ML14300A016

Response to NRC Request for Additional Information Regarding the Review of the Sequoyah Nuclear Plant, Units 1 and 2, License Renewal Application, Set 22, B.1.34-9c

ML14300A016
Person / Time
Site:	Sequoyah
Issue date:	10/22/2014
From:	Shea J W Tennessee Valley Authority
To:	Document Control Desk, Office of Nuclear Reactor Regulation
Shared Package
ML14300A009	List: CNL-14-181, Response to NRC Request for Additional Information Regarding the Review of the Sequoyah Nuclear Plant, Units 1 and 2, License Renewal Application, Set 22, B.1.34-9c
References
CNL-14-181, TAC MF0481, TAC MF0482
Download: ML14300A016 (45)

Text

Withhold from Public Disclosure in Accordance with 10 CFR 2.390. Uponremoval of Enclosure 2, this letter is uncontrolled.

Tennessee Valley Authority, 1101 Market Street, Chattanooga, Tennessee 37402CNL-14-181 October 22, 201410 CFR Part 54ATTN: Document Control DeskU.S. Nuclear Regulatory Commission Washington, D.C. 20555-0001 Sequoyah Nuclear Plant, Units 1 and 2Facility Operating License Nos. DPR-77 and DPR-79NRC Docket Nos. 50-327 and 50-328

References:

Response to NRC Request for Additional Information Regarding theReview of the Sequoyah Nuclear Plant, Units I and 2, License RenewalApplication, Set 22, B.1.34-9c (TAC Nos. MF0481 and MF0482)1. TVA Letter to NRC, "Sequoyah Nuclear Plant, Units 1 and 2 LicenseRenewal,"

dated January 7, 2013 (ADAMS Accession No. ML13024A004)

2. NRC Letter to TVA, "Requests for Additional Information for the Review ofthe Sequoyah Nuclear Plant, Units 1 and 2, License Renewal Application

-Set 22," dated September 22, 2014 (ADAMS Accession No.ML14254A204)

By letter dated January 7, 2013 (Reference 1), the Tennessee Valley Authority (TVA)submitted an application to the Nuclear Regulatory Commission (NRC) to renew theoperating licenses for the Sequoyah Nuclear Plant (SQN), Units 1 and 2. The request wouldextend the licenses for an additional 20 years beyond the current expiration dates.By Reference 2, the NRC forwarded a request for additional information (RAI) B. 1.34-9c witha response due date no later than October 22, 2014. Enclosure 1 contains TVA's non-proprietary response to RAI B.1.34-9c, suitable for public disclosure.

Enclosure 2 contains the RAI B. 1.34-9c response, portions of which Westinghouse considers to be proprietary in nature. Pursuant to 10 CFR 2.390, "Public inspections, exceptions, requests for withholding,"

paragraph (a)(4), it is requested that Enclosure 2 bewithheld from public disclosure.

Enclosure 3 provides the affidavit supporting this request.ý,t64-ý KF, U.S. Nuclear Regulatory Commission CNL-14-181 Page 2October 22, 2014Consistent 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.Enclosure 4 is an updated list of the regulatory commitments for license renewal thatsupersedes all previous versions.

Please address any questions regarding this submittal toHenry Lee at (423) 751-2683.

I declare under penalty of perjury that the foregoing is true and correct.

Executed on this22nd day of October 2014.J. Vi e resident, Nuclear Licensing

Enclosures:

1. TVA Response to NRC RAI B.1.34-9c (PWROG-14057

-non-proprietary)

2. TVA Response to NRC RAI B.1.34-9c (PWROG-14057

-proprietary)

3. Westinghouse Affidavit for RAI B.1.34-9c, CAW-14-4038

4. Regulatory Commitment List, Revision 18cc (Enclosures):

NRC Regional Administrator-Region IINRC Senior Resident Inspector

-Sequoyah Nuclear Plant ENCLOSURE ITennessee Valley Authority Sequoyah Nuclear Plant, Units I and 2 License RenewalTVA Response to NRC RAI B.1.34-9c (PWROG-14057

-non-proprietary)

Note: Westinghouse proprietary information, which has been redacted, is indicated by[bracket].

RAI B.1.34-9c

Background

By letter dated, August 21, 2014, the applicant provided its response to request for additional information (RAI) B. 1.34-9b.

In its response the applicant identified that it exceeded one of thefuel loading threshold criteria bounding assumptions made in Electric Power Research Institute (EPRI) Technical Report (TR) No. MRP-227-A (EPRI Letter No. 2013-025, dated October 14,2013). The EPRI Material Reliability Project (MRP) states that for Westinghouse-designed

reactors, the distance from the top of the active fuel to the bottom of the upper core plate (UCP)in the reactor vessel internal (RVI) upper core assembly should be greater than or equal to12.2 inches. In its response, the applicant indicated that the active fuel to UCP distance wasless than 12.2 inches for more than two effective full-power years. The applicant stated that itprojected the maximum fast neutron fluence above the UCPs to be below the screening criteriafor irradiation embrittlement of materials located above the UPC over 60 years of operation.

IssueIn Table 3-3 of TR No. MRP-227-A, the EPRI MRP identifies that irradiation-assisted stresscorrosion cracking (IASCC) and irradiation embrittlement (IE) are aging mechanisms that mayoccur in Westinghouse-designed UCPs. However, the applicant's response to RAI B. 1.34-9bdoes not indicate the specific values of the active fuel to UCP distance, the duration in whichoperations of the Sequoyah facility were out of conformance with this parameter, or theprojected fluence after 60 years. Therefore, a more-detailed quantitative response is necessary to demonstrate that operations of the applicant's units are still within the fuel loading andoperation assumptions of TR MRP-227-A.

Requesta) Provide a brief description of the analysis and methodology used to make the determination that for materials located above the UCPs, the projected fluence after 60 years of operation will be below the threshold limit.b) Identify the neutron fluence values that are used as the lower-bound neutron fluencethresholds for inducing IASCC and IE in materials located above the UCPs of theSequoyah nuclear plant, Units 1 and 2. Provide the projected neutron fluence values forthe UCPs through 60 years of licensed operation.

TVA Response to RAI B.1.34-9c a) The screening evaluations reported in MRP-191 (Reference

2) were based on the bestavailable fluence data at that time. The original screening process in MRP-191 did notidentify irradiation embrittlement (IE) as a potential degradation mechanism for theWestinghouse upper core plate (UCP). The failure modes, effects, and criticality analysis(FMECA) process described in MRP-191 concluded that there were "no additional measures" required to manage aging degradation due to fatigue and wear in theWestinghouse UCP.El -I of 4 Topical Report Condition 1 of the MRP-227-A Safety Evaluation (Reference

3) added theWestinghouse UCP as an expansion category item requiring an enhanced visual (EVT-1)examination to MRP-227-A (Reference 4).Subsequent to the FMECA process described in MRP-1 91, sensitivity studies that wereperformed in support of developing the MRP-227-A applicability guideline

template, MRP 2013-025 (Reference 5), indicated that there is a potential for plant-specific analysisto demonstrate UCP fluences above the threshold for IE of austenitic stainless steel. On afleetwide basis, some Westinghouse plants are therefore expected to remain below thescreening criterion for 60 years of operation while other plants are expected to haveportions of the UCP that exceed the criterion.

However, because the UCP is clearly not aleading indicator of IE, there would be no effect on the classification of the UCP within theMRP-227-A structure.

At most, a higher fluence value would result in adding IE as apotential aging mechanism for the UCP.Distance Between Active Fuel and UCP for Sequoyah UnitsFor Sequoyah Nuclear Plant Unit 1 (SQN1), the cycle-average distance between the top ofthe active fuel and bottom surface of the UCP has varied between [ ]. For future fuelcycles, the distance between the top of the active fuel and bottom surface of the UCP isexpected to be [ ], for a nominal distance averaged over the lifetime (through the end-of-license-extension) of [ ] for SQN1. The distance between the active fuel andbottom surface of the UCP was below 12.2 inches for 12 out of the last 19 completed fuelcycles.For Sequoyah Nuclear Plant Unit 2 (SQN2), the cycle-average distance between the top ofthe active fuel and bottom surface of the UCP has varied between [ ]. For future fuelcycles, the distance between the top of the active fuel and bottom surface of the UCP isexpected to be [ ], for a nominal distance averaged over the lifetime (through the end-of-license-extension) of [ ] for SQN2. The distance between the active fuel andbottom surface of the UCP was below 12.2 inches for 11 out of the last 19 completed fuelcycles.The guideline in MRP 2013-025 that the distance between the active fuel and the UCPshould not be less than 12.2 inches for more than two years of operation is intended toserve as an indicator on whether additional evaluations are needed to demonstrate compliance with the applicability of MRP-227-A in the upper axial direction.

Per MRP2013-025, a plant-specific analysis may be required to demonstrate that the fluence abovethe UCP does not exceed the IE threshold.

Because both Sequoyah (SQN) units have operated for more than two years with distances between the active fuel and bottom surface of the UCP below 12.2 inches, additional evaluations were performed to demonstrate compliance, as noted in the response to RAIB.1.34-9b (Reference 1).Fluence Methodology The methodology used to determine the projected fluence above the UCPs is the samefluence methodology that was used in support of the Time-Limited Aging Analysis(TLAA) for reactor vessel neutron embrittlement for the SQN License Renewal Application (Reference 6). The neutron transport methodology used in support of the TLAA follows theguidance and meets the requirements of Regulatory Guide 1.190, "Calculational andDosimetry Methods for Determining Pressure Vessel Neutron Fluence."

