ML13357A722: Difference between revisions

From kanterella
Jump to navigation Jump to search
(Created page by program invented by StriderTol)
(Created page by program invented by StriderTol)
 
(9 intermediate revisions by the same user not shown)
Line 1: Line 1:
{{Adams
#REDIRECT [[CNL-13-130, Response to NRC Request for Additional Information Regarding the Review of the License Renewal Application, B.1.41-4b, 3.0.3-1 (Requests La, 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..]]
| number = ML13357A722
| issue date = 12/16/2013
| title = Sequoyah, Units 1 and 2, Response to NRC Request for Additional Information Regarding the Review of the License Renewal Application, B.1.41-4b, 3.0.3-1 (Requests La, 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..
| author name = Shea J W
| author affiliation = Tennessee Valley Authority
| addressee name =
| addressee affiliation = NRC/Document Control Desk, NRC/NRR
| docket = 05000327, 05000328
| license number = DPR-077, DPR-079
| contact person =
| case reference number = CNL-13-130, TAC MF0481, TAC MF0482
| document type = Letter
| page count = 68
| project = TAC:MF0481, TAC:MF0482
| stage = RAI
}}
 
=Text=
{{#Wiki_filter:Tennessee Valley Authority, 1101 Market Street, Chattanooga, Tennessee 37402CNL-13-130December 16, 201310 CFR Part 54ATTN: Document Control DeskU.S. Nuclear Regulatory CommissionWashington, D.C. 20555-0001Sequoyah Nuclear Plant, Units 1 and 2Facility Operating License Nos. DPR-77 and DPR-79NRC Docket Nos. 50-327 and 50-328Subject: Response to NRC Request for Additional Information Regarding theReview of the Sequoyah Nuclear Plant, Units 1 and 2, License RenewalApplication, B.1.41-4b, 3.0.3-1 (Requests la, 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(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, Set 4/Buried Piping, Set 8, and Set 9,"dated July 25, 2013 (ADAMS Accession No. ML13213A026)3. Letter to NRC, "Response to NRC Request for Additional InformationRegarding the Review of the Sequoyah Nuclear Plant, Units 1 and 2,License Renewal Application, Sets 1, 6, 7, and Revised Responses for1.4-2, 1.4-3 and 1.4-4," dated August 9, 2013(ADAMS Accession No. ML13225A387)4. Letter to NRC, "Response to NRC Request for Additional InformationRegarding the Review of the Sequoyah Nuclear Plant, Units 1 and 2,License Renewal Application, Set 10 (30-day), B.1.9-1, B.1.4-4 RevisedRAI Responses, and Revision to LRA page 2.4-44," datedSeptember 3, 2013 (ADAMS Accession No. ML1 3252A036)Pri,,tod Wn recyclod oPaW U.S. Nuclear Regulatory CommissionPage 2December 16, 20135. Letter to NRC, "Response to NRC Request for Additional InformationRegarding the Review of the Sequoyah Nuclear Plant, Units 1 and 2,License Renewal Application, Sets 8 (B.1.33-1), 10 (3.0.3-1 Request 1),12 (B.1.23-2b), 13 (30-day), 14 (B.0.4-1a)," dated October 17, 2013(ADAMS Accession No. ML13294A462)6. Letter to NRC, "Response to NRC Request for Additional InformationRegarding the Review of the Sequoyah Nuclear Plant, Units I and 2,License Renewal Application, Sets 11 (B. 1.40-4a, B.1.25. la),13 (B. 1.41-4a), 14 (3.5.1-57, 3.5.1-87)," dated October 21, 2013(ADAMS Accession No. ML13296A017)7. Letter to NRC, "Response to NRC Request for Additional InformationRegarding the Review of the Sequoyah Nuclear Plant, Units I and 2,License Renewal Application, Sets 10 (3.0.3-1, Requests 3, 4, 6),12 (B.1.6-1b, B.1.6-2b), 16 (4.3.1-8a)," dated November 4, 2013(ADAMS Accession No. ML1 3312A005)8. NRC to TVA, "Requests for Additional Information for the Review of theSequoyah Nuclear Plant, Units I and 2, License Renewal ApplicationSet 18," dated December 6, 2013 (ADAMS Accession No.ML13323A097)By letter dated January 7, 2013 (Reference 1), Tennessee Valley Authority (TVA) submitteda License Renewal Application (LRA) to the Nuclear Regulatory Commission (NRC) torenew the operating licenses for the Sequoyah Nuclear Plant (SQN), Units 1 and 2. Therequest would extend the licenses for an additional 20 years beyond the current expirationdate.Reference 1 includes Tables (3.4.1, 3.4.2-3-5, 3.3.1, 3.3.2-11), LRA Section B.1.14,MRP-1 39 reference, LRA Appendices A and B Acceptance Criteria. TVA is submittingupdates to these tables, references, and specific LRA sections in Enclosure 1.By References 2 to 7, TVA submitted responses to requests for additional information (RAI)B.1.41-4b, 3.0.3-1 (Requests 1, 3,4, 6), and 3.4.2.1.1-2a. In a December 3, 2013 telecom,Mr. Richard Plasse, NRC Project Manager for the SQN License Renewal, requestedclarifications to these RAI responses. Enclosure I provides the requested clarifications.By Reference 8, the NRC forwarded an RAI labeled Set 18, which included RAI B.1.23-2ewith a required response date no later than January 6, 2014. Enclosure 1 provides the TVAresponse.Enclosure 2 is an updated list of the regulatory commitments for license renewal, whichsupersedes all previous versions.
U.S. Nuclear Regulatory CommissionPage 3December 16, 2013Consistent with the standards set forth in 10 CFR 50.92(c), TVA has determined that theadditional information, as provided in this letter, does not affect the no significant hazardsconsiderations associated with the proposed application previously provided in Reference 1.Please address any questions regarding this submittal to Henry Lee at (423) 843-4104.I declare under penalty of perjury that the foregoing is true and correct. Executed on this16'h day of December 2013.Respectfully,Digitally signed by J. W. Shea~~AI ON: -nJ. W. Shea. eýTenneee ValleyA.lh.6yoa-Near Lik-ning,J. v. h l er=a 5,.." Date: 2013.12.16 17:25:30 .O5'00'J. W. SheaVice President, Nuclear LicensingEnclosures:1. TVA Response to NRC Request for Additional Information: B. 1.41-4b, 3.0.3-1(Requests la, 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-139, LRA Appendices A and B Acceptance Criteria2. Regulatory Commitment List, Revision 13cc (Enclosures):NRC Regional Administrator -Region IINRC Senior Resident Inspector -Sequoyah Nuclear Plant ENCLOSURE1Tennessee Valley AuthoritySequoyah Nuclear Plant, Units 1 and 2 License RenewalTVA Response to NRC Request for Additional Information:B.1.41-4b, 3.0.3-1 (Requests la, 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-139, LRA Appendices A and B Acceptance CriteriaSet 7: RAI B.1.41-4b:Flaw tolerance evaluation methodology for high-ferrite (delta ferrite > 20%) cast austeniticstainless steel (CASS) components was discussed in RAI B.1.41-4 [ADAMS Accession No.ML13225A387, August 9, 2013, Enclosure 2, page E-2 -2 of 18, B.1.41-4.2(5)] and RAIResponse B.1.41-4a (ADAMS Accession No. ML13296A017, October 21, 2013, Enclosure 1,page E-1 -17 of 25, B.1.41-4a.1, 2nd paragraph). The NRC requested additional clarification forRAI B.1.41-4 and B.1.41-4a in a teleconference with TVA on December 3, 2013.Commitments #32.A and B have been added to address the NRC request for additionalclarification regarding flaw tolerance evaluation methodology for thermal aging embrittlement ofCASS).Set 10: RAI 3.0.3-1, Request laThe NRC requested additional clarification for RAI Response 3.0.3-1, Request 1 in ateleconference with TVA on December 3, 2013. As a result, RAI Response 3.0.3-1, Request lasupersedes the RAI Response 3.0.3-1, Request 1; provided by TVA in letter datedOctober 17, 2013, ADAMS Accession No. ML13294A462, page E-1 -3 of 13. The changesfrom the previous response are in red italics.a. Based on the results of a review of the past 10 years of plant-specific operatingexperience, microbiologically influenced corrosion (MIC) of carbon steel pipingcomponents exposed to raw water is a recurring internal corrosion (RIC). TVAconsiders MIC to be a RIC. MIC has occurred in carbon steel components exposedto raw water of the following systems.* System 24 -Raw cooling water (RCW)* System 25 -Raw service water (RSW)* System 26 -High pressure fire protection (HPFP)* System 27 -Condenser circulating water (CCW)* System 67 -Essential raw cooling water (ERCW)b. In carbon steel piping components exposed to raw water, loss of material due to MICleading to through-wall leaks has occurred at least once in each of three refuelingcycles in the last ten years. Because of this recurring failure, TVA considers MIC tobe a RIC.E-1- -1-of43
: c. RIC due to MIC in Carbon Steel Piping Components Exposed to Raw Wateri. TVA monitors loss of material due to MIC in carbon steel piping componentsexposed to raw water at Sequoyah Nuclear Plant (SQN). TVA monitors wallthinning of carbon steel piping exposed to raw water and replaces pipe wherenecessary.MIC degradation monitoring uses ultrasonic (UT) measurements to determinewall thickness at selected locations that are marked with inspection grids.The selected locations, which provide a representative sample of the pipingsystem, are chosen based on pipe configuration (horizontal pipe, verticalpipe, pipe connections such as tees); flow conditions (low or moderate flow,stagnant, intermittent flow, stagnant flow in branch close to main line flow);and operating history (known degradation or leakage). The selected gridlocations are periodically reviewed to validate their relevance and usefulness.New grid locations are added as new information, e.g., changes in systemoperations, becomes available.The UT measurements at each selected location are compared to thenominal pipe wall thickness (for initial measurements) or to previousthickness measurements to determine rates of corrosion and the estimatedtime to reach Tain. Subsequent UT measurements are performed quarterlyas determined necessary based on the rate of corrosion and expected time toreach Trin. In the last five years, approximately 70 inspections have beenperformed at approximately 45 identified grid locations. This rate ofinspections is expected to decline as the number of MIC sites is reduced infuture years. A minimum of five MIC degradation inspections per year will beperformed until the rate of MIC occurrences no longer meets the criteria forrecurring internal corrosion. See commitment #24.C.Components are replaced, if necessary, based on the rate of corrosion andthe difference between measured wall thickness and Tmin. If wall thickness isfound to be less than Trin, the issue is entered into the corrective actionprogram (CAP) for resolution. SQN considers multiple MIC locations in thetechnical evaluation of the structural integrity of the pipe when identified bythe volumetric MIC inspections.MIC degradation monitoring has been effective in identifying internal pipingcorrosion. Neither pipe leaks nor pipe wall thinning, including theconsideration of structural integrity, has resulted in the loss of a component'sability to support system pressure and flow requirements. MIC inducedleakage from piping onto nearby safety-related equipment has not resulted inthe loss of any safety function.E-1 --2-of43 ii. As discussed in the above response to Request c.i., the SQN MICdegradation monitoring has been effective in identifying loss of material dueto MIC for carbon steel components exposed to raw water. The number ofinspections and the interval between inspections are determined based oninspection results. The faGt that Neither pipe leaks nor pipe wall thinning,including the consideration of structural integrity, has resulted in the loss ofcomponent ability to support system pressure and flow requirements.Leakage from piping onto nearby safety-related equipment has not resultedin the loss of any safety function. These facts indicate the adequacy of thisapproach.iii. As discussed in the above response to Request c.i., component wallthickness is the parameter monitored to evaluate RIC due to MIC. Wallthickness measurements are taken at multiple locations representing avariety of system configurations. The inspection timing is routinelyestablished based on the rate of corrosion and expected time to reach Tmin.iv. As discussed in the above response to Request c.i., the timing of inspectionsrequired at a given location is based on the rate of corrosion and expectedtime to reach Tni. The nominal quarterly inspection frequency providesadequate opportunity to inspect any location that might exhibit a higher thanexpected rate of wall thinning.v. The HPFP system 26 and ERCW system 67 include sections of buried pipingthat are not readily inspected for MIC degradation. However, newtechnologies for inspecting buried piping to identify internal corrosion arebeing developed and are expected to be significantly improved before theend of the current license term for SQN. Prior to the period of extendedoperation (PEO), SQN will select an inspection method (or methods) that willprovide suitable indication of piping wall thickness for a representativesample of buried piping locations to supplement the existing inspectionlocations. See Commitment #9.F.vi. Although underground leaks are possible, leaks large enough to affect thefunction of these systems are expected to develop slowly. Such leaks aredetectable by changes in system performance (e.g., changes ininstrumentation readings or reduced cooling capacity), changes in systemoperation (e.g., more frequent jockey pump operation), or by the appearanceof wetted ground around the leak.vii. The Periodic Surveillance and Preventive Maintenance Program will beaugmented to incorporate the MIC degradation monitoring activities.See Commitment #24.C.E-1 --3-of43 The change to LRA Section A.1.31 (new item in the list of program activities,starting on LRA page A-24) follows with additions underlined.Perform wall thickness measurements using UT or other suitabletechniques at selected locations to identify loss of material due tomicrobiologically Influenced corrosion (MIC) in carbon steel pipingcomponents exposed to 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 waterChoose selected locations based on pipe configuration, flowconditions and operating history to represent a cross-section ofpotential MIC sites. Periodically review the selected locations tovalidate their relevance and usefulness, and modify accordingly.Compare wall thickness measurements to nominal wall thickness orprevious measurements to determine rates of corrosion degradation.Compare wall thickness measurements to minimum allowable wallthickness (Tmi,) to determine acceptability of the component forcontinued use. Perform subsequent wall thickness measurements atintervals determined for each selected location based on the rate ofcorrosion and expected time to reach Trin. Perforn a minimum of fiveMIC degradation inspections per year until the rate of MICoccurrences no longer meets the criteria for recurrina internalcorrosion.Prior to the period of extended operation, select a method (ormethods) from available technologies for inspecting internal surfacesof buried piping that provides suitable indication of piping wallthickness for a representative set of buried piping locations tosupplement the set of selected inspection locations.See Commitment #24.C.E-1 --4- of 43 The change to LRA Section B.1.31 (new table line in the Program Description)follows with additions underlined.Carbon steel Perform wall thickness measurements using UT or other suitable2 techniques at selected locations to identify loss of material due tocomponents microbiolo-gically Influenced corrosion (MIC) in carbon steel pipingexposed to components exposed to raw water in the following systems.raw water System 24 -Raw cooling waterSystem 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 conditionsand operating history to represent a cross-section of potential MIC sites.Periodically review the selected locations to validate their relevance andusefulness, and modify accordingly.Compare wall thickness measurements to nominal wall thickness orprevious measurements to determine rates of corrosion degradation.Comoare wall thickness measurements to minimum allowable wallthickness (Tn.,) to determine acceptability of the component forcontinued use. Perform subsequent wall thickness measurements atintervals determined for each selected location based on the rate ofcorrosion and expected time to reach Trai,. Perform a minimum of fiveMIC degradation inspections per year until the rate of MIC occurrencesno longer meets the criteria for recurring internal corrosion.Prior to the PEO, select a method (or methods) from availabletechnologies for inspecting internal surfaces of buried piping thatprovides suitable indication of piping wall thickness for a representativeset of buried piping locations to supplement the set of selectedinspection locations.Commitments #9.F and #24.C have been added.E-1 --5-of 43 Set 10: RAI 3.0.3-1, Request 3aB.1.31, Item 6. 