NL-17-127, 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)

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)

ML17321A079
Person / Time
Site:	Indian Point
Issue date:	11/08/2017
From:	Vitale A Entergy Nuclear Northeast
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
CAC MD5407, CAC MD5408, NL-17-127
Download: ML17321A079 (53)

Text

A Entergy Nuclear Northeast Indian Point Energy Center

• ===- Entergx 450 Broadway, GSB P.O. Box 249 Buchanan, NY 10511-0249 Tel (914) 254-6700 Anthony J Vitale Site Vice President NL-17-127 November 8, 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) USN RC 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)

2) USNRC 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)

\

3) 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)

4) 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)

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's 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

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NL-17-127 Docket Nos. 50-247 and 50-286 Page 2 of 2 warrant additionc;1I clarification or further information. Attachment 1 provides additional information to clarify the areas identified in the audit report (References 1 and 2).

Changes to the LRA sections resulting from the information provided in Attachment.1 and other administrative changes are provided in Attachment 2. Changes to the List of Regulatory Commitments are provided in Attachment 3.

By Reference 4, Entergy informed the NRC of its expectation to cease electric-gene.rating operations at IP2 by April 30, 2020, and at IP3 by April 30, 2021, respectively, subject to potential operating extensions through, but not beyond, 2024 and 2025, under very limited circumstances. Accordingly, Entergy believes that the additional information:and enhancements to the Service Water Integrity Aging Management Program described in Attachment 1 provide more than reasonable assurance that the Service Water System will continue to perform its intended functions for the limited remaining operating times of IP2 and IP3.

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

I declare!nder penalty of perjury that the foregoing is true and correct. Executed on IIL8 7

, 2011. .

Sincerely, j

AJV/rl

Attachment:

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 35 cc: Mr. Daniel H. Dorman, 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 13arton, President and CEO NYSERDA NRC Resident Inspector's Office

ATTACHMENT 1 to NL-17-127 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-17-127 Docket Nos. 50-247 and 50-286 Attachment 1 Page 1 of 11

1. NRC AUDIT REPORT ITEM Installation of External Carbon Fiber Wrap on Zurn Strainer Pit Service Water Piping. Based on information provided by NRC regional and resident staff members, the applicant had applied a nonstructural external coating of composite (carbon fiber epoxy) material on portions of the service water piping in the Zurn strainer pits. According to the applicant, this was done to protect the pipe from mechanical damage or loss of material due to external corrosion. The applicant recognized the potential that with installation of the external coating, leakage as a result of internal corrosion might not be evident through the external coating. The applicant had previously sponsored a test to show that leakage from a small hole in the pipe would be detectable through the coating. The staff was concerned that some of the Service Water Integrity program's periodic visual inspections would no longer be effective if leakage could be masked by the coating, because a significant precursor to loss of structural integrity would be lost.

In order to evaluate the coating's effect on visual inspection effectiveness, the staff reviewed the associated test 1:eport, IP-RPT-14-00022, "External Lining for Safety Related Service Water Piping." The test included: (a) two test pieces with either a 0.375 inch or a 0.500 inch drilled hole; (b) a single layer of unidirectional carbon fiber material applied with primer, wet-out, and top coat epoxies; (c) a 24 hour2.777778e-4 days <br />0.00667 hours <br />3.968254e-5 weeks <br />9.132e-6 months <br /> curing time; (d) a beginning hydrostatic test pressure of 70 pounds per square inch gauge (psig), with increases in 10 psig increments up to 100 psig; and (e) periodic observations looking for loss of hydrostatic test pressure. The test report indicated that leakage from the 0.500 inch hole occurred between 8 hours9.259259e-5 days <br />0.00222 hours <br />1.322751e-5 weeks <br />3.044e-6 months <br /> and 23 hours2.662037e-4 days <br />0.00639 hours <br />3.80291e-5 weeks <br />8.7515e-6 months <br />, and leakage from the 0.375 inch hole occurred after approximately 12 days. The leak path for both tests was identified not as penetrating through the coating itself but as extending from the drilled holes along the axis of the pipe to the edge of the coating.

During discussions, the plant staff acknowledged that the operating pressure, at locations where the carbon fiber material was installed, is lower than the pressure (100 psig) at which leakage occurred during the test. In addition, during its walkdown of the installations, the NRC staff noted that some overlapping of the carbon fiber material occurred on elbows, such that it was no longer a single layer of material. The NRC staff also noted that the installed length of the coating in some cases appeared to be greater than the coating length in the test. In addition, because it took considerably longer for leakage to be detected from the 0.375-inch hole compared to the 0.500-inch hole, the ability to detect leakage from much smaller holes (which have provided the bulk of the past operating experience where structural integrity has not been challenged) is uncertain.

Based on the above, it was not clear to the staff that the test parameters bounded the parameters of the installed coating locations and configurations. As a result, the staff questioned whether the effectiveness of the Service Water Integrity program's visual inspections was substantially diminished by the installation of the external, nonstructural carbon fiber coating. In order to address the potential masking effect of the carbon fiber coating, the staff needs additional information describing alternative inspection techniques, including the quantity, frequency, and extent, to compensate for the inability to credit periodic visual inspections.

I

NL-17-127 Docket Nos. 50-247 and 50-286 Attachment 1 Page 2 of 11

RESPONSE

In the carbon fiber-wrapped portions of the system located in the Zurn strainer pits, leakage as a result of internal corrosion occurs at or near welded joints due to designed gaps in the cement lining. As an alt,ernative to performing visual inspections for leakage at the subject carbon fiber-wrapped locations in the service water strainer pits, Entergy will perform volumetric NOE, such as radiography ()f the affected welds during the period of extended operation (PEO). Entergy will perform the NOE at IP2 and IP3 during each unit's respective refueling outage interval. The total number of inspections to be performed will be 20 percent of the total affected weld population, up tc> a maximum of 25 during each 10-year operating interval. Radiography will provide sufficient data to allow detection of piping degradation.

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

2. NRC AUDIT REPORT ITEM 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 ne<<3d to address different aging effects with different inspection requirements. In addition Entergy may need alternate inspection techniques, because the inability to detect leakage through the composite material may not allow the detection of ongoing internal corrosion at loca1tions 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.

NL-17-127 Docket Nos. 50-247 and 50-286 Attachment 1 Page 3 of 11 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 4, Entergy 1 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 to the end of thei renewed license term. 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.

) .

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

NL-17-127 Docket Nos. 50-247 and 50-286 Attachment 1 Page 4 of 11

3. NRC AUDIT REPORT ITEM 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 a unique population for the,se activities. The information needed by the staff includes: a1) 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

AL6-XN ATI Technical brochure

NL-17-127 Docket Nos. 50-247 and 50-286 Attachment 1 Page 5 of 11 Item b) the environments in the vicinity of the 300 series stainless steel/carbon steel and AL 6XN/carbon steel joints.

Response b):

As delini3ated 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 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.

• Overall

Conclusion:

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

-- i NL-17-127 Docket Nos. 50-247 and 50-286 Attachment 1 Page 6 of 11 Entergy staff previously determined that insulating kits were not necessary and subsequently revised design specifications for IP2 and IP3 to remove the requirement for insuli:1ting 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 ccintact with carbon steel. Therefore, Entergy will perform inspections for indications of galvanic corrosion from a combined population of joints where carbon steel is connected 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 AL6XN, Avesta 254 SMO, or 300-series stainless steel. The inspection population will be limited to dissimilar metal joints without galvanic insulating kits. 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. If significant loss of material is identified by the visual inspections, additional volumetric NDE 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.

4. NRC AUDIT REPORT ITEM Assessment of Through-Wall Leak Discussed in Relief Request 3-43. The staff had previously asked about changes made to the Service Water Integrity program as a result of situations like relief request 3-43, where the applicant's predictive monitoring methodology did not appear to be conservative. In its response dated May 8, 2017, the applicant stated that a contributing cause of the leak associated with relief request 3-:-43 was a less than adequate repair of a previous leak. The applicant also stated that it had recently implemented a program improvement to prevent recurrence of events related to inadequate repairs through the development of engineering report IP-RPT-16-00046, "IPEC Service Water Piping Weld Repair Process and Re-Inspection Frequency GuideJines." (See below for the staff's review of this document.)