The overallEl -2 of 4 analytical methodology is described in WCAP-14040-A (Reference

7) and WCAP-1 6083-NP-A (Reference 8). The NRC approval of the methodology is also noted in References 7and 8.In the application of this methodology to the fast neutron exposure evaluations for theSQN1 and SQN2 reactors, plant- and fuel-cycle-specific forward transport calculations were carried out using the following three-dimensional flux synthesis technique:

O(r,e,z)

= O(r,e) x [cI(r,z)/

P(r)], where0I(r,e,z) is the synthesized three-dimensional neutron flux distribution, (D (r,8) is the transport solution in (r,e) geometry, O(r,z) is the two-dimensional solution for a cylindrical reactor model using theactual axial core power distribution, and(P(r) is the one-dimensional solution for a cylindrical reactor model using thesame source per unit height as that used in the (r,e) two-dimensional calculation.

This synthesis procedure was carried out for each operating cycle at SQN1 and SQN2.Energy-and space-dependent core power distributions as well as system operating temperatures were treated on a fuel-cycle-specific basis.The analyses performed in support of the TLAA formed the basis for the current evaluation.

The (r) and (r,e) plant-specific transport results were directly used, while the (r,z) transport calculations were re-run with updated models to include information specific to regionsdirectly above the active fuel stack for SQN1. The nominal distance between the top of theactive fuel stack and the bottom of the UCP averaged over the lifetime (through the end-of-license-extension) of each respective unit was used in the analyses.

b) SQN Units I and 2, UCP Neutron Fluence ValuesAs demonstrated by the sensitivity studies performed subsequent to MRP-191, some plantsare expected to remain below the screening criterion for 60 years of operation while otherplants may have portions of the UCP that do exceed the criterion.

The UCP at each SQNunit is projected to be below the IASCC fluence criterion (2 x 1021 n/cm2). Each SQN unit isprojected to have portions of its respective UCP exceed the IE criterion for austenitic stainless steel (1 x 1021 n/cm2).The maximum projected fast neutron (E > 1.0 MeV) fluence near the lower surface of theUCP over 60 years of operation is estimated to be 1.87 x 1021 and 1.82 x 1021 n/cm2 forSQN1 and SQN2, respectively.

As noted in the response to RAI B.1.34-9b, the maximum fast neutron (E > 1.0 MeV)fluence above the UCP at each respective SQN unit is projected to be below the threshold values (both austenitic stainless steel (1 x 1021 n/cm2) and cast austenitic stainless steel(6.7 x 1020 n/cm2)) for IE over 60 years of operation.

The maximum projected fast neutron (E > 1.0 MeV) fluence near the upper surface of theUCP over 60 years of operation is estimated to be 6.39 x 1020 and 6.22 x 1020 n/cm2 forSQN1 and SQN2, respectively.

El -3 of 4 Therefore, a portion of each UCP will exceed the IE threshold value over 60 years ofoperation, while a portion of each UCP will remain below the IE threshold value. Becausethe UCP is clearly not a leading indicator of IE, there is no effect on the classification of theUCP within the MRP-227-A structure.

The higher fluence value (that exceeds the IEthreshold for IE over 60 years of operation) in each UCP will result in adding IE as apotential aging mechanism for the UCP.SQN Inspection Procedure SQN performs inservice inspections of core support structure components in accordance with Examination Category B-N-3 of Section Xl of the ASME Boiler & Pressure VesselCode (ASME Code). SQN will revise the Category B-N-3 procedure before the period ofextended operation (PEO) to reference this Request for Additional Information B.1.34-9c response and identify the inspection of the accessible regions of the upper core plate lowersurface as a specific area of interest for License Renewal required inspection.

Commitment 36.H: Revise SQN's Category B-N-3 inspection procedure to reference the September 22, 2014, NRC RAI B.1.34-9c and SQN's response (ML14254A204 andCNL-14-181) to identify that the inspection of the accessible regions the upper core platelower surface (core support structure components, VT-3 inspection below the upper coreplate to determine the general mechanical and structural condition of components) as arequired License Renewal Inspection during the PEO.

References:

1. TVA Letter to NRC, "Response to NRC Request for Additional Information Regarding theReview of the Sequoyah Nuclear Plant, Units 1 and 2, License Renewal Application, B.1.34-9b, Ten Commitment

Updates, and 3.0.3-1 Item 5b (TAC Nos. MF0481 andMF0482),"

August 21, 2014.2. Materials Reliability Program:

Screening, Categorization, and Ranking of Reactor Internals Components for Westinghouse and Combustion Engineering PWR Design (MRP-191),

EPRI, Palo Alto, CA: 2006.3. NRC Letter to TVA, "Revision 1 to the Final Safety Evaluation of Electric Power ResearchInstitute (EPRI) Report, Materials Reliability Program (MRP) Report 1016596 (MRP-227),

revision 0, "Pressurized Water Reactor (PWR) Internals Inspection and Evaluation Guidelines" (TAC NO. ME0680),"

December 16, 2011. (NRC ADAMS Accession No.:ML11308A770)

4. Materials Reliability Program:

Pressurized Water Reactor Internals Inspection andEvaluation Guidelines (MRP-227-A),

EPRI, Palo Alto, CA: 2011. 1022863.5. Materials Reliability Program:

MRP-227-A Applicability Template Guideline (MRP 2013-025),

EPRI, Palo Alto, CA, October 14, 2013.6. TVA Letter to NRC, "Sequoyah Nuclear Plant, Units 1 and 2 License Renewal,"

datedJanuary 7, 2013 (ADAMS Accession No. ML13024A004)

7. Westinghouse Report WCAP-14040-A, Rev. 4, "Methodology Used to Develop ColdOverpressure Mitigating System Setpoints and RCS Heatup and Cooldown Limit Curves,"May 2004.8. Westinghouse Report WCAP-16083-NP-A, Rev. 0, "Benchmark Testing of the FERRETCode for Least Squares Evaluation of Light Water Reactor Dosimetry,"

May 2006.El -4of4 ENCLOSURE 3Tennessee Valley Authority Sequoyah Nuclear Plant, Units I and 2 License RenewalWestinghouse Affidavit for RAI Response B.1.34-9c, CAW-14-4038

( ) Westinghouse U.S. Nuclear Regulatory Commission Document Control DeskH1555 Rockville PikeRockville, MD 20852Westinghouse Electric CompanyEngineering, Equipment and Major Projects1000 Westinghouse Drive, Building 3Cranberry

Township, Pennsylvania 16066USADirect tel:Direct fax:e-mail:Proj. letter(412) 374-4643(724) 940-8560greshaja@westinghouse.com OG-14-344 CAW-14-4038 September 30, 2014APPLICATION FOR WITHHOLDING PROPRIETARY INFORMATION FROM PUBLIC DISCLOSURE

Subject:

PWROG-14057-P, Rev. 0, "Sequoyah Nuclear Plant RAI Response for Upper Core PlateFluence -Applicant Action Items 1, 2, and 7" (Proprietary)

The proprietary information for which withholding is being requested in the above-referenced report isfurther identified in Affidavit CAW-14-4038 signed by the owner of the proprietary information, Westinghouse Electric Company LLC. The Affidavit, which accompanies this letter, sets forth the basison which the information may be withheld from public disclosure by the Commission and addresses withspecificity the considerations listed in paragraph (b)(4) of 10 CFR Section 2.390 of the Commission's regulations.

Accordingly, this letter authorizes the utilization of the accompanying Affidavit by Pressurized WaterReactor Owners Group (PWROG).Correspondence with respect to the proprietary aspects of the application for withholding or theWestinghouse Affidavit should reference CAW-] 4-4038 and should be addressed to James A. Gresham,Manager, Regulatory Compliance, Westinghouse Electric

Company, 1000 Westinghouse Drive,Building 3 Suite 310, Cranberry

Township, Pennsylvania 16066.Very truly yours,aRes A. Gresham, ManagerRegulatory Compliance Enclosures E3 -1 of 8 CAW-14-4038 AFFIDAVIT COMMONWEALTH OF PENNSYLVANIA:

ssCOUNTY OF BUTLER:Before me, the undersigned authority, personally appeared James A. Gresham, who, being by meduly sworn according to law, deposes and says that he is authorized to execute this Affidavit on behalf ofWestinghouse Electric Company LLC (Westinghouse),

and that the averments of fact set forth in thisAffidavit are true and correct to the best of his knowledge, information, and belief:4~es A. Gresham, ManagerRegulatory Compliance Sworn to and subscribed before methis 30th day of September 2014Notary PublicOMMONEALIHOF PENSYL ANI ~NOTARIAL.

SEALAnneM. teganNotary PubliclNoM Huntingdon Up., Westmoreland CountylMy Cmisuion Expires Aug. 7, 2016-- iiTiiNSYLI ANIA SOCIATION OF WjTIFR,E3-2of8 2CAW-14-4038 (1) 1 am Manager, Regulatory Compliance, Westinghouse Electric Company LLC (Westinghouse),

and as such, I have been specifically delegated the function of reviewing the proprietary information sought to be withheld from public disclosure in connection with nuclear power plantlicensing and rule making proceedings, and am authorized to apply for its withholding on behalfof Westinghouse.

(2) 1 am making this Affidavit in conformance with the provisions of 10 CFR Section 2.390 of theCommission's regulations and in conjunction with the Westinghouse Application for Withholding Proprietary Information from Public Disclosure accompanying this Affidavit.

(3) I have personal knowledge of the criteria and procedures utilized by Westinghouse in designating information as a trade secret, privileged or as confidential commercial or financial information.

(4) Pursuant to the provisions of paragraph (b)(4) of Section 2.390 of the Commission's regulations, the following is furnished for consideration by the Commission in determining whether theinformation sought to be withheld from public disclosure should be withheld.

(i) The information sought to be withheld from public disclosure is owned and has been heldin confidence by Westinghouse.

(ii) The information is of a type customarily held in confidence by Westinghouse and notcustomarily disclosed to the public. Westinghouse has a rational basis for determining the types of information customarily held in confidence by it and, in that connection, utilizes a system to determine when and whether to hold certain types of information inconfidence.

The application of that system and the substance of that system constitute Westinghouse policy and provide the rational basis required.

