or blisters are detected, follow-up physical testing will be performed wherephysically possible (i.e., sufficient room to conduct testing) on at least three locations.The testing will consist of destructive or nondestructive adhesion testing using ASTMInternational standards endorsed in Regulatory Guide 1.54. Commitment #24.F isadded.* 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 a nuclearcoatings subject matter expert qualified in accordance with ASTM D 7108-05, "StandardGuide for Establishing Qualifications for a Nuclear Coatings Specialist." Commitment#24.G.1 is added.* 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, anda prioritization of the repair areas into areas that must be repaired before returning thesystem to service and areas where coating repair can be postponed to the nextinspection. Commitment #24.G.2 is added.E-1 -6 of 42 With the exception of the EDG 7-day fuel oil tanks, perform subsequent inspections ofcoatings based on the following.i. If no flaking, debonding, peeling, delamination, blisters, or rusting are observed, andany cracking and flaking has been found acceptable, subsequent inspections will beperformed at least once every six years. If the coating is inspected on one train andno indications are found, the same coating on the redundant train would not beinspected during 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 requires newly installed coatings, subsequentinspections will occur during each of the next two refueling outage intervals toestablish a performance trend on the coating.EDG 7-day fuel oil tanks coating inspection:Subsequent coating inspections for the EDG 7-day fuel oil tanks will be at the same10 year interval as TS Surveillance Requirement 4.8.1.1.2.f. If any applied Belzonacoating on the interior of the fuel oil tanks is peeling., delaminating, or blistering, thenthe condition will be repaired and entered into the CAP. Given the favorable SQNexperience with the current Belzona repairs, it is iustifiable to repair the existingcoating applied to localized pits with Belzona and not inspect the coating for another10 years, provided a detached Belzona engineering transportability evaluation hasdetermined that the amount of Belzona applied will not migrate from the EDG 7-daytank to the day-tank. The evaluation will consider Belzona's 2.5 to 3 times higherspecific gravity than diesel fuel, potential size of loosened Belzona particles, surfacearea and depth of the applied Belzona, diesel fuel fluid velocity in the immediate areaof the applied Belzona, proximity of the repaired area to the suction line, and otherfactors.The application of Belzona to repair additional localized pitting in the 7-day EDG fueloil tanks in the future will be installed per vendor specifications. An engineeringevaluation will be performed to ensure that that additional Belzona cannot betransferable out of the tank during the interval between tank inspections and todetermine if the interval of inspections should meet the more frequent inspectionguidelines of LR-ISG-2013-01, or the NRC approved TS Surveillance Requirement of10 years. The engineering transportability evaluation will consider factors such asspecific gravity, size, depth, surface area, and fluid velocity in the evaluation.Commitment #24.D.2 is added.(Note: See LRA page A-24) Perform wall thickness measurements using UT or othersuitable techniques at selected locations to identify loss of material due tomicrobiologically influenced corrosion (MIC) in carbon steel piping components exposedto raw water in the following systems." System 24 -Raw cooling water" System 25 -Raw service water" System 26 -High Pressure Fire Protection" System 27 -Condenser circulating water" System 67 -Essential raw cooling waterE-1 -7 of 42 Choose selected locations based on pipe configuration, flow conditions and operatinghistory to represent a cross-section of potential MIC sites. Periodically review theselected locations to validate their relevance and usefulness, and modify accordingly.Compare wall thickness measurements to nominal wall thickness or previousmeasurements to determine rates of corrosion degradation. Compare wall thicknessmeasurements to minimum allowable wall thickness (Tmin) to determine acceptability ofthe component for continued use. Perform subsequent wall thickness measurements atintervals determined for each selected location based on the rate of corrosion andexpected time to reach Tmin. Perform a minimum of five MIC degradation inspections peryear until the rate of MIC occurrences no longer meets the criteria for recurring internalcorrosion.If more than one MIC-caused leak or a wall thickness less than Tmin is identified in theyearly inspection period, an additional five MIC inspections over the following 12 monthperiod will be performed for each MIC leak or finding of wall thickness less than Tmin.The total number of inspections need not exceed a total of 25 MIC inspections per year.Prior to the period of extended operation, select a method (or methods) from availabletechnologies for inspecting internal surfaces of buried piping that provides suitableindication of piping wall thickness for a representative set of buried piping locations tosupplement the set of selected inspection locations. See revised Commitment #24.C.Changes to LRA Section B.1.31, Periodic Surveillance and Preventive Maintenance Program(PSPM) follow with additions underlined and deletions lined through.Program DescriptionThere is no corresponding NUREG-1801 program.The Periodic Surveillance and Preventive Maintenance (PSPM) Program manages forspecific components' aging effects not managed by other aging management programs,including loss of material, fouling, cracking, and loss of coating integrity, change in materialproperties.Initial coating inspections will begin no later than the last scheduled refueling outage prior tothe PEO. With the exception of the EDG 7-day fuel oil tanks, subsequent coatinginspections will be performed based on the following.i. If no peeling, delamination, blisters, or rusting are observed, and any cracking andflaking has been found acceptable, subsequent inspections will be performed at leastonce every six years. If the coating is inspected on one train and no indications arefound, the same coating on the redundant train would not be inspected during thatinspection interval.ii. If the inspection results do not meet (i), yet a coating specialist has determined that noremediation is required, then subsequent inspections will be conducted every otherrefueling outage.iii. If coating degradation is observed that requires newly installed coatings, subsequentinspections will occur during each of the next two refueling outage intervals toestablish a performance trend on the coating.EDG 7-day fuel oil tanks coating inspection:Subsequent coating inspections for the EDG 7-day fuel oil tanks will be at the same 10 yearinterval as TS Surveillance Requirement 4.8.1.1.2.f. If any applied Belzona coating on theE-1 -8 of 42 interior of the fuel oil tanks is peeling, delaminating, or blistering, then the condition will berepaired and entered into the CAP. Given the favorable SQN experience with the currentBelzona repairs, it is iustifiable to repair the existing coating applied to localized pits withBelzona and not inspect the coating for another 10 years, provided a detached Belzonaengineering transportability evaluation has determined that the amount of Belzona appliedwill not migrate from the EDG 7-day tank to the day-tank. The evaluation will considerBelzona's 2.5 to 3 times higher specific gravity than diesel fuel, potential size of loosenedBelzona particles, surface area and depth of the applied Belzona, diesel fuel fluid velocity inthe immediate area of the applied Belzona, proximity of the repaired area to the suction line,and other factors.The application of Belzona to repair additional localized pitting in the 7-day EDG fuel oiltanks in the future will be installed per vendor specifications. An engineering evaluation willbe performed to ensure that that additional Belzona cannot be transferable out of the tankduring the interval between tank inspections and to determine if the interval of inspectionsshould meet the more frequent inspection guidelines of LR-ISG-2013-01, or the NRCapproved TS Surveillance Requirement of 10 years. The en-gineering transportabilityevaluation will consider factors such as specific -gravity, size, depth, surface area, and fluidvelocity in the evaluation.Carbon steel Perform wall thickness measurements using UT or other suitable techniques atpiping selected locations to identify loss of material due to microbiologically Influencedcomponents corrosion (MIC) in carbon steel piping components exposed to raw water in theexposed to following systems.System 24 -Raw cooling waterraw water System 25 -Raw service waterSystem 26 -High pressure fire protectionSystem 27 -Condenser circulating waterSystem 67 -Essential raw cooling waterChoose selected locations based on pipe configuration, flow conditions andoperating history to represent a cross-section of potential MIC sites. Periodicallyreview the selected locations to validate their relevance and usefulness, andmodify accordingly.Compare wall thickness measurements to nominal wall thickness or previousmeasurements to determine rates of corrosion degradation. Compare wallthickness measurements to minimum allowable wall thickness (Tmin) to determineacceptability of the component for continued use. Perform subsequent wallthickness measurements at intervals determined for each selected location basedon the rate of corrosion and expected time to reach Tmi,. Perform a minimum offive MIC degradation inspections per year until the rate of MIC occurrences nolonger meets the criteria for recurring internal corrosion.If more than one MIC-caused leak or a wall thickness less than Tmi, is identified inthe yearly inspection period, an additional five MIC inspections over the following12 month period will be performed for each MIC leak or finding of wall thicknessless than Ti_, The total number of inspections need not exceed a total of 25 MICinspections per year.Prior to the PEO, select a method (or methods) from available technologies forinspecting internal surfaces of buried piping that provides suitable indication ofpiping wall thickness for a representative set of buried piping locations tosupplement the set of selected inspection locations.E-1 -9 of 42
: 4. Detection of Aging EffectsPreventive maintenance activities and periodic surveillances provide for periodic componentinspections to detect aging effects. Inspection intervals are established such that theyprovide timely detection of degradation prior to loss of intended functions. kR6PeGtiGnf4epmaI&-eSample sizesT and data collection methods are dependent on component materialand environment combinations, and take into con.ideration industry and plant specificoperating experience. and manufacturers' recommendations.For coated piping components, the sample size is an area equivalent to the entire insidesurface of 73 piping segments (1 foot long) or 50% of the total length of each coating type,substrate material, and environment combination. For heat exchangers and tanks, theentire accessible area is inspected.Established techniques such as visual inspections are used. Each inspection occurs atleast once every five years, with the exception of coating inspections. , ... Which froquoc.i s based On coating conditionA.The inspection interval for coated components is based on the condition of the coating.With the exception of the EDG 7-day fuel oil tanks, subsequent coating inspections will beperformed based on the following.i. If no peeling, delamination, blisters, or rusting are observed, and any cracking andflaking has been found acceptable, subsequent inspections will be performed at leastonce every six years. If the coating is inspected on one train and no indications arefound, the same coating on the redundant train would not be inspected during thatinspection interval.ii. If the inspection results do not meet (i), yet a coating specialist has determined that noremediation is required, then subsequent inspections will be conducted every otherrefueling outage.iii. If coating degradation is observed that requires newly installed coatings, subsequentinspections will occur during each of the next two refueling outage intervals to establisha performance trend on the coating.EDG 7-day fuel oil tanks coating inspection:Subsequent coating inspections for the EDG 7-day fuel oil tanks will be at the same10 year interval as TS Surveillance Requirement 4.8.1.1.2.f. If any applied Belzonacoating on the interior of the fuel oil tanks is peeling, delaminating, or blistering, then thecondition will be repaired and entered into the CAP. Given the favorable SQNexperience with the current Belzona repairs, it is iustifiable to repair the existing coatingapplied to localized pits with Belzona and not inspect the coating for another 10 years,provided a detached Belzona engineering transportability evaluation has determined thatthe amount of Belzona applied will not migrate from the EDG 7-day tank to the day-tank.The evaluation will consider Belzona's 2.5 to 3 times higher specific gravity than dieselfuel, potential size of loosened Belzona particles, surface area and depth of the appliedBelzona, diesel fuel fluid velocity in the immediate area of the applied Belzona, proximityof the repaired area to the suction line, and other factors.The application of Belzona to repair additional localized pitting in the 7-day EDG fuel oiltanks in the future will be installed per vendor specifications. An engineering evaluationwill be performed to ensure that that additional Belzona cannot be transferable out of thetank during the interval between tank inspections and to determine if the interval ofE-1 -10 of 42 inspections should meet the more frequent inspection guidelines of LR-ISG-2013-01, orthe NRC approved TS Surveillance Requirement of 10 years. The engineeringtransportability evaluation will consider factors such as specific gravity, size, depth,surface area, and fluid velocity in the evaluation.The selection of components to be inspected will focus on locations which are mostsusceptible to aging, where practical. For coated components, inspection location selectionwill be based on an evaluation of the effect of a coating failure on component intendedfunctions, potential problems identified during prior inspections, and service life history.Established inspection methods to detect aging effects include (1) visual inspections andmanual flexing of elastomeric components and (2) visual inspections or other NDEtechniques for metallic components. Inspections are performed by personnel qualified toperform the inspections.7. Corrective ActionsIf delamination, peeling, or blisters are detected, follow-up physical testing will be performedwhere physically possible (i.e., sufficient room to conduct testing) on at least three locations.The testing will consist of destructive or nondestructive adhesion testing using ASTMInternational standards endorsed in Regulatory Guide 1.54. Corrective actions, includingroot cause determination and prevention of recurrence, are implemented in accordance withrequirements of 10 CFR Part 50, Appendix B.ElementAffectedEnhancement3.ParametersMonitored/Inspected4. Detectionof AgingEffectsPrior to the PEO, perform a visual inspection of a 2-050 percent sample of thecoated piping of the following coated piping systems or an area equivalent to theentire inside surface of 73 1-foot piping segments a maximum of 25 for eachcombination of type of coating, substrate material the coating is protectiRg, andenvironment ombnfiaton. Inspection location selection will be based on anevaluation of the effect of a coating failure on component intended functions,potential problems identified durina prior inspections, and service life history.Visually inspect the surface condition of the coated components to manage loss ofcoating integrity due to cracking, debonding, delamination, peeling, flaking, andblistering. In addition, if coatings are credited for corrosion prevention, the basem~fc=ri~l /in uir' initfw nf rlol~min~tinn vr wh=r been exposed) will be inspected to determine if corrosion has occurred.Pipingi:i.Fire protcctien carbon dioxide (galvanized piping)ii. High pressure fire protection (cement-lined piping)'"" "Makeup water treatment plant (where Saran and Polypropylene applied)v. Essential raw cooling water (where Belzona applied)E-1 -11 of 42
