NL-17-161, Supplemental Information Regarding the Service Water Integrity Aging Management Program for the Review of the Indian Point Nuclear Generating Units 2 and 3 License Renewal Application (LRA) (CAC Nos. MD5407 and MD5408)

Supplemental Information Regarding the Service Water Integrity Aging Management Program for the Review of the Indian Point Nuclear Generating Units 2 and 3 License Renewal Application (LRA) (CAC Nos. MD5407 and MD5408)

ML17363A213
Person / Time
Site:	Indian Point
Issue date:	12/21/2017
From:	Vitale A Entergy Nuclear Northeast
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
CAC MD5407, CAC MD5408, NL-17-161
Download: ML17363A213 (37)

Text

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• • ~Entergx Entergy Nuclear Northeast lndiari Point Energy Center 450 Broadway, GSB P.O. Box 249 Buchanan, NY 10511-0249 Tel (914) 254-6700 Anthony J Vitale Site Vice President NL-17-161 December 21, 2017 U.S. Nuclear Regulatory Commission Document Control Desk 11545 Rockville Pike, TWFN-2 F1 Rockville, MD 20852-2738

SUBJECT:

Supplemental Information Regarding the Service Water Integrity Aging Management Program for the Review of the Indian Point Nuclear Generating Unit Nos. 2 and 3 License Renewal Application (LRA) (CAC Nos. MD5407 and MD5408)

Docket Nos. 50-247 and 50-286 Licenses Nos. DPR-26 and DPR-64)

REFERENCES:

1) Entergy Letter, "Supplemental Information Regarding the Service Water Integrity Aging Management Program for the Review of the Indian Point Nuclear Generating Unit Nos. 2 and 3 License Renewal Application (LRA)

(CAC Nos. MD5407 and MD5408)," dated November 8, 2017 (NL-17-127)

2) USNRC Letter, "Service Water Integrity Aging Management Program Audit Report for the Indian Point Nuclear Generating Unit Nos. 2 and 3, License Renewal Application (CAC Nos. MD5407 and MD5408)," dated September 20, 2017 (ML17250A244)

3) USN RC Letter, "Summary of Telephone Conference Call Held on September 6, 2017, Between the U.S. Nuclear Regulatory Commission and Entergy Nuclear Operations, Inc. Concerning Next Actions from the Site Audit Held from August 1-3, 2017, Pertaining to the Indian Point, License Renewal Application (TAC. NOS. MD5407/MD5408)," dated September 25, 2017 (ML17256A286)

4) Entergy Letter, "Reply to Request for Additional Information for the Review of the Indian Point Nuclear Generating Unit Nos. 2 and 3, License Renewal Application, SET 2017-01(CAC Nos. MD5407 and MD5408),"

dated May 8, 2017 (NL-17-052) (ML17132A175)

5) Entergy Letter, "Amendment to License Renewal Application - Reflecting Shortened License Renewal Terms for Units 2 and 3," dated February 8, 2017 (NL-17-019) (ML17044A005)

6) Entergy Letter, "Re-Submittal of Supplemental Information Regarding the

. Service Water Integrity Aging Management Program for the Review of the Indian Point Nuclear Generating Unit Nos. 2 and 3 License Renewal Application (LRA) (CAC Nos. MD5407 and MD5408)," dated December 14, 2017 (NL-17-155)

NL-17-161 Docket Nos. 50-247 and 50-286 Page 2 of 3

Dear Sir or Madam:

From August 1 - 3, 2017, the U.S. Nuclear Regulatory Commission (NRC) staff conducted a supplemental, on-site regulatory audit to gain a better understanding of Entergy Nuclear Operations, lnc.'s (Entergy) response to the request for additional information (RAI), submitted by letter dated May 8, 2017 and new plant-specific operating experience related to the Service Water Integrity Aging Management Program. Following the completion of the audit, the NRC staff issued an audit report, which identified several areas where the aging management activities for the Service Water System warrant additional clarification or further information.

By letter dated November 8, 2017 (Reference 1), Entergy provided supplemental information regarding the Service Water Integrity Aging Management Program in response to the August 1

- 3, 2017 on-site regulatory audit. On November 30, 2017, a conference call was held between the NRC and Entergy to clarify Entergy's responses for Audit Items 3 and 6 as discussed in Reference 1. By letter dated December 14, 2017 (Reference 6), Entergy provided additional information to clarify specific areas in the Entergy response to the audit report. Reference 6 revised our previous responses to Audit Items 3 and 6, replacing Reference 1 in its entirety.

On December 19, 2017, Entergy personnel participated in a conference call with members of the NRC staff to discuss the need Jor additional clarification of the Entergy response to the report of the August 2017 service water audit. As a result of the conference call, Entergy is providing additional clarification to the response to audit items 2 and 3. The additional information is shown in Attachment 1 as revisions to the affected portions of Reference 6.

Changes to the LRA sections resulting from the information provided in Attachment 1 are provided in Attachment 2. Changes to the List of Regulatory Commitments are provided in .

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

I declare under penalty of perjury that the foregoing is true and correct. E.xecuted on I Z- 2..\ - r-:t- , 2011.

AJV/mm

- --

NL-17-161 Docket Nos. 50-247 and 50-286 Page 3 of 3 Attachments: 1. Supplemental Information Regarding the License Renewal Application Service Water Integrity Program

2. License Renewal Application Changes As a Result of Supplemental Information

3. License Renewal Application IPEC List of Regulatory Commitments Revision 37 cc: Mr. David C. Lew, Acting Regional Administrator, NRC Region I Mr. William Burton, Senior Project Manager, NRC DLR Mr. Richard V. Guzman, Senior Project Manager, NRC NRR DORL Ms. Bridget Frymire, New York State Department of Public Service Ms. Alicia Barton, President and CEO NYSERDA NRC Resident Inspector's Office

r ATTACHMENT 1 to NL-17-161 SUPPLEMENTAL INFORMATION REGARDING THE LICENSE RENEWAL APPLICATION SERVICE WATER INTEGRITY PROGRAM ENTERGY NUCLEAR OPERATIONS, INC.

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

NL-17-161 Docket Nos. 50-247 and 50-286 Attachment 1 Page 1 of 5 NRC AUDIT REPORT ITEM 2 Installation of External Carbon Fiber Repair on Service Water Pipe Weld PAB-204. The staff reviewed engineering change (EC) 61654 and noted that the repair of the non-safety-related pipe was "designed to act as the original piping should the weld fail and structural integrity compromised." The EC specified that the installation include: (a) seven layers of wrap, (b) a 6 inch overlap, and (c) a minimum total wrap length of 6 feet upstream and downstream of the weld. The staff reviewed WO 00404774-01 and noted that, except for the specified overlap at the elbow, all installation parameters were met. For the overlap at the elbow, the staff reviewed ECN 72788 for allowing the field to fit up the carbon fiber wrap with additional layers to compensate for the inability to uniformly obtain a 6 inch overlap.