Under that system, information is held in confidence if it falls in one or more of severaltypes, the release of which might result in the loss of an existing or potential competitive advantage, as follows:(a) The information reveals the distinguishing aspects of a process (or component, structure, tool, method, etc.) where prevention of its use by any ofE3 -3 of 8 3CAW-14-4038 Westinghouse's competitors without license from Westinghouse constitutes acompetitive economic advantage over other companies.

(b) It consists of supporting data, including test data, relative to a process (orcomponent, structure, tool, method, etc.), the application of which data secures acompetitive economic advantage, e.g., by optimization or improvedmarketability.

(c) Its use by a competitor would reduce his expenditure of resources or improve hiscompetitive position in the design, manufacture,

shipment, installation, assurance of quality, or licensing a similar product.(d) It reveals cost or price information, production capacities, budget levels, orcommercial strategies of Westinghouse, its customers or suppliers.

(e) It reveals aspects of past, present, or future Westinghouse or customer fundeddevelopment plans and programs of potential commercial value to Westinghouse.

(f) It contains patentable ideas, for which patent protection may be desirable.

(iii) There are sound policy reasons behind the Westinghouse system which include thefollowing:

(a) The use of such information by Westinghouse gives Westinghouse a competitive advantage over its competitors.

It is, therefore, withheld from disclosure toprotect the Westinghouse competitive position.

(b) It is information that is marketable in many ways. The extent to which suchinformation is available to competitors diminishes the Westinghouse ability tosell products and services involving the use of the information.

(c) Use by our competitor would put Westinghouse at a competitive disadvantage byreducing his expenditure of resources at our expense.E3-4of8 4CAW-14-4038 (d) Each component of proprietary information pertinent to a particular competitive advantage is potentially as valuable as the total competitive advantage.

Ifcompetitors acquire components of proprietary information, any one component may be the key to the entire puzzle, thereby depriving Westinghouse of acompetitive advantage.

(e) Unrestricted disclosure would jeopardize the position of prominence ofWestinghouse in the world market, and thereby give a market advantage to thecompetition of those countries.

(f) The Westinghouse capacity to invest corporate assets in research anddevelopment depends upon the success in obtaining and maintaining acompetitive advantage.

(iv) The information is being transmitted to the Commission in confidence and, under theprovisions of 10 CFR Section 2.390, it is to be received in confidence by theCommission.

(v) The information sought to be protected is not available in public sources or available information has not been previously employed in the same original manner or method totie best of our knowledge and belief.(vi) The proprietary information sought to be withheld in this submittal is that which isappropriately marked in PWROG-14057-P, Rev. 0, "Sequoyah Nuclear Plant RAIResponse for Upper Core Plate Fluence -Applicant Action Items 1, 2, and 7" (Proprietary),

for submittal to the Commission, being transmitted by PWROG letter OG-14-344 andApplication for Withholding Proprietary Information from Public Disclosure, to theDocument Control Desk. The proprietary information as submitted by Westinghouse isthat associated with the NRC letter, "Requests for Additional Information for the Review ofthe Sequoyah Nuclear Plant, Units I and 2, License Renewal Application

-Set 22 (TACNOS. MF0481 and MF0482),"

MIvL14254A204, September 22, 2014, and may be used onlyfor that purpose.E3 -5 of 8 5CAW-14-4038 (a) This information is part of that which will enable Westinghouse to:(i) Support reactor vessel internals aging management.

(b) Further this information has substantial commercial value as follows:(i) Westinghouse plans to sell the use of similar information to its customers for the purpose of supporting reactor internals aging management.

(iii) The information requested to be withheld reveals the distinguishing aspects of a methodology which was developed by Westinghouse.

Public disclosure of this proprietary information is likely to cause substantial harm to thecompetitive position of Westinghouse because it would enhance the ability ofcompetitors to provide similar technical evaluation justifications and licensing defenseservices for commercial power reactors without commensurate expenses.

Also, publicdisclosure of the information would enable others to use the information to meet NRCrequirements for licensing documentation without purchasing the right to use theinformation.

The development of the technology described in part by the information is the result ofapplying the results of many years of experience in an intensive Westinghouse effort andthe expenditure of a considerable sum of money.In order for competitors of Westinghouse to duplicate this information, similar technical programs would have to be performed and a significant manpower effort, having therequisite talent and experience, would have to be expended.

Further the deponent sayeth not.E3 -6 of 8 Proprietary Information NoticeTransmitted herewith are proprietary and non-proprietary versions of documents furnished to the NRC inconnection with requests associated with the NRC letter, "Requests for Additional Information for theReview of the Sequoyah Nuclear Plant, Units I and 2, License Renewal Application

-Set 22 (TAC NOS.MF0481 and MF0482),"

MLi4254A204, September 22, 2014, and may be used only for that purpose.In order to conform to the requirements of 10 CFR 2.390 of the Commission's regulations concerning theprotection of proprietary information so submitted to the NRC, the information which is proprietary in theproprietary versions is contained within brackets, and where the proprietary information has been deletedin the non-proprietary

versions, only the brackets remain (the information that was contained within thebrackets in the proprietary versions having been deleted).

Thejustification for claiming the information so designated as proprietary is indicated in both versions by means of lower case letters (a) through (f)located as a superscript immediately following the brackets enclosing each item of information beingidentified as proprietary or in the margin opposite such information.

These lower case letters refer to thetypes of information Westinghouse customarily holds in confidence identified in Sections (4)(ii)(a) through (4)(ii)(f) of the Affidavit accompanying this transmittal pursuant to 10 CFR 2.390(b)(1).

Copyright NoticeThe reports transmitted herewith each bear a Westinghouse copyright notice. The NRC is permitted tomake the number of copies of the information contained in these reports which are necessary for itsinternal use in connection with generic and plant-specific reviews'and approvals as well as the issuance, denial, amendment,

transfer, renewal, modification, suspension, revocation, or violation of a license,permit, order, or regulation subject to the requirements of 10 CFR 2.390 regarding restrictions on publicdisclosure to the extent such information has been identified as proprietary by Westinghouse, copyright protection notwithstanding.

With respect to the non-proprietary versions of these reports, the NRC ispermitted to make the number of copies beyond those necessary for its internal use which are necessary inorder to have one copy available for public viewing in the appropriate docket files in the public documentroom in Washington, DC and in local public document rooms as may be required by NRC regulations ifthe number of copies submitted is insufficient for this purpose.

Copies made by the NRC must includethe copyright notice in all instances and the proprietary notice if the original was identified as proprietary.

E3 -7 of 8 Tennessee Valley Authority Letter for Transmittal to the NRCThe following paragraphs should be included in your letter to the NRC Document Control Desk:Enclosed are:1. One (1) copy of PWROG-14057-P, Rev. 0, "Sequoyah Nuclear Plant RAI Response for Upper CorePlate Fluence -Applicant Action Items 1,2, and 7" (Proprietary)

2. One (1) copy of PWROG-14057-NP, Rev. 0, "Sequoyah Nuclear Plant RAI Response for Upper CorePlate Fluence -Applicant Action Items 1, 2, and 7" (Non-Proprietary)

Also enclosed is the Westinghouse Application for Withholding Proprietary Information from PublicDisclosure CAW-14-4038, accompanying Affidavit, Proprietary Information Notice, and Copyright Notice.As Item I contains information proprietary to Westinghouse Electric Company LLC, it is supported by anAffidavit sign6d by Westinghouse, the owner of the information.

The Affidavit sets forth the basis onwhich the information may be withheld from public disclosure by the Commission and addresses withspecificity the considerations listed in paragraph (b)(4) of Section 2.390 of the Commission's regulations.

Accordingly, it is respectfully requested that the information which is proprietary to Westinghouse bewithheld from public disclosure in accordance with 10 CFR Section 2.390 of the Commission's regulations.

Correspondence with respect to the copyright or proprietary aspects of the items listed above or thesupporting Westinghouse Affidavit should reference CAW-14-4038 and should be addressed toJames A. Gresham,

Manager, Regulatory Compliance, Westinghouse Electric

Company, 1000Westinghouse Drive, Building 3 Suite 310, Cranberry

Township, Pennsylvania 16066.E3 -8 of 8 ENCLOSURE4 Tennessee Valley Authority Sequoyah Nuclear Plant, Units I and 2 License RenewalRegulatory Commitment List, Revision 18New Commitment:

36.HChanges in the highlighted commitment list are with additions underlined.

A. This list supersedes all previous versions.

The final version will be included in the SQNUFSAR Supplement (LRA Appendix A,) before incorporation into the SQN UFSAR (after NRCapproval of the SQN LRA). After incorporation into the SQN UFSAR, changes to information within the UFSAR Supplement (such as LR commitment) will be made in accordance with10 CFR 50.59.B. Throughout this document, the phrase "prior to entering the PEO" means the SQN AMPs willbe implemented six months prior to the PEO (For SQNI: prior to 03/17/20; for SQN2: prior to03/15/21) or the end of the last refueling outage prior to each unit entering the PEO,whichever occurs later.SQN shall notify the NRC in writing within 30 days after having accomplished items listed in theLR Commitment List and include the status of those activities that have been or remain to becompleted

[ML14057A808, E-1 p40, A.1-2]E lof30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE

/AUDITITEMA. Implement the Aboveground Metallic Tanks Program as SQN1: Prior to 03/17/20 B.1.1described in LRA Section B.1.1. [3.0.3-1, Requests 3, SQN2: Prior to 03/15/21ML13312A005.11/4/13]

B. Aboveground Metallic Tanks Program includes outdoor tanks onsoil or concrete and indoor large volume water tanks (excluding thefire water storage tanks) situated on concrete that are designed forinternal pressures approximating atmospheric pressure.

Periodicexternal visual and surface examinations are sufficient to monitordegradation.

