ML17132A175

Indian Point, Units 2 and 3, Reply to Request for Additional Information for the Review of the License Renewal Application, Set 2017-01

ML17132A175
Person / Time
Site:	Indian Point
Issue date:	05/08/2017
From:	Vitale A J Entergy Nuclear Northeast
To:	Document Control Desk, Office of Nuclear Material Safety and Safeguards
References
CAC MD5407, CAC MD5408, NL-17-052
Download: ML17132A175 (49)

Text

A Entergx Entergy Nuclear Northeast Indian Point Energy Center 450 Broadway, GSB P.O. Box 249 Buchanan, NY 10511-0249 Tel (914) 254-6700 NL-17-052 May 8, 2017 Anthony J Vitale Site Vice President U.S. Nuclear Regulatory Commission Document Control Desk 11545 Rockville Pike, TWFN-2 F1 Rockville, MD 20852-2738

Dear Sir or Madam:

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) Docket Nos. 50-247 and 50-286 License Nos. DPR-26 and DPR-64 ( 1) USN RC letter, "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 March 8, 2017 (ML 17046A231) 2) USN RC letter, "Summary of Telephone Conference Call Held On March 15, 2017, Between the U.S. Nuclear Regulatory Commission and Entergy Concerning Requests for Additional Information Pertaining to the Indian Point Unit Nos. 2 and 3, License Renewal Application (CAC. Nos. MD5407 and MD5408) 3) Entergy Letter NL-17-021, "Notification of Permanent' Cessation of Power Operations, Indian Point Nuclear Generating Unit Nos. 2 and 3" (February 8, 2017) Entergy Nuclear Operations, Inc. (Entergy) is providing in Attachment 1, the additional information requested by the U.S. Nuclear Regulatory Commission (NRC) pertaining to the review of the License Renewal Application (LRA) for Indian Point Energy Center (IPEC) Unit Nos. 2 and 3. (Reference 1) Reference 1 identifies a response due date of within 30 days from the date of the letter. Subsequently, as a result of discussions held with Entergy during a March 15, 2017 conference call, the NRC staff granted a request by Entergy to provide this information within 60 days ofthe date of the letter. (Reference 2)

NL-17-052 I Docket Nos. 50-247 and 50-286 Page 2 of 2 Changes to the LRA sections resulting from the responses in Attachment 1 are provided in Attachment 2. Changes to the List of Regulatory Commitments are provided in Attachment 3. If you have any questions, or require additional information, please contact Mr. Robert Walpole at 914-254-6710. I declare under penalty of perjury that the foregoing is true and correct. Executed on fAA< e . 2011. Sincerely, AJV/mm Attachments: 1. Reply to NRC Request for Additional Information Regarding the License Renewal Application* 2. License Renewal Application Changes Due To Responses To Requests For Information 3. License Renewal Application IPEC List of Regulatory Commitments Revision 31 cc: Mr. Daniel H. Dorman, Regional Administrator, NRC Region I Mr. Sherwin E. Turk, NRC Office of General Counsel, Special Counsel Mr. William Burton, NRC Senior Project Manager, Division of License Renewal Mr. Richard Guzman, NRR Senior Project Manager Ms. Bridget Frymire, New York State Department of Public Service Mr. John B. Rhodes, President and CEO NYSERDA NRC Resident Inspector's Office ATTACHMENT 1 TO NL-17-052 RESPONSE TO NRC 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) ENTERGY NUCLEAR OPERATIONS, INC. INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 & 3 DOCKET NOS. 50-247 AND 50-286

/ NL-17-052 Docket Nos. 50-247 and 50-286 Attachment 1 Page 1 of 16 RESPONSE TO NRC 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) RAI 3.0.3-9a Background The response to RAI 3.0.3-9 dated December 2,' 2016, states the following changes to the "acceptance criteria" and "corrective actions" program elements of the Fire Water System Program and Periodic Surveillance and Preventive Maintenance Program: a. Additional wall thickness measurements will be conducted when degraded conditions are detected: b. "[i]n addition 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 the end of calculated life." c. "[i]n addition, Entergy will revise the IPEC Fire Water System Program procedures to specify that when individual piping segments are found with multiple leaks or degraded areas that align to indicate selective seam corrosion, then corrective action will be taken to replace the affected piping segment." By letter dated July 25, 2016, the staff submitted RAI 3.0.3-9. In this RAI, the staff noted September 30, 2003, and December 29, 2014, leaks in the fire protection-water system that resulted in the affected header being out of service for multiple hours. In regard to bullets (a) and (b), as demonstrated with the two events where leakage resulted in the fire water header being removed from service, use of a service life calculation based on structural integrity might not be adequate to provide reasonable assurance that future leaks will not result in a loss of intended function. During a supplemental audit conducted on February 23-25, 2016, the staff reviewed several of the applicant's calculations associated with wall thickness measurements of the fire protection-water system. The staff conducted an independent projection of corrosion rates and compared the result to structural integrity requirements.* It would appear that structural integrity requirements would have been met in the days preceding the two events. The staff reiterated this point during a public meeting conducted on October 4, 2016. The meeting summary states: Regarding the additional inspections, the NRC staff asked Entergy what the acceptance criteria [for wall thickness measurements] would be. Entergy stated that the degradation would be evaluated by performing a calculation to determine the remaining useful life for the piping relative to structural integrity. The staff stated that acceptance criteria for structural integrity does not address future /

NL-17-052 Docket Nos. 50-247 and 50-286 Attachment 1 Page 2 of 16 leaks, as discussed during the staff's February audit regarding a fire water system leak. In regard to bullet (c), the staff lacks sufficient information to confirm that the additional corrective individual piping segments are found [in the fire protection-water system] with multiple leaks or degraded areas that align to indicate selective seam corrosion ... " is sufficient to encompass all future potentially degraded configurations. A single leak could result in the need to remove the header from service for repairs. Also, the additional criterion is not applicable to the city water system, which is constructed of a similar material, exposed to the same environment, and has experienced multiple leak!:!. In regard to bullets (b) and (c), as stated with the leak that occurred on September 10, 2003, "[t]he rate of discharge and potential for runoff to adjacent safety-related equipment areas mandated that the fire water supply system be secured ... " at least one fire water system leak had the potential for a nonsafety-related component to affect the function of safety-related components. No basis was provided for why piping segments with multiple leaks or degraded areas are acceptable to be returned to service without evaluating the potential effect on the intended function of the system, or safety-related components or systems in the vicinity of the leak. In summary, if it is demonstrated that structural integrity requirements would have been met in the days preceding the leaks, the staff lacks sufficient information to conclude that the proposed acceptance criteria and corrective actions associated with recurring internal corrosion (RIC) in the fire protection-water system and city water system will be adequate to: (a) provide reasonable assurance that the systems will meet their intended function and (b) that failure of one of the systems will not impact the intended function of a safety-related component or system. For example the "acceptance criteria" and "corrective actions" program elements should discuss:

• Acceptance criteria for the maximum size pit or general corrosion that would be accepted as well as the acceptable proximity for multiple pits or multiple regions of general corrosion beyond the acceptance criteria.

• Physical compensatory actions (e.g., leak limiting device) that will be implemented until repairs can be completed, including: (a) how the need for the extent (i.e., axial length) of the physical compensatory actions will be determined; (b) timing of installation of the physical compensatory actions; and (c) follow-up inspections that will be conducted during the time period prior to the repair of the piping. Request 1. Provide a summary of the results (e.g., wall thickness measurements, required wall thickness) that would or would not support a conclusion that the degradation of the piping associated with the September 30, 2003, and December 29, 2014, leaks in the fire protection-water system would have met structural integrity requirements in the days preceding the leak.

Response NL-17-052 Docket Nos. 50-247 and 50-286 Attachment 1 Page 3 of 16 September 10. 2003 event (CR-IP2-2003-05642) UT readings were taken following this event. The nominal pipe thickness is 0.280", with a minimum allowable thickness of 87.5%, or 0.245". With the exception of the region surrounding the flaw at the leak location, the measured wall thickness was Based on these results, combined with a structural calculation addressing the character of the piping flaw and expected growth rate, it was determined that the as-found piping segment was acceptably robust for short-term (30 days) service (with a repair clamp installed at the flaw location), pending replacement. December 29. 2014 event (CR-IP2-2014-06668) No UT readings were documented following this event. The affected piping segment was replaced prior to returning the system to service. However, UT readings taken on the affected piping segment in 2008, in response to a pinhole leak, indicated remaining wall thickness at that time. The nominal pipe thickness is 0.365", with a minimum allowable thickness of 87.5%, or 0.319". At all locations, but the reported leak location, the measured wall thickness was Based on the measured wall thickness, Indian Point Energy Center (IPEC) concluded that the affected piping segments were sufficiently structurally robust to support a conclusion of boundary integrity going forward following the 2008 pinhole leak. Request 2. If it is demonstrated that structural integrity requirements would have been met in the days preceding the leaks: * -Response a. State the basis for why the proposed acceptance criteria and corrective actions for RIC in the fire protection water system and city water systems are adequate.