'Acceptance Criteria' was revised in RAI B.1.31-4 (ADAMS Accession No.ML13213A026, July 25, 2013, Enclosure 3, page E-3 -10 of 65) and 3.0.3-1 Request 3(ADAMS Accession No. ML13312A005, November 4, 2013, Enclosure 1, page E-1 -8 of 51).The NRC requested additional clarification for these RAIs in a teleconference with TVA onDecember 3, 2013. The changes from the previous response are in red italics.LRA Section B.11.31, Item 6, 'Acceptance Criteria,' is revised as follows:"6. Acceptance CriteriaPeriodic Surveillance and Preventive Maintenance Program acceptance criteria are definedin specific inspection procedures or are established during engineering evaluation of thedegraded condition. The procedures confirm that the structure or component intendedfunction(s) are maintained. Any indication or relevant condition of coating degradation isevaluated for loss of coatings integrity (i.e., no peeling or delamination, no cracking ifaccompanied by delamination or loss of adhesion, and no blisters unless completelysurrounded by sound coating bonded to the surface)."Table B-3: In the response to RAI 3.0.3-1 Request 3, (ADAMS Accession No. ML13312A005,November 4, 2013, Enclosure 1, page E-1 -10 of 51) enhancements were added to LRASections A.1.38 and B.1.38; however, the revision to LRA Appendix B, Table B-3, page B-13was not included in the WVA RAI response.Therefore, the revised Table B-3 line for 'Service Water Integrity' is shown with additionsunderlined.II I NUREG-1801 ComparisonProgram Name Plant- Consistent with Program has Program hasSpecific NUREG-1801 Enhancements Exceptions to NUREG-1801Service Water Integrity X XTable 3.3.2-1: In the response to RAI 3.0.3-1 Request 3, the changes to Table 3.3.2-1 forcomponent type should have indicated 'Tank' instead of 'Piping' (ADAMS Accession No.ML13312A005, November 4, 2013, Enclosure 1, page E-1 -13 of 51). The revisedTable 3.3.2-1 is shown with additions underlined and deletion lined through.Table 3.3.2-1: Fuel Oil SystemAging Effect Aging NUREG-Component Intended Requiring Management 1801 Table 1Type Function Material Environment Management Program Item Item Notes124AA9 Tank Pressure etal with Fuel oil (int.) Loss of Periodic Hboundary ervice coating Surveillance andLevel III or *ntegit Preventivether aintenancenternalI ProqramoatinE-1 --6-of43 Set 10: RAI 3.0.3-1, Request 4aThe NRC requested additional clarification for RAI Response 3.0.3-1, Request 4 in ateleconference with TVA on December 3, 2013. RAI Response 3.0.3-1, Request 4a supersedesthe RAI Response 3.0.3-1, Request 4; provided by TVA in letter dated November 4, 2013,ADAMS Accession No. ML13312A005, page E-1 -20 of 51. The changes from the previousresponse are in red italics.a. Table 4a was originally provided to TVA in the Set 10, August 2, 2013 RAI, and laterrevised via an e-mail from NRC Project Manager on 9/26/2013, ADAMS Accession No.ML13270A037. With the incorporation of the enhancements listed in Response f. below,the inspections and testing of in-scope fire water system components will be conductedin accordance with relevant guidance of the NFPA 25 (2011 edition) sections listed inTable 4a with exceptions described below.Modified Table 4a Fire Water System Inspection and Testing Recommendations1,2,5Description TNFPA 25 SectionSprinkler SystemsSprinkler inspections5 5.2.1.1Sprinkler testing 5.3.1Standpipe and Hose SystemsFlow tests16..Private Fire Service MainsUnderground and exposed pipingq flow 7.3.1testsHydrants 7.3.2Fire PumpsSuction screens Ti8.3.3.7Water Storage TanksExterior inspections 9.2.5.5Interior inspections 9.2.64. 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 --7 -of 43 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)1Storage tanks (internal -10 years) Visual inspection for internal corrosionObstruction InvestiqationObstuctoninternal inspection of pipinq 3 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 --8 -of 43 Exceptions to the Modified Table 4a* Inspections specified in Sections 5.2.1.1, 5.2.2 and 5.2.3 are performed on an18-month basis, not an annual basis. The frequency of once every 18 months isappropriate due to the lack of past inspection findings and the need to perform someof the inspections during a refueling outage.* Sections 14.2.1 and 14.2.2: Section 14.2.1 specifies an inspection of piping andbranch line conditions every five years unless there are multiple wet pipe systems ina building. For multiple wet pipe systems in a building, Section 14.2.2 allows aninspection on every other wet pipe system every five years. The inspection consistsof opening a flushing connection at the end of one main and removing a sprinklertoward the end of one branch line for the purpose of inspecting for the presence offoreign material. SQN is taking the following exception to Sections 14.2.1 and14.2.2. SQN performs internal inspection of the 72 high pressure fire protection(HPFP) water system strainers and associated accessible piping every 36 months. Ifforeign material or corrosion that could cause blockage is identified, the condition isentered into the CAP. In the last 10 years, only one incident of organic material(clam shells) was identified in the strainer. It was determined that the clam shellsentered the system before the HPFP system was switched from raw water to potablewater in 1998. SQN will perform a one-time visual inspection using the methodologydescribed in NFPA-25 Section 14.2.1 prior to the PEO to verify there are no foreignmaterials in the dry portions of the fire water system (i.e., those portions downstreamof deluge and pre-action valves). Any additional inspections of the dry portion of thefire water system in accordance with NFPA-25, Sections 14.2.1 or 14.2.2 will bebased on the one-time inspection results. See the enhancement in Response f.below and Commitment #9.G." Section 6.3.1 addresses flow testing and Section 6.3.1.5 addresses main draintesting. SQN is taking an exception to conducting a flow test and a main drain test ofeach zone of 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 main drain tests every 18 months with atleast one main drain test performed in each of the following buildings: (1) controlbuilding, (2) auxiliary building, (3) turbine building, (4) diesel generator building and(5) ERCW building.E-1 --9-of43 2Any flow blockage or abnormal discharge identified during flow testing is identified and enteredinto the CAP. Any change in delta pressure during the main drain testing greater than 10% at aspecific 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 istaking an exception to flow testing additional underground and exposed piping withincontrol, diesel generator and ERCW buildings for the same reason stated in theexception to Section 6.3.1 above. The station performs testing to determine frictionloss characteristics on approximately 80% of the of the exterior fire water systempiping eight inches diameter and larger. In addition, portions of the main ringheaders are flow tested in 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.* Section 13.4.3.2.2 specifies full flow testing of deluge valves. Opening a delugevalve and allowing waterflowing out of the open sprinkler heads in critical equipmentareas is considered a risk-significant activity. In addition, waterflow testing in theRCA would result in additional liquid radwaste. As allowed by NFPA-25 (2011)Section 13.4.3.2.2.2, an enhancement is provided to perform air, smoke, or othermedium testing of deluge valves in critical equipment areas.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.E-1 --10 -of 43
: b. The enhancement described in LRA Sections A. 1.13 and B. 1.13 allows the use ofnon-intrusive techniques (e.g., volumetric testing) in lieu of conducting flow testing orinternal inspections to detect flow blockage. SQN has demonstrated the use of UT onthe ERCW 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 Commitment #9.G. For piping sections wheredrainage is not occurring as expected, the following actions will be performed.i. One of two inspection methods will be used. Sprinkler heads or couplings will beremoved prior to the PEO in the area that does not drain and a visual internalinspection will be performed to verify there are no signs of abnormal corrosion (wallthickness loss) or blockage. An altemative method to the visual internal inspectionis an UT examination to 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 intemal pressures approximating atmosphericpressure. Periodic extemal visual and surface examinations are sufficient to monitordegradation. Intemal visual and surface examinations are conducted in coniunctionwith measurina the thickness of the tank bottoms to ensure that significant degradationE-1 --11 -of 43 is not occurrinq and the component's intended function is maintained during the PEG.Internal inspections are conducted whenever the tank is drained, with a minimumfreguency of at least once every 10 years. beginning in the 5-year prior to the PEG.manages l99s6 Of mtial ad cracking for the outer surfaces of the abovogroun-dmetallic uring period*ic VISual inspectionsR on tankA within the scope of licence renealRARast delineated in 10 CER 54.4. ForF in Gcope painted tanks, the programn monitors thesurwface nandfitin for blistering, flaking, cracking, peeling, discolorateion, underlyiFng rust,and physica! damage. For in scope sta~inless steel tanks, the program; will moenitorsu rface condfitin to AssurFe a clean, shiny urf~ace With no visible leaks. The visibleexterior portRQions of the ta-nks will be inpcw tlat oncAe every refuelIng cycle-.This prOgram also manages the bottom surfaces of abovoground metallic. tanks, whichare consturuted on a Frin of conreete anRd oil filled- sand. The program .reursUltrasonic testing (UT) of the tank bottoms to assess the thmckness against thethickn~ess spec-ified- in the design Specifiation. The UT- testing of the tank bottoms, willbe perfeo~nd at least once within the fie years prior to the PEG and whenever the+nle nrn A ;na A. ,r; +11 Dan Tkn-rnn a,.. H!i ka ; iln +eA ;,n +n +kPPQ." See Commitment #1.5 prEpUram CY p a OR v pr EFF up 08The 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 desiqn specification.Tank inspections are performed in accordance with the table in LRA Section A. 1.1.using periodi Gvisual inspecQtionsA on tanks iwAith~n the scope Of the programR asdelieatd i 10CFR514. Preventive me~asures were applied during cGonstuction,such as using9 the appropriate mnaterialsG, protective coatings, and elevation as specifiedin design and installation specifications. ForF in scope painted tanks, the programonitrs the ra ne condoiftion for blifsteFrng, flaking, cracking, peeling, diolo ration,ru st, and physical damage. For in scope stainless Steel tanks, the programwsill monitor surface condition to assure adcean, shiny surface with no visible leaks.The visi exterior of the tanks, will be ipeted at leas-t once- everV ' r ofuolingT-his roPFgram will also manage the bottom surface of abovogreundmentallic. tanks-,which are constructed on a ring Of concrete and oil-filled sa;nd. The program wilrequire ultrasonic Wecg (UT) of the ta.nak bottoms o #- -. asses-s s , he th i kness against thethickness specified in the design specification. The UT testing of the tank bottoms willbe perfoFrmed at least once within the five years prior to the period of extendeoperation and whenever the tanks are drained durIing the period of extended Gperation.l l =II I I I I IiIn accoroano W~RA instalIaven ana desn sos, the tanks do not employw .caulKing Or sealant at thle conrGete,'ankin4.tort.MacoR.This program will be implemented prior to the period of extended operation."E-1 --12 -of 43 The changes to LRA Section A.1.13 follow with additions underlined and deletionslined through."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 accordancewith the applicable National Fire Protection Association (NFPA) commitments asdescribed in the Fire Protection Report. System pressure is monitored such thatloss of pressure is immediately detected and corrective action initiated. Portions ofthe system exposed to water are internally visually inspected. Sprinkler heads thathave been in place for 50 years are tested in accordance with NFPA 25 Section5.3.1 if not replaced."Revise FWSP procedures to ensure a ..pr.,entative sample of sprinklerheads will-be are tested Or replaced beforo the end of the 50 year .prinklrhoad cRe~ico life an ttnyAritAOral thera#fte during the e~endedp,.riod of .peration. in accordance with NFPA-25 (2011 Edition), Section5.3.1. d o p ,t ...pl, of p.. r.kr to .conit of a miiuofnt R th,,n f-- ,v noron of,.,,~ tho nvumb.r ofvri o;A;. Rat 'egg tR~A fa, r nnrv~nkln .knhta a rmsrI OFa nnl'F mnn Of ra~nkImmn .a ..H IA &I A 44, 4- k k -F- anwilbe eplaeed. See Commitment #9.C.VVI gIVV urn VV VIVrwýýe r" V"I"F er&FMH OMgMM PI Gebwfva "ZO G-11- Gna- L-9-febew4ng option .P )o, ta!tio t:cneas avawavens or&er proteswin p~ping usmng non intrus;vomffateA-Idal 14991 be pe~feFReid priorto the period of exteded Gporatibn andporiodically thoreafter- Result of the initial evaluations %Ql be used tdJ~ater44in the appFGpriat insectien intr.al tO ensur~e aging effects AMidentified prier to loss of intnded fUnction.A- "s v'.ua: inspecten ...r..e ine..i s.u.ace of t. protecrion pip.ng w.i 9.erwromaLlf annrvit a ytmtrrunorcreier"Ifnfmtfln,% no flflt1f ^l fpl140*fhJff l~lllf t nI11 , -j n ý ' 1,1thickness to en9eaantctastrophic failur and (2 the inner- diarn te;of the piping as? pla ote design flow of tha ie A9protection system.Maintenance hitrsal e sd to demonStrate that such insectionshave been peffonned on a FeprosentWativ number of locations prior to theported of extended operation. A representative number- is 20 percent-orthe population (defined ais locatins having the same materialfenvhronmont, and aging effect combination) wit a maImum of 25lecations. Additinal inspections wil be porfemiod as needed to obtainthis reprsesntatie samnple prior to the period of extended operation andporiodically during the port ad of extonded operatien based on the findingfrom the insections pebrnfred prior to the period of extended operation.