Internal visual and surface examinations are conducted in conjunction with measuring the thickness of the tank bottoms toensure that significant degradation is not occurring and that thecomponent's intended function is maintained during the PEO.Internal inspections are conducted whenever the tank is drained, witha minimum frequency of at least once every 10 years, beginning inthe 6-year interval prior to the PEO. [3.0.3-1 item 5a, ML13294A462, E-2 -4 of 8, 10/17/13]

2 A. Revise Bolting Integrity Program procedures to ensure the SQN1: Prior to 03/17/20 B.1.2actual yield strength of replacement or newly procured bolts will be SQN2: Prior to 03/15/21less than 150 ksiB. Revise Bolting Integrity Program procedures to include theadditional guidance and recommendations of EPRI NP-5769 forreplacement of ASME pressure-retaining bolts and the guidanceprovided in EPRI TR-104213 for the replacement of otherpressure-retaining bolts.C. Revise Bolting Integrity Program procedures to specify acorrosion inspection and a check-off for the transfer tube isolation valve flange bolts.D. Revise Bolting Integrity Program procedures to visually inspect arepresentative sample of normally submerged ERCW system bolts atleast once every 5 years. (ML13252A036, Enc 1, B.1.2-2a, p20)3 A. Implement the Buried and Underground Piping and Tanks SQN1: Prior to 03/17/20 B.1.4Inspection Program as described in LRA Section B.1.4. SQN2: Prior to 03/15/21B. Cathodic protection will be provided based on the guidance ofNUREG-1801, section XI.M41, as modified by LR-ISG-2011-03.

[B.1.4-4b, ML13252A036.

E2 -4 of 7, 9/3/13] _ JE-4 -2 of 30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE

/AUDITITEM4 A. Revise Compressed Air Monitoring Program procedures to QN1: Prior to 03/17/20 B.1.5include the standby diesel generator (DG) starting air subsystem.

SQN2: Prior to 03/15/21B. Revise Compressed Air Monitoring Program procedures toinclude maintaining moisture and other contaminants below specified limits in the standby DG starting air subsystem.

C. Revise Compressed Air Monitoring Program procedures to applya consideration of the guidance of ASME OM-S/G-1998, Part 17;EPRI NP-7079; and EPRI TR-108147 to the limits specified for the airsystem contaminants D. 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 following compressed air systems:* Diesel starting air subsystem

• Auxiliary controlled air subsystem

• Nonsafety-related controlled air subsystem F. 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-4 -3 of 30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE IAUDITITEM5 A. Revise Diesel Fuel Monitoring Program procedures to monitor SQN1: Prior to 03/17/20 B.1.8and trend sediment and particulates in the standby DG day tanks. SQN2: Prior to 03/15/21B. Revise Diesel Fuel Monitoring Program procedures to monitor andtrend levels of microbiological organisms in the seven-day storagetanks.C. Revise Diesel Fuel Monitoring Program procedures to include aten-year periodic cleaning and internal visual inspection of thestandby DG diesel fuel oil day tanks and high pressure fire protection (HPFP) diesel fuel oil storage tank. These cleanings and internalinspections will be performed at least once during the ten-year periodprior to the period of extended operation (PEO) and at succeeding ten-year intervals.

If visual inspection is not possible, a volumetric inspection will be performed.

D. Revise Diesel Fuel Monitoring Program procedures to include avolumetric examination of affected areas of the diesel fuel oil tanks, ifevidence of degradation is observed during visual inspection.

Thescope of this enhancement includes the standby DG seven-day fueloil storage tanks, standby DG fuel oil day tanks, and HPFP diesel fueloil storage tank and is applicable to the inspections performed duringthe ten-year period prior to the PEO and succeeding ten-yearintervals.

6 A. Revise External Surfaces Monitoring Program procedures to SQN1: Prior to 03/17/20 B.1.10clarify that periodic inspections of systems in scope and subject to SQN2: Prior to 03/15/21aging management review for license renewal in accordance with 10CFR 54.4(a)(1) and (a)(3) will be performed.

Inspections shallinclude areas surrounding the subject systems to identify hazards tothose systems.

Inspections of nearby systems that could impact thesubject systems will include SSCs that are in scope and subject toaging. management review for license renewal in accordance with 10CFR 54.4(a)(2).

B. Revise External Surfaces Monitoring Program procedures toinclude instructions to look for the following related to metalliccomponents:

• Corrosion and material wastage (loss of material).

• Leakage from or onto external surfaces loss of material).

• Worn, flaking, or oxide-coated surfaces (loss of material).

• Corrosion stains on thermal insulation (loss of material).

• Protective coating degradation (cracking,flaking, and blistering).

• Leakage for detection of cracks on the external surfaces ofstainless steel components exposed to an air environment containing halides.C. Revise External Surfaces Monitoring Program procedures toinclude instructions for monitoring aging effects for flexiblepolymeric components, including manual or physical manipulations of the material, with a sample size for manipulation of at leastE-4 -4 of 30 LRANo. COMMITMENT IMPLEMENTATION.

SECTIONSCHEDULE I AUDITITEM(6) ten percent of the available surface area. The inspection parameters for polymers shall include the following:

" Surface cracking,

crazing, scuffing, dimensional changes (e.g.,ballooning and necking).

• Discoloration.

• Exposure of internal reinforcement for reinforced elastomers (loss of material).

• Hardening as evidenced by loss of suppleness duringmanipulation where the component and material can bemanipulated.

D. Revise External Surfaces Monitoring Program procedures tospecify the following for insulated components.

• Periodic representative inspections are conducted during each10-year period during the PEO.* For a representative sample of outdoor components, excepttanks, and indoor components, except tanks, identified withmore than nominal degradation on the exterior of thecomponent, insulation is removed for visual inspection of thecomponent surface.

Inspections include a minimum of 20percent of the in-scope piping length for each material type (e.g.,steel, stainless steel, copper alloy, aluminum).

For components with 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 inspections performed 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 representative jacketing 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 penetrate the insulation, and where water collects (for example on top ofstiffening rings).E-4 -5 of 30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE

/AUDITITEM(6)

• Inspection locations are based on the likelihood of corrosion under 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 barrer 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 insulation reveal 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 inspections under the insulation will continue as described above.[3.0.3-1 Request 6a, ML13357A722, E-1 -24 of 43, 12/16/13]

E. Revise External Surfaces Monitoring Program procedures toinclude acceptance criteria.

Examples include the following:

" Stainless steel should have a clean shiny surface with nodiscoloration.

• Other metals should not have any abnormal surfaceindications.

• Flexible polymers should have a uniform surface texture andcolor with no cracks and no unanticipated dimensional change, no abnormal surface with the material in an as-newcondition with respect to hardness, flexibility, physicaldimensions, and color." Rigid polymers should have no erosion,

cracking, checking orchalks.F. For a representative sample of outdoor insulated components andindoor insulated components operated below the dew point, whichhave been identified with more than nominal degradation on theexterior of the component, insulation is removed for inspection of thecomponent surface.

For a representative sample of indoor insulated E-4 -6 of 30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE I AUDITITEM(6) components operated below the dew point, which have not beenidentified with more than nominal degradation on the exterior of thecomponent, the insulation exterior surface is inspected.

Theseinspections will be conducted during each 10-year period during thePEO. [3.0.3-1 Request 6a, ML13357A722, E-1 -23 of 43, 12/16/13]

G. Specific, measurable, actionable/attainable and relevantacceptance criteria are established in the maintenance andsurveillance procedures or are established during engineering evaluation of the degraded condition.

[ML1 3357A722, E-1 -43 of 43,12/16/13]

7 A. Revise Fatigue Monitoring Program procedures to monitor and SQN1: Prior to 03/17/20 B.1.11track critical thermal and pressure transients for components that SQN2: Prior to 03/15/21have been identified to have a fatigue Time Limited Aging Analysis.

B. Fatigue usage calculations that consider the effects of the reactorwater environment will be developed for a set of sample reactorcoolant system (RCS) components.

This sample set will include thelocations identified in NUREG/CR-6260 and additional plant-specific component 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.

F,, 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 structural weld overlays.

D. Revise Fatigue Monitoring Program procedures to provideupdates of the fatigue usage calculations and cycle-based fatiguewaiver evaluations on an as-needed basis if an allowable cycle limit isapproached, or in a case where a transient definition has beenchanged, unanticipated new thermal events are discovered, or thegeometry of components have been modified.

E. Revise Fatigue Monitoring Program procedures to track thetensioning cycles for the reactor coolant pump hydraulic studs.E-4 -7 of 30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE IAUDITITEM8 A. Revise Fire Protection Program procedures to include an SQN1: Prior to 03/17/20 B.1.12inspection of fire barrier walls, ceilings, and floors for any signs of QN2: Prior to 03/15/21degradation such as cracking,

spalling, or loss of material caused byfreeze thaw, chemical attack, or reaction with aggregates.

B. Revise Fire Protection Program procedures to provide acceptance criteria of no significant indications of concrete

cracking, spalling, andloss of material of fire barrier walls, ceilings, and floors and in otherfire barrier materials.

9Implement the Fire Water System Program (FWSP) as described inLRA Section B.1.13.A. [Blank]B. [Blank]C. Revise FWSP procedures to ensure-sprinkler heads are tested inaccordance with NFPA-25 (2011 Edition),

Section 5.3.1 [3.0.3-1Request 4a]D. [Blank]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. [Blank]G. Revise FWSP procedures to include periodically remove arepresentative sample of components, such as sprinkler heads orcouplings, within five years prior to the PEO, and every five yearsduring the PEO, to perform a visual internal inspection of the dry firewater system piping for evidence of corrosion, and loss of wallthickness, and foreign material that may result in flow blockage usingthe methodology described in NFPA-25 Section 14.2.1.The acceptance criteria shall be "no debris" (i.e., no corrosion products that could impede flow or cause downstream components tobecome clogged).