: 3. With the exception of the EDG 7-day fuel oil tanks, perform subsequent inspectionsParameters of coatings based on the following.Monitored/In i. If no flaking, debonding, peeling, delamination, blisters, or rusting arespected observed, and any cracking and flaking has been found acceptable, subsequent4. Detection inspections will be performed at least once every six years. If the coating isof Aging inspected on one train and no indications are found, the same coating on theEffects redundant train would not be inspected during that inspection interval.ii. If the inspection results do not meet (i), yet a coating specialist hasdetermined that no remediation is required, then subsequent inspections will beconducted every other refueling outage.iii. If coating degradation is observed that requires newly installed coatings,subsequent inspections will occur during each of the next two refueling outageintervals to establish a performance trend on the coating.EDG 7-day fuel oil tanks coating inspection:Subsequent coating inspections for the EDG 7-day fuel oil tanks will be at the same10 year interval as TS Surveillance Requirement 4.8.1.1.2.f. If any appliedBelzona coating on the interior of the fuel oil tanks is peeling., delaminating., orblistering, then the condition will be repaired and entered into the CAP. Given thefavorable SQN experience with the current Belzona repairs, it is justifiable to repairthe existing coating applied to localized pits with Belzona and not inspect thecoating for another 10 years, provided a detached Belzona engineeringtransportability evaluation has determined that the amount of Belzona applied willnot migrate from the EDG 7-day tank to the day-tank. The evaluation will considerBelzona's 2.5 to 3 times higher specific gravity than diesel fuel, potential size ofloosened Belzona particles, surface area and depth of the applied Belzona, dieselfuel fluid velocity in the immediate area of the applied Belzona, proximity of therepaired area to the suction line, and other factors.The application of Belzona to repair additional localized pitting in the 7-day EDGfuel oil tanks in the future will be installed per vendor specifications. An engineeringevaluation will be performed to ensure that that additional Belzona cannot betransferable out of the tank during the interval between tank inspections and todetermine if the interval of inspections should meet the more frequent inspectionguidelines of LR-ISG-2013-01, or the NRC approved TS Surveillance Requirementof 10 years. The engineering transportability evaluation will consider factors suchas specific gravity, size, depth, surface area, and fluid velocity in the evaluation.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. lear well (where Epoxy PhenGOGi Goati ngA~isGGsin protective coatingNo. 7155 or equal applied)i "austic. (where TVA soe.s Sec-tion 27 aaolied- draw.in. 166365:-o E-1 -12 of 42 7ICG20--92627 1)}... .................. .... ................... o ...........i..f-. I.k,..- AIAIAAIA Min ') 920-r* A A f- ; f; C C a IV. two ý IV VVO Wr W Wriv ---.0 -am ---.1 r PC2 M M" ---No. 2, 3, Or 4 applied)IItVi6. Gauc19tic batcfllng (whiere 21162" ru-hher lined- with c-FlioRnated rub~ecompouRd applied)vii. Cask decontamination collector (where 2 coats Red Lead in oil, Fed SPECTTP-85 Type II applied)Viii. Main feed pup turFbine oil (whcre ceating applied)iX. Gland eal wateFr (where red oil basod 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 fuel oil (where Belzona applied)xiii. Condensate storageHeat Exchangersi.ii.Electric board room chiller package (where Belzona applied)Incore instrument room water chiller package B (where Belzona applied)6. Include the following acceptance criteria for loss of coating integrity: (1) peeling andAcceptance delamination are not permitted, (2) cracking is not permitted if accompanied byCriteria delamination or loss of adhesion, and (3) blisters are limited to intact blisters thatare completely surrounded by sound coating bonded to the surface.7. Corrective If delamination, peeling, or blisters are detected, follow-up physical testing will beAction performed where physically possible (i.e.. sufficient room to conduct testing) on atleast three locations. The testing will consist of destructive or nondestructiveadhesion testing using ASTM International standards endorsed in Regulatory Guide1.54.Commitments #24.D.E.F and G are added; #24.C is revised to include text fromcommitment #9.F; subsequently, #9.F is deleted.E-1- 13of42 Changes to LRA Tables follow with additions underlined and deletions lined through.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 1Type Function Mateuial Environment Management Program Item Item NotesP-PRg P-Fessu4* Treated W-ater Les-of a PeHio-betindaiy SeiViOe-Level (4#-.) Geat*Rg Surveillance andIm-er-ethe ifegFy PFeventoe0 tPrA' Getn Pfeff~anRTank Press, P Metal-with TrFeated Water bes-ofn perfinroni -betundaiy S-e-woe- Lev'el (m. Geatin ~ Srvilac andQ- eA the RteqFyG~ti~~at afeaTable 3.3.2-17-19: Hypochlorite System, Nonsafety-Related Components Affecting Safety-related SystemsAging Effect AgingComponent Intended Requiring Management NUREG-1801 Table 1Type Function Material Environment Management Program Item Item NotesPOPR9Presruie Metal itWh TFeaded I nrr, n pprfindonibeOindaiy Se-P;0n- eeIev e IWVateF-(. Geoatii ~ Srilnc nill 9F ther integFi PrP~PentM.e_ _aig P*GgFa4:gTan PressuFe Metal-wth Treaded L-ess-f PeFod-HbG64nda ~ Sep,'ine- Level WateF-(*nt.) GeatfRg Survefillance andIll Ar Qthef ntegFyt prevenoeGMatea fa4 eE-1- 14of42 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 NotesTa4Pressure MetAWith Treated .latF Iess-eA P-e-iedie -be9*ida~-y Sepvr LevIele (Ikb Geatfig Surveillance andIII er Athef 4tegFty PFeveRti~eD temal ha.4-; teR eR-ee_ _ _i4 _ _ P+fefa4 _ _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 NotesT44 P2%eewe Metal-wOW T-feetPd -ess-ef P-eFie4edw -beUfdwy SePAGe Level 0i4" Geating Surveillance and111 eF ethef Rteg~ity P~eventev0 RteFRal MalntenaRGe_ _ _ _ _o~ P+egafaR4__Table 3.3.2-17-3: Central Lubricating Oil System, Nonsafet -Related Com ponents Affecting Safety-Related SystemsAging Effect AgingGCmpent Intended Requiring Management NUREG-1801 Table 1Type Function Material Environment Management Program Item Item NotesT[ank P~essUe Metal-with b=6be-go! 4-n.) 1ose AeiiAdie -14boudaFy SeiVwieLevleel Geati.Rg SrilAnc nd"I A- A-thef RteF PetRym RtPFRA' N.Ma4-; mRUBR M -2E-1- 15of42 Table 3.3.2-17-14: Gland Seal Water System, Nonsafety-Related Components Affecting SafeL -Related SystemsAging Effect AgingComponent Intended Requiring Management NUREG-1801 Table 1Type Function Material Environment Management Program Item Item NotesPressure Metal-with Treatd water L-ess-of PeFiedG --Hbe~lRda~y SeFm~eeLevel 0#i-.) GeatW~g SurVeillance andTable 3.4.2-2: Main and Auxiliary Feedwater SystemAging Effect AgingComponent Intended Requiring Management NUREG-1801 Table 1Type Function Material Environment Management Program Item Item NotesTank Pressure Metal with Treated water Loss of Periodic Hboundary Service Level (it.) coating Surveillance andIII or other integrity Preventiveinternal Maintenancecoating ProgramE-1- 16of42 Set 10: RAI 3.0.3-1, Request 4bRAI Response 3.0.3-1, Request 4b supersedes and replaces RAI Response 3.0.3-1,Request 4a entirely. (ADAMS Accession No. ML13357A722, dated December 16,2013, Enclosure 1, pages E-1 -11 to 16 of 43) Changes to RAI 3.0.3-1, Request 4afollow with additions underlined and deletions lined through.a. Table 4a was originally provided to TVA in the Set 10, August 2, 2013 RAI, and laterrevised via an e-mail from the NRC Project Manager on September 26, 2013, ADAMSAccession No. ML13270A037. With the incorporation of the enhancements listed inResponse f. below, the inspections and testing of in-scope fire water systemcomponents will be conducted in accordance with relevant guidance of the NFPA 25(2011 edition) sections listed in Table 4a with exceptions described below.Modified Table 4a Fire Water System Inspection and Testing Recommendations1,2.5Description INFPA 25 SectionSprinkler SystemsSprinkler inspectionss 5.2.1.1Sprinkler testingq 5.3.1Standpipe and Hose SystemsFlow tests 1 6.3.1Private Fire Service MainsUndergqround and exposed pipin~q flow 7.3.1testsHydrants 7.3.2Fire PumpsSuction screens 1 8.3.3.7Water Storage TanksExterior inspections 9.2.5.5-Interior inspections 9.2.6g, 9.2.7Valves and System-Wide TestingMain drain test 13.2.5Deluge valves5  13.4.3.2.2 through 13.4.3.2.5Water Spray Fixed SystemsE-1 17 of 42 Strainers (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)Operational Test Discharge Patterns 11.3.2.6(annually)6Storage tanks (internal -10 years) Visual inspection for internal corrosionObstruction InvestigationObstruction, internal inspection of piping3 1 14.2 and 14.31. 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 energized 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.E-1 18 of 42 Exceotions to the Modified Table 4aInspections specified in Sections 5.2.1.1, 5.2.2 and 5.2.3 are performed on an 18-monthbasis, not an annual basis. The frequency of once every 18-months is appropriate dueto the lack of past inspection findings and the need to perform some of the inspectionsduring a refueling outage.Sections 14.2.1 and 14.2.2: Section 14.2.1 specifies an inspection of piping and branchline conditions every five years unless there are multiple wet pipe systems in a building.For multiple wet pipe systems in a building, Section 14.2.2 allows an inspection on everyother wet pipe system every five years. The inspection consists of opening a flushingconnection at the end of one main and removing a sprinkler toward the end of onebranch line for the purpose of inspecting for the presence of foreign material. SQN istaking the following exception to Sections 14.2.1 and 14.2.2. SQN performs internalinspection of the 72 high pressure fire protection (HPFP) water system strainers andassociated accessible piping every 36 months. If foreign material or corrosion that couldcause blockage is identified, the condition is entered into the CAP. In the last 10 years,only one incident of organic material (clam shells) was identified in the strainer. It wasdetermined that the clam shells entered the system before the HPFP system wasswitched from raw water to potable water in 1998. SQN will perform a one time visu .alinsGpection us6ing the methodology desc~ribed- in NEPPA 25 Section 14.2.1 prior to the PEOto Yerify there are no foreign mnaterials in the dr,' por-tions of the fire wateprys~tem (i.e.,those portions downstream of deluge and pre action valves). Any additional inspectonsGof the dry portion of the fire water syste~m in accore-dance with NF=PA 25, Sections 14.2.1Or 14.2.2 will be based On the one time inspecton r-esults. See the enhancement inResponse f. below and Commitment #9.G.Section 6.3.1 addresses flow testing and Section 6.3.1.5 addresses main drain testing.SQN is taking an exception to conducting a flow test and a main drain test of each zoneof the automatic standpipe system.Every three years, the station flow tests the highest elevation areas in the ERCWbuilding to ensure sufficient pressure and flow at lower elevations. In addition, everythree years, SQN flow tests the fire water hoses in the NRC-approved Fire ProtectionReport (FPR) to ensure the required minimum flow is established. This consists oftesting eight fire water hoses in the control building, thirty-seven fire water hoses inthe auxiliary building, five fire water hoses in the condenser circulating waterbuilding, four fire water hoses in the diesel generator building, and nine fire waterhoses in the ERCW building. Acceptance criteria for the open flow paths consist of(1) verifying valve operability and (2) flow through valve and connection shall beverified and there shall be no indication of obstruction or other undue restriction ofwater flow. In addition, other fire water hose stations are tested to ensure there is anopen flow path through each hose station every five years.Flow or main drain testing increases risk due to the potential for water contactingcritical equipment in the area. In addition, flow and main drain testing in theradiological areas increase the amount of liquid radwaste. Therefore, SQN will notperform main drain tests on every standpipe with an automatic water supply or onevery system riser. SQN will perform 30 25 main drain tests every 18-months(for three 18-month intervals) with at least one main drain test performed in each ofE-1 19 of 42 the following buildings: (1) control building; (2) auxiliary building, (3) turbine building,(4) diesel generator building and (5) ERCW building.The results of the main drain tests from the three 18-month inspection intervals willbe evaluated to determine if the NFPA 25 (2014 Edition) main drain test guidancecan be applied to the number of main drain tests performed (.i.e., Section 13.2.5, "Amain drain test shall be conducted annually for each water supply lead-in to abuilding water-based fire protection system to determine whether there has been achange in the condition of the water supply" and Section 13.2.5.1 'Where the lead-into a building supplies a header or manifold serving multiple systems, a single maindrain test shall be performed.") Commitment #9.0 is revised.Any flow blockage or abnormal discharge identified during flow testing is identifiedand entered into the CAP. Any change in delta pressure during the main draintesting greater than 10% at a specific location will be entered into the CAP.Not performing additional flow or main drain testing in the radiological controlled areaand areas that contain critical equipment required for normal and shutdownoperations reduces risk 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 testing in addition to that described above.Section 7.3.1 addresses flow testing of underground and exposed piping. SQN is takingan exception to flow testing additional underground and exposed piping within control,diesel generator and ERCW buildings for the same reason stated in the exception toSection 6.3.1 above. The station performs testing to determine friction losscharacteristics on approximately 80% of the of the exterior fire water system piping eightinches diameter and larger. In addition, portions of the main ring headers are flow testedin the turbine, service and auxiliary buildings.The tests assess the pressure loss of the various pipe segments. The tests areperformed every three years and the results are trended. Based on ten years of testresults and the use of potable water, there is reasonable assurance of an open flowpath without performing additional flow testing. In addition, hydrants are testedannually.Based on the current testing and trending, the addition of a risk-significant activity,and the production of additional radwaste in RCAs is not warranted.Based on the above exceptions Commitment #9.D is to no longer applicable and isdeleted.Section 13.4.3.2.2 specifies full flow testing of deluge valves. Opening a deluge valveand allowing water flowing out of the open sprinkler heads in critical equipment areas isconsidered a risk-significant activity. In addition, water flow testing in the RCA wouldresult in additional liquid radwaste. As allowed by NFPA-25 (2011) Section13.4.3.2.2.2, an enhancement is provided to perform air, smoke, or other medium testingof deluge valves in critical equipment areas.E-1 20 of 42 SQN will ensure that the dry piping downstream of deluge valves protecting indoorareas containing critical equipment by flow testing with air, smoke or other medium toensure pipes from deluge valve through the sprinkler heads are clear.Based on the trip testing of the deluge valves without flow through the downstreampiping and sprinkler heads, additional testing in the RCA or areas containing criticalequipment is not warranted due to the addition of risk-significant activities and theproduction of additional radwaste. See commitment #9.M.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. SQN has demonstrated the use of UT on theERCW system to identify blockage from silt and clams. According to the NFPA-25(2011) handbook, the use of x-ray, ultrasound, and remote video techniques can beused in lieu of impairing the system to conduct visual inspections. The use of thesetechniques provides reasonable assurance that the effects of aging will be managedsuch that the fire water system components will continue to perform their intendedfunctions consistent with the current 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 pre-action sprinkler system piping and valves, willbe inspected prior to the PEO. See Commitments #9.G and P. For piping sectionswhere drainage is not occurring as expected, the following actions will be performed.i. a) One of the following inspection methods will be used to ensure there is no flowblockage in each five-year interval beginning with the five-year interval before thePEO:(1) Perform a flow test or flush sufficient to detect potential flow blockage.(2) Remove sprinkler heads or couplings in the areas that do not drain andperform a 100% visual internal inspection to verify there are no signs ofabnormal corrosion (wall thickness loss) or blockage.(3) Perform a 100% UT examination of the area that does not drain to identifyblockage.If option (a. 1) is chosen, controls will be established to ensure potentialblockage is not moved to another part of the system where it may beundetected.b) In each five-year interval during the PEO, 20% of the length of piping segmentsthat cannot be drained or piping segments that allow water to collect will besubiected to UT wall thickness examination. The piping examined during eachinspection interval will be piping that was not previously examined.One of two inspection moethedr will be used. Sprinklor heads Or couIplings will beremoved prior to the PEG in the area that does not drain and a visual internal4i nspection will be performned to verify there are no signs of abno-rmal co-rrosion (wallE-1 21 of 42 thickness los6) 9r blockage. An alternative method to the visualinenlnpctoIs an IT .m toto identify blockage.ii. The monitored parameter is the condition of the internal surface.iii. The inspections will be performed within five years prior to the PEO andsubsequent inspections will be once every five years during the PEO.iv. The extent of the inspection will consist of verifying that there is no blockage in thearea that does not drain.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. Any signs of abnormal corrosion or blockage will be entered into theCAP.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. The fire water tanks have been removed from the Above Ground Metallic TanksProgram and included in the Fire Water Systems Program. The fire water storage tankswill be inspected in accordance with NFPA-25 (2011 Ed.) requirements. SeeCommitment #9.J.f. The change to LRA Section A.1.1 follows with additions underlined and deletions linedthrough."The Aboveground Metallic Tanks Program includes outdoor tanks on soil or concreteand indoor large volume water tanks (excluding the fire water storage tanks) situatedon concrete that are designed for internal pressures approximating atmosphericpressure. Periodic external visual and surface examinations are sufficient to monitordegradation. Internal visual and surface examinations are conducted in conjunctionwith measuring the thickness of the tank bottoms to ensure that significant degradationis not occurring and the component's intended function is maintained during the PEO.Internal inspections are conducted whenever the tank is drained, with a minimumfrequency of at least once every 10 years, beginning in the 5-year prior to the PEO."See Commitment #1.B.The change to LRA Section B.1.1 follows with additions underlined and deletions linedthrough."The Aboveground Metallic Tanks AMP is a new program that manages loss ofmaterial and cracking fe. of the outside and inside surfaces of the aboveground tankssituated on concrete or soil. Outdoor tanks, (excluding the fire water storage tanks),and certain indoor tanks are included. The program relies on periodic inspections tomonitor for the effects of aging. Tank inside surfaces are inspected by visual or surfaceexamination methods as necessary to detect the applicable aging effects.This program will manage the bottom surface of aboveground tanks that are supportedon earthen or concrete foundations. The program will require UT of the tank bottomsto assess the thickness against the specified thickness in the design specification.Tank inspections are performed in accordance with the table in LRA Section A. 1 .1.E-1 22 of 42 This program will be implemented prior to the period of extended operation."The changes to LRA Section A.1.13 follow with additions underlined and deletions linedthrough."The Fire Water System Program (FWSP) 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 FWSP procedures to ensure sprinkler heads are tested in accordancewith NFPA-25 (2011 Edition), Section 5.3.1. See Commitment #9.C.* Commitment #9.B is deleted.* Revise FWSP procedures to periodically remove a representative sample ofcomponents such as sprinkler heads or couplings within five years prior to thePEO and every five years during the PEO, to perform a visual internal inspectionof dry fire water system piping for evidence of corrosion, loss of wall thickness,and foreign material that may result in flow blockage using the methodologydescribed in NFPA-25 Section 14.2.1. This includes the- sections of dry pipingdescribed in NRC Information Notico (IN) 2013 06, whoro drainage is notGG6iF~- The acceptance criteria shall be "no debris" (i.e., no orsoproducts- that could impede flow Or cause downstreamn components to becoernclogged). .Ay signs of abnormal bckago will he into the1A R.Commitment #9.G is revised. Commitment #9.A is deleted. Commitment#9.G replaces #9.A.Revise FWSP procedures to perform one of the following inspection methods forthose sections of dry piping described in NRC Information Notice (IN) 2013-06,where drainage is not occurring, to ensure there is no flow blockage in each five-year interval beginning with the five-year period before the PEO:(a) Perform a flow test or flush sufficient to detect potential flow blockage.(b) Remove sprinkler heads or couplings in the areas that do not drain andperform a 100% visual internal inspection to verify there are no sigqns ofabnormal corrosion (wall thickness loss) or blockage.(c) Perform a 100% UT examination of the area that does not drain to identifyblockage.If option (a) is chosen, controls will be established to ensure potential blockage isnot moved to another part of the system where it may be undetected.In each five-year interval during the PEO, 20% of the length of piping segmentsthat cannot be drained or piping segments that allow water to collect will besubiected to UT wall thickness examination. The piping examined during eachinspection interval will be piping that was not previously examined.Commitment #9.P is added.E-1 23 of 42