NL-17-127 Docket Nos. 50-247 and 50-286 Attachment 1 Page 7 of 11 As part of its responses to RAls for relief request 3-43, by letter dated October 3, 2007, (ADAMS Accession No. ML072890132) the applicant stated that a "final assessment of why a new through-wall leak developed near the area of the prior repair has not been completed." The staff requested a copy of the referenced assessment in order to determine whether changes to the program addressed all of the potentially non-conservative aspects of the predictive monitoring methodology associated with the relief request. However, the applicant could not locate the refereinced assessment while the audit team was on site. During breakout sessions, the applicant indicated that changes made to the program since the 2007 event, including the recently issued 1:mgineering report IP-RPT-16-00046, have addressed all of the issues related to the event. It was not clear to the staff whether additional changes to the program were warranted based on the circumstances surrounding the relief request, without additional information from the applicant to support its position.

RESPONSE

Entergy has developed a comprehensive approach for dealing with future issues such as the one described in relief request (RR) 3-43. Engineering report IP-RPT-16-00046, "IPEG Service Water Piping Wield Repair Process and Re-Inspection Frequency Guidelines" provides consistent repair methods and guidelines for subsequent re-inspections during the PEO. The guidelines of this report, which the NRG staff reviewed during its August 2017 on-site audit, provide reasonable assurance that future losses of function as described in the subject relief request will be prevented. It provides clear direction and utilizes engineering expertise and operating experience to ensure future repairs will be performed adequately. It also provides specific guidance on determining the appropriate times for re-inspection to ensure that when degradation is found, a scheduled follow-up will occur based on an official calculation by the engineering department. Entergy will add instructions to Service Water Integrity Program implementing procedures to implement the guidelines of report IP-RPT-16-00046. Based on this information, there is reasonable assurance that the issue described in relief request RR 3-43 will not recur during the PEO.

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

5. NRG AUDIT REPORT ITEM Review of Service Water Piping Weld Repair Process and Re Inspection Frequency Guideline, (IP-RPT-16-000,~. In its RAI response dated May 8, 2017, the applicant stated that, as a program improvement to prevent recurrence of events related to inadequate repairs, it had recently implem,snted IP-RPT-16-00046. As part of the audit, the staff reviewed the cited guideline and noted that'the document provides guidance related to:

• ensuring ultrasonic inspection data sufficiently characterizes the extent of degradation (e.g., extent of readings, grid size) through coordination between inspection personnel and desi!~n engineers,

• developing formal calculations in accordance with EN-GS-S-008-MULTl to determine the extent of repairs and the timing of follow on inspections,

• determining the number and extent of required repairs,

NL-17-127 Docket Nos. 50-24 7 and 50-286 Attachment 1 Page 8 of 11

• considering the impact of welding on the integrity of the pipe internal lining, and

• determining the re-inspection interval based on weld repair configuration (e.g., full penetration weld, partial penetration weld, weld overlay), minimum wall thickness requirements;-, and corrosion allowance.

Although the staff did not identify any issues with this new guidance, the staff noted that the current version of the Service Water Integrity program, which was issued prior to the new guidance, does not cite IP-RPT-16-00046. During subsequent discussions, the applicant acknowledged that the program should be enhanced to credit the newly implemented guidance.

RESPONSE

As discussed above in response to NRC audit report Item 4, Entergy will add instructions to Service Water Integrity Program implementing procedures to implement the guidelines of report IP-RPT-16-00046.

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

6. NRC AUDIT REPORT ITEM Corrective Actions for Inoperable Containment Due to Leaks in Service Water Piping. In its RAI response dated May 8, 2017, the applicant addressed LERs 247/2015-001, 247/2015 004, 247/2016-010, and 286/2016-001 that all relate to inoperable containment due to leaks in service water system fan cooler unit piping. For the two Unit 2 events in 2015, the applicant stated that flow rates were higher than necessary leading to flow-accelerated corrosion at the weld joint, and tlhe program was not changed because the issues did not involve deficiencies in the Service Water Integrity program.

Since service water systems are not susceptible to flow-accelerated corrosion, but are susceptible to erosion, and because the Service Water Integrity program includes inspections for erosion, it was not clear to the staff that the Unit 2 events did not involve deficiencies in the program.

The staff reviewed Report No. F15565-R-001, "Evaluation of Wall Thinning of Fan Cooler Unit Elbow, Indian Point Unit 2," that determined the nature and root cause of the associated leaks.

The report concludes that the "leakage of the elbow occurred as a,result of flow accelerated corrosion attack as a direct consequence of high flow rates and turbulence created by the sharp ridge on the inne!r surface at the intrados of the elbow." The staff noted that the loss of material occurred only on the side of the elbows.

As part of its review, the staff independently noted that industry guidance in NSAC-202L, "Recommendations for an Effective Flow-Accelerated Corrosion Program," excludes systems with high levels of dissolve oxygen (greater than 1000 ppb) such as service water systems because they aria not susceptible to flow-accelerated corrosion. Consequently, the staff did not agree with the root cause report's conclusion that the leak was caused by flow-accelerated corrosion. In addition,, based on the leak locations (on the sides of the elbows), the staff noted

NL-17-127 Docket Nos. 50-247 and 50-286 Attachment 1 Page 9 of 11 the similarity with re-circulation cavitation, which appear to be associated with the broader issues addresse:d in LR ISG 2012-01, "Wall Thinning Due to Erosion Mechanisms."

The applicant's IRAI response dated May 8, 2017, describes the corrective actions for the leak as adjusting syst~m flow rates to lower the fluid velocity in the affected piping. The staff agrees that this change to the system operating parameter would reduce the loss of material rate, but as noted in the above cited LR ISG, the effectiveness of the corrective actions, which eliminate the source of an erosion mechanism, should be verified. During the audit, the applicant acknowledged that additional activities would be needed to verify that the reduced flow rates resolve the loss of material issue.

For the Unit 3 event in 2016, corrective actions specified in LER 286/2016-001 included revising the Generic Letter 89-13 program to include a requirement to conduct a definitive number of volumetric inspedion for we!ds made of 904L material each pre-outage interval. Although specified in the LER (dated December 21, 2016), the applicant's RAI response discussing this LER (dated May 8, 2017), did not include any information about this change to the program.

During its review of the associated corrective action document (CR-IP3-2016-03607, CA No.

27), the staff noted that the applicant will inspect 13 of the 904L welds each pre outage interval.

However, the corrective action document also states that the acceptance criteria for the selected sample will be that specified in ASME Code Case N-513-3. As previously discussed in RAI 3.0.3-10-2a (see Entergy's RAI response dated May 8, 2017), loss of structural integrity, which is the basis for the Code Case N 513 3 acceptance criteria, may not be an appropriate acceptance crite!ria for all situations.

Given that the s,~rvice water system leak causing the containment to be inoperable apparently met structural integrity criteria, it was not clear to the staff that criteria from Code Case N-513-3 would be appropriate acceptance criteria for the periodic inspections of 904L welds. Since Code Case N-5'13-3 allows leakage and specifically does not address the consequences of leakage, the specified acceptance criteria for the periodic sample of 904L welds would not maintain intended functions consistent with the current licensing basis. In order to complete its review of the Service Water Integrity program, the staff needs additional information that clarifies the adequacy of the acceptance criteria for the 904L weld inspections.

In a related area1, the staff noted that in its RAI response dated May 8, 2017, the applicant described the cause of pin-hole leaks in'LER 247/2013-004 as "improper material use." As clarified by its letter dated June 27, 2017 (ADAMS Accession No. ML17187A140), the applicant stated that the te~rm was intended to refer to the inability to characterize degradation associated with the configuration of socket welded fittings. The applicant also stated that 300 series stainless steel material remains in use in the service water system and the "requirements for NOE [non-destructive examination] of 300 series stainless steel piping are already included in the scope of the Service Water Integrity program."