Because the credited piping material changed from carbon steel to a nonmetallic composite, Entergy may need to address different aging effects with different inspection requirements. In addition Entergy may need alternate inspection techniques, because the inability to detect leakage through th~ composite material may not allow the detection of ongoing internal corrosion at locations where structural integrity is needed at the carbon steel-to-nonmetallic composite interface. To address the issues introduced by this repair, the staff needs additional information regarding: a) the aging effects that need to be managed for the nonmetallic composite material (with associated aging management program, if applicable) and b) confirmation that degradation of cement-lined service water piping has not occurred at locations other than at welds (e.g. mid-span between welds) such that alternate inspection requirements would be needed to confirm the structural integrity near the carbon steel to nonmetallic composite interface locations.

RESPONSE

A section of IP3 24-inch diameter service water return piping, including an elbow, was overlaid with carbon fiber-reinforced epoxy at elevation 41 feet in the primary auxiliary building due to

• corrosion adjacent to the downstream elbow to pipe weld. The carbon fiber-reinforced epoxy overlay provides strength and design characteristics equivalent to the original piping. The piping was prepared prior to application to ensure that the carbon fiber-reinforced epoxy material properly adheres to the pipe.

Aging effects that could occur for the carbon fiber-reinforced epoxy were evaluated.

The carbon fiber-reinforced epoxy material is a bidirectional carbon fiber fabric saturated with epoxy resin. Because the internal surface of the carbon fiber-reinforced epoxy coating is tightly adhered to the carbon steel surface of the piping, no aging effects requiring management could occur without a through-wall leak in the underlying carbon steel piping. The minimum wall thickness of the piping was 0.121 inches in January, 2015, after approximately 40 years of operation. This corresponds to a corrosion rate of approximately 0.006 inches per year. At IP3, the assumed service water piping corrosion rate is 0.012 inches per year. Using a corrosion rate of just less than 0.012 inches per year instead of the calculated corrosion rate, localized corrosion would not be through-wall by April 30, 2025. As discussed in Reference 5, Entergy has filed an amendment to the IPEC License Renewal Application (LRA) changing the end date of the proposed term of the renewed license for IP3 to April 30, 2025. Based on this, the internal surface of the carbon fiber-reinforced epoxy is not expected to be in contact with raw water prior

, NL-17-161 Docket Nos. 50-247 and 50-286 Attachment 1 Page 2 of 5 to the end of the renewed license term. Entergy will perform a volumetric examination at the location identified with the minimum wall thickness in 2016 to confirm that the carbon steel piping is not degrading at a rate that will result in exposure of the internal surface of the carbon fiber-reinforced epoxy to raw water prior to the end of the renewed license term. The volumetric examination will be performed prior to 12/31/21. Therefore, a line item with an internal environment for the carbon fiber-reinforced epoxy is not necessary in revised LRA Table 3.3.2-2-IP3.

The external surface of the carbon fiber-reinforced epoxy is exposed to a cool indoor air environment with low light exposure, conditions that minimize the potential for aging effects due to temperature or ultraviolet light. In addition, the raw discharge water (service water) flowing through the piping is heated from the numerous loads that it cools, thereby reducing the potential for condensation. Although aging effects would be minimized due to these operating conditions, operating experience relative to long-term aging effects of carbon fiber-reinforced epoxy installations at nuclear plants is limited. As a result, aging effects will conservatively be identified for the carbon fiber-reinforced epoxy. Since the carbon fiber-reinforced epoxy entails fibrous material similar to fiberglass and both utilize epoxy, aging effects applicable to fiberglass are deemed potential aging effects. Cracking, blistering, and loss of material are conservatively identified as aging effects for the carbon fiber-reinforced epoxy external surface. Visual inspection performed in accordance with the Periodic Surveillance and Preventive Maintenance Program will manage these aging effects.

Entergy reviewed relevant OE of the service water system for the period of 2004-2016 and did not find relevant examples of leakage of the concrete lined piping at locations "mid-span" of the carbon steel welds. Therefore, no alternate inspection requirements are needed to confirm structural integrity near the carbon steel to nonmetallic composite interface locations.

I The LRA is revised as shown in Attachment 2 with additions underlined and deletions lined through.

',

• NL-17-161 Docket Nos. 50-247 and 50-286 Attachment 1 Page 3 of 5 NRC AUDIT REPORT ITEM 3 Use of 6 Percent Molybdenum Stainless Steel (AL-6XN).

LER 247/2013-004 addresses pitting corrosion of 300 series stainless steel service water piping that was replaced with 6 percent molybdenum stainless steel (AL-6XN). Based on industry operating experience, the staff noted that, because AL-6XN has a more positive corrosion potential than 300 series stainless steels, the introduction.of AL-6XN can increase the susceptibility of carbon steel to galvanic corrosion. During a breakout session, the applicant noted that the service water system contains dissimilar-metal flanged joints between carbon steel and AL-6XN, as well as 300 series stainless steel. Consequently, the staff questioned whether AL-6XN flanged components should be considered as a unique population within the Service Water Integrity program. During discussions, the plant staff stated that AL-6XN is sufficiently similar to 300 series stainless steels that components made from AL-6XN do not need to be considered as unique populations; however, the plant staff noted that the similarity is based on whether the surfaces of the stainless steel components have been passivated and the grade of 300 series stainless steel.

• During its subsequent review of the Service Water Piping Specification (9321-01-248 35), the staff noted that the applicant-had previously removed the requirement for the use of insulating kits on dissimilar-metal flanged joints. Because the absence of insulating kits increases the susceptibility of carbon steel to loss of material due to galvanic corrosion, it was not clear to the staff that the condition or absence of insulating kits on dissimilar-metal flanged joints could be disregarded. In order address the issues introduced by these changes, the staff needs additional information to determine whether current inspection of dissimilar-metal flanged connections can be credited by the Service Water Integrity program and whether AL-6XN needs to be considered as a1unique population for these activities. The information needed by the staff includes: a) the difference in the corrosion potential of the stainless steel alloy(s) used in the service water system and the corrosion potential of AL-6XN, b) the environment in the vicinity of the 300 series stainless steel/carbon steel and AL-6XN/carbon steel joints, c) the coatings in the vicinity of the 300 series stainless steel/carbon steel and AL-6XN/carbon steel joints, and d) whether current inspections account for greater susceptibility to galvanic corrosion when insulating kits are not used.