* Re~vise, the- Fire Water System Program full flow tes6ting to be OR accpordan-e. Withfull flow te.tig standaFdr. of NEPA 25 (2011). Commitment #9.D is deleted.Commitment #9.0 replaces #9.D.* Revise Fire W~ater System Programn procedures based on the results of afeasibility study to perform the mnain dr-ain tests iacodneWith NFPP.A 215(2011 Edition) Sect*io 13.2.5. Commitment #9.L is deleted. Commitment #9.0replaces #9. L." Revise FWSP procedures to perform an obstruction evaluation in accordancewith NFPA-25 (2011 Edition), Section 14.3.1. See Commitment #9.H." Revise FWSP procedures to conduct follow-up volumetric examinations ifinternal visual inspections detect surface irregularities that could be indicative ofwall loss below nominal pipe wall thickness. See Commitment #9.1.* Revise FWSP procedures to annually inspect the fire water storage tank exteriorpainted surface for signs of degradation. If degradation is identified, conductfollow-up volumetric examinations to ensure wall thickness is equal to or exceedsnominal wall thickness. The fire water storage tanks will be inspected inaccordance with NFPA-25 (2011 Edition) requirements. See Commitment #9.J." Revise FWSP procedures to include a fire water storage tank interior inspectionevery five years that includes inspections for signs of pitting, spalling, rot, wastematerial and debris, and aquatic growth. Include in the revision direction toperform fire water storage tank interior coating testing, if any degradation isidentified, in accordance with ASTM D 3359 or equivalent, a dry film thicknesstest at random locations to determine overall coating thickness; and a wetsponge test to detect pinholes, cracks or other compromises of the coating. Ifthere is evidence of pitting or corrosion ensure the FWSP procedures directperformance of an examination to determine wall and bottom thickness. SeeCommitment #9.K.Revise FWSP procedures to perform annual spray head discharge pattern testsfrom all open spray nozzles to ensure that patterns are not impeded by pluggednozzles, to ensure that nozzles are correctly positioned, and to ensure thatobstructions do not prevent discharge patterns from wetting surfaces to beprotected. Where the nature of the protected critical equipment or property issuch that water cannot be discharged, the nozzles shall be inspected for properorientation and the system tested with air, smoke or some other medium toensure that the nozzles are not obstructed.Revise FWSP procedures to ensure that the dry piping is unobstructeddownstream of deluge valves protecting indoor areas containing criticalequipment by flow testing with air, smoke or other medium from deluge valvethrough the sprinkler heads. Based on the trip testing of the deluge valveswithout flow through the downstream piping and sprinkler heads, additionaltesting in the RCA or areas containing critical equipment is not warranted due tothe addition of risk-significant activities and the production of additional radwaste.See Commitment #9.M.Revise FWSP procedures to perform an internal inspection of the accessiblepiping associated with the strainer inspections for corrosion and foreign materialE-1 24 of 42 that may cause blockage. Document any abnormal corrosion or foreign materialin the CAP. See Commitment #9.N." Revise FWSP procedures to perform 30 25 main drain tests every 18-months(for three 18-month intervals) with at least one main drain test performed in eachof the following buildings: (1) control building, (2) auxiliary building, (3) turbinebuilding, (4) diesel generator building and (5) ERCW building.The results of the main drain tests from the three 18-month inspection intervalswill be evaluated to determine if the NFPA 25 (2014 Edition) main drain testguidance can be applied to the number of main drain tests performed (.i.e.,Section 13.2.5, "A main drain test shall be conducted annually for each watersupply lead-in to a building water-based fire protection system to determinewhether there has been a change in the condition of the water supply" andSection 13.2.5.1 'Where the lead-in to a building supplies a header or manifoldserving multiple systems, a single main drain test shall be performed.")Any flow blockage or abnormal discharge identified during flow testing or anychange in delta pressure during the main drain testing greater than 10% at aspecific location is entered into the CAP.Flow or main drain testing increases risk due to the potential for water contactingcritical equipment in the area, and main drain testing in the RCAs increases theamount of liquid radwaste. Therefore, SQN will not perform main drain tests onevery standpipe with an automatic water supply or on every system riser.See Commitment #9.0.* Revise FWSP procedures to include acceptance criteria equivalent to "no debris"(i.e., no corrosion products that could impede flow or cause downstreamcomponents to become clogged). Any signs of abnormal corrosion or blockagewill be removed, its source determined and corrected, and entered into the CAP.See Commitment #9.G.The changes to LRA Section B.1.13 follow with additions underlined and deletions linedthrough."The Fire Water System Program (FWSP) manages loss of material and fouling for fireprotection components and the fire water storage tanks that are tested in accordancewith the SQN Fire Protection Report (FPR) and LR Commitment #9.Consistent with NFPA 25, the SQN program includes system performance testing inaccordance with the FPR. This periodic full-flow testing includes monitoring thepressure of tested pipe segments, which verifies that system pressure remainsadequate for system intended functions. Results are trended. Periodic flushing is alsoperformed in accordance with the FPR.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 ofE-1 25 of 42 extended operation and at plant-specific intervals based during the period of extendedoperation. Periodic visual inspections of fire water system internals will monitorsurface 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 in accordance with SQN FPR and LR Commitment #9before the end of 50-year sprinkler service life and every ten years thereafter duringthe period of extended operation. General requirements of the program include testingand maintaining fire detectors and visually inspecting the fire hydrants to detect signsof corrosion. Fire hydrant flow tests are performed annually to ensure the fire hydrantscan 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."Elements AffectedEnhancements4. D~~tfn of A,...,.OfeetgReviso Fire Water System Program to i.. ncludc one ofthe following options:.allI thr~k~r'r eylate Of fi~ MFt~t9 M *ic SOCi ntrusive techniques (e.g., volumetric testing) to identify evidence otloss of material will be performed prior to the period of extendedoperation and periodically thpeireaftper. Rpesults of the initiaevaluationls will be used to determline the appropriate Iinpectioninterval to ensure aging effecGts are identified prior te loss otintended function.*A visual inspection Of the intrna srface of fire protection pipingwvill be performed upon each ontrY into the system for rou tine orcorrective mnainten-ance. These insF~ecti9ns will be canable ofevaluating (1) Wa_41 thickness_; to ensure against catastrophic failureand-- -- (2) I diameter of the piping as it applies to the designflewý of the fire protection system. Maintenance history shall be usedto demonstrate that such inspections have been perfomAed on arepresentatfive numbe~Pr Of locGations prior to the period of extendedoperation. A representative number is 20 percent of the population(defined as Iocations having the same material, eVnironment, andaging effect combination) with a maximum of 25 locations,.Additional inspections Will be performned as needed to obtain thisrepresentatfive sample prior to the period of ex(tended operation andnnrir~irI 0- ^^rr;a hana,4, ^f -f-A-4ar k-A~~n -nnn athv;ulfufAt. tran, %I~ I lfff**ll ^rtn rflnr nror tn tP ¶nnr~nlnextended operation. Commitment #9.B is deleted.4. Detection of AgingEffectRevise FWSP procedures to ensure sprinkler heads are tested inaccordance with NFPA-25 (2011 Edition), Section 5.3.1E-1 26 of 42
: 4. Detection of Aging Revise FWSP procedures to perform an obstruction evaluation inEffect accordance with NFPA-25 (2011 Edition), Section 14.3.1.4. Detection of Aging Revise FWSP procedures to perform an internal inspection of theEffect accessible piping associated with the strainer inspections forcorrosion and foreign material that may cause blockage. Documentany abnormal corrosion or foreign material in the Corrective ActionProgram.4. Detection of Aging Revise FWSP procedures to perform 30 25 main drain tests everyEffect 18-months (for three 18-month intervals) with at least one maindrain test performed in each of the following buildings: (1) controlbuilding, (2) auxiliary building, (3) turbine building, (4) dieselgenerator building and (5) ERCW building.The results of the main drain tests from the three 18-monthinspection intervals will be evaluated to determine if the NFPA 25(2014 Edition) main drain test guidance can be applied to thenumber of main drain tests performed (i.e., Section 13.2.5, "A maindrain test shall be conducted annually for each water supply lead-into a building water-based fire protection system to determinewhether there has been a change in the condition of the watersupply" and Section 13.2.5.1 "Where the lead-in to a buildingsupplies a header or manifold serving multiple systems, a singlemain drain test shall be performed.")Any flow blockage or abnormal discharge identified during flowtesting is identified and entered into the CAP. Any change in deltapressure during the main drain testing greater than 10% at aspecific location will be entered into the CAP.Flow or main drain testing increases risk due to the potential forwater contacting critical equipment in the area, and main draintesting in the RCAs increases the amount of liquid radwaste.Therefore, SQN will not perform main drain tests on everystandpipe with an automatic water supply or on every system riser.3. Parameters Revise FWSP procedures to periodically remove a representativeMonitored or Inspected sample of components such as sprinkler heads or couplings, fiveyears prior to the PEO, and every five years during the PEO, toperform a visual internal inspection of dry fire water system pipingfor evidence of corrosion, loss of wall thickness, and foreignmaterial using the methodology described in NFPA-25 Section14.2.1. Thri inrcldes +h tho.. sections of dry piping described in NRCInf,9ormAtion. NolGt (IN) 2013 06, whee drainage 6 occurriRgdue teodesign.The acceptance critcria shall be "no debris" (i.e., no corrosionproducts, that could impede flew Or cause doWnstream componentsto becoeme clogg9ed). Any signs of abnormnal corrosion Or blockageweill be entercd into the CAP-. Commitment #9.G is revised.E-1 27 of 42
: 4. Detection of Aging Effect Revise FWSP procedures to conduct follow-up volumetricexaminations if internal visual inspections detect surfaceirregularities that could be indicative of wall loss belownominal pipe wall thickness.4. Detection of Aging Effect Revise FWSP procedures to annually inspect the fire waterstorage tank exterior painted surface for signs of degradation.If degradation is identified, conduct follow-up volumetricexaminations to ensure wall thickness is equal to or exceedsnominal wall thickness. The fire water storage tanks will beinspected in accordance with NFPA-25 (2011 Edition)requirements.4. Detection of Aging EffectRevise FWSP procedures to perform One of the followinginspection methods for those sections of dry piping sectionsthat are not draining to ensure there is no flow blockage ineach five-year interval beginning with the five year periodbefore the PEO:(a) Perform a flow test or flush sufficient to detectpotential flow blockage.(b) Remove sprinkler heads or couplings in the areasthat do not drain and perform a 100% visual internalinspection to verify there are no sians of abnormalcorrosion (wall thickness loss) or blockage.(c) Perform a 100% UT examination of the area thatdoes not drain to identify blockaae.I I IIf ootion (a) is chosen. controls will be established to ensurepotential blockage is not moved to another part of thesystem where it may not be detected.In each five-year interval durina the PEO. 20% of the lenathof piping segments that cannot be drained or pipingseaments that allow water to collect will be subiected to UTwall thickness examination.The pipinq examined durinq each inspection interval will bepiping that was not previously examined.Commitment #9.P is added.=V Vý V FU H ur ya um FkxqFc1M prvtýfi d! 41ý%A: +^ý+in +^ k^ im %Ai;+k ;ail! +I^tA# +^ý+,tandards of NFoPA 25(2011) Commitment #9.D is deleted.r.sulto of a fea;ibility .tud,: to perform the .aindR. E ;ai tests inaCormmane with NFtPA 25 (2011 EditiOn) eteon 13.2.5.Commitment #9.L is deleted.E-1 28 of 42
: 4. Detection of Aging Effect Revise FWSP procedures to include a fire water storage tankinterior inspection every five years that includes inspectionsfor signs of pitting, spalling, rot, waste material and debris,and aquatic growth. Include in the revision direction toperform 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 todetermine overall coating thickness; and a wet sponge test todetect pinholes, cracks or other compromises of the coating.4. Detection of Aging Effect Revise FWSP procedures to perform a non-destructiveexamination to determine wall thickness wheneverdegradation is identified during internal tank inspections.4. Detection of Aging Effect Revise FWSP procedures to perform annual spray headdischarge pattern tests from all open spray nozzles to ensurethat patterns are not impeded by plugged nozzles, to ensurethat nozzles are correctly positioned, and to ensure thatobstructions do not prevent discharge patterns from wettingsurfaces to be protected. Where the nature of the protectedcritical equipment or property is such that water cannot bedischarged, the nozzles shall be inspected for properorientation and the system tested with air, smoke or someother medium to ensure that the nozzles are not obstructed.Revise FWSP procedures to ensure that the dry piping isunobstructed downstream of deluge valves protecting indoorareas containing critical equipment by flow testing with air,smoke or other medium from deluge valve through thesprinkler heads.Based on the trip testing of the deluge valves without flowthrough the downstream piping and sprinkler heads,additional testing in the RCA or areas containing criticalequipment is not warranted due to the addition of risk-significant activities and the production of additionalradwaste.6. Acceptance Criteria The acceptance criteria shall be "no debris" (i.e., no corrosionproducts that could impede flow or cause downstreamcomponents to become clogged). Any signs of abnormalcorrosion or blockage will be removed, its source determinedand corrected, and entered into the CAP.Commitment #9.F is moved to #24.C; then #9.F is deleted. Commitments #9.A.D.F.L aredeleted; #9.G.O are revised; and #9.P is added.E-1 29 of 42 LRA Table 3.3.2-2: High Pressure Fire Protection -Water System, line items and the corresponding Table 3.3.1 and 3.3.4Component Intended Aging Effect Aging NUREG-1801 Table 1Function Material Environment Requiring Management Item Item NotesType Management ProgramTank Pressure Carbon Air-outdoor Loss of Fire Water System VII.HI.A-95 3.3.1-67 Eboundary steel (ext.) materialTank Pressure Carbon Concrete (ext.) Loss of Fire Water System VIII.E.SP-115 3.4.1.30 Eboundary steel materialTank Pressure Carbon Soil (ext.) Loss of Fire Water System VIII.E.SP-115 3.4.1-30 Eboundary steel material3.3.1-67 Steel tanks exposed Loss of material Chapter XI.M29, No Loss of material for steel tanks, except fire water storage tanks,to air -outdoor due to general, "Aboveground exposed to outdoor air is managed by the Aboveground Metallic Tanks(external) pitting, and Metallic Tanks" Program. The Fire Water System Program manages loss of materialcrevice for fire water storage tanks.corrosion3.4.1-30 Steel, stainless steel, Loss of material Chapter XI.M29, No Consistent with NUREG-1801 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 Program manages loss of material for fire water storage tanks exposedoutdoor (external) corrosion to concrete or soil. Loss of material for stainless steel tanks exposedto outdoor air (applies to components in Table 3.2.2-1 only) ismanaged by the Aboveground Metallic Tanks Program. There are noaluminum or stainless steel tanks exposed to outdoor air in the steamand power conversion systems in the scope of license renewal.E-1 30 of 42 Set 10: RAI 3.0.3-1, Request 6b cracking for aluminium and copper componentsAs a result of a teleconference call with Mr. Plasse, NRC, on December 17, 2013, TVA providesadditional