Any signs of abnormal corrosion or blockage willbe removed, its source determined and corrected, and entered intothe CAP. Due dates:SQN 1: within five years prior to 03/17/20, and every five yearsduring the PEOSQN2: within five years prior to 03/15/21, and every five yearsduring the PEO [ML14113A208 pg E-1-6 due dates][3.0.3-1, Req 4a.d, i to vi, ML13357A722, E-1 -11], [ML14057A808, 3.0.3-1.4b, E-1 p25]H. Revise FWSP procedures to perform an obstruction evaluation in3QN1: Prior to 03/17/203QN2: Prior to 03/15/21B.1.13E 8of30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE IAUDITITEM(9) accordance with NFPA-25 (2011 Edition),

Section 14.3.1.I. Revise FWSP procedures to conduct follow-up volumetric examinations if internal visual inspections detect surface irregularities that 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 examinations to 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 accordance with 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 procedures direct performance of an examination to determine wall and bottomthickness.

L. [Blank]M. Revise FWSP procedures to perform an annual spray headdischarge pattern tests from all open spray nozzles to ensure thatpatterns are not impeded by plugged nozzles, to ensure that nozzlesare correctly positioned, and to ensure that obstructions do notprevent discharge patterns from wetting surfaces to be protected.

Where the nature of the protected critical equipment or property issuch that water cannot be discharged, the nozzles shall be inspected for proper orientation and the system tested with air, smoke or someother medium to ensure that the nozzles are not obstructed.

Ensure that the dry piping is unobstructed downstream of delugevalves protecting indoor areas containing critical equipment by flowtesting with air, smoke or other medium from deluge valve throughthe sprinkler heads.Based on the trip testing of the deluge valves without flow through thedownstream piping and sprinkler heads, additional testing in the RCAor areas containing critical equipment is not warranted due to theaddition of risk-significant activities and the production of additional radwaste.

[3.0.3-1.4a, ML13357A722, E-1 -14 of 43, 12/16/13]

N. Revise FWSP procedures to perform an internal inspection of theE-4 -9 of 30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE

/AUDITITEM(9) accessible piping associated with the strainer inspections forcorrosion and foreign material that may cause blockage.

Documentany abnormal corrosion or foreign material in the CAP. [3.0.3-1, Request 4a, ML13357A722, E-1 -15 of 43, 12/16/13]

0. Revise FWSP procedures to perform 25 main drain tests every18-months with at least one main drain test performed in each of thefollowing buildings:

(1) control building, (2) auxiliary

building, (3)turbine building, (4) diesel generator building and (5) ERCW building.

The results of the main drain tests from the three 18-month inspection intervals will be evaluated to determine if the NFPA 25 (2014 Edition)main drain test guidance can be applied to the number of main draintests performed

(.i.e., Section 13.2.5, "A main drain test shall beconducted annually for each water supply lead-in to a building water-based fire protection system to determine whether there has been achange in the condition of the water supply" and Section 13.2.5.1'Where the lead-in to a building supplies a header or manifold servingmultiple

systems, a single main drain test shall be performed.")

Any flow blockage or abnormal discharge identified during flowtesting or any change in delta pressure during the main drain testinggreater than 10% at a specific location is entered into the CAP.Flow or main drain testing increases risk due to the potential for watercontacting critical equipment in the area, and main drain testing in theRCAs increases the amount of liquid radwaste.

Therefore, SQN willnot perform main drain tests on every standpipe with an automatic water supply or on every system riser. [3.0.3-1, Request 4a,ML13357A722, E-1 -15 of 43, 12/16/13]

P. Revise FWSP procedures to perform One of the following inspection methods for those sections of dry piping described in NRCInformation Notice (IN) 2013-06, where drainage is not occurring, toensure there is no flow blockage in each five-year interval beginning with the five-year period before the PEO:(a) Perform a flow test or flush sufficient to detect potential flowblockage.

(b) Remove sprinkler heads or couplings in the areas that do notdrain and perform a 100% visual internal inspection to verifythere are no signs of abnormal corrosion (wall thickness loss)or blockage.

If option (a) is chosen, controls will be established to ensurepotential blockage is not moved to another part of the systemwhere it may be undetected.

In each five-year interval during the PEO, 20% of the length ofpiping segments that cannot be drained or piping segments thatallow water to collect will be subjected to UT wall thickness examination.

The piping examined during each inspection interval will be piping that was not previously examined.

[9.P isE 10 of 30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE IAUDITITEM(9) added ML14057A808, E-1 p23, 3.0.3-1.4b]

[9.P(c) is deletedin ML14197A267 pg E-1 -5]If the results of a 1 Q0% internal visual inspection are acceptable, and the segment is not subsequently wetted, no furtheraugmented tests or inspections will be performed.

(3.0.3-1-3 Request 4c, ML14197A267 pg E-1 -5)10 A. Revise Flow Accelerated Corrosion (FAC) Program procedures SQN1: Prior to 03/17/20 B.1.14to implement NSAC-202L guidance for examination of components SQN2: Prior to 03/15/21upstream of piping surfaces where significant wear is detected.

B. Revise FAC Program procedures to implement the guidance inLR-ISG-2012-01, which will include a susceptibility review based oninternal operating experience, external operating experience, EPRITR-101 1231, Recommendations for Controlling Cavitation,

Flashing, Liquid Droplet Impingement, and Solid Particle Erosion in NuclearPower Plant Piping, and NUREG/CR-6031, Cavitation Guide forControl Valves. [B.1.14-1 and B.1.38-1]

11 Revise Flux Thimble Tube Inspection Program procedures to SQN1: Prior to 03/17/20 B.1.15include a requirement to address if the predictive trending projects SQN2: Prior to 03/15/21that a tube will exceed 80% wall wear prior to the next plannedinspection, then initiate a Service Request (SR) to define actions (i.e.,plugging, repositioning, replacement, evaluations, etc.) required toensure that the projected wall wear does not exceed 80%. If anytube is found to be >80% through wall wear, then initiate a ServiceRequest (SR) to evaluate the predictive methodology used andmodify as required to define corrective actions (i.e., plugging, repositioning, replacement, etc).12 A. Revise Inservice Inspection-IWF Program procedures to clarify SQN1: Prior to 03/17/20 B.1.17that detection of aging effects will include monitoring anchor bolts for SQN2: Prior to 03/15/21loss of material, loose or missing nuts, and cracking of concretearound the anchor bolts.B. Revise ISI -IWF Program procedures to include the following corrective action guidance.

When an indication is identified on a component support exceeding the acceptance criteria of IWF-3400, but an evaluation concludes the support is acceptable for service, the program shall requireexamination of additional similar/adjacent supports per IWF-2430unless the evaluation of the identified condition againstsimilar/adjacent supports concludes that it would not adversely affect the design function of similar adjacent supports.

Thisevaluation will be performed regardless of whether the programowner chooses to perform corrective measures to restore thecomponent to its original design condition, per IWF-3112.3(b) orIWF-3122.3(b).

[ML13190A276.

El-37of79, 7/1/13]E 11of30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE IAUDITITEM13 Inspection of Overhead Heavy Load and Light Load (Related to SQN1: Prior to 03/17/201 B.1.18Refueling)

Handling Systems:

SQN2: Prior to 03/15/21A. Revise program procedures to specify the inspection scope willinclude monitoring of rails in the rail system for wear; monitoring structural components of the bridge, trolley and hoists for the agingeffect of deformation,

cracking, and loss of material due to corrosion; and monitoring structural connections/bolting for loose or missingbolts, nuts, pins or rivets and any other conditions indicative of loss ofbolting integrity.

B. Revise program procedures to include the inspection andinspection frequency requirements of ASME B30.2.C. Revise program procedures to clarify that the acceptance criteriawill include requirements for evaluation in accordance with ASMEB30.2 of significant loss of material for structural components andstructural bolts and significant wear of rail in the rail system.D. Revise program procedures to clarify that the acceptance criteriaand maintenance and repair activities use the guidance provided inASME B30.214 A. Implement the Internal Surfaces in Miscellaneous Piping and SQN1: Prior to 03/17/20 B.1.19Ducting Components Program as described in LRA Section B.1.19. SQN2: Prior to 03/15/21B. Specific, measurable, actionable/attainable and relevantacceptance criteria are established in the maintenance andsurveillance procedures or are established during engineering evaluation of the degraded condition.

[ML1 3357A722, E-1 -43 of 43,12/16/13]

15 Implement the Metal Enclosed Bus Inspection Program as SQN1: Prior to 03/17/20 B.1.21described in LRA Section B.1.21. SQN2: Prior to 03/15/2116 A. Revise Neutron Absorbing Material Monitoring Program SQN1: Prior to 03/17/20 B.1.22procedures to perform blackness testing of the Boral coupons within SQN2: Prior to 03/15/21the ten years prior to the PEO and at least every ten years thereafter based 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 determine the 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 SQN1: Prior to 03/17/20 B.1.24in LRA Section B.1.24 SQN2: Prior to 03/15/21E-4 -12 of 30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE

/AUDITITEM18 Implement the Non-EQ Inaccessible Power Cable (400 V to 35 kV) SQN1: Prior to 03/17/20 B.1.25Program as described in LRA Section B.1.25 SQN2: Prior to 03/15/21A. B.1.25.1a

[ML13296A017, E-1-12of25, 10/21/13]

8.A.1 & A.2 are1. [Blank] completed.

See Cn1-14-105, Enc 1, p14 of 16.2. [Blank]3. Prior to the PEO, the license renewal commitment for the Non-EQ 8.A3:rInaccessible Power Cables (400 V to 35 kV) Program will QN2: Prior to 03/15/21establish 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 the 18.A4: 09/30/14maximum allowable water level to preclude cable submergence inthe manhole.

If the inspection identifies submergence ofinaccessible power cable for more than a few days, the condition will be documented and evaluated in the SQN CAP. Theevaluation will consider results of the most recent diagnostic

testing, insulation type, submergence level, voltage level,energization cycle (usage),

and various other inputs to determine whether the cables remain capable of performing their intendedcurrent licensing basis function.