• The established acceptance criteria and the implemented corrective actions were deemed adequate to provide reasonable assurance of short-term fire protection water system pressure boundary integrity. Adequacy of structural integrity was reasoned to provide adequate assurance that a large-scale leak would not occur, pending replacement of the affected piping segments. This is consistent with experience regarding subsequent leaks from other piping segments that had been deemed acceptable for structural integrity following discovery of leaks.

• Going forward, any leaking fire protection I city water pipe segments will be promptly repaired (e.g., installation of leak repair clamp), while also .entering the condition into the work control process to effect replacement of the impacted segment(s). Calculational projections of future structural integrity of piping segments, based on assumed rates, will continue to be completed, but these results will not be used as the sole means of determining the need and timing of piping segment replacement. The basis for NL-17-052 Docket Nos. 50-24 7 and 50-286 Attachment 1 Page 4of16. acceptance criteria and enhanced corrective action include a focus on identifying indications of selective seam corrosion (as previously experienced), which is the limiting case capable of presenting a large corrosion-induced piping leak, potentially requiring a relatively broad-scope system isolation to enable repair. During the first quarter of 2017, IPEC completed a focused refurbishment project addressing fire protection piping system integrity. This project replaced those segments of the fire protection piping that had exhibited the most significant corrosion and recurrent leakage. These piping segments were typically legacy piping, that is, Unit 1 piping manufactured prior to 1970 using electric resistance and flash welding techniques resulting in a longitudinal seam weld susceptible to selective seam corrosion. With implementation of the refurbishment project and enhanced corrective actions, there is reasonable assurance that any leaks that may be experienced be limited to a nuisance level of water diversion. Request Response b. State the basis for why piping segments with multiple leaks or degraded areas are acceptable to be returned to service. Any leaks are evaluated and repaired, prior to returning the affected piping segment to service. An activity is concurrently entered into the IPEC 12-week work schedule for replacement of the affected piping. The leak repair and affected piping segment evaluations provide reasonable assurance of ongoing fire protection piping integrity, pending replacement of the degraded piping segment. Request Response c. Alternatively, propose additional acceptance criteria and corrective actions, and the basis for these changes, sufficient to provide reasonable

• assurance that the fire protection-water system and city water system will meet their intended function(s) and not impact the intended function of a safety-related component or system. As discussed in the response to Question 2(a), the most significantly impacted legacy (Unit 1) piping sections have been replaced. Going forward, the following acceptance criteria and corrective actions will apply to the fire protection and city water piping systems:

• If routine inspections identify evidence of selective seam corrosion, IPEC will replace the affected piping segment on an accelerated schedule within the 12-week work schedule. Based on the enhanced inspection schedule and improved understanding of the failure mechanism, and the growth rate, this approach is considered adequate to provide reasonable assurance of sustained piping integrity, pending the accelerated replacement. J NL-17-052 Docket Nos. 50-247 and 50-286 Attachment 1 Page 5 of 16

• Any discovered leaks that are not indicative of a pattern suggesting selective seam corrosion will be cause for entry of the affected piping segment(s) into the 12-week work schedule, for timely replacement. Interim repairs (clamps/patches) will be applied as necessary to ensure pressure boundary integrity and eliminate nuisance water runoff. In summary, going forward, the results of UT inspections that support a conclusion of adequate structural integrity on piping segments that exhibit significant corrosion or leaks will not be used as the sole basis for maintaining the affected piping in service for an indefinite time. Rather, work order(s) addressing such affected piping segments will be processed through the work control system, to provide assurance of timely piping replacement. RAI 3.0.3-9b Background 1. The response to RAI 3.0.3-9 dated December 2, 2016, states that wall thickness measurements will be conducted on the fire protection-water system and city water systems "until recurring internal corrosion has subsided." 2. The response to RAI 3.0.3-9 dated December 2, 2016, states, "[i]n addition, Entergy will revise the IPEC Fire Water System Program procedures to specify that when individual piping segments are found with multiple leaks or degraded areas that align to indicate selective seam corrosion, then corrective action will be taken to replace the affected piping segment." 3. The response to RAI 3.0.3-9 dated December 2, 2016, states that the Periodic Surveillance and Preventive Maintenance Program will be revised to include periodic internal visual or ultrasonic wall thickness measurements. Issue 1. The term "until RIC has subsided" as used in association with conducting wall thickness measurements is undefined .. LR-ISG-2012-02, Section 3.3.2.2.8, "Loss of material due to Recurring Internal Corrosion," defines RIC as, "if the search of plant-specific operating experience (OE) reveals repetitive occurrences (e.g., one per refueling outage cycle that has occurred over: (a) three or more sequential or nonsequential cycles for a 10-year OE search, or (b) two or more sequential or nonsequential cycles for a 5-year OE search) of aging effects with the same aging mechanism in which the aging effect resulted in the component either not meeting plant-specific acceptance criteria or experiencing a reduction in wall thickness greater than 50 percent (regardless of the minimum wall thickness)." It is not clear how "subsided" would be integrated with the criteria in LR-ISG-2012-02. 2. In regard to replacing piping segments that are found with multiple leaks or degraded areas that align to indicate selective seam corrosion, the changes to the program and updated final safety analysis report (UFSAR) supplement do not specify the timing of the replacement. 3. It is not clear to the staff how internal visual inspections conducted for the Periodic Surveillance and Preventive Maintenance Program will be capable of quantifying wall loss. l !