responses to RAI Response 3.0.3-1, Request 6a and revisions to LRA Tables 3.4.2-2and 3.4.2-3-9, to address the issue of cracking of aluminum and copper alloy (>15% Zn or >8%Al) components under insulation. (ADAMS Accession No. ML13357A722, dated December 16,2013, Enclosure 1, pages E-1 -22 of 43) Changes to RAI 3.0.3-1, Request 6a follow withadditions underlined.Cracking as an aging mechanism with the environment of condensation will be added to thefollowing tables (that contained copper alloy piping and aluminum piping):Table 3.4.2-3-9: Condenser Circulating Water System, Nonsafety-Related ComponentsAffecting Safety-Related Systems Summary of Aging Management EvaluationPiging Pressure Copper Condensation Cracking External _Hboundary alloy > (ext) Surfaces 40415% Zn Monitoringor > 8%AlTable 3.4.2-2: Main and Auxiliary Feedwater System Summary of Aging ManagementEvaluationaioin Pressure Aluminum Condensation Cracking External -iboundary (ext) Surfaces 404MonitoringE-1 31 of 42 Set 14: RAI B.1.34-8, Clevis Bolt (non-proprietary/redacted version)Background:LRA Table 3.1.2-2, Reactor Vessel Internals, indicates that the clevis insert bolts are nickel alloy andthat cracking will be managed by the Reactor Vessel Internals Program in the "no additional measure"inspection category. Appendix A to Materials Reliability Program: Pressurized Water Reactor InternalsInspection and Evaluation Guidelines (MRP-227-A) (Reference 1) indicates that failure of Alloy X-750,precipitation-hardenable nickel-chromium alloy, clevis insert bolts were reported by one Westinghousedesigned plant in 2010. Furthermore, the staff noted that these clevis insert bolts failed because ofcracking, which is an aging effect that was not addressed in MRP-227-A.The staff noted that the only aging mechanism requiring management by MRP-227-A for the clevis insertbolts is wear and the bolts are categorized as an "Existing Programs" component. Thus, under MRP-227-A, the clevis insert bolts will be inspected in accordance with the ASME Code, Section X1 InserviceInspection Program to manage the effects due to wear only.Issue:The staff noted that the ASME Code, Section X1 specifies a VT-3 visual inspection for the clevis insertbolts, which may not be adequate to detect cracking before bolt failure occurs. In addition, since crackingof the clevis insert bolts was not addressed during the development ofMRP-227-A, it is not clear to the staff whether this operating experience is applicable to the applicantand whether the Reactor Vessel Internals Program will need to be modified to account for this operatingexperience.Request:1. Specify the fabrication material, including any applicable heat treatment, for the clevis insert bolts atUnits I and 2.2. Discuss and justify whether the operating experience associated with cracking of the clevis insertbolts is applicable to Units I and 2.a. If applicable, discuss and justify how the Reactor Vessel Internals Program will be augmentedto require an inspection of the clevis insert bolts capable of detecting cracking. If the ReactorVessel Internals Program will not be augmented, provide a technical justification for theadequacy of the existing VT-3 visual inspection to detect cracking before it results in clevisinsert bolt failure.TVA RAI B.1.34-8 Response:The following response provides the technical justification for the adequacy of the existing inspectionrequirement to manage the effects of possible cracking of lower radial support clevis insert bolts (capscrews).1. Fabrication MaterialThe cap screws installed at SQN Units 1 and 2 were fabricated from Inconel X-750 material. Theprocurement specification outlined a heat treatment very similar to what would be considered as [heat treatment, but preceded with an equalization heat treatment. The following heat treatmentsequence was used:* [I* [IE-1 32 of 42 This material and heat treatment is the same as used for the clevis insert cap screws at the referenceplant where cracking has been observed (Reference 2). The cap screws are of the same design, exceptthat the SQN cap screw shank length is [ ] longer. The cap screws were installed with the sametorque as that used for the reference plant.2. Cracked Clevis Insert Cap Screw Operatingq Experience ApplicabilityThe main function of the Lower Radial Support System (LRSS) is to prevent tangential or rotationalmotion of the lower internals assembly while permitting axial displacement and differential radialexpansion. SQN Units 1 and 2 have six radial supports spaced at 60 degree intervals around thecircumference of the vessel. Although labeled as radial supports, the supports actually support the corebarrel only in the tangential direction because the tangential clearances between the core barrel keysand the vessel clevis inserts are much smaller than the radial clearances. This basic arrangement is thesame for the SQN units and the reference plant where clevis insert cap screw cracking was observed;however, the clevis designs are different. See Figure 1 for this comparison. The same number of eightcap screws is arranged in the same two vertical columns of four cap screws each. Two interference-fitdowel pins of the same size are located in-line with the cap screws in the same manner as the referenceplant. The main design difference is that the SQN reactor clevis insert is U-shaped, with the cap screwslocated inboard of the "U"; whereas the reference plant insert, while also being U-shaped, has flanges oneither side where the cap screws are located. The tangential interference fit of the insert against thesupport lug is at the ends of these flanges for the reference plant design and on the sides of the "U" forthe SQN reactor design. Therefore, the tangential interference-fit compression stiffness of the two insertsare different.Because of the small tangential clearance between the radial keys and the clevis insert, the keys arepotentially subjected to flow-induced vibration loads and wear at the key-to-keyway (clevis) interface.These supports are designed to prevent excessive lateral and rotational displacement of the lowerinternals during seismic and loss-of-coolant accident (LOCA) conditions. The supports also limitdisplacements and misalignments in order to avoid overstressing the core barrel and to ensure that thecontrol rods can be freely inserted. Therefore, assuming the clevis inserts remain in place as limited bythe adjoining radial keys and support lugs, the design function of the LRSS will be maintained duringseismic and LOCA conditions.Because the clevis insert cap screws for the SQN units are of the same design (except for the [ ]longer shank), of the same material, torqued to the same degree, and operated at close to or slightlyhotter TwId inlet temperatures as compared to the reference plant, it is possible that these cap screwscan eventually crack in a manner similar to that of the reference plant in Reference 2. Therefore, theoperating experience discussed above is applicable to SQN Units 1 and 2. A recent draft reportsummarizing metallurgical investigations of the degraded cap screws from the reference plant providedpreliminary confirmation that primary water stress corrosion cracking (PWSCC) was the failuremechanism.As discussed in Reference 2, structural evaluations performed to justify continued operation in theas-found condition demonstrated safe operation was acceptable for an additional fuel cycle. The onlyconcern was possible long-term effects, such as the potential for vibratory loads to eventually causeloosening and wear of the insert and the subsequent increase in gaps between the insert, radial key, andsupport lug. For this evaluation, due to the difference in design of the clevis insert, a similar review ofthe structural adequacy of the SQN clevis insert design was performed to determine if broken capscrews present a structural concern for safe operation. The structural aspects and loose partsassessment, as performed for Reference 2, are discussed in the following paragraphs.Clevis Support Lug Primary StressThe clevis insert, if completely loose to slide radially inward, is captured in a manner similar to thereference plant and is restrained by a similar radial gap before it contacts the radial key. This conditionwould require the two interference-fit dowel pins to also lose restraint. With the clevis insert displacedE-1 33 of 42 fully inward, the primary stresses on the clevis support lugs remain acceptable relative to the reactorvessel original ASME, 1968 Edition, code of construction under plant-specific maximum upset andfaulted condition loads due to seismic and LOCA conditions. These loads include the maximum impactloads that occur against the clevis inserts.Clevis Insert Primary Plus Secondary StressThe bending stress of the insert is maximized if it is assumed that one entire column of cap screws isbroken and the other column of screws is intact. This forces the loose side of the insert to expand andcontract to a greater extent relative to the support lug. With the maximum resulting interference duringheatup and maximum tangential and radial loadings during cooldown, when a small clearance can exist,the resulting stress range remains within the primary plus secondary stress range analyzed in thegeneric analysis of record for this clevis insert design. Therefore, the increase in insert stress due tobroken cap screws remains acceptable.Cap Screw Primary Plus Secondary StressThis scenario uses the same cap screw arrangement as discussed above where one column of capscrews is entirely broken. In this case, during cooldown, when the insert is not tangentially preloadedagainst the support lug, the entire applied radial load on the insert is reacted by the intact cap screws.The resulting cap screw stress produced by this prying load on the insert is acceptable with four intactscrews. However, with three or less intact screws, the allowable stress intensity can be potentiallyexceeded. During heatup or steady-state operation, the clevis insert remains preloaded against thesupport lug, and this type of loading on the intact screws will not occur.Clevis Insert Restraining Force (No Cap Screws)If all of the cap screws are broken, and no restraint by the dowel pins is assumed, the clevis insert canstill resist sliding. During normal hot operation, the insert maintains preload over the range of initialshrink-fit interference applied to the insert. As a result, the frictional resistance of the insert against thesupport lug is always greater than the applied frictional radial loads acting on the insert from the key.These hot preload forces are greater than the forces in the range calculated for the reference plant, andso have greater resistance to loosening and sliding. Therefore, although long-term loosening and wear,which would be expected to occur over more than a few cycles, cannot be ruled out, the clevis insertdesign installed at SQN Units 1 and 2 provides improved resistance to such long-term effects relative tothe reference plant. Operating experience with damaged bolts and one dowel pin, as described inReference 2, showed no discernible change in the clevis insert wear surfaces after operation for twoadditional cycles. It is fully expected that with the design installed at SQN Units 1 and 2, longeroperation can be maintained before discernable degradation occurs. In addition, the insert has a thickupper flange that prevents it from falling downward, and the downward force from the downcomer flowwill prevent it from working upward.Likewise, during core barrel removal at cold conditions, the interference fit of the insert provides greaterfrictional force than the applied frictional force produced by the key sliding upward against the insert.The two dowel pins will also provide additional vertical constraint of the insert. Therefore, in addition tonormal operation, the clevis insert design also prevents separation of the insert during core barrelremoval operations if the cap screws (and dowel pins) are non-functional.Loose Parts AssessmentAs discussed above, loss of the insert itself will not occur. Although over time, it may slowly displaceradially inward toward the core barrel key by approximately 0.7 to 0.8 inches, it will not move any further.The remaining engagement of the insert in the support lug will maintain adequate support of the corebarrel against any normal, upset, or faulted condition loads.The insert cap screws have the same head design and locking device design as the reference plant. Alock bar is installed in a groove in the cap screw head and the bar is welded to the insert counterborewhere the cap screw is inserted. If a cap screw head should separate, the lock bar can, over time, wearE-1 34 of 42 and separate, causing the cap screw head to be loose in the counterbore recess. The as-built radialgaps measured between the core barrel radial keys and the inserts are all less than the height of the capscrew heads by at the least, [ ] for one unit and [ ] for the other unit. Therefore, the cap screwheads remain captured, unless over a long period of time, wear of the heads reduces the height of theheads by this amount. The cap screw head wear is expected to be small because the cap screwmaterial is much harder than the clevis insert and radial key material. During hot pressurized operation,the radial gaps reduce by [ I , which would increase the retention interference to [ ].Evaluations were performed on the potential for loose parts with failed clevis insert cap screws for thereference plant (Reference 2). Lock bars at the degraded cap screw locations have experiencedwear-related degradation; therefore, the potential for loose parts from the lock bars to affect otherlocations in the reactor vessel was also evaluated. The SQN units and the reference plant have thesame lower internals design which uses a thermal shield, domed lower support plate and secondarycore support arrangement, and diffuser plate; therefore, the effects of where these loose parts would becaptured or would impact against the lower internals is the same. Therefore, no significant degradationof mechanical components is expected as a result of the potential presence of loose parts from the lockbars in the primary system.3. Reactor Vessel Internals Pro-gram Au-gmentation AssessmentBased on the structural evaluations above and operation with potential loose parts of the type andquantities that are no different than have already been evaluated, safe operation of the reactors andprimary systems at SQN Units 1 and 2 is assured. The ability of the LRSS to perform its intendeddesign function under seismic and LOCA condition loadings is unrelated to the integrity of the capscrews and dowel pins that are used to hold the clevis insert in place. If all of the cap screws and dowelpins separate, complete disengagement of one of the clevis inserts will not occur, because of the smallsize of the gaps between the clevis inserts and radial keys. [ ] Wear orsome degradation of a key might occur, but the key would still be expected to maintain functionality.Taken as a whole, the core barrel and LRSS are expected to maintain their design function withdegraded clevis insert bolts. Based on the evaluations performed to date, there are no safety oroperability concerns.Relative to augmentation of the reactor internals inspection program, crack detection prior to cap screwfailure is not required due to inherent design redundancy as discussed above. The only aspect toconsider is the possibility of wear and looseness of the insert if the cap screws should becomedegraded. The MRP-227-A categorization for wear-only is based on the primary concern for clevis insertlooseness and wear of the clevis insert and radial key interfacing surfaces that could potentially lead toincreased motion at the bottom end of the core barrel, rather than bolt material cracking. SCC wasconsidered and screened in MRP-191 (Reference 3). Actions to address SCC are included inMRP-227-A, Existing Category Components. Manifestation of cap screw cracking is identified as aresult of the observation of wear (see note 2 of Table 4-9, MRP-227-A). Existing inspections are alreadyin place to account for concern. Qualified SQN personnel performing video camera inspections at10-year intervals, as specified in ASME Code Section Xl and MRP-227-A, are capable of identifyingwear or dislodged components of the clevis insert cap screws or dowel pins at any location. Visualinspection at 10-year intervals can also detect wear and displacement of the clevis insert. Inspection ofthe insert and key contact surfaces can detect wear-in relative to adjacent non-contact surfaces. If capscrew heads are observed to be loose, any movement of the insert relative to the vessel support lug canbe easily observed. Anomalous conditions of this sort will result in corrective actions before any LRSSloss of function can occur. During the last in-service inspections at Unit 1 in 2005 and Unit 2 in 2004, noindications of loosening or adverse wear were observed. Based on these considerations andobservations, the Reactor Vessel Internals Inspection program will not be augmented for crack detectionof the lower radial support clevis insert bolts. Continued monitoring of industry operating experience inthe area will be performed and the program will be modified, if necessary. See Commitment #27.C.E-1 35 of 42 Support LugReference Plant (Reference 2) SQN Units 1 and 2Figure 1Lower Radial Support ComparisonReferences1. EPRI Document, MRP-227-A, "Materials Reliability Program: Pressurized Water ReactorInternals Inspection and Evaluation Guidelines (MRP-227-A)," December 23, 2011.2. Westinghouse InfoGram, IG-10-1, "Reactor Internals Lower Radial Support Clevis Insert CapScrew Degradation," March 31, 2010.3. EPRI Document, MRP-191, "Materials Reliability Program: Screening, Categorization, andRanking of Reactor Internals Components for Westinghouse and Combustion Engineering PWRDesign (MRP-191)," November 8, 2006.E-1 36 of 42 Set 18: RAI B.1.34-9, MRP-227ABackground:The applicant's Reactor Vessel Internals Program implements the guidance of Materials ReliabilityProgram (MRP)-227-A to manage the aging effects of reactor vessel internals (RVI) components.Applicant/Licensee Action Item No. 1 of MRP-227-A states that each applicant/licensee shall refer, inparticular, to the assumptions regarding plant design and operating history made in the failure modes,effects and criticality analysis and functionality analyses for reactors of their design (i. e., Westinghouse,CE, or B&W) which support MRP-227 and describe the process used for determining plant-specificdifferences in the design of their RVI components or plant operating conditions, which result in differentcomponent inspection categories. The applicant/licensee shall submit this evaluation for NRC reviewand approval as part of