* Commitment #9.B is deleted.E-1 -13 of 43 Revise FWSP procedures to iPkude-periodically remove a representativesample of components, such as sprinkler heads or couplings, within fiveyears prior to the PEO and every five years during the PEO, to perform avisual internal inspection of the dry fire water system piping i teiFals forevidence of corrosion, aeR-loss of wall thickness, and foreign material thatmay result in flow blockage using the methodology described in NFPA-25Section 14.2.1. This includes those sections of dry piping described in NRCInformation Notice (IN) 2013-06, where drainage is not occurrinqg.The acceptance criteria shall be "no debris" (i.e., no corrosion products thatcould impede flow or cause downstream components to become clogged).An;" addit~iani! ina .Oct~ng in '144 FA 5 etin ...!14A 2 2 1499.,13i on ,.e .,..... ..Any signs of abnormalcorrosion or blockage will be entered into the CAP. See Commitment #9.G.* 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 indicativeof wall loss below nominal pipe wall thickness. See Commitment #9.1.* Revise FWSP procedures to annually inspect the fire water storage tankexterior painted surface for signs of degradation. If degradation is identified,conduct follow-up volumetric examinations to ensure wall thickness is equalto or exceeds nominal wall thickness. The fire water storage tanks will beinspected in accordance with NFPA-25 (2011 Edition) requirements. SeeCommitment #9.J.* Revise FWSP Procedures to include a fire water storage tank interiorinspection every five years that includes inspections for signs of pitting,spalling, rot, waste material and debris, and aquatic growth. Include in therevision direction to perform fire water storage tank interior coating testing, ifany degradation is identified, in accordance with ASTM D 3359 or equivalent,a dry film thickness test at random locations to determine overall coatingthickness: and a wet sponge test to detect pinholes, cracks or othercompromises of the coating. If there is evidence of pitting or corrosion ensurethe FWSP procedures direct performance of an examination to determinewall and bottom thickness. See Commitment #9.K.Revise FWSP procedures to perform annual spray head discharge patterntests from all open spray nozzles to ensure that patterns are not impeded bypluaged nozzles, to ensure that nozzles are correctly positioned, and toensure that obstructions do not prevent discharge patterns from wettingsurfaces to be protected. Where the nature of the protected criticalequipment or property is such that water cannot be discharged, the nozzlesshall be inspected for proper orientation and the system tested with air.smoke or some other medium to ensure that the nozzles are not obstructed.Ensure that the dry piping is unobstructed downstream of deluge valvesprotecting indoor areas containing critical equipment by flow testing with air.smoke or other medium from deluge valve through the sprinkler heads.Based on the trip testing of the deluge valves without flow through thedownstream piping and sprinkler heads, additional testing in the RCA orareas containing critical equipment is not warranted due to the addition ofE-1 -14 of 43 risk-significant activities and the production of additional radwaste. SeeCommitment #9.M.Revise FWSP procedures to perform an internal inspection of the accessiblepiping associated with the strainer inspections for corrosion and foreignmaterial that may cause blockage. Document any abnormal corrosion orforeign material in the CAP. See Commitment #9.N.Revise FWSP procedures to perform 30 main drain tests every 18 months.At least one main drain test is performed in each of the following buildings:(1) control building, (2) auxiliary building. (3) turbine building. (4) dieselgenerator building, and (5) ERCW building. Any flow blockage or abnormaldischarge identified during flow testing or any change in delta pressure duringthe main drain testing greater than 10% at a specific location is entered intothe CAP.Flow or main drain testing increases risk due to the potential for watercontacting critical equipment in the area, and main drain testing in the RCAsincreases the amount of liquid radwaste. Therefore, SQN will not performmain drain tests on every standpipe with an automatic water supply or onevery system riser. See Commitment #9.0.E-1 -15 of 43 The changes to LRA Section B.1.13 follow with additions underlined and deletionslined through."The Fire Water System Program (FWSP) manages loss of material and fouling forfire protection components and the fire water storage tanks that are tested inaccordance with the SQN Fire Protection Report (FPR) and LR Commitment #9.Consistent with NFPA 25, the SQN program includes system performance testingin accordance 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 isalso performed 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,such as volumetric testing, or as an alternative to non-intrusive testing, by visuallymonitoring internal surface conditions upon each entry into the system for routineor corrective maintenance. The use of internal visual inspections is acceptablewhen inspections can be performed (based on past maintenance history) on arepresentative number of locations. These inspections will be performed beforethe period of extended operation and at plant-specific intervals based during theperiod of extended operation. Periodic visual inspections of fire water systeminternals will monitor surface condition for indications of loss of material.In addition, the water system pressure is continuously monitored such that loss ofpressure is immediately detected and corrective action initiated. If not replaced,sprinkler heads are tested in accordance with SQN FPR and LR Commitment #9before the end of 50-year sprinkler service life and every ten years thereafterduring the period of extended operation. General requirements of the programinclude testing and maintaining fire detectors and visually inspecting the firehydrants to detect signs of corrosion. Fire hydrant flow tests are performedannually to ensure the fire hydrants can perform their intended function.Program acceptance criteria are (a) the water based fire protection system canmaintain required pressure, (b) no signs of unacceptable degradation are observedduring non-intrusive or visual inspections, (c) minimum design pipe and tank wallthickness is maintained, and (d) no biofouling exists in the sprinkler systems thatcould cause corrosion in the sprinklers."E-1 -16 of 43 Elements Affected EnhancementsElements AffectedEnhancements.9 , lntnnt.nn nt flrnnrw L..flnntt~Water- System Pfgram proed -reS to inc Iudaonn of the following Optionse14A4ll thickne8 evalut.plibns of efhi protetion piping singfte'hniqUes (e.g., volUmetfr; testing) to idnnfyeVidence Of 10o9S of Material9 wil4 be perFormed priorto thepenod Of oxtended 9Peration and periodically theS8349Ft.Rosu!tM of tho initial evaluations MAWl be use:d to dotor.Mithe appropriate inspection inte-PA'al to- e-nsure aging effectsare idontiGfo prior- to ioss Of intended function., A jr6qption of tho internml trfa- -of firprotection will Ib, prformnd upon each entFy into thosystem for- routine or coriema#Ientoancoe. Thes.npot ins willh be capablo of evaluating (1) wall thicknessto ensure against Gatastrophic faiur and (2) the innepdiam-tr -of the piping as i, applies to the dosion floW of thoAFir pao~tieRto system. UaintenRancoe hoisoy shagl be used toa reprosent-atie numbe-rof locations prior to the period oaextended operatifn. A representative number is 20 pemontof the population (defined as locations having the samematorial, envirmnment, and aging effect Gcmbinatofn) with aAddional will be performed as,, n d- le to obtainthis roprosentativo sample perio to the period of extendcoppratieon and periodically during the pro fetneporforemed prir to the portead of exeinded opemrtion.Commitment #9.B is deleted.4. Detection of Aqinq Effect Revise FWSP procedures to ensure a repentatiVGsample-of-sprinkler heads will be are tested OF ePlaGedb-efore- the end of the 50 Year Bprinkler head gtaoric life andat ten year intrM4le thereafter during the ewdended period ofoperIation. in accordance with NFPA-25 (2011 Edition),Section 5.3.1 defines a reprecontativo of epr~inkloeto. Deteto o ofanmi nimmcftnoeFtS thpr e an four spruinker Orone percent Of the nu_'mberQ Of SpFrnkl8re per individualeprinkler sample, WhicheVer ic greater. If the option; toroplaco the eprinklere is choene, all eprinkler hoade ththave been in seerhie for -50 yeare will be replaced.4. Detection of Aging Effect Revise FWSP Procedures to perform an obstructionevaluation in accordance with NFPA-25 (2011 Edition),Section 14.3.1.E-1 -17 of 43
: 4. Detection of Aging Effect Revise FWSP procedures to perform an intemal inspectionof the accessible piping associated with the strainerinspections for corrosion and foreign material that maycause blockage. Document any abnormal corrosion orforeign material in the Corrective Action Prmgram.4. Detection of Aging Effect Revise FWSP procedures to perform 30 main drain testsevery 18 months at least one main drain test performed ineach of the following buildings: (1) control building, (2) auxbuilding. (3) turbine building, (4) diesel generator building,and (5) ERCW building.Any flow blockage or abnormal discharge identified duringflow testing is identified and entered into the CAP. Anychance in defta pressure during the main drain testinggreater than 10% at a specific location will be entered intothe CAP.Flow or main drain testing increases risk due to the potentialfor water contacting critical equipment in the area, and maindrain testing in the RCAs increases the amount of liquidradwaste. Therefore, SQN will not perform main drain testson every standpipe with an automatic water supply or onevery system riser.3. Parameters Monitored or, Revise FWSP procedures to i#wude-periodically remove aInspected representative samole of components such as sprinklerheads or couplings, five years prior to and every five yearsduring the PEO. to perform a visual internal inspection ofdy fire water system piping inqtemrai for evidence ofcorrosion, afid-loss of wall thickness, and foreign materialusing the methodology described in NFPA-25 Section14.2.1. This includes those sections of dry piping describedin NRC Information Notice (IN) 2013-06, where drainage isnot occurring due to desigqn. The acceptance criteria shallbe "no debris" (i.e., no corrosion products that could impedeflow or cause downstream components to become clogged).An, addrtlonrl iweGns ~inn ia Gtterrrdan~ ws~h AlWPA MalsaectionS 14.2.1 or 14.22 21i41 ba b;4soid on tho Wnti3!ir'n. Any signs of abnormal corrosion orblockage will be entered into the CAP.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 ofdegradation. If degradation is identified, conduct follow-upvolumetric examinations to ensure wall thickness is equal toor exceeds nominal wall thickness.E-1 -18 of 43
: 4. Detection of Aging Effect Revise FWSP procedures to include a fire water storagetank interior inspection every five years that includesinspections for signs of pitting, spalling, rot, waste materialand debris, and aquatic growth. Include in the revisiondirection to perform fire water storaae tank interior coatinqtesting, if any degradation is identified, in accordance withASTM D 3359 or equivalent, a dry film thickness test atrandom locations to determine overall coating thickness:and a wet sponge test to detect pinholes, cracks or othercompromises 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 owen swray nozzles toensure that patterns are not impeded by Plumged nozzles, toensure that nozzles are correctly positioned, and to ensurethat obstructions do not prevent discharge patterns fromwetting surfaces to be protected. Where the nature of theprotected critical equipment or property is such that watercannot be discharged, the nozzles shall be inspected forproper orientation and the system tested with air, smoke orsome other medium to ensure that the nozzles are notobstructed.SQN will ensure that the dry piping is unobstructeddownstream of deluge valves protecting indoor areascontaining critical equipment by flow testing with air, smokeor other medium from deluge valve through the sprinklerheads.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-siqnificant activities and the production of additionalradwaste.E-1 -19 of 43 The changes to affected LRA Table 3.3.2-2: High Pressure Fire Protection -Water System, line items and the corresponding Table3.3.1 and 3.3.4 line items follow with additions underlined and deletions marked through.Component Intended Aging Effect Aging NUREG- Table 1Tyn Material Environment Requiring Management 1801 Item Item NotesType Function Management Program 1ITank Pressure Carbon Air-outdoor Loss of Abovegr VII.HI.A- 3.3.1-67 Gboundary steel (ext.) material Motallic Tanks 95-EFire WaterSystemTank Pressure Carbon Concrete Loss of VIII.E.SP- 3.4.1.30 Gboundary steel (ext.) material Metalfic Tanks 115EFire WaterSystemTank Pressure Carbon Soil (ext.) Loss of Aboeground VIII.E.SP- 3.4.1-30 Gboundary steel material Metallic Tanks 115 EFire WaterSystemE-1 -20 of 43 3.3.1-67 Steel tanks exposed Loss of material Chapter XI.M29, No Concsitent with NhUREG 1901. Loss of material forto air -outdoor due to general, "Aboveground steel tanks, except fire water storage tanks, exposed to(external) pitting, and Metallic Tanks" outdoor air is managed by the Aboveground Metalliccrevice Tanks Program. The Fire Water System Programcorrosion manages loss of material for fire water storage tanks.3.4.1-30 Steel, stainless steel, Loss of material Chapter XI.M29, No Consistent with NUREG-1 801 for most components.aluminum tanks due to general, "Aboveground Loss of material for steel tanks exposed to concrete orexposed to soil or pitting, and Metallic Tanks" soil is managed by the Aboveground Metallic Tanksconcrete, air -crevice Program. The Fire Water System Program managesoutdoor (external) corrosion loss of material for fire water storage tanks exposed toconcrete or soil. Loss of material for stainless steeltanks exposed to outdoor air (applies to components inTable 3.2.2-1 only) is managed by the AbovegroundMetallic Tanks Program. There are no aluminum orstainless steel tanks exposed to outdoor air in thesteam and power conversion systems in the scope oflicense renewal.Commitments #9.B.C, G -0 have been revised.E-1 -21 of 43 Set 10: RAI 3.0.3-1, Request 6aTVA Response to RAI 3.0.3-1 Reauest 6a -Corrosion under insulationThe NRC requested additional clarification for RAI Response 3.0.3-1, Request 6 in ateleconference with TVA on December 3, 2013. As a result, RAI Response 3.0.3-1,Request 6a supersedes the RAI Response 3.0.3-1, Request 6; provided by TVA by letterdated November 4, 2013, ADAMS Accession No. ML13312A005, page E-1 -36 of 51. Thechanges from the previous response are in red italics.The response to Request 6.a. is provided by responding to Issues 6.a. through 6.f. andproviding a change to the LRA.During the PEO, there will be periodic representative inspections of the in-scope mechanicalcomponent surfaces under insulation and the insulation exterior surface. Insulated indoorcomponents (with process fluid temperature below the dew point) and outdoor componentswill be inspected. SQN has procedural control over jacketing and insulation. The followingdiscusses the periodic representative inspections.a. SQN representative inspections are conducted during each 10-year period during thePEO.bl. For a representative sample of outdoor components, except tanks, and indoorcomponents, except tanks, identified with more than nominal degradation on theexterior of the component, insulation is removed for visual inspection of the componentsurface. Inspections include a minimum of 20 percent of the in-scope piping length foreach material type (i.e., steel, stainless steel, copper alloy, aluminum). Forcomponents with a configuration which does not conform to a 1-foot