NL-17-060, Reply to Requests for Additional Information for the Review of the Indian Point License Renewal Application RAI Set 2017-02

Reply to Requests for Additional Information for the Review of the Indian Point License Renewal Application RAI Set 2017-02

ML17145A288
Person / Time
Site:	Indian Point
Issue date:	05/19/2017
From:	Vitale A Entergy Nuclear Northeast, Entergy Nuclear Operations
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
CAC MD5407, CAC MD5408, NL-17-060
Download: ML17145A288 (36)

Text

• =w~* Entergx Entergy Nuclear Northeast Indian Point Energy Center 450 Broadway, GSB P.O. Box249 Buchanan, NY 10511-0249 Tel (914) 254 6700 NL-17-060 May 19, 2017 Anthony J Vitale Site Vice President c*

U.S. Nuclear Regulatory Commission Document Control Desk 11545 Rockville Pike, TWFN-2 F1 Rockville, MD 20852-2738

Dear Sir or Madam:

Reply to Requests for Additional Information for the Review of the Indian Point License Renewal Application RAI SET 2017-02 (CAC Nos. MD5407 and MD5408)

Docket Nos. 50-247 and 50-286 License Nos. DPR-26 and DPR-64

1) USN RC letter, "Requests for Additional Information for the Review of the Indian Point License Renewal Application RAI SET 2017-02 (CAC Nos. MD5407 and MD5408)," dated April 19, 2017(ML170~8A327)

• Entergy Nuclear Operations, Inc. (Entergy) is providing in Attachment 1 the additional information requested by the U.S. Nuclear Regulatory Commission (NRC) pertaining to the review of the License Renewal Application (LRA) for Indian Point Energy Center (IPEC) Unit Nos. 2 and 3 (Reference 1 ).

Changes to the LRA sections resulting from the responses in Attachment 1 are provided in. Changes to the List of Regulatory Commitments are provided in Attachment 3.

If you have any questions, or require additional information, please contact Mr. Robert Walpole at 914-254-6710.

I declc;lre under penalty of perjury that the foregoing is true and correct. Executed on

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Attachments:

NL-17-060 Docket Nos. 50-24 7 and 50-286 Page 2 of 2

1.

Reply to NRC Request for Additional Information Regarding the License Renewal Application

2.

License Renewal Application Changes Due To Responses To Requests For Information

3.

License Renewal Application IPEC List of Regulatory Commitments Revi~ion 33 cc:

Mr. Daniel H. Dorman, Regional Administrator, NRC Region I Mr. Sherwin E. Turk, NRC Office of General Counsel, Special Counsel Mr. William Burton, NRC Senior Project Manager, Division of License Renewal Mr. Richard V. Guzman, NRR Senior Project Manager Ms. Bridget Frymire, New York State Department of Public Service Mr. John B. Rhodes, President and CEO NYSERDA NRC Resident Inspector's Office

ATTACHMENT 1 to NL-17-060

. REPLY TO NRC REQUEST FOR ADDITIONAL INFORMATION REGARDING THE LICENSE RENEWAL APPLICATION ENTERGY NUCLEAR OPERATIONS, INC.

INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 & 3 DOCKET NOS. 50-247 AND 50-286

RAI B.1.35-1

Background

NL-17-060 Page 1 of 5 By letter dated January 17, 2017, the applicant submitted the changed status of Commitments 41 and 42 for Indian Point Unit 2 and Unit 3 (IP2 and IP3 respectively). Previously, the applicant identified these license renewal commitments to manage cracking due to primary water stress corrosion cracking (PWSCC) for steam generator divider plates and tube-to-tubesheet welds. The January 17, 2017, letter indicates that the applicant eliminated Commitment 41 (regarding divider plates) and closed Commitment 42 (regarding tube-to-tubesheet welds) based on License Renewal Interim Staff Guidance (LR-ISG) 2016-01, "Changes to Aging Management Guidance for Various Steam Generator Components."

In the letter, the applicant also provided proprietary information to demonstrate that the industry analyses in EPRI Report 3002002850 are applicable and bounding for the applicant's units (as discussed in LR-ISG-2016-01). EPRI Report 3002002850 describes industry analyses of potential crack initiation and propagation in steam generator head components (e.g., divider plate cracking into the steam generator head). The EPRI report also addresses the implication of the potential cracking for the integrity of reactor coolant pressure boundary, taking into account material's resistance to PWSCC (e.g., resistance of Alloy 690) and steam generator loading conditions.

In addition, Tables 4-2 and 4-3 of EPRI Report 3002002850 identify the turbine roll test as one of the bounding thermal transients for the industry analyses. LRA Tables 4.3-1 and 4.3-2 describe design transients for ASME Class 1 fatigue analysis for IP2 and IP3, respectively.

LRA Table 4.3-1 indicates that the number of turbine-roll-test cycles analyzed for IP2 is 20 cycles. LRA Table 4.3-2 indicates that the turbine-roll-test transient is not a design transient for IP3.

In its review of the applicant's information, the staff noted the following concerns:

The number of turbine-roll-test cycles analyzed in EPRI Report 3002002850 is less than that analyzed for IP2 in LRA Table 4.3-1 (i.e., 20 cycles). This indicates that the loading conditions analyzed in the EPRI report for this transient may not bound the IP2 loading conditions.

Given that the LRA Table 4.3-2 does not identify the turbine roll test as an IP3 design transient for ASME Class 1 fatigue analysis, it is not clear how the applicant ensures the loading conditions at IP3 are bounded by those analyzed in EPRI Report 3002002850 in terms of the turbine-roll-test transient.

RAI B.1.35-1. Request 1 NL~17-060 Page 2 of 5 Explain why the IP2 steam generator loading conditions are bounded by those analyzed in EPRI Report 3002002850 even though the number of turbine-roll-test cycles analyzed in the EPRI report is less than that analyzed for IP2 in LRA Table 4.3-1.

Response

A turbine roll test is a test performed during initial hot functional testing prior to commercial plant operation. The IP2 cycle counting program conservatively assumes that one turbine roll test was performed at IP2. IP2 has no plans to perform any additional turbine roll tests during its remaining operating life. IP2 has revised the cycle counting program to reduce the number of allowable turbine roll tests from 20 to 10 to be consistent with the EPRI analysis.

The steam generators at IP2 were replaced in 2000. The turbine roll test transient only occurs during plant hot functional testing; therefore, the IP2 replacement steam generators have not experienced and will not experience a turbine roll test transient. Because the IP2 replacement steam generators were installed after any turbine roll tests would have been performed, the loading conditions at IP2 are bounded by the loading conditions analyzed in EPRI Report 3002002850.

RAI B.1.35-1. Request 2 Discuss how the applicant ensures that the loading conditions at IP3 are bounded by those analyzed in EPRI Report 3002002850 in terms of the turbine-roll-test transient.

Response

A turbine roll test is a test performed during initial hot functional testing prior to commercial plant operation. The turbine roll test transient was not tracked prior to submittal of the license renewal application and therefore, was not included in LRA Table 4.3-2. Turbine roll test transients have since been added to the IP3 cycle counting program.