its application to implement the approved version of MRP-227. The applicantprovided its response to Applicant/Licensee Action Item No. 1 in license renewal application Appendix C.Issue:The staff noted that the applicant's response to Applicant/Licensee Action Item No. 1 did not adequatelyaddress the three key variables at the applicant's site that feed into the screening process for agingdegradation (stress, neutron fluence, and temperature) nor determine how these variations, if any, wouldultimately affect the aging management recommendations.The staff's concern was addressed generically with the industry as documented in the. followingdocuments: Meeting Summary EPRI-Westinghouse January 22-23, 2013 (ADAMS Accession No.ML 13042A048) and Summary of Telecom with EPRI and Westinghouse Electric Company on February25, 2013 (ADAMS Accession No. ML13067A262).The staff also noted that by letter dated October 14, 2013, the Materials Reliability Program issued EPRILetter: MRP 2013-025. The staff noted that the purpose of this letter was to provide an MRP-227-Arelated guidance document for MRP members to use in developing reactor internals related informationfor plant-specific inspection programs. Specifically, the enclosure was developed to provide utilities withthe basis for a plant to respond to the NRC's request for additional information to demonstratecompliance with the basic technical applicability assumptions in MRP-227-A for originally licensed anduprated conditions.Request:1. Cold-worked Materials -Does the plant have non-weld or bolting austenitic stainless steel (SS)components with 20 percent cold work or greater, and if so, do the affected components haveoperating stresses greater than 30 ksi? (If both conditions are true, additional components mayneed to be screened in for stress corrosion cracking.)2. Fuel Design or Fuel Management -Does the plant have atypical fuel design or fuel managementthat could render the assumptions of MRP-227-A, regarding core loading/core design, non-representative for that plant?TVA Response to RAI B.1.34-9:This RAI is generically applicable to PWR plants who comply with MRP-227-A as the basis for theirReactor Vessel Internals aging management program. TVA will provide a response to this RAI as part ofa PWR Owners Group task. (Commitment #27.D) Although the PWR Owners Group task has not yetbeen formalized and initiated, the current plan is to present the task for developing a response to thisRAI in the February 2014 meeting. Following authorization of this task, TVA will provide an update tothis response with a defined schedule for completion within 120 days from the authorization date (i.e.,approximately December 1, 2014)The TVA response will be consistent with the guidance provided in MRP 2013-025. SeeCommitment #27.DE-1 37 of 42 Set 19: RAI A.1-2, LR Commitments and the SQN UFSAR:Background:By letter dated January 7, 2013, Tennessee Valley Authority (TVA) submitted an applicationpursuant to Title 10 of the Code of Federal Regulations (CFR) Part 54, to renew the operatinglicense, DPR-77 and DPR-79 for Sequoyah Nuclear Plant, Units I and 2 (SQN), for review bythe U.S. Nuclear Regulatory Commission (NRC) staff. The staff of NRC is reviewing thisapplication in accordance with the guidance in NUREG-1800, "Standard Review Plan forReview of License Renewal Applications for Nuclear Power Plants." During the review of theSQN license renewal application (LRA) by the NRC staff, TVA made commitments related toaging management programs (AMPs), aging management reviews (AMRs), and time-limitedaging analyses, as applicable, related to managing the aging effects of structures andcomponents prior to the period of extended operation (PEO). The list of these commitments, aswell as the implementation schedules and the sources for each commitment, will be included asa Table in Appendix A to the LRA and the SER with Open Items.In Section 1.7, "Summary of Proposed License Conditions," of the SER with Open Items, thestaff stated that following its review of the LRA, including subsequent information andclarifications provided by the applicant, it identified proposed license conditions. The firstlicense condition requires the information in the updated safety analysis report (USAR)supplement, submitted pursuant to 10 CFR 54.21(d), as revised during the LRA review process,be made a part of the USAR. The second license condition in part states that the new programsand enhancements to existing programs listed in Appendix A of the SER and the applicant'sUSAR supplement be implemented no later than 6 months prior to the PEO. This licensecondition also states, in part, that activities in certain other commitments shall be completed by6 months prior to the PEO or the end of the last refueling outage prior to the PEO, whicheveroccurs later.The NRC plans to revise Appendix A of the SER to align with this guidance and to reformat thelicense condition to be as follows:The USAR supplement submitted pursuant to 10 CFR 54.21(d), as revised during thelicense renewal application review process, and as supplemented by Appendix A ofNUREG [OOq, "Safety Evaluation Report Related to the License Renewal ofSequoyah Nuclear Plant, Units I and 2" dated [Month Year], describes certain programsto be implemented and activities to be completed prior to the PEO.a) The licensee shall implement those new programs and enhancements to existingprograms no later than 6 months prior to PEO.b) The licensee shall complete those inspection and testing activities, as noted inCommitment Nos. x through xx of Appendix A of NUREG XX)0, by the 6 month dateprior to PEO or the end of the last refueling outage prior to the PEO, whicheveroccurs later.The licensee shall notify the NRC in writing within 30 days after having accomplisheditem (a) above and include the status of those activities that have been or remain to becompleted in item (b) above.The staff also notes that in the course of its evaluating multiple commitments to be implementedin the future in order to arrive at a conclusion of reasonable assurance that requirements of10 CFR 54.29(a) have been met, these license renewal commitments must be incorporatedeither into a license condition or into a mandated licensing basis document, such as the USAR.Those commitments that are incorporated into the USAR are typically done so by incorporatingE-1 38 of 42 each one verbatim (or by a summary and a commitment reference number) into the respectiveUSAR summaries in the applicant's LRA Appendix A.Issue:As proposed by the applicant and as reflected in the SER Appendix A, the implementationschedule for some commitments may conflict with the implementation schedule intended by thegeneric license condition. In addition, these licensing commitments need to be incorporatedeither into a license condition or into the applicant's USAR summary in such a manner asdiscussed above.Request:1. Identify those commitments to implement new programs and enhancements to existingprograms. Indicate the expected date for completing the implementation of each of theseprograms and enhancements.2. Identify those commitments to complete inspection or testing activities prior to the PEO.Indicate the expected dates for the completion of each of these inspection and testingactivities.3. For each commitment provided by the applicant in the SER Appendix A, identify where andhow TVA proposes that it be incorporated: into either a license condition or into the SQNUSAR.TVA Response to RAI A.1-21. SQN LR Commitment List Rev 14, LRA Appendices A.1 and B.O.1 have been revised toclarify when LR commitments will be implemented.Changes to LRA Appendices A.1 and B.O.1 follow with additions underlined and deletionslined through."A.1 Aging Management ProgramsThe integrated plant assessment for license renewal identified aging managementprograms (AMPs) necessary to provide reasonable assurance that components withinthe scope of license renewal will continue to perform their intended functions consistentwith the current licensing basis (CLB) for the period of extended operation (PEO). Thissection describes the AMPs aging management programs and activities required duringthe PEO operation. AMPs Aging management progra.nm will beimplemented prior to entering the PEO period of )deFd opcrtion.The phrase "Prior to entering the PEO" means the SQN AMPs will be implemented sixmonths prior to the PEO (for SQNI: prior to 03/17/20; for SQN2: prior to 03/15/21) or theend of the last refueling outage prior to each unit entering the PEO, whichever occurslater. The specific implementation date is provided in the commitment list for eachindividual commitment.The corrective action, confirmation process, and administrative controls of the SQN (10CFR Part 50, Appendix B) Quality Assurance Program are applicable to all agingmanagement programs and activities during the PEO xtendedoperatin ...E-1 39 of 42 B.0.1 Overview... For plant-specific aging management programs (AMPs) that do not correlate withNUREG-1801, the ten elements are addressed in the program description.Throughout LRA Appendix B, the phrase "prior to entering the PEO" means the SQNAMPs will be implemented six months prior to the PEO (for SQNI: prior to 03/17/20; forSQN2: prior to 03/15/21) or the end of the last refueling outage prior to each unit entersthe PEO, whichever occurs later. The specific implementation date is provided in thecommitment list for each individual commitment."2. SQN LR Commitment List Revision 14 implementation due dates have been revised tospecify "six months prior to the PEO" to indicate when the LR commitments will becompleted.Expected date for completion of inspection and testing activities for SQN1: prior to03/17/20; for SQN2: prior to 03/15/21; or the end of the last refueling outage prior to eachunit enters the PEO, whichever occurs later.SQN shall notify the NRC in writing within 30 days after having accomplished items listed inthe LR Commitment List and include the status of those activities that have been or remainto be completed.3. The SQN Final LR Regulatory Commitment List will be included in the UFSAR Supplement(LRA Appendix A) prior to its incorporation into the UFSAR (after the NRC approved theSQN LRA). After incorporation into the SQN UFSAR, changes to information in theUFSAR Supplement will be made in accordance with 10 CFR 50.59.E-1 40 of 42 Tables 3.3.1 and 3.3.2-11 were identified by the NRC 71002 Inspection to have the incorrectenvironment type (SR 817090 / PER 817802). Update Table 3.3.1 to add Note 315 as shownbelow. The following changes to Tables 3.3.1 and 3.3.2-11 are shown with additionsunderlined.Table 3.3.1Summary of Aging Management Programs for the Auxiliary SystemsEvaluated in Chapter VII of NUREG-1801315 Piping is embedded in concrete on the top deck of he Component Cooling WaterIntake Structure with the top concrete removed and covered by a Tornado Missile Shield.This essentially creates a vaulted condition.Table 3.3.2-11, 2nd RowBuried andPressure Carbon Air Loss of Underground VII.I.A-Piping boundary steel outdoor material Piping and 78 3.3.1-78 E 315(ext) TanksInspectionE-1 41 of 42 Table 3.6.1. Line Items 3.6.1-16 and -17:As a result of a teleconference call with the NRC, on December 17,Table 3.6.1, Line Items 3.6.1-16 and -17. Changes are shown with2013, Mr. Richard Plasse, TVA provides additional responses toadditions underlined and deletions lined through:Table 3.6.1, Line Items 3.6.1-163.6.1-16 Fuse holders (not part Increased resistance of Chapter XI.E5, No NUREG-1 801 aging effects are not applicableof active equipment): connection due to chemical "Fuse Holders" to SQN.metallic clamps contamination, corrosion, and A review of SQN documents indicated that fusecomposed of various oxidation (in an air, indoor holders utilizing metallic clamps located inmetals used for controlled environment, circuits that perform an intended function ,-andelectrical connections increased resistance of are :iet part of an active device, or are replacedexposed to air -indoor, connection due to chemical based on a qualified life. do not havegcontrolled or contamination, corrosion and that .equirc m.anagementuncontrolled oxidation do not apply);fatique due to ohmic heating, Therefore, fuse holders with metallic clamps atthermal cycling, electrical SQN are not subiect to a-ging manaqementtransients review. do not have aging that require___________________________________________________________ ___ n aingmangement programTable 3.6.1, Line Items 3.6.1-173.6.1-17 Fuse holders (not part Increased Chapter XI.E5, "Fuse Holders" No NUREG-1801 aging effects are not applicableof active equipment): resistance of No aging management to SQN.metallic clamps connection due to program is required for those A review of SQN documents indicated that fusecomposed of various fatigue caused by applicants who can holders utilizing metallic clamps located inmetals used for frequent demonstrate these fuse circuits that perform an intended function -andelectrical connections manipulation or holders are located in an are not part of an active device, or are replacedexposed to air -indoor, vibration environment that does not based on a qualified life. do not have agcontrolled or subject them to environmental effect, that equire mana.gementuncontrolled aging mechanisms or fatiguecaused by frequent Therefore, fuse holders with metallic- clamps atmanipulation or vibration SQN are not subiect to aging managementreview. do not have aging effetS that rFequire....__"__......._~......an eme t programE-1 42 of 42 ENCLOSURE3Tennessee Valley AuthoritySequoyah Nuclear Plant, Units 1 and 2 License RenewalRegulatory Commitment List, Revision 14Commitments 1.B.; 6.G; 9.A.,D.,F.,G.,L.,O.,P.; 12.B; 14.B; 18.A.5; 24.C through G; 27.C.,D;31.C.,F.,G.,H.,J.,M.4; 35.B.,C.; and 37 to 44, and most implementation dates have beenrevised.Changes below are with additions underlined and deletions lined through.A. This list supersedes all previous versions. The final version will be included in theSQN UFSAR Supplement (LRA Appendix A,) before incorporation into the SQN UFSAR(after NRC approval of the SQN LRA). After incorporation into the SQN UFSAR,changes to information within the UFSAR Supplement will be made in accordance with10 CFR 50.59.B. Throughout this document, the phrase "prior to entering the PEO" means the SQN AMPswill be implemented six months prior to the PEO (For SQN1: prior to 03/17/20; forSQN2: prior to 03/15/21) or the end of the last refueling outage prior to each unitentering the PEO, whichever occurs later.SQN shall notify the NRC in writing within 30 days after having accomplished itemslisted in the LR Commitment List and include the status of those activities that have beenor remain to be completed [01/15/14 CNL-14-010, A.1-21E-3 -I of 30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE /AUDITITEMA. Implement the Aboveground Metallic Tanks Program as SQN1: Prior to 03/17/20 B.1.1described in LRA Section B.1.1. [3.0.3-1, Requests 3, QN2: Prior to 03/15/21ML1 3312A005.11/4/13]B. Above-ground Metallic Tanks Program includes outdoor tanks onsoil or concrete and indoor large volume water tanks (excluding thefire water storage tanks) situated on concrete that are designed forinternal pressures approximating atmospheric pressure. Periodicexternal visual and surface examinations are sufficient to monitordegradation. Internal visual and surface examinations are conductedin conjunction with measuring the thickness of the tank bottoms toensure that significant degradation is not occurring and that thecomponent's intended function is maintained during the PEO.Internal inspections are conducted whenever the tank is drained,with a minimum frequency of at least once every 10 years,beginning in the 5-year interval prior to the PEO. [3.0.3-1 item 5a,ML13294A462, E-2 -4 of 8, 10/17/13]2 A. Revise Bolting Integrity Program procedures to ensure the OQNI: Prior to 03/17/20 B.1.2actual yield strength of replacement or newly procured bolts will be SQN2: Prior to 03/15/21less 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 OQNI: Prior to 03/17/20 B.1.4Inspection Program as described in LRA Section B.1.4. SQN2: Prior to 03/15/21B. Cathodic protection will be provided based on the guidance ofNUREG-1801, section XI.M41, as modified by LR-ISG-2011-03.[B.1.4-4b, ML13252A036. E2 -4 of 7, 9/3/13] _ jE-3 -2 of 30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE / AUDITITEM4 A. Revise Compressed Air Monitoring Program procedures to QNI: Prior to 03/17/20 B.1.5include the standby diesel generator (DG) starting air subsystem. SQN2: Prior to 03/15/21B. 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-1 998, Part 17;EPRI NP-7079; and EPRI TR-108147 to the limits specified for the airsystem contaminantsD. Revise Compressed Air Monitoring Program procedures tomaintain moisture, particulate size, and particulate quantity belowacceptable limits in the standby DG starting air subsystem to mitigateloss of material.E. Revise Compressed Air Monitoring Program procedures toinclude periodic and opportunistic visual inspections of surfaceconditions consistent with frequencies described in ASMEO/M-SG-1 998, Part 17 of accessible internal surfaces such ascompressors, dryers, after-coolers, and filter boxes of the followingcompressed air systems:* Diesel starting air subsystem* Auxiliary controlled air subsystem* Nonsafety-related controlled air subsystemF. Revise Compressed Air Monitoring Program procedures tomonitor and trend moisture content in the standby DG starting airsubsystem.G. Revise Compressed Air Monitoring Program procedures toinclude consideration of the guidance for acceptance criteria inASME OM-S/G-1998, Part 17, EPRI NP-7079; and EPRI TR-108147.E-3- 3 of 30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE /AUDITITEM5 A. Revise Diesel Fuel Monitoring Program procedures to monitor OQNI: Prior to 03/17/20 B.1.8and trend sediment and particulates in the standby DG day tanks. SQN2: Prior to 03/15/21B. 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 SQN1: Prior to 03/17/20 B.1.10clarify that periodic inspections of systems in scope and subject to SQN2: Prior to 03/15/21aging management review for license renewal in accordance with 10CFR 54.4(a)(1) and (a)(3) will be performed. Inspections shallinclude areas surrounding the subject systems to identify hazards tothose systems. Inspections of nearby systems that could impact thesubject systems will include SSCs that are in scope and subject toaging management review for license renewal in accordance with 10CFR 54.4(a)(2).B. Revise External Surfaces Monitoring Program procedures toinclude instructions to look for the following related to metalliccomponents:* Corrosion and material wastage (loss of material).* Leakage from or onto external surfaces loss of material).* Worn, flaking, or oxide-coated surfaces (loss of material).* Corrosion stains on thermal insulation (loss of material).* Protective coating degradation (cracking, flaking, and blistering).* Leakage for detection of cracks on the external surfaces ofstainless steel components exposed to an air environmentcontaining halides.C. Revise External Surfaces Monitoring Program procedures toinclude instructions for monitoring aging effects for flexiblepolymeric components, including manual or physical manipulationsof the material, with a sample size for manipulation of at least tenE-3- 4 of 30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE / AUDITITEM(6) percent of the available surface area. The inspection parameters forpolymers shall include the following:* Surface cracking, crazing, scuffing, dimensional changes (e.g.,ballooning and necking).* Discoloration." Exposure of internal reinforcement for reinforced elastomers(loss of material).* Hardening as evidenced by loss of suppleness duringmanipulation where the component and material can bemanipulated.D. Revise External Surfaces Monitoring Program procedures tospecify the following for insulated components.* Periodic representative inspections are conducted during each10-year period during the PEO." For a representative sample of outdoor components, excepttanks, 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 jacketing isinspected. These visual inspections verify that the jacketing andinsulation is in good condition. The number of representativejacketing 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 thatinspections 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).E-3- 5 of 30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE / AUDITITEM(6)