Request NL-17-052 Docket Nos. 50-24 7 and 50-286 Attachment 1 Page 6 of 16 1. State the basis for using the term "until RIC has subsided." Response The phrase "until RIC has subsided" was intended to mean until the frequency of occurrence of piping leaks and significant wall thinning no longer meets the criteria for characterization as "recurring internal corrosion" as defined in LR-ISG-2012-02; NUREG-1801,Section IX.F). The frequency will be assessed on a rolling five-year period. The use of the term "subsided" reflects a reduction in occurrences to a frequency below the threshold for classification as "RIC." Request 2. State the maximum time from discovery until when piping segments that are found with multiple leaks or degraded areas, that align to indicate selective seam corrosion, will be replaced. / Response Any piping that develops multiple leaks, including indications of selective seam corrosion, will be entered into the corrective action program, and into the work control system for accelerated replacement, consistent with the severity of the identified condition. The maximum time from discovery until the piping is replaced will be 12 weeks unless unforeseen circumstance.s necessitate additional time. Localized piping replacement can be implemented within as little as several days. Replacement of entire piping segments, if warranted, may require most of the standard 12-week work management schedule. Request 3. State the basis for how internal visual inspections will be able to quantify wall loss. Response Visual inspections provide a qualitative basis to determine the need for subsequent UT wall thickness measurements. Visual inspections also provide an effective means of identifying selective seam corrosion (observation of uniform alignment of multiple small corrosion sites). Visual inspections will enable the identification of piping segment failure candidates, to enable the scheduling of replacement of such segments prior to development of aggregate degradation leading to failure of the affected segment(s). RAI 3.0.3-10-1 a Background In its response dated December 2, 2016, for Request 1, Indian Point Energy Center (IPEC) stated that its OE reviews identified instances similar to the condition described in LER 286/2002-001 and noted that the "corrosion at the crevice of the cement lining on the carbon NL-17-052 Docket Nos. 50-24 7 and 50-286 Attachment 1 Page 7 of 16 steel piping welds has occurred and in some cases has resulted in a loss of intended function [emphasis added]." The response also states that a key element of the Service Water Integrity (SWI) program is the use of predictive monitoring. It also notes that IPEC personnel conduct an ongoing program of volumetric non-destructive examination (NOE) of service water welds to "ensure welds are repaired or re-inspected, thereby ensuring structural integrity is maintained and no loss of function occurs during the predicted remaining service life [emphasis added]." The staff is concerned about IP's predictive monitoring methodology as it relates to identifying areas of concern with examination (NOE) and predicting the remaining service life of the welds in cement-lined piping. See IPEC relief request 3-43 for illustrative example of issues. Although IPEC's recent response discusses additional inspections if degraded conditions are found, the response did not discuss what programmatic actions will be taken if any additional loss of intended function is identified. Loss of intended function has occurred in the past and it is unclear whether any consequent changes were made to the program. Request 1. For each of the examples identified during IPEC's OE search, where loss of intended function occurred (or where the predictive monitoring methodology did not prevent a loss of structural integrity for the predicted remaining service life), discuss any changes made to the SWI program's predictive monitoring process. Include any changes to either the NOE process for identifying areas of interest, or to the methodology for predicting the remaining service life of welds in the cement-lined piping that address the apparent causes for these failures of the SWI program. Response Entergy has reviewed losses of function from 2002 to the present as outlined in Licensee Event Reports for IPEC. The relevant LERs and a brief event description are listed in the table below. The notes in the discussion column refer to paragraphs following the table that include discussion of the cause and corrective actions for each event. LICENSEE EVENT REPORT (LER) and TITLE EVENT DESCRIPTION DISCUSSION CONDITION REPORT (CR) LER 286/2002-001 Operation in a Condition Prohibited by A pinhole leak occurred on an 18" cement-lined pipe Technical Specifications Due to an Inoperable to tee weld downstream of valve SWN-38. The leak NOTE 1 CR IP3-2002-2093 Service Water Pipe Caused by a Leak That rate was approximately one drop per second. Exceeded the AOT Technical Specification Required Shutdown The 1 O" service water supply line to various LER 286/2011-003 and a Safety System Functional Failure for a conventional coolers in the turbine building Leaking Service Water Pipe Causing Flooding developed a leak in the south service water valve pit NOTE2 CR IP3-2011-00680 in the SW Valve Pit Preventing Access for The leak rate was approximately 150 gallons per Accident Mitigation minute. LER 247/2013-004 Technical Specification (TS) Prohibited Eight pinhole leaks were identified on stainless steel Condition due to an Inoperable Essential service water pipe associated with radiation NOTE 3 CR IP2-2013-3759 Service Water (SW) Header as a Result of Pin monitors. This condition caused the pipe to be Hole Leaks in Code Class 3 SW Piping declared inoperable.

LICENSEE EVENT NL-17-052 Docket Nos. 50-247 and 50-286 Attachment 1 Page 8 of 16 REPORT (LER) and TITLE EVENT DESCRIPTION DISCUSSION CONDITION REPORT (CR) Service water was weeping from a %-inch socket Technical Specification (TS) Prohibited weld. While the operability evaluation deemed that LER 286/2014-002 failure of the affected weld would have no significant -Condition due to an Inoperable Essential impact on the ability of the SW system to perform its NOTE4 Service Water (SW) Header as a Result of a CR IP3-2012-2193 safety function, the piping was declared inoperable Socket Weld Leak in Code Class 3 SW Piping due to inability of NDE techniques to characterize the flaw. Technical Specification (TS) Prohibited LER 247/2015-001 Condition due to an Inoperable Containment Personnel discovered a leak on fan cooler unit motor Caused by a Service Water Pipe Leak with a cooler service water return line. The line is a 2-inch NOTES CR IP2-2015-3550 Flaw Size that Results in Exceeding the diameter copper-nickel line. \ Allowed Leakage Rate for Containment LER 247/2015-004 Safety System Functional Failure due to an Operations discovered a leak on a copper nickel Inoperable Containment Caused by a Flawed socket welded elbow in piping serving the 21 fan NOTES Elbow on the 21 Fan Cooler Unit Service cooler unit motor cooler outlet. This resulted in the CR IP2-2015-5755 Water Motor Cooling Return Pipe 21 fan cooler unit being declared inoperable. Safety System Functional Failure due to an A pipe leak was identified at a butt weld in the Class LER 286/2016-001 3 stainless steel service water return piping within Inoperable Containment Caused by a Flaw on containment. This constituted a breach of a closed NOTE 7 the 31 Fan Cooler Unit Service Water Return CR IP3-2016-3607 system within containment resulting in the loss of Coil Line Affecting Containment Integrity containment ooerabilitv. LER 247/2016-010 Safety System Functional Failure due to an A leak was found in a 3-inch carbon steel elbow in the service water supply piping to a fan cooler unit. Inoperable Containment Caused by a Through This constituted a breach of a closed system within NOTES CR IP2-2016-6934 Wall Defect in a Service Water Supply Pipe containment resulting in the loss of containment CR IP2-2016-7271 Elbow to the 24 Fan Cooler Unit operabilitv. Notes: 1. The root cause evaluation concluded that the cause of this leak was long-term crevice corrosion at the weld joint, possibly exacerbated by a poor quality weld. Structural calculations concluded that the piping at the leak location did not meet code requirements and the piping was therefore, declared inoperable. As documented in the 2002 root cause report, a review of operating experience identified a number of leaks on the system from 1997 to 2002, none of which failed to meet operability criteria. The leak that was the subject of this LER was therefore judged unique because of its impact on structural operability. NOE indicated that a similar weld on the redundant header was satisfactory. Activities to inspect an additional 4 welds were added to the next outage scope. No changes were made to the SWI predictive modelling process other than the increased number of inspections. 2. The cause of this event was corrosion of a weld following a less than adequate repair. The Service Water Integrity Program was updated after this event to add additional lines for inspection and to inspect non-safety-related piping within the scope of license renewal with the same priority as safety-related piping for the future program inspections. This program update was completed in 2011. In addition, guidelines were developed for work planning so that future repairs would be performed properly. 3. The piping was declared inoperable because of an inability to accurately characterize degradation associated with the affected socket weld fittings. The cause of the pin-hole leaks in this event was improper material use in the service water piping. In addition, poor prioritization of a project to replace the piping contributed to the event. Because the cause of this event was not attributed to a deficiency in the Service Water Integrity Program, no program changes were made to the SWI predictive modelling process.

NL-17-052 Docket Nos. 50-247 and 50-286 Attachment 1 Page 9 of 16 4. The cause of this socket weld leak was stagnant conditions in unlined carbon steel piping. As delineated in Entergy letter NL-16-122, dated December 2, 2016, Entergy will revise the program to establish recurring internal corrosion goals for stagnant vent and drain connection piping. If these recurring internal corrosion goals are not met, Entergy will increase the frequency for flushing the affected stagnant vent and drain connection piping. The program document will be revised to reflect this enhancement by December 31,2017. 5. The cause was piping flow rates higher than necessary leading to flow-accelerated corrosion at the weld joint. The corrective action was to reduce the flow in the piping. Because these issues did not involve deficiencies in the Service Water Integrity Program, the program was not revised. Corrective actions included adjusting system flow rates to lower the velocity in the affected piping. 6. The cause and corrective actions are the same as for the issue described in Note 5. 7. The most probable cause of this event is improper weld filler metal selection leading to I pitting and crevice corrosion. The leaking elbow was recently cut out and sent for failure analysis. Once the cause is confirmed, additional corrective actions will be assigned as appropriate. 8. The cause of this was inadequate procedural guidance for inspection of newly installed internal pipe coating resulting in a small defect in the internal coating of the piping elbow. The coating defect allowed brackish water to contact the carbon steel elbow and the subsequent corrosion led to the leak in the elbow. The elbow was removed, repaired and re-coated. Corrective actions include inspecting similar elbows in future outages, revising the maintenance procedure for the application and application inspection of epoxy coating, revising the SWIP to require internal inspections whenever the elbows are removed for maintenance, and updating the engineering training program for the SWIP qualification card regarding coating and lining inspections of fan cooler piping. In addition to the LER's listed in the above table, the issue related to relief request RR 3-43 is important to discuss. The relief request was related to a minor leak identified in September 2007 on a service water supply line for the IP3 containment fan cooler units. The degraded piping met the requirements of Code Case 513-1, however the projected corrosion rate did not support continued structural integrity for the remainder of the operating cycle. Relief was requested to allow a non-standard repair that would assure structural integrity for the remainder of the operating cycle. The system did not experience a loss of function and therefore the issue did not involve an LER. A contributing cause to the September 2007 leak was a less than adequate repair of a previous leak. Maintenance personnel did not adequately restore a protective coating over the repair to prevent corrosion due to brackish raw water. Although only recently implemented, a program improvement to prevent recurrence of events related to inadequate repairs was development of engineering report IP-RPT-16-00046, IPEC Service Water Piping Weld Repair Process and inspection Frequency Guidelines. The report provides Engineering guidelines to allow for consistent repairs to IPEC service water piping welds.