The IP3 cycle counting program conservatively assumes that five turbine roll tests were performed at IP3. IP3 has no plans to perform any additional turbine roll tests during its remaining operating life. The IPEC cycle counting procedure has a limit of 5 turbine roll test transient cycles for IP3, so IP3 is bounded by the EPRI analysis.

The steam generators at IP3 were replaced in 1989. The turbine roll test transient only occurs during plant hot functional testing; therefore, the IP3 replacement steam generators have not experienced and will not experience a turbine roll test transient. Because the IP3 replacement steam generators were installed after any turbine roll tests would have been performed, the loading conditions at IP3 are bounded by the,loading conditions analyzed in EPRI Report 3002002850.

RAI 8.1.35-2

~

Background

NL-17-060 Page 3 of 5 By letter dated January 17, 2017, the applicant submitted information on the changed status of Commitments 41 and 42 for Indian Point Unit 2 and Unit 3. As the applicant's letter notes, the staff recently issued License Renewal Interim Staff Guidance (LR-ISG) 2016-01, "Changes to Aging Management Guidance for Various Steam Generator Components". LR-ISG-2016-01 includes the following guidance on aging management for steam generator components.

Visual inspections: steam generator head internal areas (head interior surfaces, divider plate assemblies, tubesheets (primary side) and tube-to-tubesheet welds) are inspected to identify signs of cracking or loss of material (e.g., rust stains and distortion of divider plates). GALL Report AMP Xl.M19, "Steam Generators,." which includes these visual inspections, is used to manage (a) loss of material due to boric acid corrosion for channel heads and tubesheets and (b) cracking due to primary water stress corrosion cracking (PWSCC) for divider plate assembles and tube-to-tubesheet welds.

Frequency of the visual inspections: at least every 72 effective full power months or every third refueling outage, whichever results in more frequent inspections.

Implementation of the EPRI steam generator guidelines, including: (a) EPRI Report 1022832 (primary-to-secondary leak guidelines); (b) EPRI Report 1025132 (in-situ pressure test guidelines); (c) EPRI Report 3002007571 (integrity assessment guidelines); and (d) EPRI Report 3002007572 (examination guidelines).

The staff needs to confirm whether the applicant's Steam Generator Integrity Program is consistent with the guidance in LR-ISG-2016-01.

RAI B.1.35-2. Request 1 Clarify whether the Steam Generator Integrity Program is consistent with the guidance discussed above (i.e., conduct of visual inspections to manage loss of material and cracking due to PWSCC; visual inspection frequency; and implementation of or plans for implementation of the EPRI steam generator guidelines by the industry-provided implementation dates). If the program is not consistent with the guidance, provide justification for why the applicant's program is adequate for aging management.

Response

The IPEC Steam Generator Integrity Program will be updated to require general visual inspections of the steam generator channel head. These visual inspections provide an opportunity to identify cracking if it were to grow into pressure boundary components

I' L

NL-17-060 Page 4 of 5 through identification of rust stains and gross cracking or distortion of the divider plate assembly.

Visual inspections will be performed whenever the steam generator primary side is opened for eddy current inspections. At IP2, the frequency is at least once every 48 effective full p'ower months per Technical Specification 5.5.7.d.2. At IP3, the frequency is at least once every 72 effective full power months (which is every third refueling outage) per Technical Specification 5.5.8.d.2.

IPEC implements the EPRI steam generator guidelines, including: (a) EPRI Report 1022832 (primary-to-secondary leak guidelines); (b) EPRI Report 1025132 (in-situ pressure test guidelines); (c) EPRI Report 1019038 (integrity assessment guidelines); and (d) EPRI Report 1013706 (examination guidelines). The IPEC Steam Generator Integrity Program is being revised to implement (c) EPRI Report 3002007571 (integrity assessment guidelines);

and (d) EPRI Report 3002007572 (examination guidelines) within the timeframes required by the EPRI Steam Generator Management Program (~GMP) in accordance with NEI 97-06 Rev 3 and NEI 03-08 Rev 2 and 3.

RAI B.1.35-2. Request 2 Discuss whether the Steam Generator Integrity Program is used to manage cracking due to PWSCC for divider plate assemblies (LRA item 3.1.1-81) and tube-to-tubesheet welds (LRA item 3.1.1-35).

Response

As indicated in LRA item 3.1.1-81, the Water Chemistry Control - Primary and Secondary Program manages cracking of the nickel-alloy steam generator divider plate exposed to reactor coolant. Aging management review results do not credit the Steam Generator Integrity Program to manage cracking of the divider plate due to PWSCC because the program does not include VT-1 or volumetric examinations that are qualified for detection of small cracks resulting from PWSCC. However, consistent with LR-ISG-2016-01 recommendations, the IPEC Steam Generator Integrity Program will be enhanced to specify a general visual inspection of the steam generator channel head.

For the steam generator tubesheets, which are steel with nickel alloy cladding, cracking is managed by the Water Chemistry Control - Primary and Secondary, and the Steam Generator Integrity Programs. This position is documented in LRA item 3.1.1-35.

In the IP3 spring 2017 refueling outage, a general visual inspection was performed on the steam generator channel head, divider plate assembly, and tube-to-tubesheet welds in all 4 steam generators looking for evidence of cracking. The inspection was specifically performed to satisfy the recommendations of LR-ISG-2016-01. The purpose of the visual

,inspection was to identify rust stains or other abnormal conditions which could indicate the presence of cracking. The visual inspection was satisfactory with no evidence of rust stains I

NL-17-060 Page 5 of 5 or other abnormal conditions which would indicate the presence of cracking. The general visual inspection identified no cracking or distortion of the divider plate.

A similar inspection is planned for IP2 in the spring 2018 refueling outage.

RAI B.1.35-2. Request 3 Provide updated description of UFSAR supplement for the Steam Generator Integrity Program as necessary. As part of the response, clarify whether the program is consistent with Revision 3 of NEI 97-06 "Steam Generator Program Guidelines."

Response

The IPEC Steam Generator Integrity Program is consistent with Revision 3 of NEI 97-06 "Steam Generator Program Guidelines."

The License Renewal Application requires changes due to the responses to this Request for Information. These changes are contained in Attachment 2. The IP3 UFSAR will be revised in the biennial update due in September 2017, and the IP2 UFSAR will be revised in the biennial update due in September 2018.

ATTAGHMENT 2 to N L-17-060 LICENSE RENEWAL APPLICATION CHANGES DUE TO RESPONSES TO REQUESTS FOR INFORMATION Changes are shown as strikethroughs for deletions and underlines for additions ENTERGY NUCLEAR OPERATIONS, INC.

INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 & 3 DOCKET NOS. 50-247 AND 50-286

Indian Point Unit No. 2 A.2.1.34 Steam Generator Integrity Program NL-17-060 Page 1of4 The Steam Generator Integrity Program is an existing program that uses nondestructive examination (NOE) techniques to identify tubes that are defective and need to be removed from service or repaired in accordance with the guidelines of the plant technical specifications. The program also includes processes for monitoring and maintaining primary and secondary side component integrity. The program defines when inspections and maintenance are performed, the scope of work, and the methods used, in accordance with the EPRI steam generator guidelines. including revisions to EPRI Steam Generator Management Program (SGMP) documents. any interim guidance provided by the SGMP.

and SGMP administrative procedures. The results of the condition monitoring assessment are compared to the operational assessment performed for the prior operating cycle with differences evaluated.