RESPONSE

An overall response is provided below, after the NRC's specific questions a) through d) are addressed.

• Item a) the difference in the corrosion potential of the stainless steel alloy(s) used in the service water system and the corrosion potential of AL-6XN.

Response a):

\

AL-6XN tested in seawater has a O volts assignment. 1 The 300-series stainless steels voltage is approximately 0.0 to -0.13 volts. 2 1

AL-6XN ATI Technical brochure

NL-17-161 Docket Nos. 50-247 and 50-286 Attachment 1 Page 4 of 5' Item b) the environments in the vicinity of the 300 series stainless steel/carbon steel and AL-6XN/carbon steel joints.

Response b):

As delineated in the LRA, the Service Water System has the following environments:

• Raw water (internal and external)

• Condensation (external)

• Treated water (internal and external)

• Air - indoor (internal and external)

• Air - outdoor (external)

• Soil (external)

The majority of the joints between carbon steel and AL-6XN or between carbon steel and stainless steel have an internal environment of raw water and an external environment of air or condensation.

Item c) the coatings in the vicinity of the 300 series stainless steel/carbon steel and AL-6XN/carbon steel joints.

Response c):

Generally, carbon steel piping 2" or greater in diameter is internally coated with cement.

Cement lining repairs are made using internal coatings such as Waterplug, Enecon, or Belzona. The 300-series stainless steel grades, AL-6XN, and Avesta 254 SMO are not internally coated. 3 The faces of some 300-series stainless steel and carbon steel flanges may be coated, in whole or in part, with Enecon and/or Belzona products for corrosion repair and/or prevention purposes.

Item d) Whether current inspections account for greater susceptibility to galvanic corrosion when insulating kits are not used.

Response d):

Past Service Water Integrity Program inspections have not accounted for greater susceptibility to galvanic corrosion when insulating kits are not installed. The program focuses on the inspection of piping and pipe welds, which include dissimilar metal flange carbon steel butt welds.

2 DBI Galvanic Table 3

IP3 Specification, "Specification For Service Water Piping and Piping Components," TS-MS-027, Revision 5, dated April 25, 2017 and IP2 Specification, "Specification For Service Water Piping,"

9321-01-248, Revision 8, dated December 2, 2013

NL-17-161 Docket Nos. 50-247 and 50-286 Attachment 1 Page 5 of 5 Overall

Conclusion:

Entergy staff previously determined that insulating kits were not necessary and subsequently revised design specifications for IP2 and IP3 to remove the requirement for insulating kits. Therefore, the Service Water System contains dissimilar metal flanged joints both with and without insulating kits.

In addition to 6 percent molybdenum AL-6XN, another alloy, Avesta 254 SMO is used at IPEC. Although AL-6XN and Avesta 254 SMO have slightly different chemical compositions, they are considered equivalent materials. As an example, AL-6XN contains approximately 6 to 7 percent molybdenum, while Avesta 254 SMO contains 6 to 6.5 percent molybdenum.

• The galvanic potential of AL-6XN is similar to the galvanic potential of 300-series stainless steels. Avesta 254 SMO has a material composition similar to AL-6XN and is expected to have a similar galvanic potential. Because of the similar galvanic potentials, galvanic corrosion rates are also expected to be similar when these materials are in contact with carbon steel. Therefore, Entergy will perform inspections for indications of galvanic corrosion from a combined population of joints where carbon steel is connecte'd to AL-6XN or Avesta 254 SMO or 300-series stainless steel.

In order to ensure that loss of material due to galvanic corrosion is not affecting the ability of the Service Water System to perform its intended function, the following enhancement will be implemented.

Revise the Service Water Integrity Program procedures to perform internal and external visual inspections where feasible of flanged connections (including flange faces, bolting, and welds) where carbon steel is in contact with AL-6XN, Avesta 254 SMO, or 300-series stainless steel. The inspection population will be limited to dissimilar metal joints without galvanic insulating kits. Inspections will focus on the bounding or lead components most susceptible to galvanic corrosion based on time in service and severity of operating conditions. Inspections will monitor for evidence of loss of material due to galvanic corrosion on a representative sample consisting of 20 percent of the population up to a maximum of 25 inspections during each 10-year period of the period of extended operation. Visual inspection results that identify appreciable localized corrosion (e.g., pitting) beyond a normal oxide layer will be entered into the corrective action program and a follow-up volumetric wall thickness examination If significant loss of material is identified by the visual inspections, additional volumetric NOE will be performed to characterize the extent of the degradation.

The LRA is revised as shown in Attachment 2 with additions underlined and deletions lined through.

ATTACHMENT 2 to NL-17-161 LICENSE RENEWAL APPLICATION. CHANGES AS A RESULT OF SUPPLEMENTAL INFORMATION Deletions are shown with strike-through and additions are underlined.

ENTERGY NUCLEAR OPERATIONS, INC.

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

NL-17-161 Docket Nos. 50-247 and 50-286

./

Attachment 2 Page 1 of 4 A.2.1.33Service Water Integrity Program The Service Water Integrity Program is an existing program that relies on implementation of the recommendations of GL 89-13 to ensure that the effects of aging on the service water system are managed through the period of extended operation. The program includes component inspections for erosion, corrosion, and biofouling to verify the heat transfer capability of safety-related heat exchangers cooled by service water and monitoring of the silt levels in the intake bays. Chemical treatment using biocides and sodium hypochlorite and periodic cleaning and flushing of infrequently used loops are methods used to control fouling within the heat exchangers and to manage loss of material in service water components. Scheduling of nonsafety-related piping examinations is determined by trending of examination results. Selection of large bore service water pipe points for volumetric inspection is based on piping configuration, results from previous inspections, consideration of follow-ups to previous repairs, and condition assessments when components are opened during preventive maintenance activities. Scope expansion for indications found by program inspections of nonsafety-related piping is based on engineering analysis, judgment and program experience. The factors that are considered include piping location, severity of use, piping materials, previous inspection results, and repair history.

The Service Water Integrity Program will be enhanced to include the following.

• Revise Service Water Integrity Program procedures to perform internal visual inspections of flanged connections where carbon steel is in contact with AL-6XN, Avesta 254 SMO, or 300-series stainless steel. The inspection population will be dissimilar metal joints without galvanic insulating kits. Inspections will focus on the bounding or lead components most susceptible to galvanic corrosion based on time in service and severity of operating conditions. Inspections will monitor for evidence of loss of material due to galvanic corrosion on a representative sample consisting of 20 percent of the population, up to a maximum of 25 inspections, during each 10-year period of the period of extended operation. Visual inspection results that identify appreciable localized corrosion (e.g., pitting) beyond a normal oxide layer will be entered into the corrective action program and a follow-up volumetric wall thickness examination If significant loss of material is identified by the visual inspections, additional volumetric NOE will be performed to characterize the extent of the degradation.