( NL-17-052 Docket Nos. 50-247 and 50-286 Attachment 1 Page 10of16 The details include repair process guidelines for leaks or pipe wall thinning found during Service Water Integrity Program inspections. It includes direction and guidance for evaluating the NOE data and information to characterize the defect. The guidelines include gridding standards for the UT inspections instructions to obtain additional UT data if needed to evaluate the defect. The report provides formal re-inspectio'n guidelines when welds are repaired. A formula is presented for standardized approaches for determining the next inspection interval. The report covers different weld configurations and repair techniques such as full penetration or partial penetration welds, grind-out and wall restorations, and overlays. Request 2. If changes were not made in response to any of the examples identified above, provide justification for the lack of changes to the predictive monitoring methodology to demonstrate that the effects of aging will be adequately managed so that the intended functions will be maintained. Also discuss how you are consistent with LRA Sections B.0.4, A.2.1, and A.3.1, as clarified in RAI responses dated July 14, 2011, and July 27, 2011, regarding appropriate program enhancements for past program failures if additional age-related losses of intended function occur in components managed by the SWI program. Response As discussed in the response to Request 1, corrective actions were taken in response to the identified events resulting in a loss of intended function. The causes of some events were not related to the Service Water Integrity Program. Therefore, the appropriate corrective actions do not necessarily involve changes to the program. Many program improvements have been implemented over time based on feedback from operating experience, the corrective action program and self-assessment activities. The following recent program inspection results are a positive indication Qf program effectiveness. In the most recent inspection period 3R19P (pre-outage) and 3R19 for Unit 3 in Februar}r and March of 2017, 50 service water system piping welds were examined by volumetric NOE methods. Thirty of the welds selected for examination were previously uninspected and 20 were follow-ups to previous exams. All 50 welds were found operable. Regarding the 30 previously uninspected welds, two of those welds were code repaired even though they were operable. One of the welds was evaluated using ASME code case N-513-3 and 5 additional welds were inspected as a result (refer to CR IP3-2017-856). The program uses engineering report IP-RPT-16-00046, IPEC Service Water Piping Weld Repair Process and Re-inspection Frequency Guidelines and engineering procedure EN-CS-S-008-MUL Tl to calculate remaining service life of the inspected welds. There were 4 previously uninspected welds that were found to require follow up exams in future outage periods due to minor degradation. Regarding the follow-up exams, 20 were performed in this inspection period. All 20 were found operable; however, it was decided to repair one of the welds because of its limited predicted remaining service life.

• NL-17-052 Docket Nos. 50-247 and 50-286 Attachment 1 Page 11 of 16 The response to Request 1 above includes examples of program changes made in response to operating experience. The operating experience review and corrective action programs will continue through the period of extended operation to improve performance of the Service Water Integrity Program as indicated in LRA Sections 8.0.4, A.2.1, and A.3.1, as clarified in RAI responses dated July 14, 2011, and July 27, 2011. RAI 3.0.3-10-2a Background The response to Request 2 states that the majority of the service water system leaks have been minor and do not result in a leak rate large enough to cause a loss of the system's intended function. This statement indicates that apparently there have been multiple instances where an excessive leak rate caused a loss of intended function in the past. During its onsite audit and review of past operating experience, the staff noted that several leaks resulted in more than minor leak rates (i.e., CR-IP3-2008-1318, CR-IP2-2013-1252, CR-IP2-2015-3744, and EN 52388) with leak rates between 1 gallon per minute and 15 gallons per minute. In addition, the staff notes Relief Request (RR) IP3-ISl-RR-10 which states that service water piping to a fan cooler unit must be isolated when an allowable leakage is exceeded and cites a Technical Specification 5.5.15 allowable leakage of 0.36 gallons per minute. The leak associated with LER 286/2011-003 demonstrates that leak rates less than that associated with a strict pressure boundary intended function (i.e., adequate flow and pressure) can cause an alternate loss of intended function due to spatial interaction effects of the leak in specific situations. So, in addition to loss of structural integritY,, some consideration must be given to the magnitude of a leak for determining the program's' effectiveness to prevent a loss of intended function. Although the SWI program does.not need to prevent all leakage, it needs to prevent leak rates that could cause a loss of intended function. It is unclear to the staff if the predictive methodology in the SWI program includes measures to ensure leak rates do not exceed some acceptance limit as an indication of a program failure. ' In addition, it is not clear whether there would be different acceptance limits for the portions of the service water system in different parts of the plant. If different acceptance limits are applicable (inside containment/outside containment, safety-related/nonsafety-related), then it is unclear if the SWI program manages aging differently for each of the various portions of the service water system to ensure the leak rates are not exceeded for each applicable part of the plant. As noted in SRP-LR Section 1.2.3.10, a past failure would not necessarily invalidate an , Aging Management Program (AMP) because the feedback from operating experience* should have resulted in appropriate program enhancements [emphasis added] or new programs. Request 1. For any past operating experience alluded to in the RAI response (where the leak rate was large enough to cause a loss of function), describe the circumstances for each occurrence and provide any changes that have been or will be made to SWI program activities to ensure future loss of intended function due to large leak rates will not occur.