The Steam Generator Integrity Program will be enhanced to include the following.

Revise appropriate procedures to require that the results of the condition monitoring assessment are compared to the operational assessment performed for the prior operating cycle *.vith differences evaluated.

Enhancements will be implemented prior to the period of extended operation.

Revise applicable procedures to specify a general visual inspection of the steam generator channel head.

This enhancement will be implemented prior to December 31, 2017.

Indian Point Unit No. 3 A.3.1.34 Steam Generator Integrity Program The Steam Generator Integrity Program is an existing program that performs uses nondestructive examination (NOE) techniques to identify tubes that are defective and need to be removed from service or repaired in accordance with the guidelines of the plant technical specifications. The* program also includes processes for monitoring and maintaining primarY and secondary side component integrity. The program defines when inspections and maintenance are performed, the scope of work, and the methods used, in accordance with the EPRI steam generator guidelines. including revisions to EPRI Steam Generator Management Program (SGMP) documents. any interim guidance provided by the SGMP. and SGMP administrative procedures. The results of the condition monitoring assessment are compared to the operational assessment performed for the prior operating cyCle with differences evaluated.

The Steam Generator Integrity Program will be enhanced to include the following.

NL-17-060 Page 2 of 4 Revise appropriate procedures to require that the results of the condition monitoring assessment are compared to the operational assessment performed for the prior operating cycle with differences evaluated.

Enhancements *11ill be implemented prior to the period of extended operation.

Revise applicable procedures to specify a general visual inspection of the steam generator channel head~

This enhancement will be implemented prior to December 31. 2017.

NL-17-060 Page 3 of4 8.1.35 STEAM GENERATOR INTEGRITY.

Program Description The Steam Generator Integrity Program is an existing program. In the industry, steam generator (SG) tubes have experienced tube degradation related to corrosion phenomena, such as primary water stress corrosion cracking (PWSCC), outside diameter stress corrosion cracking (ODSCC), intergranular attack (IGA), pitting, and wastage, along with other mechanically induced phenomena, such as denting, wear, impingement damage, and fatigue.

Nondestructive examination (NOE) techniques are used to identify tubes that are defective and need to.be removed frorri service or repaired in accordance with the guidelines of the plant technical specifications.

The Steam Generator Integrity Program includes processes for monitoring and maintaining primary and secondary side component integrity. The program defines when inspections and maintenance are performed, the scope of work, and the methods used. The Steam Generator Integrity Program is implemented in accordance with NEI 97-06, "Steam Generator Program Guidelines."

NUREG-1801 Consistency The Steam Generator Integrity Program is consistent with the program described in NUREG-1801, Section Xl.M19, Steam Generator Tube Integrity with enhancement.

Exceptjons to NUREG-1801 None Enhancements The following enhancement will be implemented prior to the period of extended operation.

Attributes Affected

5. Monitoring and Trending Enhancements Revise appropriate procedures to require that the results of the condition monitoring assessment are compared to the operational assessment performed for the prior operating cycle with differences evaluated.

The following enhancement will be implemented prior to December 31. 2017.

Attributes Affected

4. Detection of Aging Effects i

Enhancements NL-17-060 Page 4 of 4 Revise am2licable grocedures to sgecif~ a general visual insgection of the steam generator channel head.

ATTACHMENT 3 to NL-17-060 LICENSE RENEWAL APPLICATION IPEC LIST OF REGULATORY COMMITMENTS Rev.33 ENTERGY NUCLEAR OPERATIONS, INC.

INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 & 3 DOCKET NOS. 50-247 AND 50-286

1 2

List of Regulatory Commitments Rev. 33 NL-17-060 Page 1 of 22 The following table identifies those actions committed to by Entergy in this document.

Changes are shown as strikethroughs for deletions and underlines for additions.

COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION I AUDIT ITEM Enhance the Aboveground Steel Tanks Program for IP2: Complete NL-07-039 A.2.1.1 A.3.1.1 IP2 and IP3 to perform thickness measurements of NL-13-122 8.1.1 the bottom surfaces qf the condensate storage tanks, city water tank, and fire water tanks once during the first ten years of the period of extended operation.

Enhance the Aboveground Steel Tanks Program for IP2 and IP3 to require trending of thickness measurements when material loss is detected.

Implement LRA Sections, A.2.1.1, A.3.1.1 and 8.1.1, IP2 & IP3:

NL-14-147 A.2.1.1 as shown in NL-14-147.

December 31, 2019 A.3.1.1 8.1.1 Implement LRA Sections, A.2.1.1 and 8.1~1, as IP2 & IP3:

NL-:-15-092 A.2.1.1 shown in NL-15:::092 December 31, 2019 8.1.1 Enhance the Bolting Integrity Program for IP2 and IP2: Complete NL-07-039 A.2.1.2 IP3 to clarify that actual yield strength is used in A.3.1.2 selecting materials for low susceptibility to sec and IP3: Complete B.1.2 clarify the prohibition on use of lubricants containing NL-07-153 Audit Items MoS2 for bolting.

201, 241, The Bolting Integrity Program manages loss of NL-13-122 270 preload and loss of material for all external bolting.

COMMITMENT 3

Implement the Buried Piping and Tanks Inspection Program for IP2 and IP3 as described in LRA Section B.1.6.

This new program will be implemented consistent with the corresponding program described in NUREG-1801 Section Xl.M34, Buried Piping and Tanks Inspection.

Include in the Buried Piping and Tanks Inspection Program described in LRA Section B.1.6 a risk assessment of in-scope buried piping and tanks that includes consideration of the impacts of buried piping or tank leakage and of conditions affecting the risk for corrosion. Classify pipe segments and tanks as having a high, medium or low impact of leakage based on the safety class, the hazard posed by fluid contained in the piping and the impact of leakage on reliable plant operation. Determine corrosion risk through consideration of piping or tank material, soil resistivity, drainage, the presence of cathodic protection and the type of coating. Establish inspection priority and frequency for periodic inspections of the in-scope piping and tanks based on the results of the risk assessment. Perform inspections using inspection techniques with demonstrated effectiveness.

4 Enhance the Diesel Fuel Monitoring Program to include cleaning and inspection of the IP2 GT-1 gas turbine fuel oil storage tanks, IP2 and IP3 EDG fuel oil day tanks, IP2 SBO/Appendix R diesel generator fuel oil day tank, and IP3 Appendix R fuel oil storage tank and day tank once every ten years.

Enhance the Diesel Fuel Monitoring Program to include quarterly sampling and analysis of the IP2 SBO/Appendix R diesel generator fuel oil day tank, IP2 security diesel fuel oil storage tank, IP2 security

'diesel fuel oil day tank, and IP3 Appendix R fuel oil storage tank. Particulates, water and sediment checks will be performed on the samples. Filterable solids acceptance criterion will be less than or equal to 1 Omg/I. Water and sediment acceptance criterion will be less than or eaual to 0.05%.