5. Once 18.A.1, 2, and 4 are fully completed, these commitments can be deleted from this list or the UFSAR.19 Implement the Non-EQ Instrumentation Circuits Test Review SQN1: Prior to 03/17/20 B.1.26Program as described in LRA Section B.1.26. SQN2: Prior to 03/15/2120 Implement the Non-EQ Insulated Cables and Connections SQN1: Prior to 03/17/20 B.1.27Program as described in LRA Section B.1.27 SQN2: Prior to 03/15/2121 A. Revise Oil Analysis Program procedures to monitor and SQN1: Prior to 03/17/20 B.1.28maintain contaminants in the 161-kV oil filled cable system within SQN2: Prior to 03/15/21acceptable limits through periodic sampling in accordance withindustry standards, manufacturer's recommendations and plant-specific operating experience.

B. Revise Oil Analysis Program procedures to trend oil contaminant levels 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 03/17/20 B.1.29Section B.1.29. QN2: Prior to 03/15/2123 Implement the One-Time Inspection

-Small Bore Piping Program QN1: Prior to 03/17/20 B.1.30as described in LRA Section B.1.30 SQN2: Prior to 03/15/21E 13of30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE

/AUDITITEM24 A. Revise Periodic Surveillance and Preventive Maintenance 24.A&C B.1.31Program procedures as necessary to include all activities described QN 1: Prior to 03/17/20in the table provided in the LRA Section B.1.31 program description.

QN2: Prior to 03/15/21B. For in-scope components that have internal Service Level III or 24.BOther coatings, initial inspections will begin no later than the last QN1: RFO Prior toscheduled refueling outage prior to the PEO. Subsequent inspections 9/17/20will be performed based on the initial inspection results.

[3.0.3-1, Request 3, ML13312A005, pages E 2,5,7 of 51] SQN2: RFO Prior to09/15/21C. Revise Periodic Surveillance and Preventive Maintenance Program procedures to perform a minimum of five MIC degradation inspections per year until the rate of MIC occurrences no longermeets the criteria for recurring internal corrosion.

[cnl-14-105, Elp11]If more than one MIC-caused leak or a wall thickness less than Tm n isidentified in the yearly inspection period, an additional five MICinspections over the following 12 month period will be performed foreach MIC leak or finding of wall thickness less than Tmin. The totalnumber of inspections need not exceed a total of 25 MIC inspections per year. [ML14057A808, E-1 p8, 3.0.3-1-3a]

Prior to the period of extended operation, select a method (ormethods) from available technologies for inspecting internal surfacesof buried piping (System 26/HPFP Firewater and 67/ERCW) thatprovides suitable indication of piping wall thickness for arepresentative set of buried piping locations to supplement the set ofselected inspection locations

[3.0.3-1, Req la, ML13357A722, E-1 -4 of 43, 12/16/13]

[3.0.3-1 Req 1, ML13294A462, E 6 of 13, 10/17/13]

[Moved 9.F to24.C in ML14057A808, E-1 p13,29]D.1. Prior to the PEO, perform a visual inspection of a 50%sample of the coated piping in each of the following coatedpiping systems or an area equivalent to the entire insidesurface of 73 1-foot piping segments for each combination oftype of coating, substrate

material, and environment.

Inspection location selection will be based on an evaluation ofthe effect of a coating failure on component intended functions, potential problems identified during prior inspections, andservice life history.

Visually inspect the surface condition of thecoated components to manage loss of coating integrity due tocracking, debonding, delamination,

peeling, flaking, andblistering.

In addition, if coatings are credited for corrosion prevention, the base material (in the vicinity of delamination,

peeling, or blisters where base metal has been exposed) will beinspected to determine if corrosion has occurred.

Piping:i. High pressure fire protection (cement-lined piping)ii. Essential raw cooling water (where Belzona applied)E-4 -14 of 30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE

/AUDITITEM(24) 2. With the exception of the EDG 7-day fuel oil tanks, performsubsequent inspections of coatings based on the following.

i. If no flaking, debonding,

peeling, delamination,

blisters, orrusting are observed, and any cracking and flaking hasbeen found acceptable, subsequent inspections will beperformed at least once every six years. If the coating isinspected on one train and no indications are found, thesame coating on the redundant train would not beinspected during that inspection interval.

ii. If the inspection results do not meet (i), yet a coatingspecialist has determined that no remediation is required, then subsequent inspections will be conducted every otherrefueling outage.iii. If coating degradation is observed that requires newlyinstalled

coatings, subsequent inspections will occurduring each of the next two refueling outage intervals toestablish a performance trend on the coating.EDG 7-day fuel oil tanks coating inspection:

Subsequent coating inspections for the EDG 7-day fuel oil tankswill be at the same 10 year interval as TS Surveillance Requirement 4.8.1.1.2.f.

If any applied Belzona coating on theinterior of the fuel oil tanks is peeling, delaminating, or blistering, then the condition will be repaired and entered into the CAP.Given the favorable SQN experience with the current Belzonarepairs, it is justifiable to repair the existing coating applied tolocalized pits with Belzona and not inspect the coating for another10 years, provided a detached Belzona engineering transportability evaluation has determined that the amount ofBelzona applied will not migrate from the EDG 7-day tank to theday-tank.

The evaluation will consider Belzona's 2.5 to 3 timeshigher specific gravity than diesel fuel, potential size of loosenedBelzona particles, surface area and depth of the applied Belzona,diesel fuel fluid velocity in the immediate area of the appliedBelzona, proximity of the repaired area to the suction line, andother factors.The application of Belzona to repair additional localized pitting inthe 7-day EDG fuel oil tanks in the future will be installed pervendor specifications.

An engineering evaluation will beperformed to ensure that that additional Belzona cannot betransferable out of the tank during the interval between tankinspections and to determine if the interval of inspections shouldmeet the more frequent inspection guidelines of LR-ISG-2013-01, or the NRC approved TS Surveillance Requirement of 10 years.The engineering transportability evaluation will consider factorssuch as specific

gravity, size, depth, surface area, and fluidvelocity in the evaluation.

[ML14057A808, E-1 p7]E. Prior to the PEO, perform a visual inspection of thefollowing coated tanks and heat exchangers.

Visually inspect thesurface condition of the coated components to manage loss ofcoatina intearitv due to cracking.

debondina.

delamination.

Deelina.E 15of30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE

/AUDITITEM(24)flaking, and blistering.

Tanksi. Cask decontamination collector (where 2 coats Red Lead in oil,Fed SPEC TTP-85 Type II applied)ii. Safety injection lube oil reservoir (where 0.006 inch plasticcoating applied)iii. Pressurizer relief (where Ambercoat 55 applied)iv. EDG 7-day fuel oil (where Belzona applied)v. Condensate storage tankHeat Exchangers

i. Electric board room chiller package (where Belzona applied)ii. Incore instrument room water chiller package B (where Belzonaapplied)

[ML14057A808, E-1 p6]F. Any indication or relevant condition of degradation detected isevaluated.

Include the following acceptance criteria for loss of coatingsintegrity:

For any indication or relevant condition of coatingdegradation, the indication or relevant condition is evaluated forloss of coatings integrity.

[ ML14063A542, E-1 p2](1) Peeling and delamination are not permitted, (2) Cracking is not permitted if accompanied by delamination orloss of adhesion, and(3) Blisters are limited to intact blisters that are completely surrounded by sound coating bonded to the surface.Corrective Action: If delamination,

peeling, or blisters aredetected, follow-up physical testing will be performed wherephysically possible (i.e., sufficient room to conduct testing) on atleast three locations.

The testing will consist of destructive ornondestructive adhesion testing using ASTM International standards endorsed in Regulatory Guide 1.54. [ML14057A808, E-1 p6]G.1. Coating inspections are performed by individuals certified toANSI N45.2.6, "Qualifications of Inspection, Examination, andTesting Personnel for Nuclear Power Plants,"

and thatsubsequent evaluation of inspection findings is conducted by anuclear coatings subject matter expert qualified in accordance with ASTM D 7108-05, "Standard Guide for Establishing Qualifications for a Nuclear Coatings Specialist."

2. An individual knowledgeable and experienced in nuclearcoatings work will prepare a coating report that includes a list oflocations identified with coating deterioration including, wherepossible, photographs indexed to inspection

location, and aprioritization of the repair areas into areas that must be repairedbefore returning the system to service and areas where coatingrepair can be postponed to the next inspection.

[ML14057A808, E-1 p6]E 16 of 30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE

/AUDITITEM25 A. Revise Protective Coating Program procedures to clarify that SQN1: Prior to 03/17/20 B.1.32detection of aging effects will include inspection of coatings near SQN2: Prior to 03/15/21sumps or screens associated with the emergency core coolingsystem.B. Revise Protective Coating Program procedures to clarify thatinstruments and equipment needed for inspection may include, butnot be limited to, flashlights, spotlights, marker pen, mirror, measuring tape, magnifier, binoculars, camera with or without wide-angle lens,and self-sealing polyethylene sample bags.C. Revise Protective Coating Program procedures to clarify that thelast two performance monitoring reports pertaining to the coatingsystems will be reviewed prior to the inspection or monitoring process.26 A. Revise Reactor Head Closure Studs Program procedures to SQN1: Prior to 03/17/20 B.1.33ensure that replacement studs are fabricated from bolting material SQN2: Prior to 03/15/21with actual measured yield strength less than 150 ksi.B. Revise Reactor Head Closure Studs Program procedures toexclude the use of molybdenum disulfide (MoS2) on the reactorvessel closure studs and to refer to Reg. Guide 1.65, Rev1.27 A. Revise Reactor Vessel Internals Program procedures to 27.A & B B.1.34perform direct measurement of Unit 1 304 SS hold down spring SQN1: Within three Ulheight within three cycles of the beginning of the period of extended refuel cycles of the dateoperation.