A.3.1.33 Service Water Integrity Program The Service Water Integrity Program is an existing program that relies on implementation of the recommendations of GL 89-13 to ensure that the effects of aging on the service water system are managed through the period of extended operation. The program includes component inspections for erosion, corrosion, and biofouling to verify the heat transfer capability of safety-related heat exchangers cooled by service water and monitoring of the silt levels in the intake bays. Chemical treatment using 1 biocides and chlorine and periodic cleaning and flushing of infrequently used loops are methods used to control fouling within the heat exchangers and to manage loss of. material in service water components. Scheduling of nonsafety-related piping examinations is determined by trending of examination results. Selection of large bore service water pipe points for volumetric inspection is based

NL-17-161 Docket Nos. 50-247 and 50-286 Attachment. 2 Page 2 of 4 on piping configuration, results from previous inspections, consideration of follow-ups to previous repairs, and condition assessments when components are opened during preventive maintenance activities. Scope expansion for indications found by program inspections of nonsafety-related piping is based *on engineering analysis, judgment and program experience. The factors that are considered include piping location, severity of use, piping materials, previous inspection results, and repair history.

The Service Water Integrity Program will be enhanced to include the following.

• Revise Service Water Integrity Program procedures to perform internal visual inspections of flanged connections where carbon steel is in contact with AL-6XN, Avesta 254 SMO, or 300-series stainless steel. The inspection population will be dissimilar metal joints without galvanic insulating kits. Inspections will focus on the bounding or lead components most susceptible to galvanic corrosion based on time in service and severity of operating conditions. Inspections will monitor for evidence of loss of material due to galvanic corrosion on a representative sample consisting of 20 percent of the population up to a maximum of 25 inspections during each 10-year period of the period of extended operation. Visual inspection results that identify appreciable localized corrosion (e.g., pitting) beyond a normal oxide layer will be entered into the corrective action program and a follow-up volumetric wall thickness examination If signifisant loss of material is identified by the visual inspestions, additional volumetris NOE will be performed to characterize the extent of the degradation.

B.1.29 PERIODIC SURVEILLANCE AND PREVENTIVE MAINTENANCE Program Description The Periodic Surveillance and Preventive Maintenance Program is an existing program that includes periodic inspections and tests that manage aging effects not managed by other aging management programs. In addition to specific activities in the plant's preventive maintenance program and surveillance program, thePeriodic Surveillance and Preventive Maintenance Program includes enhancements to add new activities. The preventive maintenance and surveillance testing activities are generally implemented through repetitive tasks or routine monitoring of plant operations. Credit for program activities has been taken in the aging management review of the following systems and structures. All activities are new unless otherwise noted.

Service water system Visually inspect the surface of the carbon fiber-reinforced epoxy overlay on line 405 in the Unit 3 primary auxiliary building to manage cracking, blistering, and loss of material.

The inspection will be performed each operating cycle.

Revise program documents to specify a one-time volumetric examination on line 405 at the location identified with the minimum wall thickness in 2016 to confirm that the carbon

NL-17-161 Docket Nos. 50-247 and 50-286 Attachment 2 Page 3 of 4 steel piping is not degrading at a rate that will result in exposure of the internal surface of the carbon fiber-reinforced epoxy to raw water prior to the end of the renewed license term. The volumetric examination will be performed prior to December 31, 2021.

The following enhancements will be implemented prior to December 31, 2018.

Attributes Affected. Enhancements

1. Scope of Program Program activity guidance documents will

3. Parameters Monitored or be developed or revised as necessary to Inspected assure that the effects of aging will be managed such that applicable components

4. Detection of Aging Effects will continue to perform their intended

6. Acceptance Criteria functions consistent with the current licensing basis through the period of extended operation.

B.1.34 Service Water Integrity Program Description The Service Water Integrity Program is an existing program that relies on implementation of the recommendations of GL 89-13 to ensure that the effects of aging on the service water system are managed through the period of extended operation. The program includes component inspections for erosion, corrosion, and biofouling to verify the heat transfer capability of safety-related heat exchangers cooled by service water and monitoring of the silt levels in the intake bays. Chemical treatment using biocides and sodium hypochforite and periodic cleaning and flushing of infrequently used loops are methods used to control fouling within the heat exchangers and to manage loss of material in service water components. Prioritization of internal examinations of SW piping is based on safety classification. Scheduling of nonsafety-related piping examination is determined by trending of examination results. Selection of large bore service water pipe points for volumetric inspection is based on piping configuration, results from previous inspections, consideration of follow-ups to previous repairs, and condition assessments when components are opened during preventive maintenance activities. Scope expansion for indications found by program inspections of nonsafety-related piping is based on engineering analysis, judgment and program experience. The factors that are considered include piping location, severity of use, piping materials, previous inspection results, and repair history.

NL-17-161 Docket Nos. 50-247 and 50-286 Attachment 2 Page 4 of 4 NUREG-1so1 consistency The Service Water Integrity Program is consistent with the program described in NUREG-1801,Section XI.M20, Open-Cycle Cooling Water System.

Exceptions to NUREG-1 so1 None Enhancements The following enhancements will be implemented prior to December 31, 2018.

Attributes Affected Enhancements

4. Detection of Aging Effects

• Revise the Service Water Integrity Program procedures to perform internal visual inspections of flanged connections where carbon steel is in contact with AL-6XN, Avesta 254 SMO, or 300-series C

stainless steel. The inspection population will be dissimilar metal joints without galvanic insulating kits.

Inspections will focus on the bounding or lead components most susceptible to galvanic corrosion based on time in service and severity of operating conditions. Inspections will monitor for evidence of loss of material due to galvanic corrosion on a representative sample consisting of 20 percent of the population, up to a maximum of 25 inspections, during each 10-year period of the period of extended operation. Visual ins12ection results that identify a1212reciable localized corrosion (e.g., Qitting) beyond a normal oxide layer will be entered into the corrective action Qrogram and a follow-LIQ volumetric wall thickness examination If significant loss of material is identified by the visual inspections, additional volumetric NOE will be performed to characterize the extent of the degradation.

ATTACHMENT 3 to NL-17-161 LICENSE RENEWAL APPLICATION IPEC LIST OF REGULATORY COMMITMENTS Rev.37 ENTERGY NUCLEAR OPERATIONS, INC.