* 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 thejacketing 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/joints), periodic inspectionsunder the insulation will continue as described above.[3.0.3-1 Request 6a, ML13357A722, E-1 -24 of 43, 12/16/13]E. Revise External Surfaces Monitoring Program procedures toinclude acceptance criteria. Examples include the following:* Stainless steel should have a clean shiny surface with nodiscoloration.* Other metals should not have any abnormal surfaceindications.* Flexible polymers should have a uniform surface texture andcolor with no cracks and no unanticipated dimensionalchange, no abnormal surface with the material in an as-newcondition with respect to hardness, flexibility, physicaldimensions, and color.* Rigid polymers should have no erosion, cracking, checking orchalks.F. For a representative sample of outdoor insulated components andindoor insulated components operated below the dew point, whichhave been identified with more than nominal degradation on theexterior of the component, insulation is removed for inspection of thecomponent surface. For a representative sample of indoor insulatedE-3 -6 of 30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE /AUDITITEM(6) components operated below the dew point, which have not beenidentified with more than nominal degradation on the exterior of thecomponent, the insulation exterior surface is inspected. Theseinspections will be conducted during each 10-year period during the.PEO. [3.0.3-1 Request 6a, ML13357A722, E-1 -23 of 43, 12/16/13]G. Specific, measurable, actionable/attainable and relevantacceptance criteria are established in the maintenance andsurveillance procedures or are established duringq enqiineerincqevaluation of the degraded condition. [ML1 3357A722, E-1 -43 of 43,12/16/1317 A. Revise Fatigue Monitoring Program procedures to monitor and SQN1: Prior to 03/17/20 B.1.11track critical thermal and pressure transients for components that SQN2: Prior to 03/15/21have 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-3- 7 of 30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE /AUDITITEM8 A. Revise Fire Protection Program procedures to include an SQNI: Prior to 03/17/20 B.1.12inspection of fire barrier walls, ceilings, and floors for any signs of SQN2: Prior to 03/15/21degradation 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 Program (FWSP) as described inLRA Section B.1.13.SQNI: Prior to 03/17/20SQN2: Prior to 03/15/21B.1.13A.Reviso FWSP proccd'-res to nc'lude periodic visual inspection of,'re water system ...... V. .A. Ge. Of GO.. rroion aA Ad.. .os , w;aIthiekRess. [9.A is deleted in 01/15/14 CNL-14-010, 3.0.3-1, Request4b]B. 9.B was deleted in 3.0.3-1, Request 4a, ML13357A722, E-1 -13of 43, 12/16/13.C. Revise FWSP procedures to ensure-sprinkler heads are tested inaccordance with NFPA-25 (2011 Edition), Section 5.3.1 [3.0.3-1Request 4a]D. Revise the FWSP full flow testing to be inaccordance with fullNOWv UStri G+u~u 01 r-rdm .6 k~l I I). LS.-I.1 ai ., a.W. a IRequest-4a]; [9.D is deleted in 01/15/14 CNL-14-010, 3.0.3-1,Request 4b]E. Revise FWSP procedures to include acceptance criteria forperiodic visual inspection of fire water system internals for corrosion,minimum wall thickness, and the absence of biofouling in thesprinkler system that could cause corrosion in the sprinklers.F. Prior to the PEO, SQN will se!ect an inspection method (ormnethods) that will proVide suitable indication Of pip in wal thickn 1essfor a representative sample of buried piping locations to supplementthe existing inspection locations for high pressure fire protectionsystem 26 and- esselnti~al raw cooling water system 67. [3.0.3 1 Req 1,ML1329"!A.462, E 1 6 of 13, 10/!7/13] Commitment #9.F is movedto#24.C. [Commitment #9.F is deleted in 01/15/14 CNL-14-010,3.0.3-1-3a, and Request 4blG. Revise FWSP procedures to include periodically remove arepresentative sample of components, such as sprinkler heads orcouplings, within five years prior to the PEO, and every five yearsduring the PEO, to perform a visual internal inspection of the dry firewater system piping for evidence of corrosion, and loss of wallthickness, and foreign material that may result in flow blockage usingthe methodology described in NFPA-25 Section 14.2.1. Tihis. sfk ', rfA A --, ; -~r KIn lDt' Inf,-.r f; r÷ IIj __ _ ______pp__S_111_11jN____IIE-3 -8 of 30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE / AUDITITEM(9) 2013 06, wherc drainage is not occurring.The acceptance criteria shall be "no debris" (i.e.. no corrosionproducts that could impede flow or cause downstream components tobecome cloqgged). Any sigjns of abnormal corrosion or blocka-ge willbe removed, its source determined and corrected, and entered intothe CAPDue dates:SQN1: w/i 5yr prior to 03/17/15, and every 5yr during the PEOSQN2: w/i 5yr prior to 03/15/16, and every 5yr during the PEO[3.0.3-1, Request 4a.d, i to vi, ML1 3357A722, E-1 -11 of 43,12/16/13], [9.G is revised in 01/15/14 CNL-14-010, 3.0.3-1, Request4b]H. Revise FWSP procedures to perform an obstruction evaluation inaccordance with NFPA-25 (2011 Edition), Section 14.3.1.I. Revise FWSP procedures to conduct follow-up volumetricexaminations if internal visual inspections detect surface irregularitiesthat could be indicative of wall loss below nominal pipe wallthickness.J. Revise FWSP procedures to annually inspect the fire waterstorage tank exterior painted surface for signs of degradation. Ifdegradation is identified, conduct follow-up volumetric examinationsto ensure wall thickness is equal to or exceeds nominal wallthickness.The fire water storage tanks will be inspected in accordance withNFPA-25 (2011 Edition) requirements.K. Revise FWSP procedures to include a fire water storage tankinterior inspection every five years that includes inspections for signsof pitting, spalling, rot, waste material and debris, and aquatic growth.Include in the revision direction to perform fire water storage tankinterior coating testing, if any degradation is identified, in accordancewith ASTM D 3359 or equivalent, a dry film thickness test at randomlocations to determine overall coating thickness; and a wet spongetest to detect pinholes, cracks or other compromises of the coating. Ifthere is evidence of pitting or corrosion ensure the FWSP proceduresdirect performance of an examination to determine wall and bottomthickness.L. Reviseo FWSP procedu'-re based on the results of a feasibilitystudy to perform the Main drFain tests inacod nco ith NFPA 25(2011 Edition) Se.tio. 133.22.5. [9.L is deleted in 01/15/14 CNL-14-010, 3.0.3-1, Request 4b]M. Revise FWSP procedures to perform an annual spray headdischarge pattern tests from all open spray nozzles to ensure thatpatterns are not impeded by plugged nozzles, to ensure that nozzlesare correctly positioned, and to ensure that obstructions do notE-3 -9 of 30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE /AUDITITEM(9) prevent discharge patterns from wetting surfaces to be protected.Where the nature of the protected critical equipment or property issuch that water cannot be discharged, the nozzles shall be inspectedfor proper orientation and the system tested with air, smoke or someother medium to ensure that the nozzles are not obstructed.Ensure that the dry piping is unobstructed downstream of delugevalves protecting indoor areas containing critical equipment by flowtesting with air, smoke or other medium from deluge valve throughthe sprinkler heads.Based on the trip testing of the deluge valves without flow through thedownstream piping and sprinkler heads, additional testing in the RCAor areas containing critical equipment is not warranted due to theaddition of risk-significant activities and the production of additionalradwaste. [3.0.3-1, Request 4a, ML13357A722, E-1 -14 of 43,12/16/13]N. Revise FWSP procedures to perform an internal inspection of theaccessible piping associated with the strainer inspections forcorrosion and foreign material that may cause blockage. Documentany abnormal corrosion or foreign material in the CAP. [3.0.3-1,Request 4a, ML13357A722, E-1 -15 of 43, 12/16/13]0. Revise FWSP procedures to perform 30 25 main drain tests every18-months with at least one main drain test performed in each of thefollowing buildings: (1) control building, (2) auxiliary building, (3)turbine building, (4) diesel generator building and (5) ERCW building.The results of the main drain tests from the three 18-month inspectionintervals will be evaluated to determine if the NFPA 25 (2014 Edition)main drain test guidance can be applied to the number of main draintests performed (.i.e., Section 13.2.5, "A main drain test shall beconducted annually for each water supply lead-in to a building water-based fire protection system to determine whether there has been achange in the condition of the water supply" and Section 13.2.5.1"Where the lead-in to a building supplies a header or manifold servingmultiple systems, a single main drain test shall be performed.")Any flow blockage or abnormal discharge identified during flowtesting or any change in delta pressure during the main drain testinggreater than 10% at a specific location is entered into the CAP.Flow or main drain testing increases risk due to the potential for watercontacting critical equipment in the area, and main drain testing in theRCAs increases the amount of liquid radwaste. Therefore, SQN willnot perform main drain tests on every standpipe with an automaticwater supply or on every system riser. [3.0.3-1, Request 4a,ML13357A722, E-1 -15 of 43, 12/16/13]-S A.E-3- 10 of 30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE / AUDITITEM(9) P. Revise FWSP procedures to perform One of the followinginspection methods for those sections of dry piping described in NRCInformation Notice (IN) 2013-06, where drainage is not occurring, toensure there is no flow blocka-ge in each five-year interval beginningwith the five-year period before the PEO:(a) Perform a flow test or flush sufficient to detect potential flowblockage.(b) Remove sprinkler heads or couplings in the areas that do notdrain and perform a 100% visual internal inspection to verifythere are no signs of abnormal corrosion (wall thickness loss)or blockage.(c) Perform a 100% UT examination of the area that does notdrain to identify blockage.If option (a) is chosen, controls will be established to ensurepotential blockage is not moved to another part of the systemwhere it may be undetected.In each five-year interval during the PEO, 20% of the length of pipingsegments that cannot be drained or piping segments that allow waterto collect will be subiected to UT wall thickness examination. Thepiping examined during each inspection interval will be piping thatwas not previously examined. [9.P is added in 01/15/14 CNL-14-010. 3.0.3-1, Request 4bl10 A. Revise Flow Accelerated Corrosion (FAC) Program procedures SQNI: Prior to 03/17/20 B.1.14to implement NSAC-202L guidance for examination of components SQN2: Prior to 03/15/21upstream 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. [B.1.14-1 and B.1.38-1]11 Revise Flux Thimble Tube Inspection Program procedures to SQN1: Prior to 03/17/20 B.1.15include a requirement to address if the predictive trending projects SQN2: Prior to 03/15/21that 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,repositioning, replacement, etc).E-3- 11of30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE /AUDITITEM12 A. Revise Inservice Inspection-IWF Program procedures to clarify SQN1: Prior to 03/17/20 B.1.17that detection of aging effects will include monitoring anchor bolts for SQN2: Prior to 03/15/21loss 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 an indication is identified on a component support exceedingthe acceptance criteria of IWF-3400, but an evaluation concludesthe support is acceptable for service, the program shall requireexamination of additional similar/adiacent supports per IWF-2430unless the evaluation of the identified condition againstsimilar/adiacent supports concludes that it would not adverselyaffect the design function of similar adiacent supports. Thisevaluation will be performed regardless of whether the programowner chooses to perform corrective measures to restore thecomponent to its original design condition, per IWF-3112.3(b) orIWF-3122.3(b). [ML13190A276. E1-37 of 79, 7/1/13113 Inspection of Overhead Heavy Load and Light Load (Related to SQNI: Prior to 03/17/20 B.1.18Refueling) Handling Systems: -QN2: Prior to 03/15/21A. 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 A. Implement the Internal Surfaces in Miscellaneous Piping and SQN1: Prior to 03/17/20 B.1.19Ducting Components Program as described in LRA Section B.1.19. SQN2: Prior to 03/15/21B. Specific, measurable, actionable/attainable and relevantacceptance criteria are established in the maintenance andsurveillance procedures or are established during engineeringevaluation of the degraded condition. [ML1 3357A722, E-1 -43 of 43,12/16/131E-3- 12of30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE /AUDITITEM15 Implement the Metal Enclosed Bus Inspection Program as SQNI: Prior to 03/17/20 B.1.21described in LRA Section B.11.21. SQN2: Prior to 03/15/2116 A. Revise Neutron Absorbing Material Monitoring Program SQNI: Prior to 03/17/20 B.1.22procedures to perform blackness testing of the Boral coupons within SQN2: Prior to 03/15/21the ten years prior to the PEO and at least every ten years thereafterbased on initial testing to determine possible changes in boron-1 0areal density.B. Revise Neutron Absorbing Material Monitoring Programprocedures to relate physical measurements of Boral coupons to theneed to perform additional testing.C. Revise Neutron Absorbing Material Monitoring Programprocedures to perform trending of coupon testing results to determinethe rate of degradation and to take action as needed to maintain theintended function of the Boral.17 Implement the Non-EQ Cable Connections Program as described SQNI: Prior to 03/17/20 B.1.24in LRA Section B.1.24 SQN2: Prior to 03/15/2118 Implement the Non-EQ Inaccessible Power Cable (400 V to 35 kV) SQNI: Prior to 03/17/20 B.1.25Program as described in LRA Section B.1.25 SQN2: Prior to 03/15/21A. B.1.25.1a [ML13296A017, E-1-12of25, 10/21/13]1. Repair the manhole sump pump and discharge piping 18.A.1: Sept 2015deficiencies associated with the accumulation of water in sevenmanholes/hand holes that are scheduled for correction and/ormitigation by September 2015. (HH3, HH2B, HH52B, HH55A2, 18.A2 & 4: Sept 2014MH7B, MH1OA and MH32B as identified on October 1,2013) 18.A.3:2. Grade the ground surface around Manhole 31 to direct runoff SQNI: Prior to 03/17/20away from the manhole. The re-grading is scheduled for SQN2: Prior to 03/15/21completion by September 2014.3. Prior to the PEO, the license renewal commitment for the Non-EQInaccessible Power Cables (400 V to 35 kV) Program willestablish diagnostic testing activities on all inaccessible powercables 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 CAP. Theevaluation will consider results of the most recent diagnostictesting, insulation type, submergence level, voltage level,energization cycle (usage), and various other inputs to determinewhether the cables remain capable of performing their intendedcurrent licensing basis function.5. Once 18.A.1 to 4 are fully completed, Commitments 18.A.1 to 4can be deleted from this list or the UFSAR.E-3- 13of30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE /AUDITITEM19 Implement the Non-EQ Instrumentation Circuits Test Review SQNI: Prior to 03/17/20 B.1.26Program as described in LRA Section B.1.26. SQN2: Prior to 03/15/2120 Implement the Non-EQ Insulated Cables and Connections SQNI: Prior to 03/17/20 B.1.27Program as described in LRA Section B.1.27 SQN2: Prior to 03/15/2121 A. Revise Oil Analysis Program procedures to monitor and SQNI: Prior to 03/17/20 B.1.28maintain contaminants in the 161-kV oil filled cable system within SQN2: Prior to 03/15/21acceptable 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 SQNI: Prior to 03/17/20 B.1.29Section B.1.29. SQN2: Prior to 03/15/2123 Implement the One-Time Inspection -Small Bore Piping Program OQNI: Prior to 03/17/20 B.1.30as described in LRA Section B.1.30 0QN2: Prior to 03/15/2124 A. Revise Periodic Surveillance and Preventive Maintenance ?4.A&C B.1.31Program procedures as necessary to include all activities described SQN1: Prior to 03/17/20in the table provided in the LRA Section B.1.31 program description. 