IMPLEMENTATION SCHEDULE IP2: Complete IP3: Complete IP2: Complete IP3: Complete NL-17-060 Page 2 of 22 SOURCE RELATED LRA SECTION I AUDIT ITEM NL-07-039 A.2.1.5 A.3.1.5 NL-13-122 B.1.6 NL-07-153 Audit Item NL-15-121 173 NL-09-106 NL-09-111 NL-11-101 NL-07-039 A.2.1.8 A.3.1.8 NL-13-122 B.1.9 NL-07-153 Audit items NL-15-121 128, 129,

132, NL-08-057 491, 492, 510

COMMITMENT Enhance the Diesel Fuel Monitoring Program to include thickness measurement of the bottom of the following tanks once every ten years. IP2: EDG fuel oil storage tanks, EDG fuel oil day tanks, SBO/Appendix R diesel generator fuel oil day tank, GT-1 gas turbine fuel oil storage tanks, and diesel fire pump fuel oil storage tank; IP3: EDG fuel oil day tanks, EDG fuel oil storage tanks, Appendix R fuel oil storage tank, and diesel fire pump fuel oil storage,

tank.

Enhance the Diesel Fuel Monitoring Program to change the analysis for water and particulates to a quarterly frequency for the following tanks. IP2: GT-1 gas turbine fuel oil storage tanks and diesel fire pump fuel oil storage tank; IP3: Appendix R fuel oil day tank and diesel fire pump fuel oil sforage tank.

Enhance the Diesel Fuel Monitoring Program to.

specify acceptance criteria for thickness measurements of the fuel oil storage tanks within the scope of the program.

Enhance the Diesel Fuel Monitoring Program to direct samples be taken and include direction to remove water when detected.

Revise applicable procedures to direct sampling of the onsite portable fuel oil contents prior to transferring the contents to the storage tanks.

Enhance the Diesel Fuel Monitoring Program to direct the addition of chemicals including biocide when the presence of bioloQical activity is confirmed.

5 Enhance the External Surfaces Monitoring Program for IP2 and IP3 to include periodic inspections of systems in scope and subject to aging management review for license renewal in accordance with 1 O CFR 54.4(a)(1) and (a)(3). Inspections shall include areas surrounding the subject systems to identify hazards to those systems. Inspections of nearby systems that could impact the subject systems will include SSCs that are in scope and subject to aging management review for license renewal in accordance with.10 CFR 54.4(a)(2).

IMPLEMENTATION SCHEDULE

(

IP2: Complete NL-17-060 Page 3 of 22 SOURCE RELATED LRA SECTION I AUDIT ITEM NL-07-039 A.2.1.10 A.3.1.10 NL-13-122 8.1.11

COMMITMENT Implement LRA Sections A.2.1.10, A.3.1.10 and B.1.11, as shown in NL-14-147.

6 Enhance the Fatigue Monitoring Program for IP2 to monitor steady state cycles and feedwater cycles or perform an evaluation to determine monitoring is not required. Review the number of allowed events and resolve discrepancies between reference documents and monitoring procedures.

Enhance the Fatigue Monitoring Program for IP3 to include all the transients identified. Assure all fatigue analysis transients are included with the lowest limiting numbers. Update the number of design transients accumulated to date.

7 Enhance the Fire Protection Program to inspect external surfaces of the IP3 RCP oil collection systems for loss of material each refueling cycle.

Enhance the Fire Protection Program to explicitly state that the IP2 and IP3 diesel fire pump engine sub-systems (including the fuel supply line) shall be observed while the pump is running. Acceptance criteria will be revised to verify that the diesel engine does not exhibit signs of degradation while running; such as fuel oil, lube oil, coolant, or exhaust gas leakage.

Enhance the Fire Protection Program to specify that the IP2 and IP3 diesel fire pump engine carbon steel exhaust components are inspected for evidence of corrosion and cracking at least once each operating cycle.

Enhance the Fire Protection Program for IP3 to visually inspect the cable spreading room, 480V switchgear room, and EOG room C02 fire suppression system for signs of degradation, such as corrosion and mechanical damage at least once every six months.

IMPLEMENTATION SCHEDULE IP2 & IP3:

December 31, 2019 IP2: Complete IP3: Complete IP2: Complete IP3: Complete NL-17-060 Page 4 of 22 SOURCE RELATED LRA SECTION I AUDIT ITEM NL-14-147 A.2.1.10 A.3.1.10 B.1.11 NL-07-039 A.2.1.11 A.3.1.11 NL-13-122 B.1.12, NL-07-153 Audit Item 164 NL-15-121 NL-07-039 A.2.1.12 A.3.1.12 NL-13-122 B.1.13 NL-15-121

COMMITMENT 8

Enhance the Fire Water Program to include inspection of IP2 and IP3 hose reels for evidence of corrosion. Acceptance criteria will be revised to verify no unacceptable signs of degradation.

Enhance the Fire Water Program to replace all or test a sample of IP2 and IP3 sprinkler heads required for 10 CFR 50.48 using guidance of NFPA 25 (2002 edition), Section 5.3.1.1.1 before the end of the 50-year sprinkler head service life and at 10-year intervals thereafter during the extended period of operation to ensure that signs of degradation, such as corrosion, are detected in a timely manner.

Enhance the Fire Water Program to perform wall thickness evaluations of IP2 and IP3,fire protection piping on system components using non-intrusive techniques (e.g., volumetric testing) to identify evidence of loss of material due to corrosion. These inspections will be performed before the end of the current operating term and at intervals thereafter during the period of extended operation. Results of the initial evaluations will be used to determine the appropriate inspection interval to ensure aging effects are identified prior to loss of intended function.

Enhance the Fire Water Program to inspect the internal surface of foam based fire suppression tanks. Acceptance criteria will be enhanced to verify no siQnificant corrosion.

Implement LRA Sections, A.2.1.13, A.3.1.13 and B.1.14, as shown in NL-14-147.

Implement LRA Sections A.2.1.13, A.3.1.13 and B.1.14, as shown in NL-15-019 Implement LRA Sections A.2.1.13, A.3.1.13 and B.1.14, as shown in NL-15-092

. IMPLEMENTATION SCHEDULE IP2: Complete J

IP2 & IP3:

December 31, 2019 IP2 & IP3:

December 31, 2019 IP2 & IP3:

December 31, 2019 NL-17-060 Page 5 of 22 SOURCE RELATED LRA SECTION I AUDIT ITEM NL-07-039 A.2.1.13 A.3.1.13 NL-13-122 B.1.14

• NL-07-153 Audit Items 105, 106 NL-08-014 NL-14-147 A.2.1.13 A.3.1.13 B.1.14 NL-15-019 A.2.1.13 A.3.1.13 B.1.14 NL-15-092 A.2.1.13 A.3.1.13 B.1.14

COMMITMENT Implement LRA Sections A.2.1.13, A.3.1.13, and B.1.14, as shown in NL-17-052 9

Enhance the Flux Thimble Tube Inspection Program for IP2 and IP3 to 'implement comparisons to wear rates identified in WCAP-12866. Include provisions to compare data to the previous performances and perform evaluations regarding change to test frequency and scope.