Response NL-17-052 Docket Nos. 50-247 and 50-286 Attachment 1 Page 12 of 16 IPEC has reviewed all Licensee Event Reports submitted between 2004 and 2016, to identify events involving loss of function due to a high service water system leak rate. There was a Licensee Event Report (LER) written for a loss of safety function due to excessive leakage, namely LER 286/2011-003 involving a large leak in a service water valve pit. Corrective actions have been undertaken since that event. ' Other leaks that resulted in a loss of function include leaks in the service water system inside the vapor containment buildings at each unit (ref. CR-IP2-2015-03550, CR-IP2-2015-05755, CR-IP2-2016-06934/07271 & CR-IP3-2016-03607) where IPEC Technical Specification provide strict leakage limits of 0.36 gpm. However, such leaks are isolable and can be mitigated on-line by isolating the individual components. Technical Specifications allow isolation of service water to fan cooler units (FCU) for brief periods of time. If repairs are not completed within the allowed outage time," a station shut down would be required. Specific issues at Unit 2 (CR-IP2-2015-03550 & CR-IP2-2015-05755) involved two different leaks on the SW return piping from the 24 and 21 fan cooler unit motor coolers within containment. Two formal apparent cause evaluations were performed and corrective actions undertaken. The direct cause identified for both leaks was flow-accelerated corrosion (FAC). The corrective actions from the apparent cause evaluations included reducing the flow rate through this piping. Another issue at Unit 2 (CR-IP2-2016-06934/07271) involved a leak in an elbow in the SW supply to the 24 fan cooler unit main cooling coils within containment. A formal root cause evaluation was performed and corrective actions undertaken. The direct cause identified was a failure of interior coating allowing brackish river water to corrode the carbon steel pipe fitting. The corrective actions for this event included revising SWIP documents to include a requirement to conduct a visual inspection of the internal lining of all 3" FCU piping spool pieces, when removed, to be performed during future FCU cooling coil preventive maintenance activities during refueling outages. [CR-IP2-2016-07271 CA-00010]. A specific issue at Unit 3 (CR-IP3-2016-03607) involved a leak in the 31 fan cooler unit main cooling coil return piping within containment. A formal root cause evaluation was performed and corrective actions undertaken. Based upon the information available to date, a failure analysis will need to be performed on the section of pipe after it is removed. Upon completion of the failure analysis, the cause evaluation will be completed appropriate corrective actions will be promulgated. These corrective actions could include revisions to the SWIP. When applying ASME Code Case N-513-3 for operability evaluation, an extent of condition (EOC) evaluation is performed for all code class piping leaks. This is performed regardless of leakage rate and regardless of whether there was an associated loss of intended function. This* evaluation helps ensure similar susceptible locations are not degraded. Results of inspections performed for EOC evaluations are inputs into the selection of locations for the programmatic volumetric examination campaigns conducted at each unit during each operating cycle. In previous RAI responses, enhancements were proposed regarding future inspections and priority of inspections in locations where leak rates could affect functionality. In addition, the NL-17-052 Docket Nos. 50-247 and 50-286 Attachment 1 Page 13of16 program was changed in 2011 to increase the priority of inspections in non-safety portions of the service water system in areas such as the valve pit. '-Request 2. Provide the allowable leak rate limit and its bases, which the SWI program will use to determine whether aging is being adequately managed to prevent a loss of intended function. If different allowable leak rates will be used for different portions of the plant, provide the bases for each limit and address how aging will be managed differently in each portion of the plant. Response All service water piping leaks require a condition report and work order for repair. The condition report requires an evaluation to determine the system operability including evaluation of leakage rates against allowable values, such as those established for flooding concerns. Design basis allowable leak rates are considered in evaluating whether a leak results in a loss of intended function. 1 The Service Water Integrity Program will use the design basis allowable leak rates to prioritize future inspections. Different areas in the plant and different parts of the service water system have different allowable leak rates (e:g., IPEC Technical Specifications provide strict leakage limits of 0.36 gpm. Based on allowable leak rates, the program will prioritize inspections such that piping with more restrictive leakage rate limits will receive a higher percentage of inspections. The plant Technical Specifications and FSAR will be used to determine allowable leakage rates. This enhancement ")fill be implemented by December 31, 2018. IPEC will review the SW system to identify areas where leakage from non-safety related SW piping could result in unacceptable flooding. The SWI Program will be reviewed to verify that non-safety related piping, in locations subject to flooding concerns, is clearly identified in the program document. It was stated in the IPEC letter NL-16-122, dated December 2, 2016, the SWI Program will be revised to 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. This enhancement will be implemented by December 31, 2017. RAI 3.0.3-10-6a Background Based on information in RR 3-43 (2007) and RR IP3-008 (2013), IPEC determined that the average corrosion rate for the weld joints in the cement-lined piping was 0.012 inches per year. Based on the average corrosion rate cited by IPEC, the staff is concerned about the overall structural integrity of the service water system piping. The performance of additional inspections in response to a leak does not appear to address the broader structural integrity issue of the ongoing corrosion in the service water system. Since some large diameter service NL-17-052 Docket Nos. 50-247 and 50-286 Attachment 1 Page 14of16 water piping has a nominal wall thickness of 0.375 inches, with a corrosion rate of 0.012 inches per year it is unclear how piping code minimum wall thickness will be met based on the current years of operation. Although the cited corrosion rate is an average value, there are situations where the corrosion rate will be greater. Unless every pipe weld has been restored to a nominal value through ongoing maintenance activities, aging management does not seem adequate. Request 1. Discuss how the average corrosion rate of 0.012 inches per year was developed. Response The IPEC average corrosion rate of 0.012 inches per year cited in the RAI background discussion is a reference value used in structural calculations to estimate the expected remaining life of a weld if it is found degraded. The rate is based on a weld for which the concrete lining inside the pipe provides no protection from the raw water in the pipe. The 0.012 inch per year was developed by design structural engineers as they evaluated as-found conditions of the service water system. The value was determined in the 2006 time frame by assuming that leaks had taken about 31 years to develop (IP3 began operation in 1975). The nominal 0.375" wall thickness common to much of the large-bore service water piping was divided by 31 years to yield an estimated rate of 0.012 inches per year. This value is also used at IP2 due to its similar piping design. -Request 2. Explain how the SWI program assures intended functions are maintained for any scope weld that has not been inspected within the timeframe where the average corrosion rate could reduce the wall thickness to a value less than that needed for structural integrity. Response As discussed in response to Request 1, the value of 0.012 inches per year is an average over time at a specific location, typically leading to a pinhole leak; it is not a system-wide average over general areas. Significant corrosion only occurs where the protective lining inside the piping is breached leading to exposure of the weld to raw water. Through-wall corrosion typically occurs at a limited arc around the circumference of the pipe at a weld. Characterization of leaking piping commonly shows that structural integrity is maintained. A sample of system welds are inspected each cycle. A large number of inspect,ions have been performed over the previous 20 years. Results of the most recent inspections are provided in the response to Request 2 of RAI 3.0.3-10-1 a. Entergy will enhance the program to specifically sample a minimum number of system welds each operating cycle as delineated in Entergy letter NL-16-122, dated December 2, 2016. In addition, if degraded conditions are found, additional inspections will be 11>erformed. This will provide reasonable assurance that intended functions are maintained for in-scope welds that have not been inspected within the timeframe where the average corrosion rate could reduce the wall thickness to a value less than that needed for structural integrity.

RAI 3.0.3-10-7a Background NL-17-052 Docket Nos. 50-247 and 50-286 Attachment 1 Page 15of16 The RAI response dated December 2, 2016, states "Entergy has identified no past SW system through-wall issues at either IP2 or IP3 that have not been evaluated under the Corrective Action Program," and identifies the need to revise procedures as one aspect for implementing the enhancement. The staff notes that the response moved up the implementation date of the previous enhancements from December 31, 2019, to December 31, 2017. Based on the response, when combined with Management (CRG) request in CR-IP3-2009-1929, it is unclear to the staff whether any reviews were conducted of the work order system or other corrective maintenance processes to identify whether there were other instances, comparable to CR-IP3-2009-1929, where a condition report had not been initiated for service water system leaks. The current response now shows the implementation of the enhancements in IPEC letter NL-14-147 as December 2017 whereas prior correspondence showed December 2019. The staff is unsure if IPEC intended to make this change. Request 1. State whether work orders or other corrective maintenance processes were reviewed to confirm that all service water leaks have been captured and evaluated through the corrective action program. If reviews of work orders or other corrective maintenance processes were not conducted as the basis of the response, provide the bases for confidence that the causes of all past leakage that resulted in a loss of inter:ided function have been addressed by the current program.

• Response Station work orders and other corrective maintenance documents were not specifically searched when conducting the site operating experience (OE) review. The station condition report (CR) database was searched to gather the OE data. This was considered acceptable because the Corrective Action Program requires a CR to be written for a leak in service water system piping. Historically, station work requests were reviewed by a team of individuals from various work groups such as operations, work management, engineering, and maintenance. These \ individuals were knowledgeable enough to recognize potential operability or reportability issues when reviewing work orders. Their knowledge, training and experience provide a high level of confidence that CR's would have been written for conditions identified in work orders that affected operability such as service water piping leaks. Therefore, there is a high likelihood that the OE search was effective. In addition, for the time period of 2004-2014 inclusive, a review of CR's was performed to determine the number of CRG-requested CR's. The term "CRG request" was found in 115 CR's NL-17-052 Docket Nos. 50-247 and 50-286 Attachment 1 Page 16of16 out of the total of 119,200 written during that time period. That number represents less than 0.01 % of the total. With over 99.99% of the CR's generated without prompting by the CRG, there is high confidence that the OE search was effective. Request 2. Confirm the implementation date for the enhancemept discussed in IPEC letter NL-14-147. Since the enhancement is not scheduled to be completed for many months, provide interim actions that will provide assurance that all service water system leaks will be captured and evaluated through the corrective action program, or provide the bases for not needing any interim actions. Response The implementation date for the enhancement discussed in IPEC letter NL 14-147 was intentionally changed to December 2017. The established single-entry process for work order generation at IPEC requires condition report initiation for all corrective maintenance work requests. This process, effective September 2014, ensures all corrective maintenance issues are documented in the corrective action program. This provides confidence that relevant corrective maintenance will be identified during OE reviews using the corrective action program database. Even though the work management system includes these provisions to ensure .corrective maintenance activities are entered into the corrective action program, the subject enhancement was proposed for the Service Water Integrity Program to provide further assurance that all servite water leaks are evaluated in the corrective action program. Because of the above feature of the single-entry work order generation process, it is acceptable for the enhancement to be completed by the end of 2017.

, r ATTACHMENT 2 TO NL-17-052 LICENSE RENEWAL APPLICATION CHANGES DUE TO RESPONSES TO REQUESTS FOR INFORMATION ENTERGY NUCLEAR OPERATIONS, INC. INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 & 3 DOCKET NOS. 50-247 AND 50-286

• NL-17-052 Docket Nos. 50-247 and 50-286 Attachment 2 Page 1 of 6 LRA Sections A.2.1.13, A.2.1.28, A.2.1.33, A.3.1.13, A.3.1.28, A.3.1.33, B.1.14, B.1.29, and B.1.34 are revised as shown below. Additions are underlined. A.2.1.13 Fire Water System Program

• The Fire Water System Program procedures will be revised to ensure 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.