axial lengthdetermination (e.g., valve, accumulator), 20 percent of the surface area is inspected.Inspected components are 20% of the population of each material type with amaximum of 25. Alternatively, insulation is removed and a minimum of 25 inspectionsare performed that can be a combination of 1-foot axial length sections and individualcomponents for each material type (e.g., steel, stainless steel, copper alloy,aluminum).b2. For a representative sample of indoor components, except tanks, operated below thedew point, which have not been identified with more than nominal degradation on theexterior of the component, the insulation exterior surface or jacketing is inspected.These visual inspections verify that the jacketing and insulation is in good condition.The number of representative jacketing inspections will be at least 50 during each10-year period.If the inspection determines there are gaps in the insulation or damage to the jacketingthat would allow moisture to get behind the insulation, then removal of the insulation isrequired to inspect the component surface for degradation.c. For a representative sample of indoor insulated tanks operated below the dew pointand all insulated outdoor tanks, insulation is removed from either 25 1-square-footsections or 20 percent of the surface area for inspections of the exterior surface ofeach tank. The sample inspection points are distributed so that inspections occur onthe tank dome, sides, near the bottom, at points where structural supports orinstrument nozzles penetrate the insulation, and where water collects (for example ontop of stiffening rings).d. Inspection locations are based on the likelihood of corrosion under insulation (CUI).For example, CUI is more likely for components experiencing alternate wetting andE-1 -22 of 43 drying in environments where trace contaminants could be present and forcomponents that operate for long periods of time below the dew point.e. If tightly adhering insulation is installed, this insulation should be impermeable tomoisture and there should be no evidence of damage to the moisture barrier. Giventhat the likelihood of CUI is low for tightly adhering insulation, a small number ofinspections of the external moisture barrier of this type of insulation, although not zero,will be performed and credited toward the sample population.f. Subsequent inspections will consist of an examination of the exterior surface of theinsulation for indications of damage to the jacketing or protective outer layer of theinsulation, if the following conditions are verified in the initial inspection." No loss of material due to general, pitting or crevice corrosion, beyond that whichcould have been present during initial construction* No evidence of crackingNominal degradation is defined as no loss of material due to general pitting or crevicecorrosion, which could have been present during initial construction, and no evidenceof cracking. If the external visual inspections of the insulation reveal damage to theexterior surface of the insulation or there is evidence of water intrusion through theinsulation (e.g., water seepage through insulation seams/joints), periodic inspectionsunder the insulation will continue as described above.Changes to LRA Section A.1.10, External Surfaces Monitoring Program follow withadditions underlined and deletions lined through."The External Surfaces Monitoring Program manages aging effects of componentsfabricated from metallic and polymeric materials through periodic visual inspection ofexternal surfaces during system inspections and walkdowns for evidence of leakage, lossof material (including loss of material due to wear), cracking, and change in materialproperties. When appropriate for the component and material, physical manipulation isused to augment visual inspections to confirm the absence of elastomer hardening andloss of strength. Inspections will be performed by personal qualified through plant-specificprograms, and deficiencies are documented and evaluated under the CAP. Surfaces thatare not readily visible during plant operations and refueling outages are inspected whenthey are made accessible and at such intervals that would ensure the components'intended functions are maintained.For a representative sample of outdoor insulated components and indoor insulatedcomponents operated below the dew point, which have been identified with more thannominal degradation on the exterior of the component, insulation is removed for inspectionof the component surface. For a representative sample of indoor insulated componentsoperated below the dew point, which have not been identified with more than nominaldegradation on the exterior of the component, the insulation exterior surface is inspected.These inspections will be conducted during each 10-year period during the PEO.The External Surfaces Monitoring Program will be'enhanced as follows.Revise External Surfaces Monitoring Program procedures to clarify that periodicinspections of systems in scope and subject to aging management review for licenserenewal in accordance with 10 CFR 54.4(a)(1) and (a)(3) will be performed.Inspections shall include areas surrounding the subject systems to identify hazardsto those systems. Inspections of nearby systems that could impact the subjectsystems will include SSCs that are in scope and subject to aging managementreview for license renewal in accordance with 10 CFR 54.4(a)(2).E-1 -23 of 43 Revise External Surfaces Monitoring Program procedures to include instructions tolook for the following related to metallic components:Corrosion and material wastage (loss of material).Leakage from or onto external surfaces (loss of material).Worn, flaking, or oxide-coated surfaces (loss of material).Corrosion stains on thermal insulation (loss of material)., Protective coating degradation (cracking, flaking, and blistering).Leakage for detection of cracks on the external surfaces of stainless steelcomponents exposed to an air environment containing halides.Revise External Surfaces Monitoring Program procedures to include instructions formonitoring aging effects for flexible polymeric components through physicalmanipulations of the material, with a sample size for manipulation of at least tenpercent of the available surface area. The inspection parameters for polymers shallinclude the following:Surface cracking, crazing, scuffing, dimensional changes (e.g., ballooning andnecking).Discoloration., Exposure of internal reinforcement for reinforced elastomers (loss of material).I Hardening as evidenced by loss of suppleness during manipulation where thecomponent and material can be manipulated.Revise xFtoRnal Surfacos Program to ensure surfa.es thatare insulated will be incpocated when the oxtornal surface is exposed (i.e., durinmnaintenanco) at such interwals that would ensure that the cOMpononts' intendefuncGtin is maintained. Revise External Surfaces Monitoring Program procedures tospecify the following for insulated components.0 Periodic representative inspections are conducted during each 10-year perioddurinq the PEO.For a representative sample of outdoor components, except tanks, and indoorcomponents, except tanks, identified with more than nominal degradation on theexterior of the component, insulation is removed for visual inspection of thecomponent surface. Inspections include a minimum of 20 percent of the in-scopepiping length for each material type (e.g., steel, stainless steel, copper alloy,aluminum). For components with a configuration which does not conform to a 1-foot axial length determination (e.g., valve, accumulator), 20 percent of thesurface area is inspected. Inspected components are 20% of the population ofeach material type with a maximum of 25. Alternatively, insulation is removedand component inspections performed for any combination of a minimum of 25 1-foot axial length sections and individual components for each material type (e.g.,steel, stainless steel, copper alloy, aluminum.)o For a representative sample of indoor components, except tanks, operated belowthe dew point, which have not been identified with more than nominaldegradation on the exterior of the component, the insulation exterior surface oriacketing is inspected. These visual inspections verify that the iacketing andE-1- 24 of 43 insulation is in good condition. The number of representative iacketingqinspections will be at least 50 during each 10-year period.If the inspection determines there are gaps in the insulation or damage to theiacketinaq that would allow moisture to get behind the insulation, then removal ofthe insulation is required to inspect the component surface for degradation.For a representative sample of indoor insulated tanks operated below the dewpoint and all insulated outdoor tanks, insulation is removed from either 25 1-square foot sections or 20 percent of the surface area for inspections of theexterior surface of each tank. The sample inspection points are distributed sothat inspections occur on the tank dome, sides, near the bottom, at points wherestructural supports or instrument nozzles penetrate the insulation, and wherewater collects (for example on top of stiffening rings).Inspection locations are based on the likelihood of corrosion under insulation(CUI). For example, CUI is more likely for components experiencing alternatewetting and drying in environments where trace contaminants could be presentand for components that operate for long periods of time below the dew point.If tightly adhering insulation is installed, this insulation should be impermeable tomoisture and there should be no evidence of damage to the moisture barrier.Given that the likelihood of CUI is low for tightly adhering insulation, a minimalnumber of inspections of the external moisture barrier of this type of insulation,although not zero, will be credited toward the sample population.Subsequent inspections will consist of an examination of the exterior surface ofthe insulation for indications of damage to the iacketing or protective outer layerof the insulation, if the following conditions are verified in the initial inspection." No loss of material due to general, pitting or crevice corrosion, beyond thatwhich could have been present during initial construction* No evidence of crackingNominal degradation is defined as no loss of material due to general, pitting, orcrevice corrosion, beyond that which could have been present during initialconstruction, and no evidence of cracking. If the external visual inspections of theinsulation reveal damage to the exterior surface of the insulation or there isevidence of water intrusion through the insulation (e.g. water seepage throughinsulation seams/ioints), periodic inspections under the insulation will continue asdescribed above.Revise External Surfaces Monitoring Program procedures to include acceptancecriteria. Examples include the following:Stainless steel should have a clean shiny surface with no discoloration.Other metals should not have any abnormal surface indications.Flexible polymers should have a uniform surface texture and color with no cracksand no unanticipated dimensional change, no abnormal surface with the materialin an as-new condition with respect to hardness, flexibility, physical dimensions,and color.Rigid polymers should have no erosion, cracking, checking or chalks.Enhancements will be implemented prior to the period of extended operation."E-1 -25 of 43 Changes to LRA Section B.1.10, External Surfaces Monitoring Program follow withadditions underlined and deletions lined through."For polymeric materials, the visual inspection will include 100 percent of the accessiblecomponents. The sample size of polymeric components that receive physicalmanipulation is at least ten percent of the available surface area. Acceptance criteria aredefined to ensure that the need for corrective action is identified before a loss of intendedfunction(s). For stainless steel a clean shiny surface is expected. For flexible polymers auniform surface texture (no cracks) and no change in material properties (e.g., hardness,flexibility, physical dimensions, color unchanged from when the material was new) areexpected. For rigid polymers no surface changes affecting performance such as erosion,cracking, crazing, checking, and chalking are expected. The acceptance standardsinclude design standards, procedural requirements, current licensing basis, industry codesor standards, and engineering evaluations.For a representative sample of outdoor insulated components and indoor insulatedcomponents operated below the dew point, which have been identified with more thannominal dearadation on the exterior of the component, insulation is removed for inspectionof the component surface. For a representative sample of indoor insulated componentsonerated below the dew ooint, which have not been identified with more than nominaldeqradation on the exterior of the component, the insulation exterior surface is inspected.These inspections will be conducted durina each 10-year period durina the PEO.NUREG-1801 ConsistencyThe External Surfaces Monitoring Program, with enhancements, will be consistent with theprogram described in NUREG-1801, Section XI.M36, External Surfaces Monitoring ofMechanical Components.Exceptions to NUREG-1801NoneEnhancementsThe following enhancements will be implemented prior to the period of extendedoperation.Element EnhancementAffected1. Scope of Revise External Surfaces Monitoring Program procedures to clarify that periodic inspections ofProgram systems in scope and subject to aging management review for license renewal in accordance with 10CFR 54.4(a)(1) and (a)(3) will be performed. Inspections shall include areas surrounding the subjectsystems to identify hazards to those systems. Inspections of nearby systems that could impact thesubject systems will include SSCs that are in scope and subject to aging management review forlicense renewal in accordance with 10 CFR 54.4(a)(2).3. Parameters Revise External Surfaces Monitoring Program procedures to include instructions to look for theMonitored or following related to metallic components:Inspected
* Corrosion and material wastage (loss of material).* Leakage from or onto external surfaces (loss of material).* Worn, flaking, or oxide-coated surfaces (loss of material).* Corrosion stains on thermal insulation (loss of material).E-1 -26 of 43
* Protective coating degradation (cracking, flaking, and blistering).* Leakage for detection of cracks on the external surfaces of stainless steel components exposedto an air environment containing halides.3. Parameters Revise External Surfaces Monitoring Program procedures to include instructions for monitoring agingMonitored or effects for flexible polymeric components, including manual or physical manipulations of the material,Inspected with a sample size for manipulation of at least ten percent of the available surface area. Theinspection parameters for polymers shall include the following:* Surface cracking, crazing, scuffing, dimensional changes (e.g., ballooning and necking).* Discoloration.* Exposure of internal reinforcement for reinforced elastomers (loss of material).* Hardening as evidenced by loss of suppleness during manipulation where the component andmaterial can be manipulated.E-1 -27 of 43