Enhance the Flux Thimble Tube Inspection Program for IP2 and IP3 to specify the acceptance criteria as outlined in WCAP-12866 or other plant-specific 1 values based on evaluation of previous test results.

Enhance the Flux Thimble Tube Inspection Program for IP2 and IP3 to direct evaluation and performance of corrective actions based on tubes that exceed or are projected to exceed the acceptance criteria. Also stipulate that flux thimble tubes that cannot be inspected over the tube length and cannot be shown by analysis to be satisfactory for continued service, must be removed from service to ensure the integrity of the reactor coolant system pressure boundary.

IMPLEMENTATION SCHEDULE IP2 & IP3:

December 31, 2017 IP2: Complete IP3: Complete NL-17-060 Page 6 of 22 SOURCE RELATED LRA SECTION I AUDIT ITEM NL-17-052 A.2.1.13 A.3.1.13 B.1.14 NL-07-039 A.2.1.15 A.3.1.15 NL-13-122 B.1.16 NL-15-121

COMMITMENT 10 Enhance the Heat Exchanger Monitoring Program for IP2 and IP3 to include the following heat exchangers in the scope of the program.

• Safety injection pump lube oil heat exchangers RHR heat exchangers RHR pump seal coolers Non-regenerative heat exchangers Charging pump seal water heat exchangers

• Charging pump fluid drive coolers Charging pump crankcase oil coolers

• Spent fuel pit heat exchangers Secondary system steam generator sample coolers

• Waste gas compressor heat exchangers S80/Appendix R diesel jacket water heat exchanger (IP2 only)

Enhance the Heat Exchanger Monitoring Program for IP2 and IP3 to perform visual inspection on heat exchangers where non-destructive examination, such as eddy current inspection, is not possible due to ~eat exchanger design limitations.

Enhance the Heat Exchanger Monitoring Program for IP2 and IP3 to include consideration of material-environment combinations when determining sample population of heat exchangers.

Enhance the Heat Exchanger Monitoring Program for IP2 and IP3 to establish minimum tube wall thickness for the new heat exchangers identified in the scope of the program. Establish acceptance criteria for heat exchangers visually inspected to include no indication of tube erosion, vibration wear, corrosion, pitting, fouling, or scaling.

IMPLEMENTATION SCHEDULE IP2: Complete IP3: Complete NL-17-060 Page 7 of 22 SOURCE RELATED LRA SECTION I AUDIT ITEM NL-07-039 A.2.1.16 A.3.1.16 NL-13-122 8.1.17, NL-07-153 Audit Item NL-15-121 52 NL-09-018

COMMITMENT 11 Deleted 12 Enhance the Masonry Wall Program for IP2 and IP3 to specify that the IP1 intake structure is included in the program.

13 Enhance the Metal-Enclosed Bus Inspection Program for IP2 and IP3 to visually inspect the external surface of MEB enclosure assemblies for loss of material at least once every 10 years. The first inspection will occur prior to the period of extended operation and the acceptance criterion will

\\

be no significant loss of material.

Enhance the Metal-Enclosed Bus Inspection Program to add acceptance criteria for MEB internal visual inspections to include the absence of indications of dust accumulation on the bus bar, on the insulators, and in the duct, in addition to the absence of indications of moisture intrusion into the duct.

Enhance the Metal-Enclosed Bus Inspection Program for IP2 and IP3 to inspect bolted connections at least once every five years if performed visually or at least once every ten years using quantitative measurements such as thermography or contact resistance measurements.

The first inspection will occur prior to the period of extended operation.

The plant will process a change to applicable site procedure to remove the reference to "re-torquing" connections for phase bus maintenance and bolted connection maintenance.

14 Implement the Non-EQ Bolted Cable Connections Program for IP2 and IP3 as described in LRA Section B. 1.22.

IMPLEMENTATION SCHEDULE IP2: Complete IP3: Complete IP2: Complete IP3: Complete IP2: Complete IP3: Complete NL-17-060 Page 8 of 22 SOURCE RELATED LRA SECTION I AUDIT ITEM NL-09-056 NL-11-101 NL-07-039 A.2.1.18 A.3.1.18 NL-13-122 B.1.19 NL-07-039 A.2.1.19 A.3.1.19 NL-13-122 B.1.20 NL-07-153 Audit Items NL-15-121

124, NL-08-057 133, 519 NL-13-077.

NL-07-039 A.2.1.21 A.3.1.21 NL-13-122 B.1.22 NL-15-121

COMMITMENT 15 Implement the Non-EQ Inaccessible Medium-Voltage Cable Program for IP2 and IP3 as described.

in LRA Section 8.1.23.

This new program will be implemented consistent with the corresponding program described in NUREG-1801 Section Xl.E3, Inaccessible Medium-Voltage Cables Not Subject To 10 CFR 50.49 Environmental Qualification Requirements.

16 Implement the Non-EQ Instrumentation Circuits Test Review Program for IP2 and IP3 as described in LRA Section 8.1.24.

This new program will be implemented consistent with the. corresponding program described in NUREG-1801 Section Xl.E2, Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits.

17 Implement the Non-EQ Insulated Cables and Connections Program for IP2 and IP3 as described.

in LRA Section 8.1.25.

This new program will be implemented consistent with the corresponding program described in NUREG-1801 Secti.on Xl.E1, Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements.

IMPLEMENTATION SCHEDULE IP2: Complete IP3: Complete IP2: Complete IP3: Complete IP2: Complete IP3: Complete

~

NL-17-060 Page 9 of 22 SOURCE RELATED LRA SECTION I AUDIT ITEM NL-07-039 A.2.1.22 A.3.1.22 NL-13-122 8.1.23 NL-07-153 Audit item NL-15-121 173 NL-11-032 NL-11-096 NL-11-101 NL-07-039 A.2.1.23 A.3.1.23 NL-13-122 8.1.24 NL-07-153 Audit item NL-15-121 173 NL-07-039 A.2.1.24 A.3.1.24 NL-13-122 8.1.25 NL-07-153 Audit item NL-15-121 173

COMMITMENT 18 Enhance the Oil Analysis Program for IP2 to sample and analyze lubricating oil used in the SBC/Appendix R diesel generator consistent with the oil analysis for other site diesel generators.

Enhance the Oil Analysis Program for IP2 and IP3 to sample and analyze generator seal oil and turbine hydraulic control oil.

Enhance the Oil Analysis Program for IP2 and IP3 to formalize preliminary oil screening forwater and particulates and laboratory analyses including defined acceptance criteria for all components included in the scope of this program. The program will specify corrective actions in the event acceptance criteria are not met.

Enhance the Oil Analysis Program for IP2 and IP3 to formalize trending of preliminary oil screening results as well as data provided from independent laboratories.

19 Implement the One-Time Inspection Program for IP2 and I P3 as described in LRA Section B.1.27.

This new program will be implemented consistent with the corresponding program described in NUREG-1801, Section Xl.M32, One-Time Inspection.

20 Implement the One-Time Inspection - Small Bore Piping Program for IP2 and IP3 as described in LRA Section B.1.28.

This new program will be implemented consistent with the corresponding program described in NUREG-1801,.section Xl.M35, One-Time Inspection of ASME Code Class I Small-Bore Piping.