The staff notes that, while stainless steel piping is included within the scope of the program, the program's only NOE "requirements" would be periodic visual inspections of the piping looking for leakage. Similar to the previous discussion for the 904L welds, if there is stainless steel service water piping inside containment, then the detection of aging effects by only using visual inspections (based on past operating experience) would not maintain intended functions

NL-17-127 Docket Nos. 50-247 and 50-286 Attachment 1 Page 10 of 11 consistent with the current licensing basis. In order to complete its review, the staff needs additional information to clarify whether the Service Water Integrity program includes sufficient non-destructive requirements of stainless steel piping where leakage due to localized corrosion (e.g., pitting) can cause a loss of intended function.

RESPONSE

~

-'*

With respect to the erosion issues noted in the copper-nickel material service water piping elbows at IP2, the corrective action of reducing the flow rates through the elbows was implemented in 2016. Based on the service time with the previous flow rates that resulted in the erosion observed in 2015, it is expected that at least 15 years of operation at the reduced flow rate would be niecessary to cause appreciable wall thinning in the replaced elbows. The requested end date for the IP2 renewed license is 2024, which is eight years from when corrective action to reduce flow velocity was implemented in 2016. Therefore, further activities to verify effectiveness of the reduced flow rates are not warranted prior to the end of the requested term of the renewed license.

For the IP3 event in 2016, corrective actions specified in LER 286/2016-001 included revising the Generic Letter 89-13 program to include a requirement to conduct a definitive numbe~ of volumetric inspetctions for welds made of 904L material each pre-outage interval. This change will be delineateid in the SWIP and will be added to the program document as an enhancement.

The change, which only affects IP3 since IP2 does not use 904L stainless steel material, will require that 20 percent of the total welds up to a maximum of 25 be,volumetrically inspected in each 10-year interval in the PEO. This enhancement will provide reasonable assurance that future losses of function similar to those described in the referenced LER's will not occur.

In addition, Enteirgy has developed an engineering report (IP-RPT-17-00062) related to small leaks that occur on the subject piping inside the containment buildings. This report establishes a leak rate threshold below which \a leak would not result in a conclusion of a loss of safety function. Previously, any leak in the service water piping inside the containment building was considered a loss of containment safety function since Service Water piping within containment is a closed system. With this engineering report, that will no longer be the case for small leaks.

Thus, this report provides the acceptance criteria for maintaining containment integrity for small through-wall flaws within containment at both units. As all piping within the containments are ISi Class 3, in conjunction with this new report, ASME Code Case N-513-3 will be continued to be used for the evaluation and acceptance of piping structural integrity, as well for extent of condition require~ments.

For the issue related to 300-series SS piping material, Entergy has conducted a review of the service water system piping material inside the containment buildings for both Unit 2 and 3. The review determin1ed that the 300-series SS is not installed in those locations and no further actions are necessary.

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

NL-17-127 Docket Nos. 50-247 and 50-286 Attachment 1 Page 11 of 11

7. NRC AUDIT REPORT ITEM Service Water Integrity Program Extent of Condition Inspections. The staff reviewed SEP-SW-IPC-001, "NRC Generic Letter 89-13 Service Water Program," and noted that scope expansion (extent of condition) inspections used qualitative criteria. Examples include: engineering judgment, previous inspection history, materials, etc. The staff noted that the previous enhancement tci the Service Water Integrity program, regarding minimum numbers of welds to be inspected, including extent of condition inspections, only applied to cement-lined piping.

(See Entergy letter dated December 2, 2016, ADAMS Accession No. ML16350A005). Other types of materials in the service water system were not addressed in the enhancement. The staff noted that 13xtent of condition inspections should be conducted whenever inspection results do not mee! acceptance criteria. In order to obtain the information necessary to verify whether the Service Water Integrity program extent of condition inspections will be adequate to provide reasonable assurance that the service water system will meet its intended function, the staff requires the following information: .

• The.specific number of increased inspections that will be conducted when degraded conditions are detected; or

• The criteria for determining the number of increased inspections based on the degree of degradation detected during inspections.

RESPONSE

Entergy will revise the Service Water Integrity Program procedures to require a minimum of 25 NOE volumetric inspections each refueling interval per unit. These inspections will include carbon steel and other types of materials in the Service Water systems. In addition, Entergy will revise the Service Water Integrity Program to provide for five extent-of-condition inspections for each inspection that discovers wall thickness that when projected to the end of the period of extended operation is less than the minimum allowable wall thickness. This applies to degradation of in-scope piping, regardless of its material or safety class. For portions of the system found de1graded that are not covered by ASME Code Case N-513, volumetric inspection will be required unless those portions are configured in a manner that does not support NOE (e.g. socket welds or fillet welds). These enhancements will provide reasonable assurance that each service water system will continue to meet its intended function through the period of extended operation.

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

ATTACHMENT 2 to NL-17-127 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-17-127 Docket Nos. 50-247 and 50-286 Attachment 2 Page 1 of 15 3.3.2.1.2 Service Water Matf!rials Service water system components are constructed of the following materials.

• Aluminum bronze

• carbon fiber-reinforced egoxy

• carbon steel

• copper alloy

• copper alloy > 15% zinc

• copper alloy > 15% zinc (inhibited)

• glass

• gray cast iron

• Metal with internal coating

• nickel alloy

• stainless steel

• titanium

• plastic Environment Service water system components are exposed to the following environments.

air- indoor

.* condensation

• raw water

• soil

• treated water

NL-17-127

• Docket Nos. 50-247 and 50-286 Attachment 2 Page 2 of 15 Aginig Effects Requiring Management The 'following aging effects associated with the service water system require management.

• change in material properties

• cracking

• blistering

• fouling

• loss of coating integrity

• loss of material

• loss of material - wear Aging Management Programs The following aging management programs manage the aging effects for the service water system components.

• Bolting Integrity

• Buried Piping and Tanks Inspection

• Coating Integrity

• External Surfaces Monitoring

• Heat Exchanger Monitoring

• Periodic Surveillance and Preventive Maintenance

• Selective Leaching

• Service Water Integrity

• Water Chemistry Control - Closed Cooling Water

• Water Chemistry Control - Primary and Secondary

NL-17-127 Docket Nos. 50-247 and 50-286 Attachment 2 Page 3 of 15 Table 3.3.2-2-IP3

_Service Water System Summary of Aging Management Review Table 3.3.2-2-IP3: Service Water System Aging Effect NUREG-Component Intended Aging Management Table 1 Material Environment Requiring. 1801 Vol. 2 Notes Type Function Programs Item Management Item Piping Pressure Carbon fiber- Air- indoor Cracking, blistering, Periodic Surveillance -- -- E boundary reinforced (ext) loss of material and Preventive epoxy Maintenance

NL-17-127 Docket Nos. 50-24 7 and 50-286 Attachment 2 Page 4 of 15 A.3.1.28 Periodic Surveillance and Preventive Maintenance Program 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, the Periodic Surveillance and Preventive Maintenance Program includE~s enhancements to add new activities. The preventive maintenance and surveillance testing activities are generally implemented through repetitive tasks or routine monitoring of plant operations.