: 4. Detection ofAging EffectsReWARe External Sur-faca heeMontoring Program PrOcoduroc to encur~e surfacec, that are inuae ilbein.pected when the axterna.l Urfac. ior, exp.ed (i.e., during maintenance) at su.h in ....al that I Aon, ldien.u.e that the c..mponente' ineded or, maintai,,d.Revise External Surfaces MonitoringProgram procedures to specify the following for insulated components:" Periodic representative inspections are conducted during each 10-year period during the PEO." For a representative sample of outdoor components, except tanks, and indoor components, excepttanks, identified with more than nominal degradation on the exterior of the component, insulationis removed for visual inspection of the component surface. Inspections include a minimum of 20percent of the in-scope piping length for each material type (e.-g., steel, stainless steel, copperalloy, aluminum). For components with a configuration which does not conform to a 1-foot axiallength determination (e.g., valve, accumulator), 20 percent of the surface area is inspected.Inspected components are 20% of the population of each material type with a maximum of 25.Alternatively, insulation is removed and a minimum of 25 inspections are performed that can be acombination of 1-foot axial length sections and individual components for each material type (e.g.,steel, stainless steel, copper alloy, aluminum)" For a representative sample of indoor components, except tanks, operated below the dew point,which have not been identified with more than nominal degradation on the exterior of the pipingcomponent, the insulation exterior surface or iacketing is inspected. These visual inspections verifythat the iacketing and insulation is in good condition. The number of representative iacketinqinspections will be at least 50 during each 10-year period.If the inspection determines there are gaps in the insulation or damage to the jacketing that wouldallow moisture to get behind the insulation, then removal of the insulation is required to inspect thecomponent surface for degradation.* For a representative sample of indoor insulated tanks operated below the dew point and allinsulated outdoor tanks, insulation is removed from either 25 1-square foot sections or 20 percentof the surface area for inspections of the exterior surface of each tank. The sample inspectionpoints are distributed so that inspections occur on the tank dome, sides, near the bottom, at pointswhere structural supports or instrument nozzles penetrate the insulation, and where water collects(for example on top of stiffening rings)." Inspection locations are based on the likelihood of corrosion under insulation (CUI). For example,CUI is more likely for components experiencing alternate wetting and drying in environmentswhere trace contaminants could be present and for components that operate for long periods oftime below the dew point." If tightly adhering insulation is installed, this insulation should be impermeable to moisture andthere should be no evidence of damage to the moisture barrier. Given that the likelihood of CUI islow for tightly adhering insulation, a minimal number of inspections of the external moisture barrierof this type of insulation, although not zero, will be credited toward the sample population." Subsequent inspections will consist of an examination of the exterior surface of the insulation forindications of damage to the iacketing or protective outer layer of the insulation, if the followingconditions are verified in the initial inspection.* No loss of material due to general. pitting or crevice corrosion, beyond that which could havebeen present during initial construction* No evidence of crackingE-1 -28 of 43
: 4. Detection of Nominal degradation is defined as no loss of material due to general, pitting, or crevice corrosion,Aging Effects. beyond that which could have been present during initial construction, and no evidence of(continue) cracking. If the external visual inspections of the insulation reveal damage to the exterior surface ofthe insulation or there is evidence of water intrusion through the insulation (e.g. water seepagethrough insulation seams/joints), periodic inspections under the insulation will continue asdescribed above.6. Acceptance Revise External Surfaces Monitoring Program procedures to include acceptance criteria. ExamplesCriteria include the following:" Stainless steel should have a clean shiny surface with no discoloration." Other metals should not have any abnormal surface indications." Flexible polymers should have a uniform surface texture and color with no cracks and nounanticipated dimensional change, no abnormal surface with the material in an as-new conditionwith respect to hardness, flexibility, physical dimensions, and color." Rigid polymers should have no erosion, cracking, checking or chalks.The changes to LRA table line items follow with additions underlined.At the end of LRA Table 3.2.1 Engineered Safety Features, in Notes for Table 3.2.2-1through Table 3.2.2-5-3, add the following plant specific note 204."204. Pro-gram provisions for outdoor insulated components or for indoor insulatedcomponents that operate below the dew point apply..Table 3.2.2-1: Safety Injection System Summary of Aging Management EvaluationPiping Pressure Stainless Condensation Loss of External Surfaces -- -- 204boundary steel (ext) material MonitoringPiping Pressure Stainless Condensation Cracking External Surfaces -- -H204boundary steel (ext) MonitoringTank Pressure Stainless Condensation Loss of External Surfaces -- -204boundary steel (ext) material MonitorinqTank Pressure Stainless Condensation Cracking External Surfaces -- -- 204boundary steel (ext) MonitoringE-1 -29 of 43 At the end of LRA Table 3.3.1 Auxiliary Systems, in Notes for Table 3.3.2-1 through Table3.3.2-17-32, add the following plant specific note 313."313. Procqram provisions for outdoor insulated components or for indoor insulatedcomponents that operate below the dew point aDplV.Table 3.3.2-2: High Pressure Fire Protection -Water System Summary of AgingManagement EvaluationPipin Pressure Carbon Condensation Loss of External --Hboundary steel (ext) material Surfaces 313Monitorin1Table 3.3.2-4: Miscellaneous Heating, Ventilating and Air Conditioning Systems Summaryof Aging Management EvaluationEjpjq Pressure Carbon Condensation Loss of External -- -Hboundary steel (exD material Surfaces 313MonitoringTank Pressure Carbon Condensation Loss of External --Hboundary steel (ext) material Surfaces 313MonitoringTable 3.3.2-6: Control Building HVAC System Summary of Aging Management EvaluationPiping Pressure Carbon Condensation Loss of External --Hboundary steel (ext) material Surfaces 313MonitoringPiping Pressure Copper Condensation Loss of External --Hboundary alloy (ext) material Surfaces 313MonitoringE-1- 30 of 43 Table 3.3.2-11: Essential Raw Cooling Water Systems Summary of Aging ManagementEvaluation"in Pressure Carbon Condensation Loss of External --- 313boundary steel (ext) material SurfacesMonitorinqPiping Pressure Nickel Condensation Loss of External -- -- H 313boundary alloy (ext) material SurfacesMonitoringPiping Pressure Stainless Condensation Loss of External -- -- H, 313boundary steel (ext) material SurfacesMonitoringPipin Pressure Stainless Condensation Crackinq Extemal -- -313boundary steel (ext) SurfacesMonitoringTable 3.3.2-174: Raw Cooling Water System, Nonsafety-Related Components AffectingSafety-Related Systems Summary of Aging Management EvaluationPipinq Pressure Carbon Condensation Loss of External --Hboundary steel (ext) material Surfaces 313MonitorinqPioina Pressure Copper Condensation Loss of External -- -Hboundary alloy (ext) material Surfaces 313MonitorinqPiping Pressure Stainless Condensation Loss of External -Hboundary steel (ext) material Surfaces 313MonitorinqPiping Pressure Stainless Condensation Crackinq External -,boundary steel (ext) Surfaces 313MonitoringTable 3.3.2-17-5: Raw Service Water System, Nonsafety-Related Components AffectingSafety-Related Systems Summary of Aging Management EvaluationPiping Pressure Carbon Condensation Loss of External -" H_,boundary steel (ext) material Surfaces 313MonitorinqE-1 -31 of 43 Table 3.3.2-17-16: Layup Water Treatment System, Nonsafety-Related ComponentsAffecting Safety-Related Systems Summary of Aging Management Evaluationin Pressure Carbon Condensation Loss of External -- Hboundary steel (ext) material Surfaces 313MonitoringPiping Pressure Stainless Condensation Loss of External -Hboundary steel (ext) material Surfaces 313MonitoringPioina Pressure Stainless Condensation Cracking External -- -Hboundary steel (ext) Surfaces 313MonitorinqTable 3.3.2-17-22: Ice Condenser System, Nonsafety-Related Components AffectingSafety-Related Systems Summary of Aging Management EvaluationPiping Pressure Carbon Condensation Loss of External IIboundary steel (ext) material Surfaces -313MonitoringPiping Pressure Stainless Condensation Loss of External -- H,boundary steel (ext) material Surfaces -313MonitoringPi~in Pressure Stainless Condensation Cracking External -Hboundary steel (ext) Surfaces -313MonitoringTank Pressure Carbon Condensation Loss of External --boundary steel (ext) material Surfaces -313MonitoringAt the end of LRA Table 3.4.1 Steam and Power Conversion Systems, in Notes forTable 3.4.2-1 through 3.4.2-3-10, add the following plant specific note 404."404. Program provisions for outdoor insulated components or for indoor insulatedcomponents that operate below the dew point apply.E-1 -32 of 43 Table 3.4.2-1: Main Steam System Summary of Aging Management EvaluationP Pressure Carbon Condensation Loss of External Surfaces -- -- Hboundary steel (ext) material Monitorinq 404aiging Pressure .Stainless Condensation Loss of External Surfaces -- -- Hboundary steel (ext) material Monitoring 404Pipin Pressure Stainless Condensation Cracking External Surfaces -- -_- Hboundary steel (ext) Monitoring 404Table 3.4.2-2: Main and Auxiliary Feedwater System Summary of Aging ManagementEvaluationPressure Carbon Condensation Loss of External -Hboundary steel (ext) material Surfaces 404MonitoringPressure Aluminum Condensation Loss of External --Hboundary (ext) material Surfaces 404MonitoringPressure Stainless Condensation Loss of External -- -Hboundary steel (ext) material Surfaces 404MonitoringPiping Pressure Stainless Condensation Cracking External -Hboundary steel (ext) Surfaces 404MonitoringE-1- 33 of 43 Table 3.4.2-3-9: Condenser Circulating Water System, Nonsafety-Related ComponentsAffecting Safety-Related Systems Summary of Aging Management EvaluationPipin Pressure Carbon Condensation Loss of External H.. I,boundary steel (ext) material Surfaces 404MonitoringPiping Pressure Copper Condensation Loss of External H..Itboundary alloy > (ext) material Surfaces 40415% Zn Monitoringor > 8%AlPiping Pressure Stainless Condensation Loss of External .. .H,boundary steel (ext) material Surfaces 404MonitoringPipin Pressure Stainless Condensation Cracking External .. .H.boundary steel (ext) Surfaces 404MonitoinnCommitments # 6.D and F have been revised.E-1- 34 of 43 Set 18: RAI B.1.23-2eBackground:By letter dated November 15, 2013, the applicant responded to RAI B. 1.23-2d whichaddressed the need for an inspection program to manage loss of material and cracking forcontrol rod drive mechanism (CRDM) nozzle thermal sleeves. In its response, the applicantidentified the /nservice Inspection Program to manage these aging effects. The applicantalso stated that the CRDM thermal sleeve inspections are performed at the same frequencyas the reactor vessel head volumetric examinations, in accordance with ASME Code CaseN-729-1.In addition, the applicant revised the Update Final Safety Analysis Report (UFSAR)supplement for the Inservice Inspection Program by adding the following:Revise the Inservice Inspection Program procedures to perform anaugmented visual inspection of the Unit I and Unit 2 CRDM thermal sleevesand a wall thickness measurement of the six thermal sleeves exhibiting thegreatest amount of wear. The results of the augmented inspection should beused to project if there is sufficient wall thickness for the period of extendedoperation, or until the next inspection.Issue:The applicant identified an augmented visual inspection and a wall thickness measurement(i.e., volumetric examination) to manage loss of material and cracking for the CRDM nozzlethermal sleeves. However, the applicant's response does not clearly describe whether theaugmented visual inspection is periodic inspections at the same frequency as the volumetricexamination of ASME Code Case N-729-1 or a one-time inspection. In addition, theapplicant's response does not cleariy describe whether thickness measurements will beperformed on the six thermal sleeves exhibiting the greatest wear at each unit (i.e.,thickness measurements of six thermal sleeves in each unit).Request:1. Clarify whether the augmented visual inspection is periodic inspections at the samefrequency as the volumetric examination of ASME Code Case N-729-1 or a one-timeinspection. If the augmented visual inspection is a one-time inspection, provideadditional information which demonstrates the adequacy of a one-time visual inspectionto manage loss of material and cracking for these thermal sleeves.2. Clarify whether thickness measurements will be performed on the six thermal sleevesexhibiting the greatest wear in each unit. If thickness measurements are performed on atotal of six thermal sleeves for Units I and 2, provide additional information whichdemonstrates the adequacy of the inspection scope (i.e., total six thermal sleeves forUnits 1 and 2) to manage loss of material and cracking for these thermal sleeves.TVA Response to RAI RAI B.1.23-2e1. The augmented visual examination will be performed on a periodic schedule consistentwith the ASME Code Case N-729-1 exam frequency; unless the analysis of the periodicexamination data indicates a revised examination frequency is appropriate.2. UT thickness measurements will be taken on six thermal sleeves from each unit for atotal of 12 UT examinations. The locations selected will include the six thermal sleevesexhibiting the greatest wear from each unit.E-1- 35 of 43 RAI 3.4.2.1.1-2aIn a NRC teleconference with TVA on November 26, 2013, the NRC requested clarificationof the TVA response to RAI 3.4.2.1.1-2 (ADAMS Accession No. ML13294A462, Oct 17,2013, Enclosure 2, page E2 -5 of 8). TVA supplements its response to this RAI withadditions underlined and deletions lined through.TVA Response to RAI 3.4.2.1.1-2aThe chemical and volume control system (CVCS) holdup tanks receive all or a portion of thereactor coolant letdown and clean borated drainage from the CVCS and other systems. Theprinciple source of effluent directed to the holdup tanks is the letdown produced as a resultof boric acid concentration dilution in the RCS. The CVCS operates in an indoor airenvironment for which humidity control is not provided. Ac defined in the Sequoyah designcriteria dcu'ments tThe operating temperature of the CVCS holdup tank is 1300F. Thereare no sources of chilled water or raw water that could reduce the tank temperature belowthe dew point and promote condensation. Consequently, condensation is not expected onthe CVCS hold up tanks. TVA reviewed industry operating experience associated with thisissue, specifically NRC Information Notice 2013-18 "Refueling Water Storage TankDegradation." For the two tanks described in this notice with similar design as the CVCSholdup tanks at SQN, condensation leading to an environment conducive to stress corrosioncracking was assessed to be a factor. Given the lack of periodic condensation on the CVCSholdup tanks, this industry operating experience is not applicable. A review of recentcondition reports identified no applicable plant-specific operating experience