21 Enhance the Periodic Surveillance and Preventive Maintenance Program for IP2 and IP3 as necessary to assure that the effects of aging wjll be managed such that applicable components will continue to perform their intended functions consistent with the current licensing basis through the period of extended operation.

IMPLEMENTATION SCHEDULE IP2: Complete IP3: Complete IP2: Complete IP3: Complete IP2: Complete IP3: Complete IP2: Complete IP3: Complete

)

NL-17-060 Page 10 of 22 SOURCE RELATED LRA SECTION I AUDIT ITEM NL-07-039 A.2.1.25 A.3.1.25 NL-13-122 B.1.26 NL-11-101 NL-15-121 NL-07-039 A.2.1.26 A.3.1.26 NL-13-122 B.1.27 NL-07-153 Audit item NL-15-121 173 NL-07-039 A.2.1.27 A.3.1.27 NL-13-122 B.1.28 NL-07-153 Audit item NL-15-121 173 NL-07-039 A.2.1.28 A.3.1.28 NL-13-122 B.1.29 NL-15-121

COMMITMENT Implement LRA Sections A.2.1.28, A.3.1.28 and 8.1.29, as-shown in NL-17-052 22 Enhance the Reactor Vessel Surveillance Program for IP2 and IP3 revising the specimen capsule withdrawal schedules to draw and test a standby capsule to cover the peak reactor vessel fluence expected through the end of the period of extended operation.

Enhance the Reactor Vessel Surveillance Program for IP2 and IP3 to require that tested and untested specimens from all capsules pulled from the reactor vessel are maintained in storage.

23 Implement the Selective Leaching Program for IP2 and IP3 as described in LRA Section 8.1.33.

This new program will be implemented consistent -

with the corresponding program described in NUREG-1801, Section Xl.M33 Selective Leaching of Materials.

24 Enhance the Steam Generator Integrity Program for IP2 and IP3 to require that the results of the condition monitoring assessment are compared to*

the operational assessment performed for the prior ooerating cycle with differences evaluated.

25 Enhance the Structures Monitoring Program to explicitly specify that the following structures are included in the program.

• Appendix R diesel generator foundation (I P3)

• Appendix R diesel generator fuel oil tank vault

{IP3)

• Appendix R diesel generator switchgear and enclosure (IP3) city water storage tank foundation

• condensate storage tanks foundation (IP3)

• containment access facility and annex (IP3) discharge canal (IP2/3)

• emergency lighting poles and foundations (IP2/3)

• fire pumphouse (IP2)

• fire protection pumphouse (IP3)

• fire water storage tank foundations (IP2/3)

• gas turbine 1 fuel storage tank foundation IMPLEMENTA ~ION

~CH EDU LE IP2 & IP3:

December 31, 2017 IP2: Complete I

1IP3: Complete IP2: Complete IP3: Complete IP2: Complete IP3: Complete IP2: Complete*

IP3: Complete NL-17-060 Page 11 of 22 SOURCE RELATED LRA SECTION I AUDIT ITEM NL-17-052 A.2.1.28 A.3.1.28 8.1.29 NL-07-039 A.2.1.31 A.3.1.31 NL-13-122 8.1.32 NL-15-121 NL-07-039 A.2.1.32 A.3.1.32 NL-13-122 8.1.33 NL-07-153 Audit item NL-15-121 173 NL-07-039 A.2.1.34 A.3.1.34 NL-13-122 8.1.35 NL-07-039 A.2.1.35 A.3.1.35.

NL-13-122 8.1.36 NL-07-153 NL-15-121 Audit items 86, 87, 88, NL-08-057 417 NL-13-077

COMMITMENT maintenance and outage building-elevated passageway (IP2) new station security building (IP2) nuclear service building (IP1) primary water storage tank foundation (IP3) refueling water storage tank foundation (I P3) security access and office building (IP3) service water pipe chase (IP2/3)

• service water valve pit (IP3)

• transformer/switchyard support structures (IP2)

• waste holdup tank pits (IP2/3)

Enhance the Structures Monitoring Program for IP2 and IP3 to clarify that in addition to structural steel and concrete, the following commodities (including their anchorages) are inspected for each structure as applicable.

cable trays and supports concrete.portion of reactor vessel supports

• conduits and supports

• cranes, rails and girders

• equipment pads and foundations

• fire proofing (pyrocrete)

HVAC duct supports jib cranes manholes and duct banks manways, hatches and hatch covers monorails new fuel storage racks sumps Enhance the Structures Monitoring Program for IP2 and IP3 to inspect inaccessible concrete areas that are exposed by excavation for any reason. IP2 and I P3 will also inspect inaccessible concrete areas in environments where observed conditions in accessible areas exposed to the same environment indicate that significant concrete degradation is occurring.

Enhance the Structures Monitoring Program for IP2 and IP3 to perform inspections of elastomers (seals, L

IMPLEMENTATION SCHEDULE NL-17-060 Page 12 of 22 SOURCE RELATED LRA SECTION I AUDIT ITEM NL-14-146 NL-13-077

COMMITMENT gaskets, seismic joint filler, and roof elastomers) to identify cracking and change in material properties and for inspection of aluminum vents and louvers to identify loss of material.

Enhance the Structures Monitoring Program for IP2 and IP3 to perform an engineering evaluation of groundwater samples to assess aggressiveness of groundwater to concrete on a periodic basis (at least once every five years). IPEC will obtain samples from at least 5 wells that are representative of the ground water surrounding below-grade site structures and perform an engineering evaluation of the results from those samples for sulfates, pH and chlorides.

Additionally, to assess potential indications of spent fuel pool leakage, IPEC will sample for tritium in groundwater wells in close proximity to the IP2 spent fuel pool at least once every 3 months.

Enhance the Structures Monitoring Program for IP2 and IP3 to perform inspection of normally submerged concrete portions of the intake structures at least once every 5 years. Inspect the baffling/grating partition and support platform of the IP3 intake structure at least once every 5 years.

Enhance the Structures Monitoring Program for IP2 and I P3 to perform inspection of the degraded areas of the water control structure once per 3 years rather than the normal frequency of once per 5 years during the PEO.

Enhance the Structures Monitoring Program to include more detailed quantitative acceptance criteria for inspections of concrete structures in accordance with ACI 349.3R, "Evaluation of Existing Nuclear Safety-Related Concrete Structures" prior to the period of extended operation.

IMPLEMENTATION SCHEDULE NL-17-060 Page 13 of 22 SOURCE RELATED LRA SECTION I AUDIT ITEM NL-08-127 Audit Item 360 Audit Item 358 NL-11-032 NL-11-101

COMMITMENT 26 Implement the Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) Program for IP2 and IP3 as described in LRA Section B.1.37.

This new program will be implemented consistent with the corresponding program described in NUREG-1801, Section Xl.M12, Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) Proaram.

27 Implement the Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel (CASS) Program for IP2 and IP3 as described in LRA Section B.1.38.

This new program will be implemented consistent with the corresponding program described in NUREG-1801 Section Xl.M13, Thermal Aging and Neutron Embrittlement of Cast Austenitic Stainless Steel (CASS) Proaram.