• The Fire Water System Program procedures will be revised to ensure 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. A.2.1.28 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 r:nanagement 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. I 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 recirculation pump motor cooling coils and housing o city water system piping, strainer housings and valve bodies 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.

A.2.1.33 Service Water Integrity Program NL-17-052 Docket Nos .. 50-247 and 50-286 Attachment 2 Page 2 of 6

• 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 maintenance activities.

• The Service 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 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 mechanism 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. A.3.1.13 Fire Water System Program

• The Fire Water System Program procedures will be revised to ensure 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. ,

• The Fire Water System Program procedures will be revised to ensure 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. A.3.1.28 Periodic Surveillance and Preventive Maintenance Program In addition to the above, for areas of piping found degraded and returned to service, the remaining service life will be calculated. and the piping will be re-examined prior to the 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 NL-17-052 Docket Nos. 50-247 and 50-286 Attachment 2 Page 3 of 6 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. A.3.1.33 Service Water Integrity Program

• The Service 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 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 mechanism 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.

8.1.14 Fire Water System Attributes Affected 7. Corrective Action 7. Corrective Action 8.1.29 City water system NL-17-052 Docket Nos. 50-247 and 50-286 Attachment 2 Page 4 of 6 Enhancements freguency, regair, reglacement). cedures will be revised to ensure giging that exhibits leaks will be locally regaired and restored to service on an interim basis gresuming ultrasonic test data reflects adeguate structural integrity to suggort interim ogeration. The affected giging segment will be entered into the 12-week work control schedule for reglacement. The Fire Water System Program grocedures will be revised to ensure giging segments that exhibit indications of selective seam corrosion will be entered into the routine 12-week work control schedule and grocessed on an accelerated reglacement basis. Use visual or other NOE techniques to inspect a representative sample of the internals of city water piping, strainer housing, valve bodies, piping elements, and components exposed to treated water (city water) to manage loss of material. A representative sample of at least 25 inspections of city water piping will be performed at least every 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:

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

• If >5 degraded locations are found, then 15 additional volumetric examinations will be performed during the following refueling interval. In addition 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 the end of calculated life. The Periodic Surveillance and Preventive Maintenance Program grocedures will be revised to ensure city water 8.1.34 Service Water Integrity Attributes Affected 4. Detection of Aging Effects 6. Acceptance Criteria 7. Corrective Action NL-17-052 Docket Nos. 50-247 and 50-286 Attachment 2 Page 5 of 6 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. 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 I / The Service Water Integrity Program procedures will be revised to prioritize future inspections based on plant area susceptible to flooding concerns. The Service 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 Service Water Integrity Program procedures will be revised to conduct and document a 100 percent internal lining visual inspection of the IP2 three ihch fan cooler units (FCU) spool pieces when removed during FCU coil refueling outage

7. Corrective Action NL-17-052 Docket Nos. 50-247 and 50-286 Attachment 2 Page 6 of 6 :greventive maintenance activities. The Service Water Integrity Program :grocedures will be revised to :gerform 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 :grogram remains adeguate. If a new aging mechanism is found, it will also evaluate if a failure of the aging management nrogram :glan has occurred. (

ATTACHMENT 3 TO NL-17-052 LICENSE RENEWAL APPLICATION IPEC LIST OF REGULATORY COMMITMENTS Rev.31 ENTERGY NUCLEAR OPERATIONS, INC. INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 & 3 DOCKET NOS. 50-247 and 50-286

1. 1 2 List of Regulatory Commitments Rev. 31 NL-17-052 Attachment 3 Page 1 of 22 The following table identifies those actions committed to by Entergy in this document. Changes are shown as strikethroughs for deletions and underlines for additions. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION I AUDIT ITEM Enhance the Aboveground Steel Tanks Program for IP2: Complete NL-07-039 A.2.1.1 A.3.1.1 IP2 and IP3 to perform thickness measurements of NL-13-122 B.1.1 the bottom surfaces of the condensate storage tanks, city water tank, and fire water tanks once during the first ten years of the period*of extended operation. Enhance the Aboveground Steel Tanks Program for IP2 and IP3 to require trending of thickness measurements when material loss is detected. Implement LRA Sections, A.2.1.1, A.3.1.1 and B.1.1, IP2 & IP3: NL-14-147 A.2.1.1 December 31, 2019 A.3.1.1 as shown in NL-14-147. 8.1.1 Implement LRA Sections, A.2.1.1 and B.1.1, as IP2 & IP3: NL-15-092 A.2.1.1 shown in NL-15-092 December 31, 2019 B.1.1 Enhance the Bolting Integrity Program for IP2 and IP2: Complete NL-07-039 A.2.1.2 IP3 to clarify that actual yield strength is used in A.3.1.2 selecting materials for low susceptibility to sec and IP3: Complete B.1.2 clarify the prohibition on use of lubricants containing NL-07-153 Audit Items MoS2 for bolting. 201, 241, The Bolting Integrity Program manages loss of NL-13-122 270 preload and loss of material for all external bolting.

1. COMMITMENT 3 Implement the Buried Piping and Tanks Inspection Program for IP2 and IP3 as described in LRA Section B.1.6.

• This new program will be implemented consistent with the corresponding program described in NUREG-1801,,Section Xl.M34, Buried Piping and Tanks Inspection. Include in the Buried Piping and Tanks Inspection Program described in LRA Section B.1.6 a risk assessment of in-scope buried piping and tanks that includes consideration of the impacts of buried piping or tank leakage and of conditions affecting the risk for corrosion. Classify pipe segments and tanks as having a high, medium or low impact of leakage based on the safety class, the hazard posed by fluid contained in the piping and the impact of leakage on reliable plant operation. Determine corrosion risk through consideration of piping or tank material, soil resistivity, drainage, the presence of cathodic protection and the type of coating. Establish inspection priority and frequency for periodic inspections of the in-scope piping and tanks based on the results of the risk assessment. Perform inspections using inspection techniques with demonstrated effectiveness. 4 Enhance the Diesel Fuel Monitoring Program to include cleaning and inspection of the IP2 GT-1 gas turbine fuel oil storage tanks, IP2 and IP3 EOG fuel oil day tanks, IP2 SBC/Appendix R diesel generator fuel oil day tank, and IP3 Appendix R fuel oil storage tank and day tank once every ten years. Enhance the Diesel Fuel Monitoring Program to include quarterly sampling and analysis of the IP2 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 1 Omg/I. Water and sediment acceptance criterion will be less than or equal to 0.05%. IMPLEMENTATION SCHEDULE IP2: Complete IP3: Complete IP2: Complete IP3: Complete NL-17-052 Attachment 3 Page 2 of 22 SOURCE RELATED LRA SECTION I AUDIT ITEM NL-:07-039 A.2.1.5 A.3.1.5 NL-13-122 B.1.6 NL-07-153 Audit Item NL-15-121 173 NL-09-106 NL-09-111 NL-11-101 NL-07-039 A.2.1.8 A.3.1.8 NL-13-122 B.1.9 NL-07-153 Audit items NL-15-121 128, 129, 132, NL-08-057 491, 492, 510

1. COMMITMENT Enhance the Diesel Fuel Monitoring Program to include thickness measurement 'of the bottom of the following tanks once every ten years. IP2: EOG fuel oil storage tanks, 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 oil storage tank; IP3: EOG fuel oil day tanks, EOG fuel oil storage tanks, Appendix R fuel oil storage tank, and diesel fire pump fuel oil storage tank. ' Enhance the Diesel Fuel Monitoring Program to change the analysis for water and particulates to a quarterly frequency for the following tanks. IP2: GT-1 gas turbine fuel oil storage tanks and diesel fire pump fuel oil storage tank; IP3: Appendix R fuel oil day tank and diesel fire pump fuel oil storage tank. Enhance the Diesel Fuel Monitoring Program to specify acceptance criteria for thickness measurements of the fuel oil storage tanks within the scope of the program. Enhance the Diesel Fuel Monitoring Program to direct samples be taken and include direction to remove water when detected. Revise applicable procedures to direct sampling of the onsite portable fuel oil contents prior to transferring the contents to the storage tanks. Enhance the Diesel Fuel Monitoring Program to direct the addition of chemicals including biocide when the presence of biological activity is confirmed. 5 Enhance the External Surfaces Monitoring Program for IP2 and IP3 to include periodic inspections of systems in scope and subject to aging management review for license renewal in accordance with 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 could impact the subject systems will include SSCs that are in scope and subject to aging management review for license renewal in accordance with 10 CFR 54.4(a)(2). IMPLEMENTATION SCHEDULE IP2: Complete NL-17-052 Attachment 3 Page 3 of 22 SOURCE RELATED LRA SECTION I AUDIT ITEM NL-07-039 A.2.1.10 A.3.1.10 NL-13-122 8.1.11