related tocracking of these tanks. Therefore, cracking is not an aging effect requiring managementfor the CVCS holdup tanks.E-1 -36 of 43 Table 3.4.1, Line item 3.4.1-47 was revised in RAI response B.1.4-2 (ADAMS Accession No. ML13213A026, July 25, 2013,Enclosure 1, page E-1 -4 of 11) and B.1.4-4b (ADAMS Accession No. ML13252A036, September 3, 2013, Enclosure 2,page E2 -6-of-7). The NRC requested additional clarification for LRA Table 3.4.1 in a teleconference with TVA on December 3, 2013.The current Table 3.4.1, Line item 3.4.1-47 is shown.LRA Table 3.4.1Item Component Aging Effect/ Aging Further DiscussionNumber Mechanisms Management EvaluationPrograms Recommended3.4.1-47 Steel (with Loss of material Chapter XI.M41, No There are no buried steel, stainless steel orcoating or due to general, "Buried and nickel alloy components exposed to soil orwrapping), pitting, crevice, Underground concrete in the steam and power conversionstainless steel, and Piping and systems in the scope of license renewal.nickel alloy microbiologically Tanks" The seven-day EDG fuel oil tanks arepiping, piping influenced encased in structural concrete. There ispiping elements; reasonable assurance that the seven-daytanks exposed to EDG carbon steel fuel oil tanks will continuesoil or concrete to perform their intended function during theperiod of extended operation consistent withthe current licensing basis due to the designof the structural concrete encasing the tanks,the elevation of the tanks above groundwater,and the coating on the exterior of the tanks.E-1- 37 of 43 Table 3.4.2-3-5 was identified by the NRC to have the incorrect material type (PER 695107).The March 2013 NRC License Renewal audit identified that the 3/4 inch No. 7 HDT 2B oil reservoir drain valve, SQN-2-VLV-006-2601,is non-magnetic (stainless steel). This is a normally closed valve used by maintenance to drain oil from the oil reservoir. A prior walkdown in April 2012 had concluded that the valve was magnetic (carbon steel).As a result, the following change to Table 3.4.2-3-5 corrects the error, with deletions lined through and additions underlined.Table 3.4.2-3-5: Heater Drains and Vents System, Nonsafety-Related Components Affecting Safety-Related SystemsComponent Intended Aging Effect AgingType Function Material Environment Requiring Management NUREG-1801 Table I NotesManagement Program Item Itemir -indoor Loss of External 1II.H.S-29 .4.1-34avboy Pressure Carbon Ai-norLs f SurfacesV y boundary steel (ext) material MonitoringC,402steelValve body Pressure Lube oil (int) Loss of Oil Analysis lll.A.SP-95 .4.1-44boundary material ProgramStainlesssteelalve body Pressure Stainless Air- indoor None None 111..SP-12 3.4.1-58boundary steel (ext)E-1 -38 of 43 Note: The following edits, from this page forward, are made in response to SQN NRC Region 2 License Renewal 71002 Inspectionobservations.Tables 3.3.1 and 3.3.2-11 were identified by the NRC 71002 Inspection to have the incorrect environment type (SR 817090 / PER817802). As a result, the following changes to Tables 3.3.1 and 3.3.2-11 corrects the error, with deletions lined through and additionsunderlined.Table 3.3.1Summary of Aging Management Programs for the Auxiliary SystemsEvaluated in Chapter VII of NUREG-1801314 The raw water environment is strainer seal designed leak off that flows over the top of the strainer housing. Thewetted strainer housing surface is an external surface accessible for direct inspection.E-1 -39 of 43 Table 3.3.2-11Essential Raw Cooling Water SystemsSummary of Aging Management EvaluationTable 3.3.2-11: Essential Raw Cooling Water SystemsAging EffectComponent Intended Requiring Aging Management NUREG-1801 Table IType Function Material Environment Management Program Item Item NotesPressure External Surfaces IL.A-78 3.3.1-78boundary Carbon steel ir outdoor ext Loss of material Monitorin1Pressure Buried and UndergroundPPure Carbon steel Air outdoor (ext) Loss of material Piping and Tanks I1.1.A-78 3.3.1-78 Eboundar InspectionPressure External SurfacesPump casinq beoundar Cast iron Air outdoor (ext) Loss of material Monitoring VI.1.A-78 3.3.1-78 APressure External SurfacesI..A8 3.17Valve body boundars Carbon steel Air outdoor (ext) Loss of material Monitorinq S11.I.A-78 3.3.1-78Pressure Buried and UndergroundValve body Poundary Carbon steel Soil (ext) Loss of material Piping and Tanks II.C1.AP-198 3.3.1-106InspectionPressure A-i: External SurfacesStrainer housing boundary Carbon steel Raw water (ext) Loss of material Monitoring !.!.A 7-7- AG 314E-1 -40 of 43 LRA B.1.14 Program DescriptionDuring the SQN LR 71002 Inspection, the NRC requested clarification of the ProgramDescription for LRA Section B.1.14, Flow Accelerated Corrosion (PER 816717). As aresult, the Program Description for B. 1.14 is revised as follows with the deletion linedthrough."B.1.14 FLOW ACCELERATED CORROSIONProgram DescriptionThe Flow-Accelerated Corrosion (FAC) Program manages loss of material due to wallthinning caused by FAC and erosion. The program manages loss of material due to wallthinning for carbon steel piping and components by (a) performing an analysis todetermine systems subject to FAC, (b) conducting appropriate analysis to predict wallthinning, (c) performing wall thickness measurements based on wall thinning predictions,and (d) evaluating measurement results to determine remaining service life and the needfor replacement or repair of components. A representative sample of components isselected based on the most susceptible locations for wall thickness measurements at afrequency in accordance with NSAC-202L guidelines to ensure that degradation isidentified and mitigated before the component integrity is challenged. Measurementresults are used to confirm predictions and to plan long-term corrective action. In theevent measurements of wall thinning exceed predictions, the extent of the wall thinningis determined as a part of the CAP. The program relies on implementation of guidelinespublished by EPRI in NSAC-202L, Rev. 3, and internal and external operatingexperience. The program uses a predictive code for portions of susceptible systemswith design and operating conditions that are amenable to computer modeling.Inspections are performed using ultrasonic or other approved testing techniques capableof determining wall thickness. When field measurements show that the predictive codeis not conservative, the model is recalibrated. The model is also adjusted as a result ofany power up-rates. Components predicted to reach the minimum allowed wallthickness before the next scheduled outage are iselated, repaired, replaced, orreevaluated under the CAP."E-1 -41 of 43 MRP-139 DeletionDuring the SQN LR 71002 Inspection, the NRC identified that LRA Appendices A. 1.23 andB.1.23 reference MRP-139, revision 1, (PER 813531). This reference is no longer currentand has been replaced by ASME Code Case N-770-1. The following changes to the LRAidentified by italics delete the MRP-139 reference.Changes to SQN LRA Appendix A and B Nickel Alloy Programs (to delete MRP-139reference) follow with deletions lined through."A.1.23 NICKEL ALLOY INSPECTION PROGRAMThe Nickel Alloy Inspection Program manages cracking due to primary water stresscorrosion cracking (PWSCC) for nickel-alloy components and loss of material due toboric acid-induced corrosion in susceptible safety-related components in the vicinity ofnickel-alloy reactor coolant pressure boundary components as described in FPR1015009 (MRP 139, Rev. 1) and 10 CFR 50.55a. It provides (a) inspectionrequirements for the PWR vessel, pressurizer components, and piping that containPWSCC-susceptible dissimilar metals (Alloys 600/82/182) and (b) inspectionrequirements for reactor coolant pressure boundary components.B.1.23 NICKEL ALLOY INSPECTIONProgram DescriptionThe Nickel Alloy Inspection Program manages cracking due to primary water stresscorrosion cracking (PWSCC) for nickel-alloy components and loss of material due toboric acid-induced corrosion in susceptible safety-related components in the vicinity ofnickel-alloy reactor coolant pressure boundary components as required by 10 -CFR50.55a. It provides (a) inspection requirements for the PWR vessel, pressurizercomponents, and piping that contain PWSCC-susceptible dissimilar metals (Alloys600/82/182) and (b) inspection requirements for reactor coolant pressure boundarycomponents.The program monitors for reactor coolant pressure boundary cracking and leakageusing various methods, including NDE techniques, radiation monitoring, and visualinspections for boric acid deposits, leakage, or the presence of moisture to identifycracking in the reactor coolant pressure boundary or loss of material. Inspectionmethods, schedules and frequencies for susceptible components are implemented inaccordance with 10 CFR 50.55a and industr" guide!inos (e.g., EPR! 1010097 [MRP449]). Reactor coolant leakage is calculated and trended on a routine basis inaccordance with technical specifications. The acceptance criteria for identified flawsand the methodology for evaluating the flaws is prescribed in 10 CFR 50.55a.Unacceptable indications of flaws are corrected through implementation of appropriaterepair or replacement as dictated in 10 CFR 50.55a and induetr" (e.g., MRPE-1 -42 of 43 LRA Appendices A and B Acceptance CriteriaDuring the SQN LR 71002 Inspection, the NRC observed that the LRA Appendices A and BAcceptance Criteria are too general in some cases (SR 817133 / PER 817808). As a result,the changes to the LRA sections follow with additions underlined."A.1.10 External Surfaces MonitoringRevise External Surfaces Monitoring Program procedures to include acceptance criteria.Examples include the following:ý Specific, measurable, actionable/attainable and relevant acceptance criteria areestablished in the maintenance and surveillance procedures or are establishedduring engineering evaluation of the degraded condition.B.1.10 External Surfaces MonitoringS. Acceptance Criteria Revise External Surfaces Monitoring Programprocedures to include acceptance criteria. Examplesinclude the following:Specific, measurable, actionable/attainable andrelevant acceptance criteria are established inthe maintenance and surveillance proceduresor are established during engineeringqevaluation of the degraded condition.A.1.19 Internal Surfaces in Miscellaneous Piping and Ducting Components ProgramSpecific acceptance criteria are as follows:* Specific, measurable, actionable/attainable and relevant acceptance criteria areestablished in the maintenance and surveillance procedures or are establishedduring engineering evaluation of the degraded condition.B.1.19 Internal Surfaces in Miscellaneous Piping and Ducting ComponentsSpecific acceptance criteria will be as follows:.Specific, measurable, actionable/attainable and relevant acceptance criteria areestablished in the maintenance and surveillance procedures or are establishedduring engineering evaluation of the degraded condition."E-1 -43 of 43 ENCLOSURE2Tennessee Valley AuthoritySequoyah Nuclear Plant, Units I and 2 License RenewalRegulatory Commitment List, Revision 13Commitments 6.D.F, 9.B.G.M.N.O, 24.C and 32.A,B have been revised.This Commitment List Revision supersedes all previous versions. The latest revision will be included inthe LRA Appendix A, before the SQN LRA SER is issued.LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE /AUDITITEM1 Implement the Aboveground Metallic Tanks Program as described SQNI: Prior to 09/17/20 B.1.1in LRA Section B.1.1. (RAI 3.0.3-1, Requests 3a) SQN2: Prior to 09/15/212 A. Revise Bolting Integrity Program procedures to ensure the SQNI: Prior to 09/17/20 B.1.2actual yield strength of replacement or newly procured bolts will be SQN2: Prior to 09/15/21less than 150 ksiB. Revise Bolting Integrity Program procedures to include theadditional guidance and recommendations of EPRI NP-5769 forreplacement of ASME pressure-retaining bolts and the guidanceprovided in EPRI TR-1 04213 for the replacement of otherpressure-retaining bolts.C. Revise Bolting Integrity Program procedures to specify acorrosion inspection and a check-off for the transfer tube isolationvalve flange bolts.D. Revise Bolting Integrity Program procedures to visually inspect arepresentative sample of normally submerged ERCW system bolts atleast once every 5 years. (See Set 10 (30-day), Enclosure 1, B.1.2-2a)3 A. Implement the Buried and Underground Piping and Tanks SQN1: Prior to 09/17/20 B.1.4Inspection Program as described in LRA Section B.1.4. SQN2: Prior to 09/15/21B. Cathodic protection will be provided based on the guidance ofNUREG-1801, section XI.M41, as modified by LR-ISG-2011-03.E-2 -1 of 22 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE / AUDITITEM4 A. Revise Compressed Air Monitoring Program procedures to SQNI: Prior to 09/17/20 B.1.5include the standby diesel generator (DG) starting air subsystem. SQN2: Prior to 09/15/21B. Revise Compressed Air Monitoring Program procedures toinclude maintaining moisture and other contaminants below specifiedlimits in the standby DG starting air subsystem.C. Revise Compressed Air Monitoring Program procedures to applya consideration of the guidance of ASME OM-S/G-1998, Part 17;EPRI NP-7079; and EPRI TR-1 08147 to the limits specified for the airsystem contaminantsD. Revise Compressed Air Monitoring Program procedures tomaintain moisture, particulate size, and particulate quantity belowacceptable limits in the standby DG starting air subsystem to mitigateloss of material.E. Revise Compressed Air Monitoring Program procedures toinclude periodic and opportunistic visual inspections of surfaceconditions consistent with frequencies described in ASMEO/M-SG-1998, Part 17 of accessible internal surfaces such ascompressors, dryers, after-coolers, and filter boxes of the followingcompressed air systems:* Diesel starting air subsystem* Auxiliary controlled air subsystem* Nonsafety-related controlled air subsystemF. Revise Compressed Air Monitoring Program procedures tomonitor and trend moisture content in the standby DG starting airsubsystem.G. Revise Compressed Air Monitoring Program procedures toinclude consideration of the guidance for acceptance criteria inASME OM-S/G-1998, Part 17, EPRI NP-7079; and EPRI TR-108147.E-2 -2 of 22 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE / AUDITITEM5 A. Revise Diesel Fuel Monitoring Program procedures to monitor SQNI: Prior to 09/17/20 B.1.8and trend sediment and particulates in the standby DG day tanks. SQN2: Prior to 09/15/21B. Revise Diesel Fuel Monitoring Program procedures to monitor andtrend levels of microbiological organisms in the seven-day storagetanks.C. Revise Diesel Fuel Monitoring Program procedures to include aten-year periodic cleaning and internal visual inspection of thestandby DG diesel fuel oil day tanks and high pressure fire protection(HPFP) diesel fuel oil storage tank. These cleanings and internalinspections will be performed at least once during the ten-year periodprior to the period of extended operation (PEO) and at succeedingten-year intervals. If visual inspection is not possible, a volumetricinspection will be performed.D. Revise Diesel Fuel Monitoring Program procedures to include avolumetric examination of affected areas of the diesel fuel oil tanks, ifevidence of degradation is observed during visual inspection. Thescope of this enhancement includes the standby DG seven-day fueloil storage tanks, standby DG fuel oil day tanks, and HPFP diesel fueloil storage tank and is applicable to the inspections performed duringthe ten-year period prior to the PEO and succeeding ten-yearintervals.6 A. Revise External Surfaces Monitoring Program procedures to OQNI: Prior to 09/17/20 B.1.10clarify that periodic inspections of systems in scope and subject to SQN2: Prior to 09/15/21aging management review for license renewal in accordance with 10CFR 54.4(a)(1) and (a)(3) will be performed. Inspections shallinclude areas surrounding the subject systems to identify hazards tothose systems. Inspections of nearby systems that could impact thesubject systems will include SSCs that are in scope and subject toaging management review for license renewal in accordance with 10CFR 54.4(a)(2).B. Revise External Surfaces Monitoring Program procedures toinclude instructions to look for the following related to metalliccomponents:" Corrosion and material wastage (loss of material)." Leakage from or onto external surfaces loss of material)." Worn, flaking, or oxide-coated surfaces (loss of material)." Corrosion stains on thermal insulation (loss of material).