28 Enhance the Water Chemistry Control - Closed Cooling Water Program to maintain water chemistry of the IP2 SBC/Appendix R diesel generator cooling system per EPRI guidelines.

Enhance the Water Chemistry Control - Closed Cooling Water Program to maintain the IP2 and IP3 security generator and fire protection diesel cooling water pH and glycol within limits specified by EPRI Quidelines.

29 Enhance the Water Chemistry Control - Primary and

~econdary Program for IP2 to test sulfates monthly m the RWST with a limit of <150 ppb.

30 For aging management of the reactor vessel internals, IPEC will (1) participate in the industry programs for investigating and managing aging effects on reactor internals; (2) evaluate and implement the results of the industry programs as applicable to the reactor internals; and (3) upon completion of these programs, but not less than 24 months before entering the period of extended operation, submit an inspection plan for reactor internals to the NRC for review and approval.

IMPLEMENTATION SCHEDULE IP2: Complete IP3: Complete IP2: Complete IP3: Complete IP2: Complete IP3: Complete IP2: Complete IP2: Complete IP3: Complete NL-17-060 Page 14 of 22 SOURCE RELATED LRA SECTION I AUDIT ITEM NL-07-039 A.2.1.36 A.3.1.36 NL-13-122 B.1.37 NL-07-153 Audit item NL-15-121 173 NL-07-039 A.2.1.37 A.3.1.37 NL-13-122 B.1.38 NL-07-153 Audit item 173 NL-07-039 A.2.1.39 A.3.1.39 NL-13-122 B.1.40 NL-08-057 Audit item 509 NL-07-039 A.2.1.40 B.1.41 NL-13-122 NL-07-039 A.2.1.41 A.3.1.41 NL-13-122 NL-11-107

COMMITMENT IMPLEMENTATION SCHEDULE 31 Additional P-T curves will be submitted as required I P2: Complete per 10 CFR 50, Appendix G prior to the period of IP3: Complete extended operation as part of the Reactor Vessel Surveillance Program.

32 As required by 10 CFR 50.61(b)(4), IP3 will submit a IP3:

plant-specific safety analysis for plate 82803-3 to the ~pproximately 6 NRC three years prior to reaching the RT PTs

!fears after entering screening criterio,n. Alternatively, the site may he PEO choose to implement the revised PTS rule when approved.

NL-17-060 Page 15of22 SOURCE RELATED LRA SECTION I AUDIT ITEM NL-07-039 A.2.2.1.2 A.3.2.1.2 NL-13-122 4.2.3 NL-15-121 NL-07-039 A.3.2.1.4 NL-07-140 4.2.5 NL-08-014 NL-08-127

COMMITMENT 33 At least 2 years prior to entering the period of extended operation, for the locations identified in LRA Table 4.3-13 (IP2) and LRA Table 4.3-14 (IP3),

under the Fatigue Monitoring Program, IP2 and IP3 will implement one or more of the following:

(1) Consistent with the Fatigue Monitoring Program, Detection of Aging Effects, update the fatigue usage calculations using refined fatigue analyses to determine valid.CUFs less than 1.0 when accounting for the effects of reactor water environment. This includes applying the appropriate Fen factors to 'valid CUFs determined in accordance with one of the following:*

1. For locations in LRA Table 4.3-13 (IP2) and LRA Table 4.3-14 (IP3), with existing fatigue

(

analysis valid for the period of extended operation, use the existing CUF.

2. Additional plant-specific locations with a valid CUF may be evaluated. In particular, the pressurizer lower shell will be reviewed to ensure the surge nozzle remains the limiting component.

3. Representative CUF values from other plants, adjusted to or enveloping the IPEC plant specific external loads may be used if demonstrated applicable to IPEC.

4. An analysis using an NRG-approved 'version of the ASME code or NRG-approved alternative (e.g., NRG-approved code case) may be performed to determine a valid CUF.

(2) Consistent with the Fatigue Monitoring Program, Corrective Actions, repair or replace the affected locations before exceeding a CUF of 1.0.

34 IP2 SBO I Appendix R diesel generator will be installed and operational by April 30, 2008. This committed change to the facility meets the requirements of 10 CFR 50.59(c)(1) and, therefore, a license amendment pursuant to 10 CFR 50.90 is not required.

IMPLEMENTATION SCHEDULE IP2: Complete

. IP3: Complete Complete NL-17-060 Page 16 of 22 SOURCE RELATED LRA SECTION I AUDIT ITEM NL-07-039 A.2.2.2.3 A.3.2.2.3 NL-13-122 4.3.3 NL-07-153 Audit item 146 NL-08-021 NL-10-082 NL-13-122 2.1.1.3.5 NL-07-078 NL-08-074 NL-11-101

COMMITMENT

?

35 Perform a one-time inspection of representative sample area of IP2 containment liner affected by the 1973 event behind the insulation, prior to entering the period of extended operation, to assure liner degradation is not occurring in this area.

Perform a one-time inspection of representative sample area of the IP3 containment steel liner at the juncture with the concrete floor slab, prior to entering the period of extended operation, to assure liner degradation is not occurring in this area.

Any degradation will be evaluated for updating of the containment liner analvses as needed.

36 Perform a one-time inspection and evaluation of a sample of potentially affected IP2 refueling cavity concrete prior to the period of extended operation.

The sample will be obtained by core boring the refueling cavity wall in an area that is susceptible to exposure to borated water leakage. The inspection will include an assessment of embedded reinforcing steel.

Additional core bore samples will be taken, if the leakage is not stopped, prior to the end of the first ten years of the period of extended operation.

A sample of leakage fluid will be analyzed to determine the composition of the fluid. If additional core samples are taken prior to the end of the first ten years of the period of extended operation, a sample of leakaoe fluid will be analvzed.

37 Enhance the Containment lnservice Inspection (Cll-IWL) Program to include inspections of the containment using enhanced characterization of degradation (i.e., quantifying the dimensions of noted indications through the use of optical aids) during the period of extended operation. The enhancement includes obtaining critical dimensional data of degradation where possible through direct measurement or the use of scaling technologies for photographs, and the use of consistent vantage points for visual inspections.

IMPLEMENTATION SCHEDULE.

IP2: Complete IP3: Complete IP2: Complete j

IP2: Complete IP3: Complete NL-17-060 Page 17 of 22 SOURCE RELATED LRA SECTION I AUDIT ITEM NL-08-127 Audit Item 27 NL-13-122 NL-11-101 NL-15-121

)

NL-09-018 NL-08-127 Audit Item NL-11-101 359 NL-13-122 NL-09-056 NL-09-079 NL-08-127 Audit Item 361 NL-13-122

COMMITMENT 38 For Reactor Vessel Fluence, should future core loading patterns invalidate the basis for the projected values of RTpts or CvUSE, updated calculations will be orovided to the NRC.

39 Deleted 40 Evalu~te plant ~pecific and appropriate industry operating experience and incorporate lessons

~earned_ in establishing appropriate monitoring and inspect~on frequencies to assess aging effects for the new aging management programs. Documentation of the operating experience evaluated for each new program will be available on site for NRC review prior to the period of extended operation.