Surveillance testing and periodic inspections using visual or other non-destructive examination techniques verify that the following components are capable of performing their intended function.

o reactor building cranes (polar and manipulator}, crane rails, and girders, and refueling platform o containment spray system sodium hydroxide tank o recirculation pump motor cooling coils and housing o city water system components o charging1 pump casings o plant dra1in components o station air containment penetration piping o HVAC duct flexible connections o HVAC stored portable blowers and flexible trunks o EOG exhaust components o EOG duct flexible connections o EOG air intake and aftercooler components

• o EOG air start components o EOG coe>ling water makeup supply valves o security !generator exhaust components o security !generator radiator tubes o Appendix R diesel generator exhaust components o Appendix R diesel generator radiator o Appendix R diesel generator aftercooler o Appendix R diesel generator starting air components o Appendix R diesel generator crankcase exhaust components o diesel fu13I oil trailer transfer tank and associated valves o auxiliary feedwater components o

• containment cooling duct flexible connections o containment cooling fan units internals o control mom HVAC condensers and evaporators o control mom HVAC ducts and drip pans o control mom HVAC duct flexible connections o chlorination, circulating water, city water makeup, condensate pump suction, emergency diesel generator, floor drain, gaseous waste disposal, instrument air, liquid waste disposal, nuclear equipment drain, river water, station air piping, steam generator sampling, and secondary plant sampling piping corpponents, and piping elements

NL-17-127 Docket Nos. 50-247 and 50-286 Attachment 2 Page 5 of 15

o. pressurizer relief tank o main ste1am safety valve tailpipes o atmospheric dump valve silencers o auxiliary steam and condensate return system sight glass housings o condensate transfer system sight glass housings o heater drain/moisture separator drains/vents systems sight glass housings o carbon fiber-reinforced epoxy overlay on service water line 405 in primary auxiliary building The Periodic Surveillance and Preventive Maintenance Program will be enhanced as follows.

o Program activity guidance documents will be developed or revised as necessary to assure that the effects of aging will 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.

o A representative sample of at least 25 inspections of city water piping will be performed at least 13very five years. In the event that the frequency of internal corrosion meets the criteria for recurring internal corrosion, the frequency of the representative sample of 25 inspections will be increased as follows:

• 11' >1 and <5 degraded locations are found in the five year interval, then as a minimum, 10 additional volumetric examinations of system welds will be performed during the following refueling interval.

• If >5 degraded locations are found, then a minimum of 15 additional volumetric examinations will be performed during the following refueling interval.

In additic,n to the above, for areas of piping that are found degraded and returned to service, the remaining service life will be calculated and the piping will be re-examined prior to tlhe end of calculated life.

o The Periodic Surveillance and Preventive Maintenance Program procedures will be revised to ensure city water piping that exhibits leaks will be locally repaired and restored to service on an interim basis presuming ultrasonic test data reflects adequate structural integrity to support interim operation. The affected piping segment will be entered into the 12-week work control schedule for replacement, o The Periodic Surveillance and Preventive Maintenance Program procedures will be revised to ensure city water piping segments that exhibit indications of selective seam corrosion will be entered into the routine 12-week work control schedule and processed on an accelerated replacement basis.

'

Enhancements will be implemented prior to the period of extended operation December 31.

2018 A.2.1.33 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

NL-17-127 Docket Nos. 50-247 and 50-286 Attachment 2 Page 6 of 15 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 - I nonsafety-related piping examinations is determined by trending of examination results.

Selection of larg,e 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~ expan'sion for indications found by program inspections of nonsafety-related piping is based cm 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 the appropriate procedures to incorporate actions to manage corrosion issues.

o When through-wall leaks are detected, the leakage is evaluated under the corrective action program, which includes operability or functionality assessment of structural integrity and determination of appropriate corrective action.

o Accessible portions of safety-related buried service water piping will be internally inspected by robotic crawler or manual crawl-through once during the first 10 y1ears of the period of extended operation.

• Revise Service Water Integrity Program procedures by December 31, 2017 to address the following:

a) Perform a minimum of 25 volumetric NDE inspections each refueling interval per ynit number of volumetric \Meld examinations for safety related SW piping. The volumetric examinations will determine the extent of wall thinning.

e---P'erform a minimum of 10 volumetric weld examinations for cement lined piping on the IP2 S'IV system during each refueling interval.

e----# >1 and <5 degraded locations are found in a specific refueling interval, then 1O additional volumetric examinations of system welds will be performed during the following refueling interval.

e----# >5 degraded locations are found, then 15 additional volumetric examinations will be performed during the follmving refueling interval.

b) For areas of piping that are found degraded and returned to service, the remaining service life will be calculated and the piping will be re-examined prior t<> the end of calculated life.

NL-17-127

• Docket Nos. 50-247 and 50-286 Attachment 2 Page 7 of 15 c) Require a minimum of 5 additional volumetric weld examinations if a through-wall leak is discovered in non-safety related portions of the SW system that are within the scope of license renewal for 10 CFR 54.4(a)(2).

d) Increase the frequency of internal robotic* inspections on the system headers at both units from once during the first 10 years of the period of extended operation tc, also include once during the second 10 years of the period of extended operation.

e) Review the SW system to identify areas where leakage from nonsafety-related SW piping could result in unacceptable flooding and ensure the nonsafety-related piping that can cause flooding concerns is clearly identified in the program documents. Specify volumetric examination of at least 20 percent of (up to a maximum of 25) non-safety related welds located in areas subject to flooding of safety-related equipment within each 10-year period of the PEO. '

f) Specify a yearly OE review to identify any effects of aging reported on the SW system, specifically including any conditions that may have occurred in the prior year related to inadequate cement liner repairs. '

g) Include guidance for lay-up of the SW process radiation monitoring system to minimize exposure of susceptible tubing to stagnant conditions.

h) Establish recurring internal corrosion goals for stagnant vent and drain connection piping. If these recurring internal goals are not met, the frequency for flushing stagnant vent and drain connection piping will be increased.

• The Service Water Integrity Program procedures will be revised to conduct and document a 100 percent internal lining visual inspection of the IP2 three inch fan cooler units (FCU) spool pieces when removed during FCU coil refueling outage preventive maintericmce activities.

• The Service Water,lntegrity Program procedures will be revised to include generic flaw evaluation acceptance criteria based on ensuring structural integrity and leakage concerns. Program procedures will also be revised include generic Containment integrity leak rate acceptance criteria, depending on the location of a flaw. This will take the form of acceptance curves for flaw size to meet structural integrity versus pipe size, a curve for leak rate versus pipe size, and an acceptance curve for Containment integrity considering flaw size versus leak location. The intent is to provide for a rapid and easily performed assessment (i.e., operability determination) of a leak in the service water system within containment in either unit.

• The Service Water Integrity Program procedures will be revised to perform a formal review of a leak that causes a loss of function. This will include examining the cause of the leak and to determine if the aging management program remains adequate. If a new aging meichanism is found, it will also evaluate if a failure of the aging management program plan has occurred.

- '

NL-17-127 Docket Nos. 50-247 and 50-286 Attachment 2 Page 8 of 15

• The Sen,ice Water Integrity Program procedures will be revised to prioritize future inspections based on plant area susceptible to flooding concerns.

• Revise Service Water Integrity Program procedures to perform volumetric NOE, such as radiography, of the carbon fiber-wrapped welds in the service water strainer pits during the period of extended operation. The number of inspections will be 20 percent of the total affected weld population, up to a maximum of 25, during each 10-year operating interval.

• Revise Service Water Integrity Program procedures to perform internal visual inspections of flanged connections where carbon steel is in contact with AL6XN, Avesta 254 SMO, or 300-series stainless steel. The inspection population will be dissimilar metal joints without galvanic insulating kits. 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. If significant loss of material is identified by the visual inspections, additional volumetric NOE will be performed to characterize the extent of the degradation.

• Revise Service Water Integrity Program procedures to implement the guidelines of report IP-RPT-16-00046.

• Revise Service Water Integrity Program procedures to require five extent-of-condition inspections whenever inspections discover wall thickness that when projected to the end of the period of extended operation is less than the minimum allowable wall thickness.

This applies to degradation of in-scope piping, regardless of its material or safety class.

For portions of the system found degraded that are not covered by ASME Code Case N-513, volumetric inspection will be required unless those portions are configured in a manner that does not support NOE (e.g. socket welds, fillet welds, etc.).

The enhancemeint§. will be implemented prior to December 31, 2016 December 31, 2018.