* Protective coating degradation (cracking,flaking, and blistering).* Leakage for detection of cracks on the external surfaces ofstainless steel components exposed to an air environmentcontaining halides.C. Revise External Surfaces Monitoring Program procedures toinclude instructions for monitoring aging effects for flexiblepolymeric components, including manual or physical manipulationsof the material, with a sample size for manipulation of at least tenE-2 -3 of 22 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE I AUDITITEM(6)percent of the available surface area. The inspection parameters forpolymers shall include the following:* Surface cracking, crazing, scuffing, dimensional changes (e.g.,ballooning and necking).* Discoloration." Exposure of internal reinforcement for 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 beginning 5 years befor- 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).tQN1: Pri;r to 091"7115":) Prior t,,, t09!15!E-2 -4 of 22 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE (AUDITITEM(6) e 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. [RAI3.0.3-1 Request 6a]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 and .indoor insulated components operated below the dew point, which $QN1. PrFer t 0!7V!5have been identified with more than nominal degradation on the P:a-WOOM! 56exterior of the component, insulation is removed for inspection of thecomponent surface. For a representative sample of indoor insulatedE-2 -5 of 22 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE IAUDITITEM(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 1 0-year period during5 a boforo the PEO. [RAI 3.0.3-1 Request 6a]7 A. Revise Fatigue Monitoring Program procedures to monitor and SQN1: Prior to 09/17/20 B.1.11track critical thermal and pressure transients for components that SQN2: Prior to 09/15/21have been identified to have a fatigue Time Limited Aging Analysis.B. Fatigue usage calculations that consider the effects of the reactorwater environment will be developed for a set of sample reactorcoolant system (RCS) components. This sample set will include thelocations identified in NUREG/CR-6260 and additional plant-specificcomponent locations in the reactor coolant pressure boundary if theyare found to be more limiting than those considered in NUREG/CR-6260. In addition, fatigue usage calculations for reactor vesselinternals (lower core plate and control rod drive (CRD) guide tubepins) will be evaluated for the effects of the reactor waterenvironment. Fen factors will be determined as described in Section4.3.3.C. Fatigue usage factors for the RCS pressure boundarycomponents will be adjusted as necessary to incorporate the effectsof the Cold Overpressure Mitigation System (COMS) event (i.e., lowtemperature overpressurization event) and the effects of structuralweld overlays.D. Revise Fatigue Monitoring Program procedures to provideupdates of the fatigue usage calculations 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.8 A. Revise Fire Protection Program procedures to include an SQN1: Prior to 09/17/20 B.1.12inspection of fire barrier walls, ceilings, and floors for any signs of SQN2: Prior to 09/15/21degradation such as cracking, spalling, or loss of material caused byfreeze thaw, chemical attack, or reaction with aggregates.B. Revise Fire Protection Program procedures to provide acceptancecriteria of no significant indications of concrete cracking, spalling, andloss of material of fire barrier walls, ceilings, and floors and in otherfire barrier materials.E-2 -6 of 22 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE I AUDITITEM9Implement the Fire Water System Program (FWSP) as described inLRA Section B.1.13.A. Revise FWSP procedures to include periodic visual inspection offire water system internals for evidence of corrosion and loss of wallthickness.B. hr R %i Fire Water SYcter ProgramA proedureFA to inude ono of3QNI: Prior to 09/17/203QN2: Prior to 09/15/21B.1.13the following options-.-Wail tflckneesr ev.aiuatlons of fire protection piping using non------------vv v.,vv ,.v p, .. iR*F'WV8t8GhRiC3US6i90 evidenceV WVV0of io-Asu ormaeRoal will Be penorMeG PRiOrQ IRA Kte r angperiod ically there-afterf. Results of the initial evaluations will beused to determinRe the appropriate inspection intrval1 to enSUreaging effects are identified prior to loSS Of inAne function.A visual inspec-tion of the itral sufc ffire protectionpiinWill be perfoFrmed upon each entry into the system forF routinocorrectiVe maintenance. Thoce inspectionS Will be capable ofevaluating (1) wall thickness to ensure against catastr-ophicfailure and (2) the inner diameter of the piping as it applies to thedesign flow Of the fir protection; syStem. Maintenance historyshall beA u19ed to demonstrate that 6such inspections haVe beenperformed on a reprFeSentativle nu-m-ber Of locations prorF to theP21=-O A mrmaesnta-hoa numbe~r i 20%A of the pnooulationCRevine as IpocedauI s aVong Enue- pame mer iead, eronentest,and aging effeA-c5t cmio with a maximuim of 25 locations.A.ddeitial insepeiofns will botespgormedi as needed to obtain thisrepresentative sample prior to- the PIEG- and periodically duringthe PEG basetda en the fin-dings from the inspec3tions pelf0medPPROF to he PE-O-*Commitment 9.13 is deleted in RAI 3.0.3-1, Request 4a,CNL-130, Enc 1, pg E-1 -13 of 43,12/16/1 3)C. Revise FWSP procedures to ensure-sprinkler heads are tested inaccordance with NFPA-25 (2011 Edition), Section 5.3.1 [RAI 3.0.3-1Request 4a]D. Revise the FWSP full flow testing to be in accordance with fullflow testing standards of NFPA-25 (2011). [RAI B.1.13-2, RAI 3.0.3-1Request 4a]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 select an inspection method (ormethods) that will provide suitable indication of piping wall thicknessfor a representative sample of buried piping locations to supplementthe existing inspection locations for high pressure fire protectionsystem 26 and essential raw cooling water system 67. [RAI 3.0.3-1,request5a, Set 10.30, 9/3/13]G. Revise FWSP procedures to include periodically remove arepresentative sample of components, such as sprinkler heads orE-2 -7 of 22 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE IAUDITITEM(9) couplings, within five years prior to and every five years during thePEO to perform a visual internal inspection of the dry fire watersystem piping intemals 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. This includesthose sections of dry piping described in NRC Information Notice (IN)2013-06, where drainage is not occurring.The acceptance criteria shall be "no debris" (i.e., no corrosionproducts that could impede flow or cause downstream components tobecome clogged)..Any' additional insp.ct.nc. in 6ccordance withNFPA 25, Sections 14.2.1 or 14.2.2 will be bacoad on theintan tien results. Any signs of abnormal corrosion or blockage willbe entered into the CAP. (See RAI Response 3.0.3-1, Request 4a.d. iH. 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. Revise FWSP procedures based on the results of a feasibilitystudy to perform the main drain tests in accordance with NFPA-25(2011 Edition) Section 13.2.5.M. Revise FWSP procedures to perform 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 notprevent discharge patterns from wetting surfaces to be protected.E-2 -8 of 22 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE AUDITITEM(9) 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 trio testing of the deluae 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, CNL-130, Enc 1, pg 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.0. Revise Fire Water Program procedures to perform 30 main draintests every 18 months. At least one main drain test is performed ineach of the following buildings: (1) control building, (2) auxilliarybuilding, (3) turbine building, (4) diesel generator building, and (5)ERCW building.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. [RAI 3.0.3-1, Request 4a, forCommitments 9.B.C,G, M to 0]10 A. Revise Flow Accelerated Corrosion (FAC) Program procedures SQNI: Prior to 09/17/20 B.1.14to implement NSAC-202L guidance for examination of components SQN2: Prior to 09/15/21upstream of piping surfaces where significant wear is detected.B. Revise FAC Program procedures to implement the guidance inLR-ISG-2012-01, which will include a susceptibility review based oninternal operating experience, external operating experience, EPRITR-1 011231, Recommendations for Controlling Cavitation, Flashing,Liquid Droplet Impingement, and Solid Particle Erosion in NuclearPower Plant Piping, and NUREG/CR-6031, Cavitation Guide forControl Valves. [RAI B.1.14-1 and B.1.38-1] I IE-2 -9 of 22 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE I AUDITITEM11 Revise Flux Thimble Tube Inspection Program procedures to SQNI: Prior to 09/17/20 B.1.15include a requirement to address if the predictive trending projects SQN2: Prior to 09/15/21that a tube will exceed 80% wall wear prior to the next plannedinspection, then initiate a Service Request (SR) to define actions (i.e.,plugging, repositioning, replacement, evaluations, etc.) required toensure that the projected wall wear does not exceed 80%. If anytube is found to be >80% through wall wear, then initiate a ServiceRequest (SR) to evaluate the predictive methodology used andmodify as required to define corrective actions (i.e., plugging,repositioning, replacement, etc).12 A. Revise Inservice Inspection-IWF Program procedures to clarify SQN1: Prior to 09/17/20 B.1.17that detection of aging effects will include monitoring anchor bolts for SQN2: Prior to 09/15/21loss of material, loose or missing nuts, and cracking of concretearound the anchor bolts.B. Revise ISI -IWF Program procedures to include the followingcorrective action guidance.When a component support is found with minor age-relateddegradation, but still is evaluated as "acceptable for continuedservice" as defined in IWF-3400, the program owner may chooseto repair the degraded component. If the component is repaired,the program owner will substitute a randomly selected componentthat is more representative of the general population forsubsequent inspections.13 Inspection of Overhead Heavy Load and Light Load (Related to SQNI: Prior to 09/17/20 B.1.18Refueling) Handling Systems: SQN2: Prior to 09/15/21A. Revise program procedures to specify the inspection scope willinclude monitoring of rails in the rail system for wear; monitoringstructural components of the bridge, trolley and hoists for the agingeffect of deformation, cracking, and loss of material due to corrosion;and monitoring structural connections/bolting for loose or missingbolts, nuts, pins or rivets and any other conditions indicative of loss ofbolting integrity.B. Revise program procedures to include the inspection andinspection frequency requirements of ASME B30.2.C. Revise program procedures to clarify that the acceptance criteriawill include requirements for evaluation in accordance with ASMEB30.2 of significant loss of material for structural components andstructural bolts and significant wear of rail in the rail system.D. Revise program procedures to clarify that the acceptance criteriaand maintenance and repair activities use the guidance provided inASME B30.214 Implement the Internal Surfaces in Miscellaneous Piping and SQNI: Prior to 09/17/20 B.1.19Ducting Components Program as described in LRA Section B.1.19. SQN2: Prior to 09/15/21E-2- 10 of 22 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE / AUDITITEM15 Implement the Metal Enclosed Bus Inspection Program as SQNI: Prior to 09/17/20 B.1.21described in LRA Section B.1.21. SQN2: Prior to 09/15/2116 A. Revise Neutron Absorbing Material Monitoring Program SQNI: Prior to 09/17/20 B.1.22procedures to perform blackness testing of the Boral coupons within SQN2: Prior to 09/15/21the ten years prior to the PEO and at least every ten years thereafterbased on initial testing to determine possible changes in boron-10areal density.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: Priorto 09/17/20 B.1.24in LRA Section B.1.24 SQN2: Prior to 09/15/2118 Implement the Non-EQ Inaccessible Power Cable (400 V to 35 kV) SQN1: Prior to 09/17/20 B.1.25Program as described in LRA Section B.1.25 SQN2: Prior to 09/15/21A. TVA response to RAI B.1.25.1a1. Repair the manhole sump pump and discharge piping 18.A.1: Sept 2015deficiencies associated with the accumulation of water in sevenmanholes/handholes that are scheduled for correction and/ormitigation by September 2015. (HH3, HH2B, HH52B, HH55A2,MH7B, MH1OA and MH32B as identified on October 1, 2013) 18.A.3:2. Grade the ground surface around Manhole 31 to direct runoff QN1: Prior to 09/17/20away from the manhole. The re-grading is scheduled for QN2: Prior to 09/15/21completion 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.19 Implement the Non-EQ Instrumentation Circuits Test Review SQN1: Prior to 09/17/20 B.1.26Program as described in LRA Section B.1.26. SQN2: Prior to 09/15/21E-2- 11 of 22 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE IAUDITITEM20 Implement the Non-EQ Insulated Cables and Connections SQNI: Prior to 09/17/20 B.1.27Program as described in LRA Section B.1.27 SQN2: Prior to 09/15/2121 A. Revise Oil Analysis Program procedures to monitor and SQN1: Prior to 09/17/20 B.1.28maintain contaminants in the 161-kV oil filled cable system within SQN2: Prior to 09/15/21acceptable limits through periodic sampling in accordance withindustry standards, manufacturer's recommendations and plant-specific operating experience.B. Revise Oil Analysis Program procedures to trend oil contaminantlevels and initiate a problem evaluation report if contaminants exceedalert levels or limits in the 161-kV oil-filled cable system.22 Implement the One-Time Inspection Program as described in LRA QNI: Prior to 09/17/20 B.1.29Section B.1.29. QN2: Prior to 09/15/2123 Implement the One-Time Inspection -Small Bore Piping Program QNI: Prior to 09/17/20 B.1.30as described in LRA Section B.1.30 QN2: Prior to 09/15/2124 A. Revise Periodic Surveillance and Preventive Maintenance 24.A&C B.1.31Program procedures as necessary to include all activities described SQN1: Prior to 09/17/20in the table provided in the LRA Section B.1.31 program description. SQN2: Prior to 09/15/21B. RAI 3.0.3-1, Request 3, Loss of Coating Integrity:For in-scope components that have internal Service Level III or Other 24.Bcoatings, initial inspections will begin no later than the last scheduled SQN1: RFO Prior torefueling outage prior to the PEO. Subsequent inspections will be )9/17/20performed based on the initial inspection results.QN2: RFO Prior toC. RAI 3.0.3-1, Request la: Perform a minimum of five MIC 09/15/21decqradation inspections Per year until the rate of MIC occurrences nolonger meets the criteria for recurring internal corrosion.Prior to the period of extended operation, select a method (ormethods) from available technologies for inspecting internal surfacesof buried piping that provides suitable indication of piping wallthickness for a representative set of buried piping locations tosupplement the set of selected inspection locations25 A. Revise Protective Coating Program procedures to clarify that SQNI: Prior to 09/17/20 B.1.32detection of aging effects will include inspection of coatings near SQN2: Prior to 09/15/21sumps or screens associated with the emergency core coolingsystem.B. Revise Protective Coating Program procedures to clarify thatinstruments and equipment needed for inspection may include, butnot be limited to, flashlights, spotlights, marker pen, mirror, measuringtape, magnifier, binoculars, camera with or without wide-angle lens,and self-sealing polyethylene sample bags.E-2- 12 of 22 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE /AUDITITEM(25) 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 SQNI: Prior to 09/17/20 B.1.33ensure that replacement studs are fabricated from bolting material SQN2: Prior to 09/15/21with actual measured yield strength less than 150 ksi.B. Revise Reactor Head Closure Studs Program procedures toexclude the use of molybdenum disulfide (MoS2) on the reactorvessel closure studs and to refer to Reg. Guide 1.65, Revl.27 A. Revise Reactor Vessel Internals Program procedures to OQNI: Within three Ul B.1.34perform direct measurement of Unit 1 304 SS hold down spring efuel cycles of the dateheight within three cycles of the beginning of the period of extended )9/17/20operation. 