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

NL-17-161 Docket Nos. 50-247 and 50-286 Attachment 3 Page 1 of 22 List of Regulatory Commitments Rev. 37

• The following table identifies those actions committed to by Entergy in this document.

Changes are shown as strike-through for deletions and underlines for additions.

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION/

AUDIT ITEM IP2: Complete NL-07-039 A.2.1.1 1 Enhance the Aboveground Steel Tanks Program for A.3.1.1 IP2 and IP3 to perform thickness measurements of NL-13-122 8.1.1 the bottom surfaces of 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.

IP2 & IP3: NL-14-147 A.2.1.1 Implement LRA Sections, A.2.1.1, A.3.1.1 and 8.1.1, December 31, 2019 A.3.1.1 as shown in NL-14-147.

~ I 8.1.1 IP2 & IP3: NL-15-092 A.2.1.1 Implement LRA Sections, A.2.1.1 and 8.1.1, as December 31, 2019 8.1.1 shown in NL-15-092 IP2: Complete NL-07-039 A.2.1.2 2 Enhance the Bolting Integrity Program for IP2 and r A.3.1.2 IP3 to clarify that actual yield strength is used in IP3: Complete 8.1.2 selecting materials for low susceptibility to sec and 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.

NL-17-161 Docket Nos. 50-24 7 and 50-286 Attachment 3 Page 2 of 22

1. COMMITMENT, IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION/

AUDIT ITEM IP2: Complete NL-07-039 A.2.1.5 3 Implement the Buried Piping and Tanks Inspection A.3.1.5 Program for IP2 and IP3 as described in LRA IP3: Complete NL-*13-122 B.1.6 Section B.1 :6.

NL-07-153 Audit Item This new program will be implemented consistent NL-15-121 173 with the corresponding program described in NUREG-1801 Section XI.M34, Buried Piping and Tanks Inspection.

Include in the Buried Piping and Tanks Inspection NL-09-106 Program described in LRA Section B.1.6 a risk assessment of in-scope buried piping and tanks that NL-09-111 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. NL-11-101 4 IP2: Complete NL-07-039 A.2.1.8 Enhance the Diesel Fuel Monitoring Program to A.3.1.8 include cleaning and inspection of the IP2 GT-1 gas IP3: Complete NL-13-122 B.1.9 turbine fuel oil storage tanks, IP2 and IP3 EOG fuel NL-07-153 Audit items oil day tanks, IP2 SBC/Appendix R diesel generator NL-15-121 128, 129, fuel oil day tank, and IP3 Appendix R fuel oil storage tank and day tank once every ten years. 132, NL-08-057 491,492, Enhance the Diesel Fuel Monitoring Program to 510 include quarterly sampling and analysis of the IP2 SBC/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 1Omg/1. Water and sediment acceptance criterion will be less than or equal to 0.05%.

NL-17-161 Docket Nos. 50-247 and 50-286 Attachment 3 Page 3 of 22

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION/

AUDIT ITEM 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 storage 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 biological activity is confirmed.

5 IP2: Complete NL-07-039 A.2.1.10 Enhance the External Surfaces Monitoring Program for IP2 and IP3 to include periodic inspections of A.3.1.10 systems in scope and subject to aging management NL-13-122 B.1.11 review for license renewal in accordance with 1O

• CFR 54.4(a)(1) and (a)(3). Inspections shall includ~

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).

NL-17-161 Docket Nos. 50-247 and 50-286 Attachment 3 Page 4 of 22

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION/

AUDIT ITEM IP2 & IP3: NL-14-147 A.2.1.10 Implement LRA Sections A.2.1.10, A.3.1.10 and December 31, 2019 A.3.1.10 8.1.11, as shown in NL-14-147.

8.1.11 IP2: Complete NL-07-039 A.2.1.11 6 Enhance the Fatigue Monitoring Program for IP2 to A.3.1.11 monitor steady state cycles and feedwater cycles or NL-13-122 8.1.12, perform an evaluation to determine monitoring is not NL-07-153 Audit Item required. Review the number of allowed events and 164 resolve discrepancies between reference documents IP3: Complete NL-15-121 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.

IP2: Complete NL-07-039 A.2.1.12 7 Enhance the Fire Protection Program to inspect A.3.1.12 external surfaces of the IP3 RCP oil collection IP3: Complete NL-13-122 8.1.13 systems for loss of material each refueling cycle.

Enhance the Fire Protection Program to explicitly NL-15-121 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 EDG room CO 2 fire.

suppression system for signs of degradation, such as corrosion and mechanical damage at least once every six months.

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1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION/

AUDIT ITEM IP2: Complete NL-07-039 A.2.1.13 8 Enhance the Fire Water Program to include A.3.1.13 inspection of IP2 and IP3 hose reels for evidence of NL-13-122 B.1.14 corrosion. Acceptance criteria will be revised to NL-07-153 Audit Items verify no unacceptable signs of degradation.

105,106 Enhance the Fire Water Program to replace all or NL-08-014 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 sionificant corrosion.

IP2 & IP3: NL-14-147 A.2.1.13 Implement LRA Sections, A.2.1.13, A.3.1.13 and December 31, 2019 A.3.1.13 B.1.14, as shown in NL-14-147.

B.1.14 IP2 & IP3: NL-15-019 A.2.1.13 Implement LRA Sections A.2.1.13, A.3.1.13 and December 31, 2019, A.3.1.13 B.1.14, as shown in NL-15-019 B.1.14 IP2 & IP3: NL-15-092 A.2.1.13 Implement LRA Sections A.2.1.13, A.3.1.13 and December 31, 2019 A.3.1.13 B.1.14, as shown in NL-15-092 B.1.14

NL-17-161 Docket Nos. 50-247 and 50-286 Attachment 3 Page 6 of 22

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AUDIT ITEM IP2 & IP3: NL-16-122 A.2.1.13 Implement LRA Sections A.2.1.13, A.3.1.13 and December 31, 2017 A.3.1.13 B.1.14, as shown in NL-16-1224 B.1.14 IP2 & IP3: NL-17-052 A.2.1.13 Implement LRA Sections A.2.1.13, A.3.1.13, and December 31, 2017 A.3.1.13 B.1.14, as shown in NL-17-052 B.1.14 IP2: Complete NL-07-039 A.2.1.15 9 Enhance the Flux Thimble Tube Inspection Program A.3.1.15 for IP2 and IP3 to implement comparisons to wear IP3: Complete NL-13-122 B.1.16 rates identified in WCAP-12866. Include provisions NL-15-121 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 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.