A.3.1.33 Servic,e 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 eirosion, 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 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 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

NL-17-127 Docket Nos. 50-24 7 and 50-286 Attachment 2 Page 9 of 15 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 the appropriate procedures to incorporate actions to manage corrosion issues.

o When through-wall leaks are detected, the leakage is evaluated under the corrective action program, which includes operability or functionality assessment of structural integrity and determination of appropriate corrective action. \

o Accessible portions of safety-related buried service water piping will be internally inspected by robotic crawler or manual crawl-through once during the first 10 years of the period of extended operation.

• Revise Service Water Integrity Program procedures by December 31, 2017 to address the following:

a) Perform a minimum of 25 volumetric NDE inspections each refueling interval per

.Ynitnumber of volumetric weld examinations for safety related cement lined SW piping. The volumetric examinations will determine the extent of wall thinning'.

e Perform a minimum of 1O volumetric weld examinations for cement lined piping on the IP3 SV'/ system during each refueling interval.

e If >1 and <5 degraded locations are found in a specific refueling interval, then 10 additional volumetric examinations of system welds will be performed during the following refueling interval.

e If >5 degraded locations* are found, then a minimum of 15 additional volumetric examinations will be performed during the following refueling interval.

b) For areas of piping that are found degraded and returned to service, the mmaining service life will be calculated and the piping will be re-examined prior to the end of calculated life.

c) R:equire a minimum of 5 additional volumetric weld examinations if a through-wall leiak is discovered in non-safety related portions of the SW system that are within the scope of license renewal for 10 CFR 54.4(a)(2).

d) Increase the frequency of internal robotic inspections on the system headers at both units from once during the first 10 years of the period of extended operation to also include once during the second 10 years of the period of extended operation.

e) Review the SW system to identify areas where leakage from nonsafety-related SW piping could result in unacceptable flooding and ensure the nonsafety-related piping that can cause flooding concerns is clearly identified in the program documents. Specify volumetric examination of at least 20 percent of (up to a maximum of 25) non-safety related welds located in areas subject to flooding of safety-related equipment within each 10-year period of the PEO.

r ---

NL-17-127 Docket Nos. 50-247 and 50-286 Attachment 2 Page 10 of 15 f) Specify a yearly OE review to identify any effects of aging reported on the SW system, specifically including any conditions that may have occurred in the prior year related to inadequate cement liner repairs.

g) Include guidance for lay-up of the SW process radiation monitoring system to minimize exposure of susceptible tubing to stagnant conditions.

i) Establish recurring internal corrosion goals for stagnant vent and drain connection piping. If these recurring internal goals are not met, the frequency for flushing stagnant vent and drain connection piping will be increased.

• The Sen,ice Water Integrity Program procedures will be revised to include generic flaw evaluation acceptance criteria based on ensuring structural integrity and leakage concerns. Program procedures will also be revised include generic Containment integrity leak rate acceptance criteria, depending on the location of a flaw. This will take the form of acceptance curves for flaw size to meet structural integrity versus pipe size, a curve for leak rate versus pipe size, and an acceptance curve for Containment integrity considering flaw size versus leak location. The intent is to provide for a rapid and easily performed assessment (i.e., operability determination) of a leak in the service water system within containment in either unit.

• The Sen,ice Water Integrity Program procedures will be revised to perform a formal review of a leak that causes a loss of function. This will include examining the cause of the leak and to determine if the aging management program remains adequate. If a new aging mE~chanism is found, it will also evaluate if a failure of the aging management program plan has occurred.

• The Service Water Integrity Program procedures will be revised to prioritize future inspections based on plant area susceptible to flooding concerns.

• Revise Service Water Integrity Program procedures to perform volumetric NDE. such as radiography, of the carbon fiber-wrapped welds in the service water strainer pits during the period of extended operation. The number of inspections will be 20 percent of the total affected weld population, up to a maximum of 25, during each 10-year operating interval.

• Revise Service Water Integrity Program procedures to perform internal visual inspections of flanged connections where carbon steel is in contact with AL6XN, Avesta 254 SMO, or 300-series stainless steel. The inspection population will be dissimilar metal joints without galvanic insulating kits. 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. If significant loss of material is identified by the visual inspections, additional volumetric NOE will be performed to characterize the extent of the degradation.

• Revise Service Water Integrity Program procedures to implement the guidelines of report IP*-RPT-16-00046.

NL-17-127 Docket Nos. 50-247 and 50-286 Attachment 2 Page 11 of 15

• Revise Service Water Integrity Program procedures to specify a definitive number of volumetric inspections for welds made of 904L material. The number of inspections will be 20 percent of the total affected weld population, up to a maximum of 25, during each 10-year operating interval.

• Revise Service Water Integrity Program procedures to require five extent-of-condition inspections whenever inspections discover wall thickness that when projected to the end of the period of extended operation is less than the minimum allowable wall thickness.

This applies to degradation of in-scope piping, regardless of its material or safety class.

For portions of the system found degraded that are not covered by ASME Code Case N-513, volumetric inspection will be required unless those portions are configured in a manner that does not support NOE (e.g. socket welds, fillet welds, etc.}.

The enhancement will be implemented prior to Deeember 31, 2019 December 31, 2018.

NL-17-127 Docket Nos. 50-247 and 50-286 Attachment 2 Page 12 of 15 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, the Periodic 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.

The following enhancements will be implemented prior to the period of extended operation December 31, 2018.

Attributes Affected Enhancements

1. Scopei 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 PescrjiJ21i.Q.n 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

NL-17-127 Docket Nos. 50-247 and 50-286 Attachment 2 Page 13 of 15 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.

NUREG-1so1 c:onsistency 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.

Attribu1tes Affected Enhancements

4. Detection of Aging Effects \

• Perform a minimum of 25 volumetric NOE inspections each refueling interval per unit R1::1ml3eF ef 11el1::1metFis welEI e*amiRatieRs for safet1t FelateEI semeRt liReEI SW piping. The volumetric examinations will determine the extent of wall thinning.

~ PeFfeFm a FRiRim1::1m ef ~ Q 1.,iel1::1metFi6 111elEI e*aFRiRatieRS foF semeRt liReEI 13i13iR§ 9R easR 1::1Rit's SW system El1::1FiR§ easl:l Fef1::1eliR§ iRtei=val.

~ If;::.~ aREI .::a Ele§FaEleEI lesatieRs aFe fe1::1REI iR a s13esifis Fef1::1eliR§ iRtei=val, tl:leR ~ Q aEIElitieRal 11el1::1metFie e*amiRatieRs ef system 11.ielEls will 13e peFfeFmeEI EluFiR§ tl=le fellewiR§ FefueliR§ iRtei=val.

~ If;::.§ Ele§FaEleEI lesatieRs aFe fe1::1REI, tl:leR ~ a aEIElitieRal 1.,iel1::1metFis e*amiRatieRs will 13e peFfeFmed d1::1FiR§ tl=le follewiR§ rnfueliR§ iRtei=val.

• Revise Service Water Integrity Program procedures to perform volumetric NOE, such as radiography, of the carbon fiber-wrapped welds in the service water strainer pits during the period of extended operation.

NL-17-127 Docket Nos. 50-247 and 50-286 Attachment 2 Page 14 of 15 Attributes Affected Enhancements The number of ins12ections will be 20 12ercent of the total affected weld 12012ulation, u12 to a maximum of 25, during each 10-year 012erating interval.

• Revise the Service Water Integrity Program 12rocedures to 12erform internal visual ins12ections of flanged connections where carbon steel is in contact with AL6XN, Avesta 254 SMO, or 300-series stainless steel. The ins12ection 12012ulation will be dissimilar metal joints without galvanic insulating kits.

lns12ections will monitor for evidence of loss of

) material due to galvanic corrosion on a re12resentative sam12le consisting of 20 12ercent of the 12012ulation, u12 to a maximum of 25 ins12ections, during each 10-year 12eriod of the 12eriod of extended 012eration. If significant loss of material is identified by the visual ins12ections, additional volumetric NOE will be 12erformed to characterize the extent of the degradation.