If the first set of measurements is not sufficient to 39/17/20determine life, spring height measurements must be taken during thenext two outages, in order to extrapolate the expected spring height SQN2: Not Applicable to 60 years. (ML13324A982, 11/15/13, Enc 1, pages 24-25)B. Revise Reactor Vessel Internals Program procedures to includepreload acceptance criteria for the Type 304 stainless steelhold-down springs in Unit 1.C. Continued monitoring of industry operating experience in the area 27.C SQN 1 &2: Withinof RVI Clervis Bolt will be performed and the program will be three Ul refuel cycles ofmodified, if necessary.

[ML14057A808, E-1 p35, B.1.34-8]

he date 09/17/20D. [Blank] 27.D is completed.

See B. 1.34-9b in Cnl-14-105, Enc 1, pglE 17of30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE

/AUDITITEM28 A. Revise Reactor Vessel Surveillance Program procedures to SQN1: Prior to 03/17/20 B.1.35consider the area outside the beltline such as nozzles, penetrations SQN2: Prior to 03/15/21and discontinuities to determine if more restrictive pressure-temperature limits are required than would be determined by justconsidering the reactor vessel beltline materials.

B. Revise Reactor Vessel Surveillance Program procedures toincorporate an NRC-approved schedule for capsule withdrawals tomeet ASTM-E185-82 requirements, including the possibility ofoperation beyond 60 years (refer to the TVA Letter to NRC,"Sequoyah Reactor Pressure Vessel Surveillance CapsuleWithdrawal Schedule Revision Due to License RenewalAmendment,"

dated 01/10/13, ML13032A251; NRC FSER approvedon 09/27/13, ML13240A320)

C. Revise Reactor Vessel Surveillance Program procedures towithdraw and test a standby capsule to cover the peak fluenceexpected at the end of the PEO.29 Implement the Selective Leaching Program as described in LRA QN1: Prior to 03/17/20 B.1.37Section B.1.37. QN2: Prior to 03/15/2130 Revise Steam Generator Integrity Program procedures to ensure QNI: Prior to 03/17/20 B.1.39that corrosion resistant materials are used for replacement steam IQN2: Prior to 03/15/21generator tube plugs.31 A. Revise Structures Monitoring Program (SMP) procedures to SQN1: Prior to 03/17/20 B.1.40include the following in-scope structures:

SQN2: Prior to 03/15/21" Carbon dioxide building" Condensate storage tanks' (CSTs) foundations and pipe trench* East steam valve room Units 1 & 2* Essential raw cooling water (ERCW) pumping station* High pressure fire protection (HPFP) pump house and waterstorage tanks' foundations

" Radiation monitoring station (or particulate iodine and noble gasstation)

Units 1 & 2" Service building" Skimmer wall (Cell No. 12)* Transformer and switchyard support structures and foundations B. Revise SMP procedures to specify the following list of in-scopestructures are included in the RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants Program (SectionB.1.36):* Condenser cooling water (CCW) pumping station (also known asintake pumping station) and retaining walls" CCW pumping station intake channel* ERCW discharge box" ERCW protective dike* ERCW pumping station and access cellsE 18of30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE

/ AUDITITEM(31) e Skimmer wall, skimmer wall Dike A and underwater damC. Revise SMP procedures to include the following in-scopestructural components and commodities:

• Anchor bolts* Anchorage/embedments (e.g., plates, channels,

unistrut, angles,other structural shapes)* Beams, columns and base plates (steel)* Beams, columns, floor slabs and interior walls (concrete)

• Beams, columns, floor slabs and interior walls (reactor cavityand primary shield walls; pressurizer and reactor coolant pumpcompartments; refueling canal, steam generator compartments; crane wall and missile shield slabs and barriers)

• Building concrete at locations of expansion and grouted anchors;grout pads for support base plates" Cable tray" Cable tunnel* Canal gate bulkhead* Compressible joints and seals" Concrete cover for the rock walls of approach channel* Concrete shield blocks* Conduit* Control rod drive missile shield* Control room ceiling support system* Curbs" Discharge box and foundation

• Doors (including air locks and bulkhead doors)* Duct banks* Earthen embankment

• Equipment pads/foundations

• Explosion bolts (E. G. Smith aluminum bolts)* Exterior above and below grade; foundation (concrete)

• Exterior concrete slabs (missile barrier) and concrete caps* Exterior walls: above and below grade (concrete)

• Foundations:

building, electrical components, switchyard, transformers, circuit breakers, tanks, etc." Ice baskets* Ice baskets lattice support frames* Ice condenser support floor (concrete)

" Insulation (fiberglass, calcium silicate)

• Intermediate deck and top deck of ice condenser

• Kick plates and curbs (steel -inside steel containment vessel)" Lower inlet doors (inside steel containment vessel)* Lower support structure structural steel: beams, columns,plates (inside steel containment vessel)* Manholes and handholes

• Manways,

hatches, manhole covers, and hatch covers(concrete)

• Manways,

hatches, manhole covers, and hatch covers (steel)E 19 of 30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE AUDITITEM(31)

• 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 penetrating primary 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 electrical equipment and instrumentation

• Riprap* Rock embankment

• Roof or floor decking" Roof membranes

• Roof slabs* RWST rainwater diversion skirt* RWST storage basin* Seals and gaskets (doors, manways and hatches)* Seismic/expansion joint* Shield building concrete foundation, wall, tension ring beamand dome: interior, exterior above and below grade" Steel liner plate" Steel sheet piles* Structural bolting* Sumps (concrete)

• 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 support~ J. I ______________________________

.5.E 20 of 30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE

/AUDITITEM(31) framing* Trenches (concrete)

• Tube track* Turning vanes* Vibration isolators D. Revise SMP procedures to include periodic sampling andchemical analysis of ground water chemistry for pH, chlorides, andsulfates on a frequency of at least every five years.E. Revise Masonry Wall Program procedures to specify masonrywalls located in the following in-scope structures are in the scope ofthe Masonry Wall Program:* Auxiliary building* Reactor building Units 1 & 2" Control bay* ERCW pumping station" HPFP pump house* Turbine buildingF. Revise SMP procedures to include the following parameters to bemonitored or inspected:

• Requirements for concrete structures based on ACI 349-3Rand ASCE 11 and include monitoring the surface condition forloss of material, loss of bond, increase in porosity andpermeability, loss of strength, and reduction in concrete anchorcapacity due to local concrete degradation.

• Loose or missing nuts for structural bolting.* Monitoring gaps between the structural steel supports andmasonry walls that could potentially affect wall qualification.

• Monitor the surface condition of insulation (fiberglass, calciumsilicate) to identify exposure to moisture that can cause loss ofinsulation effectiveness.

G. Revise SMP procedures to include the following components tobe monitored for the associated parameters:

• Anchors/fasteners (nuts and bolts) will be monitored for looseor missing nuts and/or bolts, and cracking of concrete aroundthe anchor bolts.* Elastomeric vibration isolators and structural sealants will bemonitored for cracking, loss of material, loss of sealing, andchange in material properties (e.g., hardening).

• [moved to the last bullet on '31.F']H. Revise SMP procedures to include the following for detection ofaging effects:* Inspection of structural bolting for loose or missing nuts.* Inspection of anchor bolts for loose or missing nuts and/orbolts, and cracking of concrete around the anchor bolts.* Inspection of elastomeric material for cracking, loss of material, E 21 of 30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE I AUDITITEM(31) 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 elastomeric material is suspect.

Include instructions to augment the visualexamination of elastomeric material with physical manipulation of 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 significant degradation is occurring.

• Inspection of submerged structures at least once every fiveyears.Inspections of water control structures should be conducted under 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 structures immediately (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 insulation effectiveness.

• Revise SMP procedures to clarify that detection of agingeffects will include the following.

Qualifications of personnel conducting the inspections ortesting and evaluation of structures and structural components meet the guidance in Chapter 7 of ACl 349.3R.I. Revise SMP procedures to prescribe quantitativeacceptance criteria based on the quantitative acceptance criteria of ACI 349.3Rand information provided in industry codes, standards, and guidelines including ACI 318, ANSI/ASCE 11 and relevant AISC specifications.

Industry and plant-specific operating experience will also beconsidered in the development of the acceptance criteria.

J. [Blank]K. Revise SMP procedures to include the following acceptance criteria for insulation (calcium silicate and fiberglass)

• No moisture or surface irregularities that indicate exposure tomoisture.

L. Revise SMP procedures to include the following preventive E-4 -22 of 30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE AUDITITEM(31) 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 protected storage.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 contentto assess the effect of the water inleakage on the concrete andthe reinforcing 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 subjected to petrographic examination.

4. The results of the tests and SMP inspections will be used todetermine further corrective

actions, including, but not limited to,more frequent inspections, sampling and analysis of theinleakage water for minerals and iron, and evaluation of theaffected area using evaluation criteria and acceptance criteria ofACI 349.3R. [Outcome of the Nrc 01/14/14 telecom]5. Commitment

1. 31.M will be implemented before the PEO for SQNUnits 1 and 2.. [ML13296A017, E-1-10of25, 10/21/13, for31.M.1 to 5]E 23 of 30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE

/AUDITITEM32 Implement the Thermal Aging Embrittlement of Cast Austenitic B.1.41Stainless Steel (CASS) as described in LRA Section B.1.41A. B.1.41-4a:

For those CASS components with delta ferrite content 32.A> 25%, additional analysis will be performed using plant-specific SQN1: Prior to 03/17/20materials data and best available fracture toughness curves. SQN2: Prior to 03/15/21(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-specific flaw 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)

[ML13357A722, E-1 -1 of 43, 12/16/13]

33 A. Revise Water Chemistry Control -Closed Treated Water SQN1: Prior to 03/17/20 B.1.42Systems Program procedures to provide a corrosion inhibitor for the SQN2: Prior to 03/15/21following chilled water subsystems in accordance with industryguidelines and vendor recommendations:

0 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 personnel qualification procedures that are capable of detecting corrosion orcracking.