41 Deleted IMPLEMENTATION SCHEDULE IP2: Complete IP3: Complete I P2: Complete IP3: Complete NL-17-060 Page 18 of 22 SOURCE RELATED LRA SECTION I AUDIT ITEM NL-08-143 4.2.1 NL-13-122 NL-15-121 NL-09-079 NL-09-106 8.1.6 8.1.22 NL-13-122 8.1.23 NL-15-121 8.1.24 8.1.25 8.1.27 8.1.28 8.1.33 8.1.37 8.1.38 NL-17-005 N/A

COMMITMENT 42 IPEC will develop a plan for each unit to address the potential for cracking of the primary to secondary pressure boundary due to PWSCC of tube-to-tubesheet welds using one of the following two options.

Option 1 (Analysis)

JPEC will perform an analytical evaluation of the steam generator tube-to-tubesheet welds in order to establish a technical basis for either determining that the tubesheet cladding and welds are not susceptible to PWSCC, or redefining the pressure boundary in which the tube-to-tubesheet weld is no longer included and, therefore, is not required for reactor coolant pressure boundary function. The redefinition of the reactor coolant pressure boundary must be approved by the NRC as a license amendment request.

Option 2 (Inspection)

I I PEC will perform a one-time inspection of a representative number of tube-to-tubesheet welds in each steam generator to determine if PWSCC cracking is present. If weld cracking is identified:

a. The condition will be resolved through repair or engineering evaluation to justify continued service, as appropriate, and

b. An ongoing monitoring program will be established to perform routine tube-to-tubesheet weld inspections for the remaining life of the steam aenerators.

IMPLEMENTATION SCHEDULE IP2: Complete IP3: Complete IP2:

Not Applicable IP3: Not Applicable NL-17-060 Page 19 of 22 SOURCE RELATED LRA SECTION I AUDIT ITEM NL-11-032 N/A NL-11-074 NL-11-090 NL-11-096 NL-17-005 I

COMMITMENT 43 IPEC will review design basis ASME Code Class 1 fatigue evaluations to determine whether the NUREG/CR-6260 locations that have been evaluated for the effects of the reactor coolant environment on fatigue usage are the limiting locations for the IP2 and IP3 configurations. If more limiting locations are identified, the most limiting location will be evaluated for the effects of the reactor coolant environment on fatigue usage.

IPEC will use the NUREG/CR-6909 methodology in the evaluation of the limiting locations consisting of nickel allov, if anv.

44 I PEC will include written explanation and justification of any user intervention in future evaluations using the WESTEMS "Design CUF" module.

/',

45 IPEC will not use the NB-3600 option of the WESTEMS program in future design calculations until the issues identified during the NRC review of the program have been resolved.

46 Include in the IP2 ISi Program that IPEC will perform twenty-five volumetric weld metal inspections of socket welds during each 10-year ISi interval scheduled as specified by IWB-2412 of the ASME Section XI Code during the period of extended operation.

In lieu of volumetric examinations, destructive examinations may be performed, where one

\\

destructive examination may be substituted for two volumetric examinations.

47 Deleted.

IMPLEMENTATION SCHEDULE IP2: Complete IP3: Complete IP2: Complete IP3: Complete IP2:Complete IP3: Complete IP2: Complete NL-17-060 Page 20 of 22 SOURCE RELATED LRA SECTION I AUDIT ITEM NL-11-032 4.3.3 NL-13-122 NL-11-101 NL-15-121 NL-11-032 N/A NL-11-101 NL-13-122 NL-15-121 NL-11-032 N/A NL-11-101 NL-13-122 NL-15-121 NL-11-032 N/A NL-11-074 NL-13-122 NL-14-093 N/A

COMMITMENT 48 Entergy will visually inspect IPEC underground piping within the scope of license renewal and subject to aging management review prior to the period of extended operation and then on a frequency of at least once every two years during the period of extended operation. This inspection frequency will be maintained unless the piping is subsequently coated in accordance with the preventive actions specified in NUREG-1801 Section Xl.M41 as modified by LR-ISG-2011-03. Visual inspections will be supplemented with surface or volumetric non-destructive testing if indications of significant loss of material are observed. Consistent with revised NUREG-1801 Section Xl.M41, such adverse indications will be entered into the plant corrective action program for evaluation of extent of condition and for determination of appropriate corrective actions (e.g., increased inspection frequency, repair, replacement).

49 Recalculate each of the limiting CUFs provided in section 4.3 of the LRA for the reactor vessel internals to include the reactor coolant environment effects (Fen) as provided in the IPEC Fatigue Monitoring Program using NUREG/CR-5704 or NUREG/CR-6909. In accordance with the corrective actions specified in the Fatigue Monitoring Program, corrective actions include further CUF re-analysis, and/or repair or replacement of the affected components prior to the CUFen reaching 1.0.

~

50 Replace the IP2 split pins during the 2016 refueling outage (2R22).

51 Enhance the Service Water Integrity Program by implementing LRA Sections A.2.1.33, A.3.1.33 and B.1.34, as shown in NL-14-147.

Implement LRA Sections A.2.1.33, A.3.1.33 and B.1.34, as shown in NL-17-052 IMPLEMENTATION SCHEDULE IP2: Complete IP3: Complete IP2: Complete IP3: Complete IP2: Complete IP3: N/A IP2 & IP3:

December 31, 2017 IP2 & IP3:

December 31, 2017 NL-17-060 Page 21 of 22 SOURCE RELATED LRA SECTION I AUDIT ITEM NL-12-174 N/A NL-13-122 NL-15-121 NL-13-052 A.2.2.2 A.3.2.2 NL-13-122 NL-15-121 NL-13-122 A.2.1.41 B.1.42 NL-14-067 NL-14-147 A.2.1.33 A.3.1.33 B.1.34 NL-17-052 A.2.1.33 A.3.1.33 B.1.34

COMMITMENT 52 Implement the Coating Integrity Program for IP2 and IP3 as described in LRA Section B.1.42, as shown in NL-15-019.

53 Revise Bolting Integrity Program to include visual inspection of a representative sample of closure bolting (bolt heads, nuts, and threads) from components with an internal environment of a clear gas, such as air or nitrogen. A representative sample will be 20 percent of the population (for each bolting material and environment combination) up to a maximum of 25 fasteners during each 10-year period of the period of extended operation. The inspections will be performed when the bolting is removed to the extent that the bolting threads and bolt heads are accessible for inspections that cannot be performed during visual inspection with the threaded fastener installed.

54 Enhance the Steam Generator Integrity Program as follows.

Revise a1212licable 12rocedures to s12ecify a general visual ins12ection of the steam generator channel head.

IMPLEMENTATION SCHEDULE IP2 & IP3:

December 31, 2024 May 31, 2018 December 31 2017 NL-17-060

• Attachment 3 Page 22 of 22 SOURCE RELATED LRA SECTION I AUDIT ITEM NL-15-019 A.2.1.42 A.3.1.42 B.1.43 NL-17-053 A.2.1.2 A.3.1.2 B.1.2 NL-17-060 A.2.1.34 A.3.1.34 B.1.35

)

(

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