• Revise IP3 Service Water Integrity Program 12rocedures to include 12rovisions to s12ecify a definitive number of volumetric ins12ections for welds made of 904L material. The number of ins12ections will be 20 12ercent of the total affected weld 12012ulation, u12 to a maximum of 25, during each 10-year 012erating interval.

• Revise Service Water Integrity Program 12rocedures to reguire five extent-of-condition ins12ections whenever ins12ections discover wall thickness that when 12rojected to the end of the 12eriod of extended 012eration is less than the minimum allowable wall thickness. This a1212lies to degradation of in-sco12e 12i12ing, regardless of its material or safety class. For 12ortions of the system found degraded that are not covered by ASME Code Case N-513, volumetric ins12ection will be reguired unless those 12ortions are configured in a manner that does not su1212ort NOE (e.g. socket welds, fillet welds, etc.).

NL-17-127 Docket Nos. 50-247 and 50-286 Attachment 2 Page 15 of 15 Attributes Affected Enhancements

7. Corrective Actions

• Revise Service Water Integrity Program grocedures to imglement the guidelines of regort IP-RPT 00046.

ATTACHMENT 3 to NL-17-127 LICENSE RENEWAL APPLICATION IPEC LIST OF REGULATORY COMMITMENTS Rev.35 ENTERGY NUCLEAR OPERATIONS, INC.

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

NL-17-127 Docket Nos. 50-247 and 50-286 Attachment 3 Page 1 of 22 List of Regulatory Commitments Rev. 35 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 wate~r 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.

8.1.1 IP2 & IP3: NL-15-092 A.2.1.1 Implement LRI~ Sections, A.2.1.1 and B.1.1, as December 31, 2019 8.1.1 shown in NL-1!5-092 IP2: Complete NL-07-039 A.2.1.2 2 Enhance the Bolting Integrity Program for IP2 and 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 prohlbition on use of lubricants containing NL-07-153 Audit Items MoS2 for boltin1~.

201,241, The Bolting lnt13grity Program manages loss of NL-13-122 270 preload and loss of material for all external bolting.

NL-17-127 Docket Nos. 50-247 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 progiram 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 leakag<<~ and of conditions affecting the risk for corrosion. Classify pipe segments and tariks 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 /

I 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 I

IP2: Complete NL-07-039 A.2.1.8 4 Enhance the Diesel Fuel Monitoring Program to include cleaning and inspection of the IP2 GT-1 gas A.3.1.8 IP3: Complete NL-13-122 B.1.9 turbine fuel oil :storage tanks, IP2 and IP3 E.DG fuel NL-07-153 Audit items oil day tanks, IP2 SBC/Appendix R diesel generator NL-15-121 128, 129, fuel oil day tanl<, and IP3 Appendix R fuel oil storage 132, tank and day tank once every ten years.

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-17-127 Docket Nos. 50-24 7 and 50-286 Attachment 3 Page 3 of 22

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION/

AUDIT ITEM Enhance the D.iesel Fuel Monitoring Program to include thickness measurement of the bottom of the following tanks once every ten years. IP2: EOG fuel oil storage tan~:s, EOG fuel oil day tanks, SBC/Appendix R diesel generator fuel oil day tank, GT-1 gas turbine fuel oil storage tanks, and diesel fire pump fuel c,il storage tank; IP3: EOG fuel oil day tanks, EOG fued 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 addiUon of chemicals including biocide when the preseince of biological activity is confirmed.

5 IP2: Complete NL-07-039 A.2.1.10 Enhance the External Surfaces Monitoring Program I for IP2 and IP3 to include periodic inspections of A.3.1.10 NL-13-122 B.1.11 systems in scope and subject to aging management review for license renewal in accordance with 10 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 cc,uld impact the subject systems will include SSCs that are in scope and subject to aging J management review for license renewal in accordance with 10 CFR 54.4(a)(2).

NL-17-127 Docket Nos. 50-247 and 50-286 Attachment 3 Page 4 of 22

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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, a1s 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 B.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 monitorin£1 procedures.

Enhance the Fatigue Monitoring Program for IP3 to include all the transients identified. Assure all fatigue analysis transi1:mts 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 (i11cluding 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 IP:~ diesel fire pump engine carbon steel exhaust components are inspected for evidence of corrosion and c;racking 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 CO2 fire suppression system for signs of degradation, such as corrosion and mechanical damage at least once every six months.

NL-17-127 Docket Nos. 50-247 and 50-286 Attachment 3 Page 5 of 22

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION/

AUDIT ITEM IP2: Complete NL-07-039 A.2.1.13 8 Enhance the F ire Water Program to include A.3.1.13 inspectio n of II::,2 and I P3 hose reels for evidence of NL-13-122 8.1.14 corrosion. Ace:eptance criteria will be revised to NL-07-153 Audit Items verify no unacGeptable signs of degradation.

105, 106 Enhance the F ire Water Program to replace all or NL-08-014 test a sa111ple of IP2 and IP3 sprinkler heads required f or 10 CFR 50.48 using guidance of NFPA 25 (2002 editic1n), Section 5.3.1.1.1 before the end of the 50-yei arsp rinkler head service life and at 10-year _,,

intervals t here after during the extended period of operation to er1sure that signs of degradation, such as corrosi on, a re detected in a timely manner.

Enhance the F ire Water Program to perform wall thickness eval uations of IP2 and IP3 fire protection piping on syste:m components using non-intrusive technique s (e. tL volumetric testing) to identify evidence of los,s of material due to corrosion. These inspectio1nswi II be performed before the end of the current 01perat iing term and at intervals thereafter during th<<3 per"10d of extended operation. Results of the initial evalu ations will be used to determine the appropric:1te ins pection interval to ensure aging effects areide ntified prior to loss of intended function.

Enhance the F ke Water Program to inspect the internals urface of foam based fire suppression tanks. Ac cepta nee criteria will be enhanced to verify no signifo::ant c orrosion.

IP2 & IP3: NL-14-147 A.2.1.13 lmplemer1t LRI\ Sections, A.2.1.13, A.3.1.13 and December 31, 2019 A.3.1.13 8.1.14, a:s sho wn in NL-14-147.

8.1.14 IP2 & IP3: NL-15-019 A.2.1.13 lmplement LRI\ Sections A.2.1.13, A.3.1.13 and December 31, 2019 A.3.1.13 8.1.14, a:s shown in NL-15-019 8.1.14 IP2 & IP3: NL-15-092 A.2.1.13 lmplemer1t LRJl, Sections A.2.1.13; A.3.1.13 and December 31, 2019 A.3.1.13 8.1.14, ais shown in NL-15-092 8.1.14

\

NL-17-127 Docket Nos. 50-247 and 50-286 Attachment 3 Page 6 of 22

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION/

' AUDIT ITEM IP2 & IP3: NL-16-122 A.2.1.13 lmglemer,t LRfI. Sections A.2.1.13, A.3.1.13 and December 31 2017 A.3.1.13 B.1.14, a:s shm11,n in NL-16-1224 B.1.14 IP2 & IP3: NL-17-052 A.2.1.13 lmplemer,t LRfI. Sections A.2.1.13, A.3.1.13, and B.1.14, a:s she, IVn in NL-17-052 December 31, 2017 A.3.1.13 B.1.14 IP2: Complete NL-07-039 A.2.1.15 9 Enhance the Fiux Thimble Tube Inspection Program A.3. ~ .15 for IP2 an dlP3 to implement comparisons to wear IP3: Complete NL-13-122 B.1.16 rates ider,tified in WCAP-12866. Include provisions NL-15-121 to compa re dat a to the previous performances and perform ei valua tions regarding change to test frequenc11 and scope.

Enhance the Fllux Thimble Tube Inspection Program for IP2 ar1d IP3 to specify the acceptance criteria as outlined i1nWCAP-12866 or other plant-specific values bc:1 sed a,n evaluation of previous test results.