4 This commitment erroneously deleted in NL-17-052

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AUDIT ITEM IP2: Complete NL-07-039 A.2.1.16 10 Enhance the Heat Exchanger Monitoring Program .

A.3.1.16 for IP2 and IP3 to include the following heat IP3: Complete NL-13-122 B.1.17, exchangers in the scope of the program.

NL-07-153 Audit Item

• Safety injection pump lube oil heat NL-15-121 52 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

• SBO/Appendix R diesel jacket water heat exchanger (I P2 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 heat 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 NL-09-018 include no indication of tube erosion, vibration wear, corrosion, pitting, fouling, or scaling.

11 NL-09-056 Deleted NL-11-101 12 IP2: Complete NL-07-039 A.2.1.18 Enhance the Masonry Wall Program for IP2 and IP3 A.3.1.18 to specify that the IP1 intake structure is included in IP3: Complete NL-13-122 B.1.19 the oroaram.

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AUDIT ITEM IP2: Complete NL-07-039 A.2.1.19 13 Enhance the Metal-Enclosed Bus Inspection A.3.1.19 Program for IP2 and IP3 to visually inspect the IP3: Complete NL-13-122 B.1.20 external surface of MEB enclosure assemblies for NL-07-153 Audit Items loss of material at least once every 10 years. The NL-15-121 124, first inspection will occur prior to the period of NL-08-057 133,519 extended operation and the acceptance criterion will be no significant loss of material.

' NL-13-077 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 IP2: Complete NL-07-039 A.2.1.21 Implement the Non-EQ Bolted Cable Connections Program for IP2 and IP3 as described in LRA A.3.1.21 Section B.1.22. IP3: Complete NL-13-122 B.1.22 NL-15-121 15 IP2: Complete NL-07-039 A.2.1.22 Implement the Non-EQ Inaccessible Medium-A.3.1.22 Voltage*Cable Program for IP2 and IP3 as described in LRA Section B.1.23. IP3: Complete NL-13-122 B.1.23 NL-07-153 Audit item This new program will be implemented consistent NL-15-121 173 with the corresponding program described in NL-11-032 NUREG-1801 Section XI.E3, Inaccessible Medium-Voltage Cables Not Subject To 1O CFiR 50.49 NL-11-096 Environmental Qualification Requirements.

• NL-11-101

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AUDIT ITEM IP2: Complete NL-07-039 A.2.1.23 16 Implement the Non-EQ Instrumentation Circuits Test A.3.1.23 Review Program for IP2 and IP3 as.described in IP3: Complete NL-13-122 8.1.24 LRA Section B.1.24.

NL-07-153 Audit item This new program will be implemented consistent NL-15-121 173 with the corresponding program described in

\

NUREG-1801 Section XI.E2, Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in r

Instrumentation Circuits.

IP2: Complete NL-07-039 A.2.1.24 17 Implement the Non-EQ Insulated Cables and A.3.1.24 Connections Program for IP2 and IP3 as described IP3: Complete NL-13-122 8.1.25 in LRA Section 8.1.25.

NL-07-153 Audit item This new program will be implemented consistent NL-15-121 173 with the corresponding program described in NUREG-1801 Section XI.E1, Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements.

IP2: Complete NL-:07-039 A.2.1.25 18 Enhance the Oil Analysis Program for IP2 to sample A.3.1.25 and analyze lubricating oil used in the SBC/Appendix IP3: Complete NL-13-122 8.1.26 R diesel generator consistent with the oil analysis for NL-11-101 other site diesel generators.

NL-15-121 Enhance the Oil Analysis Program for IP2 and IP3 to i 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 for water 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.

NL-17-161

(

Docket Nos. 50-247 and 50-286 Attachment 3 Page 10 of 22

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AUDIT ITEM IP2: Complete NL-07-039 A.2.1.26 19 Implement the One-Time Inspection Program for IP2 A.3.1.26 and IP3 as described in LRA Section B.1.27.

IP3: Complete NL-13-122 B.1.27 This new program will be implemented consistent NL-07-153 Audit item with the corresponding program described in ,* NL-15-121 173 NUREG-1801,Section XI.M32, One-Time Inspection.

IP2: Complete NL-07-039 A.2.1.27 20 Implement the One-Time Inspection - Small Bore A.3.1.27 Piping Program for IP2 and IP3 as described in LRA IP3: Complete NL-13-122 , B.1.28 Section B.1.28.

NL-07-153 Audit item This new program will be implemented consistent NL-15-121 173 with the corresponding program described in NUREG-1801,Section XI.M35, One-Time Inspection of ASME Code Class I Small-Bore Pipina.

IP2: Complete NL-07-039 A.2.1.28 21 Enhance the Periodic Surveillance and Preventive A.3.1.28 Maintenance Program for IP2 and IP3 as necessary IP3: Complete NL-13-122 B.1.29 to assure that the effects of aging will be managed NL-15-121 such that applicable components will continue to perform their intended functions consistent with the current licensing basis through the period of extended operation. ,

IP2 & IP3: NL-16-122 A.2.1.28 Implement LRA Sections A.2.1.28, A.3.1.28 and December 31, 2017 A.3.1.28 B.1.29, as shown in NL-16-1225 B.1.29 IP2 & IP3: NL-17-052 A.2.1.28 Implement LRA Sections A.2.1.28, A.3.1.28 and December 31,

, 2017 A.3.1.28 B.1.29, as shown in NL-17-052 B.1.29 IP2 & IP3: NL-17-155 A.2.1.28 Implement LRA Sections A.2.1.28, A.3.1.28 and December 31, 2018 A.3.1.28 B.1.29, _as shown in NL-17-155 B.1.29 IP2 & IP3: NL-17-161 B.1.29 lm~lement LRA Section B.1.29,as shown in NL December 31 2018 161 5

This commitment erroneously deleted iri NL-17-052

NL-17-161 Docket Nos. 50-247 and 50-286 Attachment 3 Page 11 of 22

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AUDIT ITEM IP2: Complete NL-07-039 A.2.1.31 22 Enhance the Reactor Vessel Surveillance Program A.3.1.31 for IP2 and IP3 revising the specimen capsule IP3: Complete. NL-13-122 8.1.32 withdrawal schedules to draw and test a standby NL-15-121 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.

IP2: Complete NL-07-039 A.2.1.32 23 Implement the Selective Leaching Program for IP2 A.3.1.32 and IP3 as described in LRA Section 8.1.33.

IP3: Complete NL-13-122 8.1.33 This new program will be implemented consistent NL-07-153 Audit item with the corresponding program described in NL-15-121 173 NUREG-1801,Section XI.M33 Selective Leaching of Materials.