0. Revise Water Chemistry Control -Closed Treated WaterSystems Program procedures to perform sampling and analysis ofthe glycol cooling system per industry standards and in no casegreater than quarterly unless justified with an additional analysis.

E-4 -24 of 30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE IAUDITITEM(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 system* Glycol cooling loop system" High pressure fire protection diesel jacket water system* Chilled water portion of miscellaneous HVAC systems (i.e.,auxiliary

building, Incore Chiller 1A, 1B, 2A, & 2B, and 6.9 kVShutdown Board Room A & B)F. Components inspected will be those with the highest likelihood of 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 03/17/20 B.1.7venting the SCV bottom liner plate weld leak test channels to the SQN2: Prior to 03/15/21containment atmosphere prior to the CILRT and resealing the ventpath after the CILRT to prevent moisture intrusion during plantoperation.

35 A. From RAI B.1.6-1 Response:

Modify the configuration of the SQN 35.A: B.1.6Unit 1 test connection access boxes to prevent moisture intrusion to SQN 1: Prior to 03/17/20the leak test channels.

Prior to installing this modification, TVA will SQN2: Not Applicable perform remote visual examinations inside the leak test channels byinserting a borescope video probe through the test connection tubing.B. From B.1.6-1b Response:

To monitor the condition of the access 35. B & C:boxes and associated materials, develop and implement an SQN1: Prior to 03/17/20instruction/procedure to perform visual examinations of all accessible SQN2: Prior to 03/15/21surfaces, including the access box surfaces, cover plate, welds, andgasket sealing surfaces of the access boxes on each unit every otherrefueling outage with the gasketed access box lid removed.C. From B.1.6-2b Response:

develop and implement aninstruction/procedure to continue volumetric examinations where theSCV domes were cut at the frequency of once every five years untilthe coatings are reinstalled at these locations.

E-4 -25 of 30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE I 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 inspection techniques 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 sufficient wall 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 successful demonstration of a wear depth measurement

process, SQN willrevise Inservice Inspection Program procedures to use thedemonstrated process at accessible locations to measure depth ofwear on the CRDM housing penetration wall associated with contactwith the CRDM thermal sleeve centering pads. (RAI B.1.23-2c; Cnl-14-105, Enc 1, A & B.1.16, Inservice Inspection

Program, rev 17)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 thewall thickness of the accessible CRDM housing penetration wear inthe area of the thermal sleeve centering tabs at the end of the nextRVH inspection interval and compare the projected wall thickness tothe thickness used in Sequoyah design basis analyses todemonstrate validity of the analyses.

(RAI B.1.23-2c; Cn1-14-105, Enc 1, A & B.1.16, Inservice Inspection

Program, rev 17)F. Revise Inservice Inspection Program procedure to monitor thewear of the accessible CRDM housing penetrations in weldexamination volume. (RAI B.1.23-2c)

SQN 1: Prior to 03/17/20SQN2: Prior to 03/15/21B.1.16E-4 -26 of 30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE

/AUDITITEM(36) G. TVA ASME Section Xl Program procedure which defines theClass 1 components subject to examination will be revised tospecifically require a visual examination method VT-3 of the clevisbolts, dowel pins and tack welds as well as the six core support pads.[ML14063A542, E-1 p4, B.1.34-8a]

H. Revise SQN's Category B-N-3 inspection procedure to reference the September

22. 2014, NRC RAI B.1.34-9c and the SQN'sresponse (ML14254A204 and CNL-14-181) to identify that theinspection of the accessible regions the upper core Plate lowersurface (core support structure components, VT-3 inspection belowthe upper core plate to determine the general mechanical andstructural condition of components) as a required License RenewalInspection during the PEO. (CNL-14-181)

E 27 of 30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE I AUDITITEM37TVA will implement the Operating Experience for the AMPs inaccordance with the TVA response to the RAI B.0.4-1 on07/29/13, ML13213A027; and 10/17/13 letter, RAls B.0.4-1a andA.1-la.A. Revise OE Program Procedure to include current and futurerevisions to NUREG-1801, "Generic Aging Lessons Learned(GALL) Report,"

as a source of industry OE, and unanticipated age-related degradation or impacts to aging management activities as a screening attribute.

B. Revise the Corrective Action Procedure (CAP) Procedure toprovide a screening process of corrective action documents foraging management items, the assignment of aging corrective actions to appropriate AMP owners, and consideration of theaging management trend code.C. Revise AMP procedures as needed to provide for review andevaluation by AMP owners of data from inspections, tests,analyses or AMP OEs. [ML14063A542, E-1 p3]D. Revise the OE Program Procedure to provide guidance forreporting plant-specific OE on unanticipated age-related degradation or impact to aging management activities to the TVAfleet and/or INPO.E. Revise the OE, CAP, Initial and Continuing Engineering SupportPersonnel Training to address age-related topics, theunanticipated degradation or impacts to the aging management activities; 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."

F. A comprehensive and holistic AMP training topic list will bedeveloped before the date the SQN renewed operating license isscheduled to be issued.G. TVA AMP OE Process, AMP adverse trending

& evaluation inCAP, AMP Initial and Refresher Training will be fully implemented by the date the SQN renewed operating license is scheduled tobe issued.Once Commitment 37 is fully completed, Commitment 37 can bedeleted from this list or the UFSAR.17.A, B, D-G: No laterhan the scheduled issueJate of the renewed)perating licenses for3QN Units 1 & 2.Currently February2015)37.C:3QN1: Prior to 03/17/203QN2: Prior to 03/15/21B.0.4E-4 -28 of 30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE AUDITITEM38 A. Implement the Service Water Integrity Program (SWIP) as SQN1: Prior to 03/17/20 B.1.38described in LRA Section B.1.38. [3.0.3-1, Requests 3, SQN2: Prior to 03/15/21ML13312A005.E-1

-11 of 51, 11/4/13, for 38.A to F]B. Parameters Monitored/Inspected:

Revise SWIP procedures tomonitor the condition of coated surfaces in the heat exchangers credited in the response to NRC Generic Letter (GL) 89-13 response.

C. Detection of aging Effect: Revise the SWIP procedures toperform periodic visual inspections to manage loss of coating integrity due to cracking, debonding, delamination,

peeling, flaking, andblistering in heat exchangers credited in the NRC Generic Letter (GL)89-13 response.

D. Acceptance Criteria:

Revise the SWIP procedures to include thefollowing coating integrity acceptance criteria:

(1) peeling and delamination are not permitted, (2) cracking is not permitted if accompanied by delamination or lossof adhesion, and(3) blisters are limited to intact blisters that are completely surrounded by sound coating bonded to the surface.E. Monitoring and Trending:

Revise SWIP procedures to ensure anindividual knowledgeable and experienced in nuclear coatings workwill prepare a coating report that includes a list of locations identified with coating deterioration including, where possible, photographs indexed to inspection

location, and a prioritization of the repair areasinto areas that must be repaired before returning the system toservice and areas where coating repair can be postponed to the nextinspection.

F. Qualification:

Revise SWIP procedures to ensure coatinginspections are performed by individuals certified to ANSI N45.2.6,"Qualifications of Inspection, Examination, and Testing Personnel forNuclear Power Plants,"

and that subsequent evaluation of inspection findings is conducted by a nuclear coatings subject matter expertqualified in accordance with ASTM D 7108-05, "Standard Guide forEstablishing Qualifications for a Nuclear Coatings Specialist."

~1. I I.E 29 of 30 LRANo. COMMITMENT IMPLEMENTATION SECTIONSCHEDULE

/AUDITITEM(38) G. Before the PEO, revise Service Water Integrity Programprocedures to(1) Monitor the existence of fouling or clogging in ERCWstagnant/dead leg piping.This enhancement is applicable to ERCW flow-paths that fulfill asafety-related function.

(2) Periodically place normally ERCW stagnant/dead legs in servicefor the purpose of flushing.

Alternatively, periodically flush thenormally stagnant/dead leg by temporarily/permanently installing a flushing valve (without placing the line in service).

(3) In lieu of flushing, perform periodic radiograph, demonstrated ultrasonic or visual inspections of ERCW stagnant

/dead legpiping are acceptable to confirm the absence of fouling/clogging, and(4) When ERCW clogging/fouling of stagnant/dead leg piping isidentified, enter findings into the corrective action program andperform an evaluation of the impact of ERCW design functions.

(Cn1-14-105, Enc 1, A&B.1.38 Service Water Integrity, rev 17)39 Implement the Boric Acid Corrosion Program as described in LRA SQN1: Prior to 03/17/20 B.1.3Section B.1.3. SQN2: Prior to 03/15/2140 Implement the Environmental Qualification (EQ) Of Electric QNI: Prior to 03/17/20 B.1.9Components Program as described in LRA Section B.1.9. QN2: Prior to 03/15/2141 Implement the Masonry Wall Program as described in LRA Section QN1: Prior to 03/17/20 B.1.20B.1.20. IQN2: Prior to 03/15/2142 Implement the Nickel Alloy Inspection Program as described in SQN1: Prior to 03/17/20 B.1.23LRA Section B.1.23. SQN2: Prior to 03/15/2143 Implement the Water Chemistry Control -Primary And Secondary SQN1: Prior to 03/17/20 B.1.43Program as described in LRA Section B.1.43. SQN2: Prior to 03/15/2144 Implement the RG 1.127, Inspection Of Water-Control Structures SQN1: Prior to 03/17/20 B.1.36Associated With Nuclear Power Plants Program as described in SQN2: Prior to 03/15/21LRA Section B.1.36.The above table identifies the 44 SQN NRC LR commitments.

Any other statements in this letterare provided for information purposes and are not considered to be regulatory commitments.

This commitment list revision supersedes all previous versions.

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