Enhance the Flux Thimble Tube Inspection Program for IP2 ar1d IP3 to direct evaluation and performance of correct ive ac:tions based on tubes that exceed or are projec::ted t c> exceed the acceptance criteria. Also stipulate fl,hat fl ux thimble tubes that cannot be inspected over the tube length and cannot be shown by analys is to be satisfactory for continued service, must be remov ed from service to ensure the integrity of the rea. ctor c oolant system pressure boundary.

4 This commitment erroneously deleted in NL-17-052

NL-17-127 Docket Nos. 50-247 and 50-286 Attachment 3 Page 7 of 22

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION/

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 8.1.17, exchange1rs in the scope of the program.

NL-07-153 Audit Item

• Safety injection pump lube oil heat NL-15-121 52 exchan !~ers

• RIHR heiat exchangers

• RIHR plimp seal coolers

• Non-re~1enerative heat exchangers

• Chargin g pump seal water heat exchangers

• Chargin g pump fluid drive coolers

• Chargin g pump crankcase oil coolers

• Spent f uel pit heat exchangers

• S1~cond ary system steam generator sample coolers

• Waste~;ias compressor heat exchangers

• SBO/A~>pendix R diesel jacket water heat exchan !~er (IP2 only) \

Enhance the H eat Exchanger Monitoring Program '-

for IP2 and IP3 to perform visual inspection on heat exchange1rs wh ere non-destructive examination, such as eddy c urrent inspection, is not possible due to heat e"chan s;ier design limitations.

Enhance the H eat Exchanger Monitoring Program for IP2 and IP3 to include consideration of material-environment cc,mbinations when determining sample population of h1eat exchangers.

Enhance the H eat Exchanger Monitoring Program for IP2 and IP3 to establish minimum tube wall thickness for th e new heat exchangers identified in the scope1 of th 1e program. Establish acceptance criteria for heat exchangers visually inspected to include no indi cation of tube erosion, vibration wear, corrosion, pittin19, fouling, or scaling.

(

NL-09-018

NL-17-127 Docket Nos. 50-24 7 and 50-286 Attachment 3 Page 8 of 22

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION/

AUDIT ITEM NL-09-056 11 Deleted NL-11-101 IP2: Complete NL-07-039 A.2.1.18 12 Enhance the IVlasonry 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 8.1.19 the progr am.

IP2: Complete NL-07-039 A.2.1.19 13 Enhance the IVletal-Enclosed Bus Inspection A.3.1.19 Program for IP 2 and IP3 to visually inspect the IP3: Complete NL-13-122 8.1.20 external isurfac e of MEB enclosure assemblies for NL-07-153 Audit Items loss of materia I at least once every 10 years. The NL-15-121 124, first inspe ction will occur prior to the period of NL-08-057 133,519 extended operation and the acceptance criterion will be no sig nifica nt loss of material.

NL-13-077

!

Enhance the IVletal-Enclosed Bus Inspection Program to ad d acceptance criteria for MEB internal visual ins pecticms to include the absence of indication s of d ust accumulation on the bus bar, on the insulcltors, and in the duct, in addition to the absence of ind ications of moisture intrusion into the duct.

Enhance the Metal-Enclosed Bus Inspection Program for IP 2 and IP3 to inspect bolted connectio ns at least once every five years if performe1d visu ally or at least once every ten years using qUcmtitative measurements such as thermogr,aphy or contact resistance measurements.

The first i nspe c:tion will occur prior to the period of extended operation.

The plant willp recess a change to applicable site procedun~tore1move the reference to "re-torquing" connectic1 ns fo r phase bus maintenance and bolted connectic1n ma intenance.

IP2: Complete NL-07-039 A.2.1.21 14 lmplemer1t the Non-EQ Bolted Cable Connections A.3.1.21 Program*for IP:2 and IP3 as described in LRA IP3: Complete NL-13-122 8.1.22 Section B .1.22 NL-15-121

NL-17-127 Docket Nos. 50-24 7 and 50-286 Attachment 3 Page 9 of 22

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION/

AUDIT ITEM IP2: Complete NL-07-039 A.2.1.22 15 lmpleme nt the Non-EQ Inaccessible Medium-A.3.1.22 Voltage<~able .Program for IP2 and IP3 as described IP3: Complete NL-13-122 B.1.23 in LRA Sectior1 B.1.23.

NL-07-153 Audit item This new prog ram will be implemented consistent NL-15-121 173 with the corres ponding program described in NL-11-032 NUREG- 1801 Section XI.E3, Inaccessible Medium-Voltage C~able s Not Subject To 10 CFR 50.49 NL-11-096 Environrn ental Qualification Requirements.

NL-11-101 IP2: Complete NL-07-039 A.2.1.23 16 lmpleme1nt the Non-EQ Instrumentation Circuits Test A.3.1.23 Review Progra m for IP2 and IP3 as described in IP3: Complete NL-13-122 B.1.24 LRA Sec tion B .1.24.

NL-07-153 Audit item This new prog ram will be implemented consistent NL-15-121 173 with the c:orres ponding program described in 0 NUREG- 1801 Section XI.E2, Electrical Cables and Connecti ons Not Subject to 10 CFR 50.49 Environm ental Qualification Requirements Used in lnstrume ntatio n Circuits.

IP2: Complete NL-07-039 A.2.1.24 17 lmpleme1,t the Non-EQ Insulated Cables and Connecti,ons Program for IP2 and IP3 as described A.3.1.24 IP3: Complete NL-13-122 B.1.25 in LRA 81action B.1.25.

NL-07-153 Audit item This new prog ram will be implemented consistent NL-15-121 173 with the c:orres ponding program described in NUREG- 1801 Section XI. E 1, Electrical Cables and Connecti1:msN ot Subject to 10 CFR 50.49 Environm ental Qualification Requirements.

NL-17-127 Docket Nos. 50-247 and 50-286

• Attachment 3 Page 10 of 22

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION/

AUDIT ITEM IP2: Complete NL-07-039 A.2.1.25 18 Enhance the C)ii Analysis Program for IP2 to sample A.3.1.25 and analyzelu bricating oil used in the SBO/Appendix IP3: Complete NL-13-122 8.1.26 R diesel gener*ator consistent with the oil analysis for NL-11-101 other site~ dies 131 generators.

NL-15-121 Enhance the C)ii Analysis Program for IP2 and IP3 to sample c:t nd an alyze generator seal oil and turbine hydraulic: cont rel oil.

Enhance the C>ii Analysis Program for IP2 and IP3 to formalize: preli mi nary oil screening for water anq particulates an d laboratory analyses including defined c:1 ccept:ance criteria for all components included in the scope of this program. The program will speci fy carrective actions in the event acceptani ce eriteria are not met.

Enhance the CIii Analysis Program for IP2 and IP3 to formalize trencHng of preliminary oil screening results as well a:s data1 provided from independent laboratori es.

IP2: Complete NL-07-039 A.2.1.26 19 lmpleme1,t the One-Time Inspection Program for IP2 A.3.1.26 and IP3 a s de scribed in LRA Section 8.1.27.

IP3: Complete NL-13-122 8.1.27 This new prog ram will be implemented consistent NL-07-153 Audit item with the c: orres ponding program described in NL-15-121 173 NUREG- 1801 ,Section XI.M32, One-Time lnspectio n.

IP2: Complete NL-07-039 A.2.1.27 20 lmplemer,t the One-Time Inspection - Small Bore Piping Pr ogran, for IP2 and IP3 as described in LRA A.3.1.27 IP3: Complete NL-13-122 8.1.28 Section El .1.28 NL-07-153 Audit item This new prog ram will be implemented consistent NL-15-121 173 with the c: orres ponding program described in NUREG-*1801 ,Section XI.M35, One-Time Inspection of ASME Code Class I Small-Bore Piping.

IP2: Complete NL-07-039 A.2.1.28 21 Enhance the P,eriodic Surveillance and Preventive Maintena nee Program for IP2 and IP3 as necessary A.3.1.28 IP3: Complete NL-13-122 8.1.29 to assure that the effects of aging will be managed such that appl icable components will continue to NL-15-121 perform ti1eir intended functions consistent with the current lie:ensi ng basis through the period of extended aperation.