1. COMMITMENT Implement LRA Sections A.2.1.10, A.3.1.10 and 8.1.11, as shown in NL-14-147. 6 Enhance the Fatigue Monitoring Program for IP2 to monitor steady state cycles and feedwater cycles or perform an evaluation to determine monitoring is not required. Review the number of allowed events and I resolve discrepancies between reference documents and monitoring procedures. Enhance the Fatigue Monitoring Program for IP3 to include all the transients identified. Assure all fatigue analysis transients are included with the lowest limiting numbers. Update the number of design transients accumulated to date. 7 Enhance the Fire Protection Program to inspect external surfaces of the IP3 RCP oil collection systems for_loss of material each refueling cycle. Enhance the Fire Protection Program to explicitly state that the IP2 and IP3 diesel fire pump engine sub-systems (including the fuel supply line) shall be observed while the pump is running. Acceptance criteria will be revised to verify that the diesel engine does not exhibit signs of degradation while running; such as fuel oil, lube oil, coolant, or exhaust gas leakage. Enhance the Fire Protection Program to specify that the IP2 and IP3 diesel fire pump engine carbon steel exhaust components are inspected for evidence of corrosion and cracking at least once each operating cycle. ' Enhance the Fire Protection Program for IP3 to visually inspect the cable spreading room, 480V switchgear room, and EOG room C02 fire suppression system for signs of degradation, such as corrosion and mechanical damage at least once every six months. IMPLEMENTATION SCHEDULE IP2 & IP3: December 31, 2019 IP2: Complete IP3: Complete IP2: Complete IP3: Complete NL-17-052 Attachment 3 Page 4 of 22 SOURCE RELATED LRA SECTION I AUDIT ITEM NL-14-147 A.2.1.10 A.3.1.10 8.1.11 NL-07-039 A.2.1.11 A.3.1.11 NL-13-122 8.1.12, NL-07-153 Audit Item 164 NL-15-121 / NL-07-039 A.2.1.12 A.3.1.12 NL-13-122 8.1.13 I NL-15-121 '

1. COMMITMENT 8 Enhance the Fire Water Program to include inspection of IP2 and IP3 hose reels for evidence of corrosion. Acceptance criteria will be revised to verify no unacceptable signs of degradation. Enhance the Fire Water Program to replace all or test a sample of IP2 and IP3 heads required for 10 CFR 50.48 using guidance of NFPA 25 (2002 edition), Section 5.3.1.1.1 before the end of the sprinkler head service life and at 1 O:..year intervals thereafter during the extended period of operation to ensure that signs of degradation, such as corrosion, are detected in a timely manner. Enhance the Fire Water Program to perform wall thickness evaluations of IP2 and IP3 fire protection piping on system components using non-intrusive techniques (e.g., volumetric testing) to identify evidence of loss of material due to corrosion. These inspections will be performed before the end of the current operating term and at intervals thereafter during the period of extended operation. Results of the initial evaluations will be used to determine the appropriate inspection interval to ensure aging effects are identified prior to loss of intended function. Enhance the Fire Water Program to inspect the internal surface of foam based fire suppression tanks. Acceptance criteria will be enhanced to verify no siQnificant corrosion. Implement LRA Sections, A.2.1.13, A.3.1.13 and 8.1.14, as shown in NL-14-147. Implement LRA Sections A.2.1.13, A.3.1.13 and 8.1.14, as shown in NL-15-019 Implement LRA Sections A.2.1.13, A.3.1.13 and 8.1.14, as shown in NL-15-092 .....____* IMPLEMENTATION SCHEDULE IP2: Complete --I ' ( IP2 & IP3: I December 31, 2019 IP2 & IP,3: December 31, 2019 IP2 & IP3: December 31, 2019 NL-17-052 Attachment 3 Page 5 of 22 SOURCE RELATED LRA SECTION I AUDIT ITEM NL-07-039 A.2.1.13 A.3.1.13 NL-13-122 8.1.14 NL-07-153 Audit Items 105, 106 NL-08-014 : -NL-14-147 A.2.1.13 A.3.1.13 8.1.14 NL-15-019 A.2.1.13 A.3.1.13 8.1.14 NL-15-092 'A.2.1.13 A.3.1.13 8.1.14

1. COMMITMENT Implement LRA Sections A.2.1.13, l\.3.1.13, and B.1.14, as shown in NL 16 122 lm12lement LRA Sections A.2.1.13, A.3.1.13, and 8.1.14, as shown in NL-17-052 9 Enhance the Flux Thimble Tube Inspection Program for IP2 and IP3 to implement comparisons to wear rates identified in WCAP:-12866. Include provisions to compare data to the previous performances and perform evaluations regarding change to test frequency and scope. Enhance the Flux Thimble Tube Inspection Program for IP2 and IP3 to specify the acceptance criteria as outlined in WCAP-12866 or other plant-specific values based on evaluation of previous test results. Enhance the Flux Thimble Tube Inspection Program for IP2 and IP3 to direct evaluation and performance of corrective actions based on tubes that exceed or are projected to exceed the acceptance criteria. Also stipulate that flux thimble tubes that cannot be inspected over the tube length and cannot be shown by analysis to be satisfactory for continued service, must be removed from service to ensure the integrity of the reactor coolant system pressure boundary. ' IMPLEMENTATION SCHEDULE llD'l 0 Ir\'>. --* In----'---'J '1 'ln-17 1----*---'...__ IP2 & IP3: December 31 2017 IP2: Complete IP3: Complete NL-17-052 Attachment 3 Page 6 of 22 SOURCE RELATED LRA SECTION I AUDIT ITEM NL 16 122 A.2.1.13 A.3.1.13 _I B.1.14 NL-17-052 A.2.1.13 A.3.1.13 8.1.14 . ,* NL-07-039 A.2.1.15 A.3.1.15 NL-13-122 8.1.16 NL-15-121

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

• Safety injection pump lube oil heat exchangers *: RHR heat exchangers

• RHR pump seal coolers

• Non-regenerative heat exchangers

• Charging pump seal water heat exchangers

• Charging pump fluid drive coolers

• Charging pump crankcase oil coolers

• Spent fuel pit heat exchangers

• Secondary system steam generator sample coolers

• Waste gas compressor heat exchangers

• SBC/Appendix R diesel jacket water heat exchanger (IP2 only) Enhance the Heat Exchanger Monitoring Program for IP2 and IP3 to perform visual inspection on heat exchangers where non-destructive examination, such as eddy current inspection, is not possible due to heat exchanger design limitations. Enhance the Heat Exchanger Monitoring Program for IP2 and IP3 to include consideration of material-environment combinations when determining sample population of heat exchangers. Enhance the Heat Exchanger Monitoring Program for IP2 and IP3 to establish minimum tube wall thickness for the new heat exchangers identified in the scope of the program. Establish acceptance criteria for heat exchangers visually inspected to include no indication of tube erosion, vibration wear, corrosion, pitting, fouling, or scaling. ' IMPLEMENTATION SCHEDULE IP2: Complete IP3: Complete \ NL-17-052 Attachment 3 Page 7 of 22 SOURCE RELATED LRA SECTION I AUDIT ITEM NL-07-039 A.2.1.16 A.3.1.16 NL-13-122 B.1.17, NL-07-153 Audit Item NL-15-121 52 NL-09-018 -I