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 Letter, 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 1.28 A. Revise Reactor Vessel Surveillance Program procedures to 3QN1: Prior to 09/17/20 B.1.35consider the area outside the beltline such as nozzles, penetrations 3QN2: Prior to 09/15/21and discontinuities to determine if more restrictive pressure-temperature limits are required than would be determined by justconsidering the reactor vessel beltline materials.B. Revise Reactor Vessel Surveillance Program procedures toincorporate an NRC-approved schedule for capsule withdrawals tomeet ASTM-E1 85-82 requirements, including the possibility ofoperation beyond 60 years (refer to the TVA Letter to NRC,"Sequoyah Reactor Pressure Vessel Surveillance CapsuleWithdrawal Schedule Revision Due to License RenewalAmendment," dated 01/10/13, ML13032A251; NRC approval, on09/27/13, 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 QN1: Prior to 09/17/20 B.1.37Section B.1.37. QN2: Prior to 09/15/2130 Revise Steam Generator Integrity Program procedures to ensure QNI: Prior to 09/17/20 B.1.39that corrosion resistant materials are used for replacement steam QN2: Prior to 09/15/21generator tube plugs.E-2- 13 of 22 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE / AUDITITEM31A. Revise Structures Monitoring Program procedures to includethe following in-scope structures:" Carbon dioxide building* Condensate storage tanks' (CSTs) foundations and pipe trench* East steam valve room Units 1 & 2* Essential raw cooling water (ERCW) pumping station* High pressure fire protection (HPFP) pump house and waterstorage tanks' foundations" Radiation monitoring station (or particulate iodine and noble gasstation) Units 1 & 2" Service building* Skimmer wall (Cell No. 12)* Transformer and switchyard support structures and foundationsB. Revise Structures Monitoring Program procedures to specify thefollowing list of in-scope structures are included in the RG 1.127,Inspection of Water-Control Structures Associated with NuclearPower Plants Program (Section B.1.36):* Condenser cooling water (CCW) pumping station (also known asintake pumping station) and retaining walls* CCW pumping station intake channel* ERCW discharge box* ERCW protective dike" ERCW pumping station and access cells" Skimmer wall, skimmer wall Dike A and underwater damC. Revise Structures Monitoring Program procedures to include thefollowing in-scope structural components and commodities:* Anchor bolts* Anchorage/embedments (e.g., plates, channels, unistrut, angles,other structural shapes)* Beams, columns and base plates (steel)* 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 foundationSQNI: Prior to 09/17/20SQN2: Prior to 09/15/21B.1.40E-2- 14 of 22 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE / AUDITITEM(31) % 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 siding* Miscellaneous steel (decking, grating, handrails, ladders,platforms, enclosure plates, stairs, vents and louvers, framingsteel, etc.)* Missile barriers/shields (concrete)* Missile barriers/shields (steel)" Monorails* Penetration 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-A .A ___________________________________ IE-2- 15 of 22 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE / AUDITITEM(31) 9 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 (steel)* Sump liners (steel)* Sump screens* Support members; welds; bolted connections; supportanchorages to building structure (e.g., non-ASME piping andcomponents supports, conduit supports, cable tray supports,HVAC duct supports, instrument tubing supports, tube 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 supportframing" Trenches (concrete)" Tube track* Turning vanes* Vibration isolatorsD. Revise Structures Monitoring Program procedures to includeperiodic sampling and chemical analysis of ground water chemistryfor pH, chlorides, and sulfates on a frequency of at least every fiveyears.E. Revise Masonry Wall Program procedures to specify masonrywalls located in the following in-scope structures are in the scope ofthe Masonry Wall Program:* Auxiliary building* Reactor building Units .1 & 2* Control bay* ERCW pumping station* HPFP pump house* Turbine buildingF. Revise Structures Monitoring Program procedures to include thefollowing parameters to be monitored or inspected:* Requirements for concrete structures based on ACI 349-3Rand ASCE 11 and include monitoring the surface condition forloss of material, loss of bond, increase in porosity andpermeability, loss of strength, and reduction in concrete anchorcapacity due to local concrete degradation.E-2- 16 of 22 LRANo. COMMITMENT IMPLEMENTATION SECTIONNo.COM TSCHEDULE /AUDITITEM(31)
* Loose or missing nuts for structural bolting.* Monitoring gaps between the structural steel supports andmasonry walls that could potentially affect wall qualification.G. Revise Structures Monitoring Program procedures to include thefollowing components to be monitored for the associated parameters:* Anchors/fasteners (nuts and bolts) will be monitored for looseor missing nuts and/or bolts, and cracking ofconcrete aroundthe anchor bolts.* Elastomeric vibration isolators and structural sealants will bemonitored for cracking, losi of material, loss of sealing, andchange in material properties (e.g., hardening).* Monitor the surface condition of insulation (fiberglass, calciumsilicate) to identify exposure to moisture that can cause loss ofinsulation effectiveness.H. Revise Structures Monitoring Program procedures to include thefollowing for detection of aging effects:* Inspection of structural bolting for loose or missing nuts.* Inspection of anchor bolts for loose or missing nuts and/orbolts, and cracking of concrete around the anchor bolts.* Inspection of elastomeric material for cracking, loss of material,loss of sealing, and change in material properties (e.g.,hardening), and supplement inspection by feel or touch todetect hardening if the intended function of the elastomericmaterial is suspect. Include instructions to augment the visualexamination of elastomeric material with physical manipulationof at least ten percent of available surface area.* Opportunistic inspections when normally inaccessible areas(e.g., high radiation areas, below grade concrete walls orfoundations, buried or submerged structures) becomeaccessible due to required plant activities. Additionally,inspections will be performed of inaccessible areas inenvironments where observed conditions in accessible areasexposed to the same environment indicate that significantdegradation is occurring.* Inspection of submerged structures at least once every fiveyears.Inspections of water control structures should be conductedunder the direction of qualified personnel experienced in theinvestigation, design, construction, and operation of thesetypes of facilities.* Inspections of water control structures shall be performed onan interval not to exceed five years.* Perform special inspections of water control structuresimmediately (within 30 days) following the occurrence ofsignificant natural phenomena, such as large floods,earthquakes, hurricanes, tornadoes, and intense local rainfalls." Insulation (fiberglass, calcium silicate) will be monitored forloss of material and change in material properties due topotential exposure to moisture that can cause loss of insulationeffectiveness.I. Revise Structures Monitoring Program procedures to prescribeE-2- 17 of 22 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE / AUDITITEM(31) quantitative acceptance criteria based on the quantitative acceptancecriteria of ACl 349.3R and information provided in industry codes,standards, and guidelines including ACI 318, ANSI/ASCE 11 andrelevant AISC specifications. Industry andplant-specific operating experience will also be considered in thedevelopment of the acceptance criteria.J. Revise Structures Monitoring Program procedures to clarify thatdetection of aging effects will include the following.Qualifications of personnel conducting the inspections or testing andevaluation of structures and structural components meet theguidance in Chapter 7 of ACI 349.3R.K. Revise Structures Monitoring Program procedures to include thefollowing acceptance criteria for insulation (calcium silicate andfiberglass)* No moisture or surface irregularities that indicate exposure tomoisture.L. Revise Structures Monitoring Program procedures to include thefollowing preventive actions.Specify protected storage requirements for high-strength fastenercomponents (specifically ASTM A325 and A490 bolting).Storage of these fastener components shall include:1. Maintaining fastener components in closed containers to protectfrom dirt and corrosion;2. Storage of the closed containers in a protected shelter;3. Removal of fastener components from protected storage only asnecessary; 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, if necessary.5. Commitment #31 .M will be implemented before the PEO for SQNUnits 1 and 2.-L ______________________________________________________________ _____________________ I ________E-2- 18 of 22 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 SQN1: Prior to 09/17/20SQN2: Prior to 09/15/21A. 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.(SQN1: Prior to 09/17/18 SQN2: Prior to 09/15/19)33 A. Revise Water Chemistry Control -Closed Treated Water SQN1: Prior to 09/17/20 B.1.42Systems Program procedures to provide a corrosion inhibitor for the SQN2: Prior to 09/15/21following chilled water subsystems in accordance with industryguidelines and vendor recommendations:* Auxiliary building cooling* Incore Chiller 1A, 1B, 2A, & 2B* 6.9 kV Shutdown Board Room A & BB. Revise Water Chemistry Control -Closed Treated WaterSystems Program procedures to conduct inspections whenever aboundary is opened for the following systems:* Standby diesel generator jacket water subsystem* Component cooling system" Glycol cooling loop 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.(33) E. Revise Water Chemistry Control -Closed Treated WaterSystems Program procedures to inspect a representative sample ofpiping and components at a frequency of once every ten years forthe following systems:* Standby diesel generator jacket water subsystem* Component cooling systemE-2 -19 of 22 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE / AUDITITEM* Glycol cooling loop system* High pressure fire protection diesel jacket water system* Chilled water portion of miscellaneous HVAC systems (i.e.,auxiliary building, Incore Chiller 1A, 1B, 2A, & 2B, and 6.9 kVShutdown Board Room A & B)F. Components inspected will be those with the highest likelihoodof corrosion or cracking. A representative sample is 20% of thepopulation (defined as components having the same material,environment, and aging effect combination) with a maximum of 25components. These inspections will be in accordance withapplicable ASME Code requirements, industry standards, or otherplant-specific inspection and personnel qualification procedures thatensure the capability of detecting corrosion or cracking.34 Revise Containment Leak Rate Program procedures to require SQN1: Prior to 09/17/20 B.1.7venting the SCV bottom liner plate weld leak test channels to the SQN2: Prior to 09/15/21containment atmosphere prior to the CILRT and resealing the ventpath after the CILRT to prevent moisture intrusion during plantoperation.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 SQN1: Prior to 09/17/20the 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 5. B & C:boxes and associated materials, perform visual examinations of all SQN1: Prior to 09/17/20accessible surfaces, including the access box surfaces, cover plate, SQN2: Prior to 09/15/21welds, and gasket sealing surfaces of the access boxes on each unitevery other refueling outage with the gasketed access box lidremoved.C. From B.1.6-2b Response: Continue volumetric examinationswhere the SCV domes were cut at the frequency of once every fiveyears until the coatings are reinstalled at these locations.E-2- 20 of 22 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE /AUDITITEM36A. Revise Inservice Inspection Program procedures to include asupplemental inspection of Class 1 CASS piping components thatdo 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. (RAIB. 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)SQNI: Prior to 09/17/20SQN2: Prior to 09/15/21B.1.16E-2- 21 of 22 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE /_AUDITITEM37TVA will implement the Operating Experience for the AMPs inaccordance with the TVA response to the RAI B.O.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) to provide ascreening process of corrective action documents for agingmanagement items, the assignment of aging corrective actionsto appropriate AMP owners, and consideration of the agingmanagement 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 SON 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 SON renewed operating license isscheduled to be issued.S1o later than the3cheduled issue date of:he renewed operatingicenses for SON Units 1K 2. (Currently February2015)B.0.438 Implement the Service Water Program as described in LRA Section SQNI: Prior to 09/17/20 B.1.38B.1.38. (RAI 3.0.3-1, Request 3) SQN2: Prior to 09/15/211The above table identifies the 3_8 SON NRC LR commitments. Any other statements in this letterare provided for information purposes and are not considered to be regulatory commitments.This Commitment Revision supersedes all previous versions.E-2- 22 of 22
}}

Latest revision as of 12:47, 11 April 2019

Redirect to:

Retrieved from "https://kanterella.com/w/index.php?title=ML13357A722&oldid=1438066"