NL-17-127 Docket Nos. 50-247 and 50-286 Attachment 3

_)

Page 11 of 22

1. COMMITMENT IMPLEMENTATION SOURCE RELATED

.\

SCHEDULE LRA SECTION/

AUDIT ITEM IP2 & IP3: NL-16-122 A.2.1.28 lm12leme11t LR.t~ Sections A.2.1.28, A.3.1.28 and December 31 2017 A.3.1.28 8.1.29, a s sho wn in NL-16-1225 8.1.29 IP2 & IP3: NL-17-052 A.2.1.28 lmpleme11t LR.t~ Sections A.2.1.28, A.3.1.28 and December 31, 2017 A.3.1.28 8.1.29, a s sho wn in NL-17-052 8.1.29 IP2 & IP3: NL-17-127 A.2.1.28 lm12leme1,t LR.t~ Sections A.2.1.28, A.3.1.28 and December 31 2018 A.3.1.28 8.1.29, a s shown in NL-17-127 8.1.29 IP2: Complete NL-07-039 A.2.1.31 22 Enhance the Reactor Vessel Surveillance Program A.3.1.31 for IP2 ar1d IP3, revising the specimen capsule IP3: Complete NL-13-122 8.1.32 withdraw,3lsch edules to draw and test a standby NL-15-121 capsule t 0 cov13r the peak reactor vessel fluence expected throu gh the end of the period of extended operation Enhance the Reactor Vessel Surveillance Program for IP2 ar1d IP3, to require that tested and untested specimen s frorn all capsules pulled from the reactor vessel ar,e mai ntained in storaqe.

IP2: Complete NL-07-039 A.2.1.32 23 lmplemer,t the Selective Leaching Program for IP2 A.3.1.32 and IP3 ~* s des.cribed in LRA Section 8.1.33.

IP3: Complete NL-13-122 8.1.33 This new prog ram will be implemented consistent NL-07-153 Audit item with the c: orres ponding 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 I P3to require that the results of the IP3: Complete NL-13-122 8.1.35 condition moni taring assessment are compared to the opera1 tiona I assessment performed for the prior operating cycle: with differences evaluated.

Enhance the Structures Monitoring Program to IP2: Complete NL-07-039 A.2.1.35 25 explicitly *speci fy that the following structures are A.3.1.35 included i n the program. IP3: Complete NL-13-122 8.1.36

• Appel1dix R'. diesel generator foundation (IP3) NL-07-153

• Appel1dix R'. diesel generator fuel oil tank vault NL-15-121 Audit items (IP3) 86, 87, 88,

• Appel1dix R: diesel generator switchgear and NL-08-057 417 enclo:sure (IP3) 5 This commitment erroneously deleted in NL-17-052

NL-17-127 Docket Nos. 50-24 7 and 50-286 Attachment 3 Page 12 of 22

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION/

AUDIT I

ITEM

• city water storage tank foundation

• condEmsate, storage tanks foundation (IP3) NL-13-077

• containmer1t access facility and annex (IP3)

• discharge c:anal (I P2/3)

• emeq~ency lighting poles and foundations (IP2/3)

• fire pumph<)Use (IP2)

• fire protecti on pumphouse (IP3)

• fire water storage tank foundations (IP2/3)

• gas turbine 1 fuel storage tank foundation

• maintenanc:e and outage building-elevated passagewa1y (IP2)

• new s;tation security building (IP2)

• nuclear service building (IP1)

• primary wa ter storage tank foundation (IP3)

• refueling w ater storage tank foundation (IP3)

• security access and office building (I P3)

• servic:e wat er pipe chase (IP2/3)

• servic:e wat er valve pit (IP3)

• transforme r/switchyard support structures (IP2)

• waste, hold up 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, t he following commodities (including their ancllorag E~s) are inspected for each structure as applicabl*~-

• cable trays and supports

• concrete pc>rtion of reactor vessel supports

• conduits an1d supports

• cranes, rail s and girders

• equipment pads and foundations

• fire proofin ~J (pyrocrete)

• HVAC duct supports

• jib cranes

• manholes c,nd duct banks

\

• manways, hatches and hatch covers

• monorails

• new fuel st <)rage racks

• sumps NL-13-077

NL-17-127 Docket Nos. 50-247 and 50-286 Attachment 3 Page *13 of 22

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION/

AUDIT ITEM Enhance the Structures Monitoring Program for IP?

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 si!~nificant concrete degradation is occurring.

Enhance the Structures Monitoring Program for IP2 and IP3 to perform inspections of elastomers (seals, 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 sa1mples to assess aggressiveness of groundwater to concrete on a periodic basis (at least once every five years). IPEC will obtain samples NL-08-127 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 leaka~1e, IPEC will sample for tritium in groundwater WE~lls 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 normai frequency of once per 5 years during the PEO. Audit Item 358

NL-17-127 Docket Nos. 50-247 and 50-286 Attachment 3 Page 14 of 22

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION/

AUDIT ITEM 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. NL-11-032 NL-11-101 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 B.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) ProQram.

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 Stafnless 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 chemi,stry 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\lP2 and IP3 security generator and fire protection diesel cooling water pH and glycol within limits specified by EPRI Quidelines.

IP2: Complete NL-07-039 A.2.1.40 29 Enhance the Water Chemistry Control - Primary and 8.1.41 Secondary Program for IP2 to test sulfates monthly NL-13-122 in the RWST with a limit of <150 ppb.

NL-17-127 Docket Nos. 50-247 and 50-286 Attachment 3 Page 15 of 22

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION/

AUDIT ITEM 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 '

'1 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 NL-11-107 operation, submit an inspection plan for reactor internals to the NRC for review ahd approval.

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 Prooram.

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 ~pproximately 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.

NL-17-127 Docket Nos. 50-247 and 50-286 Attachment 3 Page 16 of 22

1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION/

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 exceeding a CUF of 1.0.

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AUDIT ITEM

~omplete NL-13-122 2.1.1.3.5 34 IP2 SBO / Appendix R diesel generator will be NL-07-078 installed and operational by April 30, 2008. This 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 NL-11-101 required.

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 samples are taken prior to the end of the first ten years of the period of extended operation, a sample of leakage fluid will be analyzed.

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AUDIT ITEM 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 indi_cations 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.

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 I,

• • - *J" be provided to the NRC.

NL-09-079 39 Deleted IP2: Complete NL-09-106 8.1.6 40 Evaluate plant specific and appropriate industry 8.1.22 operating experience and incorporate lessons IP3: Complete NL-13-122 8.1.23

~earned_ in establishing appropriate monitoring and NL-15-121 8.1.24 1nspect~on 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 41 Deleted NL-17-005 N/A

.I

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AUDIT ITEM NL-11-032 N/A 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)

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

\ 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 generators.

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

IP2: Complete NL-11-032 N/A 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 IP2: Complete NL-11-032 N/A 45 IPEC will not use the NB-3600 option of the 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 IP2: Complete NL-11-032 NIA 46 Include in the IP2 ISi Program that IPEC will perform twenty-five volumetric weld metal inspections of NL-11-074 socket welds during each 10-year ISi interval NL-13-122 sch_eduled 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 N/A l

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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 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 supplementedwith 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 for 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 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

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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 8.1.34, as shown in NL-17-052 8.1.34 IP2 & IP3: NL-17-127 A.2.1.33 lmi:2lement LRA Sections A.2.1.33, A.3.1.33 and December 31 2018 A.3.1.33 8.1.34, as shown in NL-17-127 8.1.34 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 8.1.42, as shown in 8.1.43 NL-15-019.

May31,2018 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 '

8.1.2 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 December 31, 2017 NL-17-060 A.2.1.34 54 as follows. A.3.1.34 8.1.35

• Revise applicable procedures to specify a general visual inspectfon 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.