IP2: Complete NL-07-039 A.2.1.34 24 Enhance the Steam Generator Integrity Program for A.3.1.34 IP2 and IP3 to require that the results of the IP3: Complete NL-13-122 8.1.35 condition monitoring assessment are compared to the operational assessment performed for the prior operatino cvcle with differences evaluated.

Enhance the Structure.s Monitoring Program to IP2: Complete NL-07-039 A.2.1.35 25 explicitly. specify that the following structures are . A.3.1.35 included in the program. IP3: Complete NL-13-122 8.1.36

• Appendix R diesel generator foundation (IP3) NL-07-153

• Appendix R diesel generator fuel oil tank vault NL-15-121 Audit items (IP3) 86, 87, 88,

• Appendix R diesel generator switchgear and NL-08-057 417

• enclosure (IP3)

• city water storage tank foundation

• condensate storage tanks foundation (IP3) NL-13-077

• containment access facility and annex (IP3)

• discharge canal (IP2/3)

• emergency lighting poles and foundations (IP2/3)

• fire pumphouse (I P2) '

• fire protection pumphouse (IP3)

• fire water storage tank foundations (IP2/3)

• gas turbine 1 fuel storage tank foundation

• maintenance and outage building-elevated passageway (IP2)

NL-17-161 Docket Nos. 50-247 and 50-286 Attachment 3 Page 12 of 22

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION/

AUDIT ITEM

• new station security building (IP2)

• nuclear service building (IP1)

• primary water storage tank foundation (IP3)

• refueling water storage tank foundation (IP3)

• 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) NL-14-146 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 suppqrts

• 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 NL-13-077 Enhance the Structures Monitoring Program for IP2 and IP3 to inspect inaccessible concrete areas that are exposed by excavation for any reason. IP2 and IP3 will also inspect inaccessible concrete areas in environments where observed conditions in accessible areas exposed to the same environment indicate that significant concrete deg~adation is occurring.

Enhance the Structures Monitoring Program for IP2 and IP3 to perform inspections of elastomers (seals, oaskets, seismic ioint filler, and roof elastomers) to

NL-17-161 Docket Nos. 50-247 and 50-286 Attachment 3 Page 13 of 22

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA

' SECTION/

AUDIT ITEM 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 NL-08-127 once every five years). IPEC will obtain samples Audit Item from at least 5 wells that are representative of the 360 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 IP3 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. Audit Item 358 I

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 NL-11-032 period of extended operation.

I NL-11-101

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AUDIT ITEM IP2: Complete NL-07-039 A.2.1.36 26 Implement the Thermal Aging Embrittlement of Cast A.3.1.36 Austenitic Stainless Steel (CASS) Program for IP2 IP3: Complete NL-13-122 8.1.37 and IP3 as described in LRA Section 8.1.37.

NL-07-153 Audit item This new program will be implemented consistent NL-15-121 173 with the corresponding program described in NUREG-1801,Section XI.M12, Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) Proaram.

IP2: Complete NL-07-039 A.2.1.37 27 Implement the Thermal Aging and Neutron A.3.1.37 Irradiation Embrittlement of Cast Austenitic Stainless IP3: Complete NL-13-122 8.1.38 Steel (CASS) Program for IP2 and IP3 as described NL-07-153 Audit item in LRA Section 8.1.38.

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

IP2: Complete NL-07-039 A.2.1.39 28 Enhance the Water Chemistry Control - Closed A.3.1.39 Cooling Water Program to maintain water chemistry IP3: Complete NL-13-122 8.1.40 of the IP2 SBC/Appendix R diesel generator cooling NL-08-057 Audit item system per EPRI guidelines. .

509 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 guidelines.

IP2: Complete NL-07-039 A.2.1.40 29 Enhance the Water Chemistry Control - Primary and 8.1.41

~econdary Program for IP2 to test sulfates monthly NL-13-122 1n the RWST with a limit of <150 oob.

IP2: Complete NL-07-039 A.2.1.41 30 For aging management of the reactor vessel A.3.1.41 internals, IPEC will (1) participate in the industry IP3: Complete NL-13-122 programs for investigating and managing aging effects on reactor internals; (2) evaluate and impl~ment the results of the industry programs as applicable to the reactor inte;rnals; and (3) upon completion of these programs, but not less than 24 months before entering the period of extended NL-11-107 operation, submit an inspection plan for reactor internals to the NRC for review and aoorc:ival.

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AUDIT ITEM IP2: Complete NL-07-039 A.2.2.1.2 31 Additional P-T curves will be submitted as required A.3.2.1.2 per 10 CFR 50, Appendix G prior to the period of IP3: Complete NL-13-122 4.2.3 extended operation as part of the Reactor Vessel NL-15-121 Surveillance ProQram.

As required by 10 CFR 50.61 (b)(4), IP3 will submit a IP3: NL-07-039 A.3.2.1.4 32 plant-specific safety analysis for plate 82803-3 to the Approximately 6 NL-07-140 4.2.5 NRC three years prior to reaching the RTPTs years after entering NL-08-014 screening criterion. Alternatively, the site may he PEO NL-08-127 choose to implement the revised PTS rule when approved.

/

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AUDIT ITEM IP2: Complete NL-07-039 A.2.2.2.3 33 At least 2 years prior to entering the period of *,

A.3.2.2.3 extended operation, for the locations identified in IP3: Complete NL-13-122 4.3.3 LRA Table 4.3-13 (IP2) and LRA Table 4.3-14 (IP3),

NL-07-153 Audit item under the Fatigue Monitoring Program, IP2 and IP3 146 will implement one or more of the following:

NL-08-021 (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 NL-10-082 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 exceedinQ a CUF of 1.0.

34 Complete NL-13-122 2.1.1.3.5 IP2 SBO / Appendix R diesel generator will be installed and operational by April 30, 2008. This NL-07-078 committed change to the facility meets the

~

NL-08-074 requirements of 10 CFR 50.59(c)(1) and, therefore, a license amendment pursuant to 10 CFR 50.90 is not required. NL-11-101

NL-17-161 Docket Nos. 50-247 and 50-286 Attachment 3 Page 17 of 22

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AUDIT ITEM IP2: Complete NL-08-127 Audit Item 35 Perform a one-time inspection of representative 27

. sample area of IP2 containment liner affected by the NL-13-122 1973 event behind the insulation, prior to entering the period of extended operation, to assure liner IP3: Complete degradation is not occurring in this area.

NL-11-101 Perform a one-time inspection of representative NL-15-121 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 NL-09-018 containment liner analyses as needed.