0QN2: Prior to 03/15/21B. For in-scope components that have internal Service Level III or ?4.BOther coatings, initial inspections will begin no later than the last OQNI: RFO Prior toscheduled refueling outage prior to the PEO. Subsequent inspections )9/17/20will be performed based on the initial inspection results. [3.0.3-1,Request 3, ML13312A005, pages E-1- 2,5,7 of 51] SQN2: RFO Prior to9/15/21C. Perform a minimum of five MIC degradation inspections per yearuntil the rate of MIC occurrences no longer meets the criteria forrecurring internal corrosion.If more than one MIC-caused leak or a wall thickness less than identified in the yearly inspection period, an additional five MICinspections over the following 12 month period will be performed foreach MIC leak or finding of wall thickness less than Tm.._in. The totalnumber of inspections need not exceed a total of 25 MIC inspectionsper year. [01/15/14 CNL-14-010, 3.0.3-1-3a]Prior to the period of extended operation, select a method (ormethods) from available technologies for inspecting internal surfacesof buried piping (System 26/HPFP Firewater and 67/ERCW) thatprovides suitable indication of piping wall thickness for arepresentative set of buried piping locations to supplement the set ofselected inspection locations[3.0.3-1, Request la, ML13357A722, E-1 -4 of 43, 12/16/13][3.0.3-1 Reg 1, ML13294A462, E-1-6 of 13, 10/17/13; moved from9.F to 24.C in 01/15/14 CNL-14-010, 3.0.3-1, Request 4bWE-3- 14 of 30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE / AUDITITEM(24) D.1. Prior to the PEO, perform a visual inspection of a 50%sample of the coated piping in each of the following coated pipingsystems or an area equivalent to the entire inside surface of 73 1-footpiping segments for each combination of type of coating, substratematerial, and environment. Inspection location selection will bebased on an evaluation of the effect of a coating failure oncomponent intended functions, potential problems identified duringprior inspections, and service life history. Visually inspect the surfacecondition of the coated components to manage loss of coatingintegrity due to cracking, debonding., delamination, peeling, flaking,and blistering. In addition, if coatings are credited for corrosionprevention, the base material (in the vicinity of delamination, peeling.,or blisters where base metal has been exposed) will be inspected todetermine if corrosion has occurred.Pipina:i. High pressure fire protection (cement-lined piping)ii. Essential raw cooling water (where Belzona applied)2. With the exception of the EDG 7-day fuel oil tanks, performsubsequent inspections of coatings based on the following.i. If no flaking, debonding., peeling, delamination, blisters, orrusting are observed, and any cracking and flaking has beenfound 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), yet a coating specialisthas determined that no remediation is required, thensubsequent inspections will be conducted every other refuelingoutage.iii. If coating degradation is observed that requires newly installedcoatings, subsequent inspections will occur during each of thenext two refueling outage intervals to establish a performancetrend on the coating.EDG 7-day fuel oil tanks coating inspection:Subsequent coating inspections for the EDG 7-day fuel oil tanks willbe at the same 10 year interval as TS Surveillance Requirement4.8.1.1.2.f. If any applied Belzona coating on the interior of the fueloil tanks is peeling, delaminating, or blistering, then the condition willbe repaired and entered into the CAP. Given the favorable SQNexperience with the current Belzona repairs, it is justifiable to repairthe existing coating applied to localized pits with Belzona and notinspect the coating for another 10 years, provided a detachedBelzona engineering transportability evaluation has determined thatthe amount of Belzona applied will not migrate from the EDG 7-daytank to the day-tank. The evaluation will consider Belzona's 2.5 to 3times higher specific gravity than diesel fuel, potential size ofloosened Belzona particles, surface area and depth of the appliedE-3- 15 of 30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE / AUDITITEM(24) Belzona, diesel fuel fluid velocity in the immediate area of the appliedBelzona, proximity of the repaired area to the suction line, and otherfactors.The application of Belzona to repair additional localized pitting in the7-day EDG fuel oil tanks in the future will be installed per vendorspecifications. An engineering evaluation will be performed to ensurethat that additional Belzona cannot be transferable out of the tankduring the interval between tank inspections and to determine if theinterval of inspections should meet the more frequent inspectionguidelines of LR-ISG-2013-01, or the NRC approved TS SurveillanceRequirement of 10 years. The engineering transportability evaluationwill consider factors such as specific gravity, size, depth, surfacearea, and fluid velocity in the evaluation. [01/15/14 CNL-14-010,3.0.3-1-3alE. Prior to the PEO, perform a visual inspection of thefollowing coated tanks and heat exchangers. Visually inspect thesurface condition of the coated components to manage loss ofcoating integrity due to cracking, debonding, delamination, peeling,flaking, and blistering.Tanksi. Cask decontamination collector (where 2 coats Red Lead in oil,Fed SPEC TTP-85 Type II applied)ii. Safety iniection lube oil reservoir (where 0.006 inch plasticcoating applied)iii. Pressurizer relief (where Ambercoat 55 applied)iv. EDG 7-day fuel oil (where Belzona applied)v. Condensate storage tankHeat Exchangersi. Electric board room chiller package (where Belzona applied)ii. Incore instrument room water chiller package B (where Belzonaapplied) [01/15/14 CNL-14-010, 3.0.3-1-3a]F. Include the following acceptance criteria for loss of coatingintegrity:(1) Peeling and delamination are not permitted,(2) Cracking is not permitted if accompanied by delamination orloss of adhesion, and(3) Blisters are limited to intact blisters that are completelysurrounded by sound coating bonded to the surface.Corrective Action: If delamination, peeling, or blisters aredetected, follow-up physical testing will be performed wherephysically possible (i.e., sufficient room to conduct testing) on atleast three locations. The testing will consist of destructive ornondestructive adhesion testing using ASTM Internationalstandards endorsed in Regulatory Guide 1.54. [01/15/14 CNL-14-010, 3.0.3-1-3a]E-3- 16of30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE /AUDITITEM(24) G.1. Coatinq inspections are performed by individuals certified toANSI 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."2. An individual knowledgeable and experienced in nuclear coatingswork will prepare a coating report that includes a list of locationsidentified with coating deterioration including, where possible,photographs indexed to inspection location, and a prioritization of therepair areas into areas that must be repaired before returning thesystem to service and areas where coating repair can be postponedto the next inspection. [01/15/14 CNL-14-010, 3.0.3-1-3a]25 A. Revise Protective Coating Program procedures to clarify that SQN1: Prior to 03/17/20 B.1.32detection of aging effects will include inspection of coatings near SQN2: Prior to 03/15/21sumps or screens associated with the emergency core coolingsystem.B. Revise Protective Coating Program procedures to clarify thatinstruments and equipment needed for inspection may include, butnot be limited to, flashlights, spotlights, marker pen, mirror, measuringtape, magnifier, binoculars, camera with or without wide-angle lens,and self-sealing polyethylene sample bags.C. Revise Protective Coating Program procedures to clarify that thelast two performance monitoring reports pertaining to the coatingsystems will be reviewed prior to the inspection or monitoringprocess.26 A. Revise Reactor Head Closure Studs Program procedures to SQN1: Prior to 03/17/20 B.1.33ensure that replacement studs are fabricated from bolting material SQN2: Prior to 03/15/21with actual measured yield strength less than 150 ksi.B. Revise Reactor Head Closure Studs Program procedures toexclude the use of molybdenum disulfide (MoS2) on the reactorvessel closure studs and to refer to Reg. Guide 1.65, Revl.E-3- 17 of 30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE IAUDITITEM27 A. Revise Reactor Vessel Internals Program procedures to SQNI: Within three Ul B.1.34perform direct measurement of Unit 1 304 SS hold down spring refuel cycles of the dateheight within three cycles of the beginning of the period of extended 09/17/20operation. If the first set of measurements is not sufficient todetermine life, spring height measurements must be taken during the SQN2: Not Applicablenext two outages, in order to extrapolate the expected spring heightto 60 years. (11/15/13, Enclosure 1, pages 24-25)B. Revise Reactor Vessel Internals Program procedures to includepreload acceptance criteria for the Type 304 stainless steelhold-down springs in Unit 1.C. Continued monitoring of industry operating experience in the areaof RVI Clervis Bolt will be performed and the program will bemodified, if necessary. [1/13/14 CNL-14-010, E-2-5of6, B.1.34-81D. MRP-227-A serves as the basis for the SQN Reactor Vessel 7.D: -December 1.Internals aging management program. TVA plans to providea 2014response to RAI B.1.34-9. (MRP-227A) as part of a PWR OwnersGroup task. Although the PWR Owners Group task has not yet beenformalized and initiated, the current plan is to present the task fordeveloping a response to RAI B.1.34-9 in the February 2014 meeting.Following authorization of this task, TVA will provide an update to RAIB.1.34-9 with a defined schedule for completion within 120 days fromthe authorization completion date.The TVA response will be consistent with the guidance provided inMRP 2013-025.Once 27.D is fully completed, Commitments 27.D can be deletedfrom this list or the UFSAR. [ML13296A017, E-1-10of25, 10/21/13][1/13/14 CNL-14-010, B.1.34-91E-3- 18 of 30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE /AUDITITEM28 A. Revise Reactor Vessel Surveillance Program procedures to SQNI: Prior to 03/17/20 B.1.35consider the area outside the beltline such as nozzles, penetrations SQN2: Prior to 03/15/21and discontinuities to determine if more restrictive pressure-temperature limits are required than would be determined by justconsidering the reactor vessel beltline materials.B. Revise Reactor Vessel Surveillance Program procedures toincorporate an NRC-approved schedule for capsule withdrawals tomeet ASTM-E1 85-82 requirements, including the possibility ofoperation beyond 60 years (refer to the TVA Letter to NRC,"Sequoyah Reactor Pressure Vessel Surveillance CapsuleWithdrawal Schedule Revision Due to License RenewalAmendment," dated 01/10/13, ML1 3032A251; NRC FSER approvedon 09/27/13, ML13240A320)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 OQNI: Prior to 03/17/20 B.1.37Section B.1.37. SQN2: Prior to 03/15/2130 Revise Steam Generator Integrity Program procedures to ensure SQN1: Prior to 03/17/20 B.1.39that corrosion resistant materials are used for replacement steam SQN2: Prior to 03/15/21generator tube plugs.31 A. Revise Structures Monitoring Program (SMP) procedures to SQN1: Prior to 03/17/20 B.1.40include the following in-scope structures: SQN2: Prior to 03/15/21* 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 SMP procedures to specify the following list of in-scopestructures are included in the RG 1.127, Inspection of Water-ControlStructures Associated with Nuclear Power Plants Program (SectionB.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 damE-3- 19of30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE / AUDITITEM(31) C. Revise SMP procedures to include the following in-scopestructural 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)" Lower inlet doors (inside steel containment vessel)" Lower support structure structural steel: beams, columns,plates (inside steel containment vessel)* Manholes and handholes* Manways, hatches, manhole covers, and hatch covers(concrete)* Manways, hatches, manhole covers, and hatch covers (steel)* Masonry walls" Metal sidingE-3- 20 of 30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE / AUDITITEM(31)
* Miscellaneous steel (decking, grating, handrails, ladders,platforms, enclosure plates, stairs, vents and louvers, framingsteel, etc.)" Missile barriers/shields (concrete)" Missile barriers/shields (steel)" Monorails" Penetration 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 joint* Shield building concrete foundation, wall, tension ring beamand dome: interior, exterior above and below grade* Steel liner plate* Steel sheet piles* Structural bolting* Sumps (concrete)" Sumps (steol)* 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 tracksupports, pipe whip restraints, jet impingement shields,masonry walls, racks, panels, cabinets and enclosures forelectrical equipment and instrumentation)* Support pedestals (concrete)* Transmission, angle and pull-off towers" Trash racks" Trash racks associated structural support framing* Traveling screen casing and associated structural supportframingE-3- 21 of 30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE /AUDITITEM(31) 9 Trenches (concrete)* Tube track* Turning vanes* Vibration isolatorsD. Revise SMP procedures to include periodic sampling andchemical analysis of ground water chemistry for pH, chlorides, andsulfates on a frequency of at least every five years.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 I & 2* Control bay* ERCW pumping station" HPFP pump house* Turbine buildingF. Revise SMP procedures to include the following parameters to bemonitored 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.* Monitor the surface condition of insulation (fiberglass, calciumsilicate) to identify exposure to moisture that can cause loss ofinsulation effectiveness.G. Revise SMP procedures to include the following components tobe 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).* [moved to the last bullet on '31.F' ]H. Revise SMP procedures to include the following for detection ofaging 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.E-3 -22 of 30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE AUDITITEM(31)
* 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.* Revise SMP procedures to clarify that detection of a-ginqeffects will include the following.Qualifications of personnel conducting the inspections ortesting and evaluation of structures and structural componentsmeet the guidance in Chapter 7 of ACI 349.3R.I. Revise SMP procedures to prescribe quantitative acceptancecriteria based on the quantitative acceptance criteria of ACI 349.3Rand information provided in industry codes, standards, and guidelinesincluding ACI 318, ANSI/ASCE 11 and relevant AISC specifications.Industry and plant-specific operating experience will also beconsidered in the development of the acceptance criteria.J. [moved to the last bullet on '31.H' ]K. Revise SMP procedures to include the following acceptancecriteria for insulation (calcium silicate and fiberglass)* No moisture or surface irregularities that indicate exposure tomoisture.E-3- 23 of 30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE /AUDITITEM(31)L. Revise SMP procedures to include the following preventiveactions.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. RAI B.1.40-4a Response (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, iofReeessa- includin-g, butnot limited to, more frequent inspections, sampling and analysis ofthe inleakage water for minerals and iron, and evaluation of theaffected area using evaluation criteria and acceptance criteria ofACI 349.3R. [Outcome of the Nrc 01/14/14 telecom]5. Commitment #31 .M will be implemented before the PEO for SQNUnits 1 and 2.. [ML13296A017, E-1-10of25, 10/21/13, for 31.M.1to 5]E-3- 24 of 30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE /AUDITITEM32 Implement the Thermal Aging Embrittlement of Cast Austenitic 32.A B.1.41Stainless Steel (CASS) as described in LRA Section B.1.41 SQNI: Prior to 03/17/20SQN2: Prior to 03/15/21A. B.1.41-4a: For those CASS components with delta ferrite content> 25%, additional analysis will be performed using plant-specificmaterials data and best available fracture toughness curves.(B.1.41-4a, ML13225A387, E-1 -19 of 25)B. B.1.41-4b: For CASS materials with estimated delta ferrite > 20% 32.Bthat have been determined susceptible to thermal aging, a flaw SQN1: Prior to 09/17/18tolerance analysis may be necessary. If a flaw tolerance analysis will SQN2: Prior to 09/15/19be required for the susceptible CASS components, the SQN-specificflaw tolerance method will be submitted to the NRC for review andapproval at least two years prior to the PEO; unless ASME hasapproved the flaw tolerance analysis methodology that SQN will use.(SQNI: Priorto 09/17/18 SQN2: Prior to 09/15/19)[ML13357A722, E-1 -1 of 43, 12/16/13]33 A. Revise Water Chemistry Control -Closed Treated Water SQN1: Prior to 03/17/20 B.1.42Systems Program procedures to provide a corrosion inhibitor for the SQN2: Prior to 03/15/21following 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 system" High pressure fire protection diesel jacket water system* Chilled water portion of miscellaneous HVAC systems (i.e.,auxiliary building, Incore Chiller 1A, 1B, 2A, & 2B, and 6.9 kVShutdown Board Room A & B)C. Revise Water Chemistry Control-Closed Treated Water SystemsProgram procedures to state these inspections will be conducted inaccordance with applicable ASME Code requirements, industrystandards, or other plant-specific inspection and personnelqualification procedures that are capable of detecting corrosion orcracking.D. Revise Water Chemistry Control -Closed Treated WaterSystems Program procedures to perform sampling and analysis ofthe glycol cooling system per industry standards and in no casegreater than quarterly unless justified with an additional analysis.E. Revise Water Chemistry Control -Closed Treated WaterSystems Program procedures to inspect a representative sample ofE-3 -25 of 30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE /AUDITITEMpiping 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 03/17/20 B.1.7venting the SCV bottom liner plate weld leak test channels to the SQN2: Prior to 03/15/21containment atmosphere prior to the CILRT and resealing the ventpath after the CILRT to prevent moisture intrusion during plantoperation.35 A. From RAI B.1.6-1 Response: Modify the configuration of the SQN 35.A: B.1.6Unit 1 test connection access boxes to prevent moisture intrusion to SQNI: Prior to 03/17/20the leak 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, develop and implement an SQNI: Prior to 03/17/20instruction/procedure to perform visual examinations of all accessible SQN2: Prior to 03/15/21surfaces, including the access box surfaces, cover plate, welds, andgasket sealing surfaces of the access boxes on each unit every otherrefueling outage with the gasketed access box lid removed.C. From B.1.6-2b Response: develop and implement aninstruction/procedure to continue volumetric examinations where theSCV domes were cut at the frequency of once every five years untilthe coatings are reinstalled at these locations.E-3- 26 of 30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE /AUDITITEM36 A. Revise Inservice Inspection Program procedures to include a QNI: Prior to 03/17/20 B.1.16supplemental inspection of Class 1 CASS piping components that SQN2: Prior to 03/15/21do not meet the materials selection criteria of NUREG-0313,Revision 2, with regard to ferrite and carbon content. An inspectiontechniques qualified by ASME or EPRI will be used to monitorcracking.Inspections will be conducted on a sampling basis. The extent ofsampling will be based on the established method of inspection andindustry operating experience and practices when the program isimplemented, and will include components determined to be limitingfrom the standpoint of applied stress, operating time andenvironmental considerations. (RAI 3.1.2.2.6.2-1)B. Revise the Inservice Inspection Program procedures to performan augmented visual inspection of the Unit 1 and Unit 2 CRDMthermal sleeves and a wall thickness measurement of the six thermalsleeves exhibiting the greatest amount of wear. The results of theaugmented inspection should be used to project if there is sufficientwall thickness for the PEO, or until the next inspection. (RAI B.1.23-2d)C. Evaluate industry operating experience related to CRDM housingpenetration wear and initiatives to measure CRDM housingpenetration wear and resulting wall thickness. Upon successfuldemonstration of a wear depth measurement process, SQN will usethe demonstrated process at accessible locations to measure depthof wear on the CRDM housing penetration wall associated withcontact with the CRDM thermal sleeve centering pads. (RAI B.1.23-2c)D. Revise Inservice Inspection Program procedure to perform anexamination of the accessible CRDM housing penetrations todetermine the amount of wear in the area of the thermal sleevecentering pads for Units 1 and 2. The accessible locations consist ofthe centermost CRDM housing penetrations 1 through 5.