IP2: Complete NL-08-127 Audit Item 36 Perform a one-time inspection and evaluation of a NL-11-101 359 sample of potentially affected IP2 refueling cavity NL-13-122 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 NL-09-056 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 NL-09-079 determine the composition of the fluid. If additional core sampl~s are taken prior to the end of the first

' ten years of the period of extended Operation, a sample of leakaQe fluid will be analvzed.

IP2: Complete NL-08-127 Audit Item 37 Enhance the Containment lnservice Inspection (CII-361 IWL) Program to include inspections of the IP3: Complete NL-13-122 containment using enhanced characterization of degradation (i.e., quantifying the dimensions of noted i indications through the use of optical aids) during the period of extended operation. The enhancement I 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.

NL-17-161 Docket Nos. 50-24 7 and 50-286 Attachment 3 Page 18 of 22

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION/

AUDIT ITEM IP2: Complete NL-08-143 4.2.1 38 For Reactor Vessel Fluence, should future core loading patterns invalidate the basis for the projected IP3: Complete NL-13-122 values of RTpts or CvUSE, updated calculations will NL-15-121 be provided to the NRC.

NL-09-079 39 Deleted IP2: Complete NL-09-106 8.1.6 40 Evalu~te. plant ~pecific and appropriate industry 8.1.22 operating experience and incorporate lessons IP3: Complete NL-13-122 8.1.23

~earne~ in establishing appropriate monitoring and NL-15-121 8.1.24 inspection frequencies to assess aging effects for the 8.1.25 new aging management programs. Documentation 8.1.27 of the operating experience evaluated for each new 8.1.28 program will be available on site for NRC review 8.1.33 prior to the period of extended operation.

8.1.37 8.1.38 NL-17-005 NIA 41 Deleted

1 NL-17-161 Docket Nos. 50-247 and 50-286 Attachment 3 Page 19 of 22

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AUDIT ITEM 42 IPEC will develop a plan for each unit to address the NL-11-032 NIA 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)

IPEC will perform an analytical evaluation of the steam generator tube-to-tubesheet welds in order to IP2: Complete NL-11-074 establish a technical basis for either determining that the tubesheet cladding and welds are not susceptible IP3: Complete NL-11-090 to PWSCC, or redefining the pressure boundary in which the tube-to-tubesheet weld is no longer NL-11-096 included and, therefore, is not required for reactor coolant pressure boundary function. The redefinition IP2: NL-17-005 of the reactor coolant pressure boundary must be Not Applicable approved by the NRC as a license amendment request. IP3: Not Applicable Option 2 (Inspection)

IPEC 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 oenerators.

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AUDIT ITEM IP2: Complete NL-11-032 4.3.3 43 IPEC will review design basis ASME Code Class 1 fatigue evaluations to determine whether the IP3: Complete NUREGICR-6260 locations that have been NL-13-122 evaluated for the effects of the reactor coolant NL-11-101 environment on fatigue usage are the limiting NL-15-121 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 NUREGICR-6909 methodology in the evaluation of the limiting locations consisting of nickel alloy, if any.

IP2: Complete NL-11-032 NIA 44 IPEC will include written explanation and justification of any user intervention in future evaluations using IP3: Complete NL-11-101 the WESTEMS "Design CUF" module.

~

NL-13-122 NL-15-121 45 IPEC will not use the NB-3600 option of the IP2: Complete NL-11-032 NIA WESTEMS program in future design calculations IP3: Complete NL-11-101 until the issues identified during the NRC review of NL-13-122 the program have been resolved.

NL-15-121 46 Include in the IP2 ISi Program that IPEC will perform IP2: Complete NL-11-032 NIA twenty-five volumetric weld metal inspections of NL-11-074 socket welds during each 10-year ISi interval NL-13-122 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. NL-14-093 NIA

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AUDIT ITEM IP2: Complete NL-12-174 N/A 48 Entergy will visually inspect IPEC underground piping within the scope of license renewal and IP3: Complete subject to aging management review prior to the f NL-13-122 period of extended operation and then on a NL-15-121 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 XI.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 XI.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).

IP2: Complete NL-13-052 A.2.2.2 49 Recalculate each of the limiting CUFs provided in A.3.2.2 section 4.3 of the LRA fdr the reactor vessel internals IP3: Complete to include the reactor coolant environment effects NL-13-122 (Fen) as provided in the IPEC Fatigue Monitoring NL-15-121 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 t components prior to the CUFen reaching 1.0.

Replace the IP2 split pins during the 2016 IP2: Complete NL-13-122 A.2.1.41 50 refueling outage (2R22). 8.1.42 IP3: N/A NL-14-067 IP2 & IP3: NL-14-147 A.2.1.33 51 Enhance the Service Water Integrity Program by December 31, 2017 A.3.1.33 implementing LRA Sections A.2.1.33, A.3.1.33 and 8.1.34 8.1.34, as shown in NL-14-147.

IP2 & IP3: NL-16-122 A.2.1.33 Implement LRA Sections A.2.1.33, A.3.1.33 and December 31, 2017 A.3.1.33 8.1.34, as shown in NL-16-122 8.1.34

NL-17-161 Docket Nos. 50-247 and 50-286

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AUDIT ITEM IP2 & IP3: NL-17-052 A.2.1.33 Implement LRA Sections A.2.1.33, A.3.1.33 and December 31, 2017 A.3.1.33 B.1.34, as shown in NL-17-052 B.1.34 IP2 & IP3: NL-17-155 A.2.1.33 Implement LRA Sections A.2.1.33, A.3.1.33 and December 31, 2018 A.3.1.33 B.1.34, as shown in NL-17-155 B.1.34 IP2 & IP3: NL-17-161 A.2.1.33 lmglement LRA Sections A.2.1.33, A.3.1.33 and December 31 2018 A.3.1.33 B.1.34, as shown in NL-17-161 B.1.34 IP2 & IP3: NL-15-019 A.2.1.42 52 Implement the Coating Integrity Program for IP2 and December 31, 2024 A.3.1.42 IP3 as described in LRA Section B.1.42, as shown in B.1.43 NL-15-019.

May 31, 2018 NL-17-053 A.2.1.2 53 Revise Bolting Integrity Program to include visual A.3.1.2 inspection of a representative sample of closure B.1.2 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.

Enhance the Steam Generator Integrity Program as December 31, 2017 NL-17-060 A.2.1.34 54 follows. A.3.1.34 8.1.35

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

Revise the Buried Piping and Tanks Inspection December 31, 2017 NL-17-084 A.2.1.5 55 Program for IP2 and IP3 to incorporate the changes A.3.1.5 shown in LAR Sections A.2.1.5 and A.3.1.5 in letter NL-17-084.