(RAI B.1.23-2c)E. Revise Inservice Inspection Program procedure to estimate theCRDM housing penetration wear at the end of the next RVHinspection interval and compare the projected wall thickness to thethickness used in Sequoyah design basis analyses to demonstratevalidity of the analyses. (RAI B.1.23-2c)F. Revise Inservice Inspection Program procedure to monitor thewear of the accessible CRDM housing penetrations in weldexamination volume. (RAI B.1.23-2c)E-3- 27 of 30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE / AUDITITEM37TVA will implement the Operating Experience for the AMPs inaccordance with the TVA response to the RAI B.0.4-1 on07/29/13, ML13213A027; and 10/17/13 letter, RAIs B.0.4-1a andA.l-la.* Revise OE Program Procedure to include current and futurerevisions to NUREG-1 801, "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 Corrective Action Procedure (CAP) Procedure toprovide a screening process of corrective action documents foraging management items, the assignment of aging correctiveactions to appropriate AMP owners, and consideration of theaging 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.* Once Commitment 37 is fullv comDleted. Commitment 37 can beNo later than thescheduled issue date ofýhe renewed operatingicenses for SQN Units 1& 2.ýCurrently February2015)B.0.4deleted from this list or the UFSAR.E-3 -28 of 30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE /AUDITITEM38A. Implement the Service Water Integrity Program (SWIP) asdescribed in LRA Section B.1.38. [3.0.3-1, Requests 3,ML13312A005.E-1 -11 of 51, 11/4/13, for 38.A to F1B. Parameters Monitored/Inspected J: Revise SWIP procedures tomonitor the condition of coated surfaces in the heat exchangerscredited in the response to NRC Generic Letter (GL) 89-13 response.SQNI: Prior to 03/17/20SQN2: Prior to 03/15/21B.1.38C. Detection of aging Effect: Revise the SWIP procedures toperform periodic visual inspections to manage loss of coating integritydue to cracking., debonding., delamination, peeling, flaking, andblistering in heat exchangers credited in the NRC Generic Letter (GL)89-13 response.D. Acceptance Criteria: Revise the SWIP procedures to include thefollowina coatina intearitv acceotance criteria:(1) peeling and delamination are not permitted,(2) cracking is not permitted if accompanied by delamination or lossof adhesion, and(3) blisters are limited to intact blisters that are completely surroundedby sound coating bonded to the surface.E. Monitorina and Trendina: Revise SWIP orocedures to ensure anindividual knowledgeable and experienced in nuclear coatings workwill prepare a coating report that includes a list of locations identifiedwith coatina deterioration includina. where nossible. ohotoaraohsindexed to inspection location, and a prioritization of the repair areasinto areas that must be repaired before returning the system toservice and areas where coating repair can be postponed to the nextinspection.F. Qualification: Revise SWIP procedures to ensure coatinginspections are performed by individuals certified to ANSI N45.2.6,"Qualifications of Inspection, Examination, and Testing Personnel forNuclear Power Plants," and that subsequent evaluation of inspectionfindings is conducted by a nuclear coatings subject matter expertqualified in accordance with ASTM D 7108-05, "Standard Guide forEstablishing Qualifications for a Nuclear Coatings Specialist."39 Implement the Boric Acid Corrosion Program as described in LRA SQN1: Prior to 03/17/20 B.1.3Section B.1.3. SQN2: Prior to 03/15/2140 Implement the Environmental Qualification (Eq) Of Electric SQNI: Prior to 03/17/20 B.1.9Components Proaram as described in LRA Section B.1.9. SQN2: Prior to 03/15/2141 Implement the Masonry Wall Program as described in LRA Section SQN1: Prior to 03/17/20 B.1.20B.1.20. SQN2: Prior to 03/15/2142 Implement the Nickel Alloy Inspection Program as described in SQN1: Prior to 03/17/20 B.1.23LRA Section B.1.23. SQN2: Prior to 03/15/21E-3- 29 of 30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE /AUDITITEM43 Implement the Water Chemistry Control -Primary And Secondary SQNI: Prior to 03/17/20 B.1.43Program as described in LRA Section B.1.43. SQN2: Prior to 03/15/2144 Implement the RG 1.127, Inspection Of Water-Control Structures SQNI: Prior to 03/17/20 B.1.36Associated With Nuclear Power Plants Program as described in SQN2: Prior to 03/15/21LRA Section B.1.36.The above table identifies the 44 SQN NRC LR commitments. Any other statements in this letterare provided for information purposes and are not considered to be regulatory commitments.This commitment list revision supersedes all previous versions.E-3- 30 of 30 ENCLOSURE 4Tennessee Valley AuthoritySequoyah Nuclear Plant, Units 1 and 2 License RenewalWestinghouse Affidavit for RAI Response B.1.34-8, [TVA-14-2, CAW-14-3884]
O WestinghouseU.S. Nuclear Regulatory CommissionDocument Control Desk11555 Rockville PikeRockville,. MD 20852Westinghouse Electric CompanyEngineering, Equipment and Major Projects1000 Westinghouse DriveCranberry Township, Pennsylvania 16066USADirect tel: (412) 374-4643Direct fax: (724) 720-0754e-mail: greshaja@westinghouse.comProj letter: TVA-14-2CAW-14-3884January 13, 2014APPLICATION FOR WITHHOLDING PROPRIETARYINFORMATION FROM PUBLIC DISCLOSURESubject: LTR-RIDA-13-172, Revision 1, Attachment l"Final Response to U.S. NRC RAI B.I.34-8 onthe Sequoyah Nuclear Plant Reactor Lower Radial Support Clevis Insert Bolts" (Proprietary)The proprietary information for which withholding is being requested in the above-referenced report isfurther identified in Affidavit CAW-14-3884 signed by the owner of the proprietary information,Westinghouse Electric Company LLC. The Affidavit, which accompanies this letter, sets forth the basison which the information may be withheld from public disclosure by the Commission and addresses withspecificity the considerations listed in paragraph (b)(4) of 10 CFR Section 2.390 of the Commission'sregulations.Accordingly, this letter authorizes the utilization of the accompanying Affidavit by Tennessee ValleyAuthority.Correspondence with respect to the proprietary aspects of the application for withholding or theWestinghouse Affidavit should reference CAW-] 4-3884, and should be addressed to James A. Gresham,Manager, Regulatory Compliance, Westinghouse Electric Company, Suite 310, 1000 WestinghouseDrive, Cranberry Township, Pennsylvania 16066.Very truly yours,*James'A. Gresham, ManagerRegulatory ComplianceEnclosures CAW-14-3884AFFIDAVITCOMMONWEALTH OF PENNSYLVANIA:ssCOUNTY OF BUTLER:Before me, the undersigned authority, personally appeared James A. Gresham, who, being by meduly sworn according to law, deposes and says that he is authorized to execute this Affidavit on behalf ofWestinghouse Electric Company LLC (Westinghouse), and that the averments of fact set forth in thisAffidavit are true and correct to the best of his knowledge, information, and belief:James A. Gresham, ManagerRegulatory ComplianceSworn to and subscribed before methis 13th day of January 2014Notary PublicCOMMONWEALTH OF PENNSYLVANIANotarial SealAnne M. Stegman, Notary PublicUnity Twp., Westmoreland countyMy Commission Expires Aug. 7, 2016MEMBER, PENNSYLVANIA ASSOCIATION OF NOTARIES 2CAW-14-3884(1) I am Manager, Regulatory Compliance, in Engineering, Equipment and Major Projects,Westinghouse Electric Company LLC (Westinghouse), and as such, I have been specificallydelegated the function of reviewing the proprietary information sought to be withheld from publicdisclosure in connection with nuclear power plant licensing and rule making proceedings, and amauthorized to apply for its withholding on behalf of Westinghouse.(2) 1 am making this Affidavit in conformance with the provisions of 10 CFR Section 2.390 of theCommission's regulations and in conjunction with the Westinghouse Application for WithholdingProprietary Information from Public Disclosure accompanying this Affidavit.(3) I have personal knowledge of the criteria and procedures utilized by Westinghouse in designatinginformation as a trade secret, privileged or as confidential commercial or financial information.(4) Pursuant to the provisions of paragraph (b)(4) of Section 2.390 of the Commission's regulations,the following is furnished for consideration by the Commission in determining whether theinformation sought to be withheld from public disclosure should be withheld.(i) The information sought to be withheld from public disclosure is owned and has been heldin confidence by Westinghouse.(ii) The information is of a type customarily held in confidence by Westinghouse and notcustomarily disclosed to the public. Westinghouse has a rational basis for determiningthe types of information customarily held in confidence by it and, in that connection,utilizes a system to determine when and whether to hold certain types of information inconfidence. The application of that system and the substance of that system constitutesWestinghouse policy and provides the rational basis required.Under that system, information is held in confidence if it falls in one or more of severaltypes, the release of which might result in the loss of an existing or potential competitiveadvantage, as follows:(a) The information reveals the distinguishing aspects of a process (or component,structure, tool, method, etc.) where prevention of its use by any of 3CAW-14-3884Westinghouse's competitors without license from Westinghouse constitutes acompetitive economic advantage over other companies.(b) It consists of supporting data, including test data, relative to a process (orcomponent, structure, tool, method, etc.), the application of which data secures acompetitive economic advantage, e.g., by optimization or improvedmarketability.(c) Its use by a competitor would reduce his expenditure of resources or improve hiscompetitive position in the design, manufacture, shipment, installation, assurance.of quality, or licensing a similar product.(d) It reveals cost or price information, production capacities, budget levels, orcommercial strategies of Westinghouse, its customers or suppliers.(e) It reveals aspects of past, present, or future Westinghouse or customer fundeddevelopment plans and programs of potential commercial value to Westinghouse.(f) It contains patentable ideas, for which patent protection may be desirable.(iii) There are sound policy reasons behind the Westinghouse system which include thefollowing:(a) The use of such information by Westinghouse gives Westinghouse a competitiveadvantage over its competitors. It is, therefore, withheld from disclosure toprotect the Westinghouse competitive position.(b) It is information that is marketable in many ways. The extent to which suchinformation is available to competitors diminishes the Westinghouse ability tosell products and services involving the use of the information.(c) Use by our competitor would put Westinghouse at a competitive disadvantage byreducing his expenditure of resources at our expense.
4CAW-14-3884(d) Each component of proprietary information pertinent to a particular competitiveadvantage is potentially as valuable as the total competitive advantage. Ifcompetitors acquire components of proprietary information, any one componentmay be the key to the entire puzzle, thereby depriving Westinghouse of acompetitive advantage.(e) Unrestricted disclosure would jeopardize the position of prominence ofWestinghouse in the world market, and thereby give a market advantage to the -competition of those countries.(f) The Westinghouse capacity to invest corporate assets in research anddevelopment depends upon the success in obtaining and maintaining acompetitive advantage.(iv) The information is being transmitted to the Commission in confidence and, under theprovisions of 10 CFR Section 2.390, it is to be received in confidence by theCommission.(v) The information sought to be protected is not available in public sources or availableinformation has not been previously employed in the same original manner or method tothe best of our knowledge and belief.(vi) The proprietary information sought to be withheld in this submittal is that which iscontained in LTR-RIDA-13-172, Revision 1, Attachment 1"Final Response to U.S. NRCRAI B. 1.34-8 on the Sequoyah Nuclear Plant Reactor Lower Radial Support Clevis InsertBolts" (Proprietary), for submittal to the Commission, being transmitted by TennesseeValley Authority letter and Application for Withholding Proprietary Information fromPublic Disclosure, to the Document Control Desk. The proprietary information assubmitted by Westinghouse is that associated with Unites States Nuclear RegulatoryCommission Letter, "Requests for Additional Information for the Review of theSequoyah Nuclear Plant, Units I and 2, License Renewal Application (TAC NOS.MF0481 and MF0482) -SET 14," ML14263A338, September 26, 2013, and may beused only for that purpose.
5 CAW-14-3884(a) This information is part of that which will enable Westinghouse to:(i) Support reactor vessel internals aging management.(b) Further this infornmation has substantial commercial value as follows:(i) Westinghouse plans to sell the use of similar information to its customersfor the purpose of supporting reactor internals aging management relative tolower radial support operational justification with degraded clevis insert capscrews.(ii) The information requested to be withheld reveals the distinguishingaspects of a methodology which was developed by Westinghouse.Public disclosure of this proprietary information is likely to cause substantial harm to thecompetitive position of Westinghouse because it would enhance the ability ofcompetitors to provide similar technical evaluation justifications and licensing defenseservices for commercial power reactors without commensurate expenses. Also, publicdisclosure of the information would enable others to use the information to meet NRCrequirements for licensing documentation without purchasing the right to use theinformation.The development of the technology described in part by the information is the result ofapplying the results of many years of experience in an intensive Westinghouse effort andthe expenditure of a considerable sum of money.In order for competitors of Westinghouse to duplicate this information, similar technicalprograms would have to be performed and a significant manpower effort, having therequisite talent and experience, would have to be expended.Further the deponent sayeth not.
PROPRIETARY INFORMATION NOTICETransmitted herewith are proprietary and/or non-proprietary versions of documents furnished to the NRCin connection with requests for generic and/or plant-specific review and approval.In order to conform to the requirements of 10 CFR 2.390 of the Commission's regulations concerning theprotection of proprietary information so submitted to the NRC, the information which is proprietary in theproprietary versions is contained within brackets, and where the proprietary information has been deletedin the non-proprietary versions, only the brackets remain (the information that was contained within thebrackets in the proprietary versions having been deleted). The justification for claiming the informationso designated as proprietary is indicated in both versions by means of lower case letters (a) through (f)located as a superscript immediately following the brackets enclosing each item of information beingidentified as proprietary or in the margin opposite such information. These lower case letters refer to thetypes of information Westinghouse customarily holds in confidence identified in Sections (4)(ii)(a)through (4)(ii)(f) of the Affidavit accompanying this transmittal pursuant to 10 CFR 2.390(b)(1).COPYRIGHT NOTICEThe reports transmitted herewith each bear a Westinghouse copyright notice. The NRC is permitted tomake the number of copies of the information contained in these reports which are necessary for itsinternal use in connection with generic and plant-specific reviews and approvals as well as the issuance,denial, amendment, transfer, renewal, modification, suspension, revocation, or violation of a license,permit, order, or regulation subject to the requirements of 10 CFR 2.390 regarding restrictions on publicdisclosure to the extent such information has been identified as proprietary by Westinghouse, copyrightprotection notwithstanding. With respect to the non-proprietary versions of these reports, the NRC ispermitted to make the number of copies beyond those necessary for its internal use which are necessary inorder to have one copy available for public viewing in the appropriate docket files in the public documentroom in Washington, DC and in local public document rooms as may be required by NRC regulations ifthe number of copies submitted is insufficient for this purpose. Copies made by the NRC must includethe copyright notice in all instances and the proprietary notice if the original was identified as proprietary.
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