1. COMMITMENT 11 Deleted 12 Enhance the Masonry Wall Program for IP2 and IP3 to specify that the IP1 intake structure is included in the proQram. 13 Enhance the Metal-Enclosed Bus Inspection Program for IP2 and IP3 to visually inspect the external surface of MEB enclosure assemblies for loss of material at least once every 10 years. The first inspection will occur prior to the period of extended operation and the acceptance criterion will be no significant loss of material. Enhance the Metal-Enclosed Bus Inspection Program to add acceptance criteria for MEB internal visual inspections to include the absence of indications of dust accumulation on the bus bar, on the insulators, and in the duct, in addition to the absence of indications of moisture intrusion into the duct. Enhance the Metal-Enclosed Bus Inspection Program for IP2 and IP3 to inspect bolted connections at least once every five years if performed visually or at least once every ten years using quantitative measurements such as thermography or contact resistance measurements. The first inspection will occur prior to the period of extended operation. The plant will process a change to applicable site procedure to remove the reference to "re-torquing" connections for phase bus maintenance and bolted connection maintenance. 14 Implement the Non-EQ Bolted Cable Connections Program for IP2 and IP3 as described in LRA Section B. 1.22. IMPLEMENTATION SCHEDULE IP2: Complete IP3: Complete IP2: Complete IP3: Complete IP2: Complete IP3: Complete NL-17-052 Attachment 3 Page 8 of 22 SOURCE RELATED LRA SECTION I AUDIT ITEM NL-09-056 NL-11-.101 NL-07-039 A.2.1.18 A.3.1.18 NL-13-122 B.1.19 NL-07-039 A.2.1.19 A.3.1.19 NL-13-122 B.1.20 NL-07-153 Audit Items NL-15-121 124, NL-08-057 133, 519 NL-13-077 NL-07-039 A.2.1.21 A.3.1.21 NL-13-122 B.1.22 NL-15-121

1. COMMITMENT IMPLEMENTATION SCHEDULE 15 Implement the Non-EQ Inaccessible Medium-IP2: Complete Voltage Cable Program for IP2 and IP3 as described IP3: Complete in LRA Section 8.1.23. This new program will be implemented consistent

• with the corresponding program described in NUREG-1801 Section Xl.E3, Inaccessible Medium-Voltage Cables Not Subject To 10 CFR 50.49 Environmental Qualification Requirements. 16 Implement the Non-EQ Instrumentation Circuits Test IP2: Complete Review Program for IP2 and IP3 as described in LRA Section 8.1.24. IP3: Complete ' This new program will be implemented consistent with the corresponding program described in NUREG-1801 Section Xl.E2, ElectricalCables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits. 17 Implement the Non-EQ Insulated Cables and IP2: Complete Connections Program for IP2 and IP3 as described IP3: Complete in LRA Section 8.1.25. This new program will be implemented consistent with the corresponding program described in NUREG-1801 Section Xl.E1, Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements. NL-17-052 Attachment 3 Page 9of22 SOURCE RELATED LRA SECTION I AUDIT ITEM NL-07-039 A.2.1.22 A.3.1.22 NL-13-122 8.1.23 NL-07-153 Audit item NL-15-121 173 NL-11-032 NL-11-096 NL-11-101 NL-07-039 A.2.1.23 A.3.1.23 NL-13-122 8.1.24 NL-07-153 Audit item NL-15-121 ,., 173 NL-07-039 A.2.1.24 A.3.1.24 NL-13-122 8.1.25 NL-07-153 Audit item NL-15-121 173

1. COMMITMENT 18 Enhance the Oil Analysis Program for IP2 to sample and analyze lubricating oil used in the SBC/Appendix R diesel generator consistent with the oil analysis for other site diesel generators. Enhance the Oil Analysis Program for IP2 and IP3 to sample and analyze generator seal oil and turbine hydraulic control oil. Enhance the Oil Analysis Program for IP2 and IP3 to formalize preliminary oil screening for water and particulates and laboratory analyses including defined acceptance criteria for all components included in the scope of this program. The program will specify corrective actions in the event acceptance criteria are not met. I Enhance the Oil Analysis Program for IP2 and IP3 to formalize trending of preliminary oil screening results as well as data provided from independent laboratories. 19 Implement the One-Time Inspection Program for IP2 . and IP3 as described in LRA Section B.1.27. This new program will be implemented consistent with the corresponding program described in NUREG-1801, Section Xl.M32, One-Time Inspection. 20 Implement the One-Time Inspection -Small Bore Piping Program for IP2 and IP3 as described in LRA Section B.1.28. This new program will be implemented consistent with the corresponding program described in , NUREG-1801, Section Xl.M35, One-Time Inspection of ASME Code Class I Small-Bore PipinQ. 21 Enhance the Periodic Surveillance and Preventive Maintenance Program for IP2 and IP3 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. IMPLEMENTATION SCHEDULE IP2: Complete IP3: Complete IP2: Complete IP3: Complete IP2: Complete IP3: Complete IP2: Complete IP3: Complete NL-17-052 Attachment 3 Page 10 of 22 SOURCE RELATED LRA SECTION I AUDIT ITEM NL-07-039 A.2.1.25 A.3.1.25 NL-13-122 B.1.26 NL-11-101 NL-15-121 \ NL-07-039 A.2.1.26 A.3.1.26 NL-13-122 B.1.27 NL-07-153 Audit item NL-15-121 173 NL-07-039 A.2.1.27 A.3.1.27 NL-13-122 B.1.28 NL-07-153 Audit item NL-15-121 173 NL-07-039 A.2.1.28 A.3.1.28 NL-13-122 B.1.29 NL-15-121

1. COMMITMENT Implement LRA Seotions A.2.1.28, A.3.1.28 and B.1.29, as sho1Nn in NL 16 122 LRA Sections A.2.1.28, A.3.1.28 and 8.1.29, as shown in NL-17-052 22 Enhance the Reactor Vessel Surveillance Program for IP2 and IP3 revising the specimen capsule withdrawal schedules to draw and test a standby capsule to cover the peak reactor vessel fluence expected through the end of the period of extended operation. Enhance the Reactor Vessel Surveillance Program for IP2 and IP3 to require that tested and untested specimens from all capsules pulled from the reactor vessel are maintained in storage. 23 Implement the Selective Leaching Program for IP2 and IP3 as described in LRA Section 8.1.33. This new program will be implemented consistent with the corresponding program described in NUREG-1801, SectionXl.M33 Selective Leaching of Materials. 24 Enhance the Steam Generator Integrity Program for IP2 and IP3 to require that the results of the condition monitoring assessment are compared to the operational assessment performed for the prior operating cycle with differences evaluated. 25 E_nhance the Structures Monitoring Program to -explicitly specify that the following structures are included in the program.

• Appendix R generator foundation (IP3)

• Appendix R diesel generator fuel oil tank vault (IP3)

• Appendix R diesel generator switchgear and enclosure (IP3)

• city water storage tank foundation

• condensate storage tanks foundation (IP3)

• containment access facility and annex (IP3)

• discharge canal (IP2/3)

• emergency lighting poles and foundations (IP2/3)

• fire pumphouse (IP2) IMPLEMENTATION SCHEDULE ID'l 0 ID'l* ---* -:i-t 'ln-17 -----, __ I IP2 & IP3: December 31 2017 IP2: Complete IP3: Complete IP2: Complete IP3: Complete IP2: Complete IP3: Complete IP2: Complete ' IP3: Complete \ I NL-17-052 Attachment 3 Page 11 of 22 SOURCE RELATED LRA SECTION I AUDIT ITEM NL 16 122 A.2.1.28 A.3.1.28 B.1.29 NL-17-052 A.2.1.28 A.3.1.28 8.1.29 NL-07-039 A.2.1.31 A.3.1.31 NL-13-122 8.1.32 NL-15-121 NL-07-039 A.2.1.32 A.3.1.32 NL-13-122 8.1.33 NL-07-153 Audit item NL-15-121 173 NL-07-039 A.2.1.34 A.3.1.34 NL-13-122 8.1.35 NL-07-039 A.2.1.35 A.3.1.35 NL-13-122 8.1.36 NL-07-153 NL-15-121 Audit items 86, 87, 88, NL-08-057 417 NL-13-077

1. COMMITMENT

• fire protection pumphouse (IP3)

• fire water storage tarik foundations (IP2/3)

• gas turbine 1 fuel storage tank foundation

• maintenance and outage building-elevated passageway (IP2)

• new station security building (IP2)

• nuclear service building (IP1)

• primary water storage tank foundation (IP3)

• refueling water storage tank foundation (IP3)

• security access and office building (IP3)

• service water pipe chase (IP2/3)

• service water valve pit (IP3)

• transformer/switchyard support structures (IP2)

• waste holdup tank pits (IP2/3) Enhance the Structures Monitoring Program for IP2 and IP3 to clarify that in addition to structural steel and concrete, the following commodities (including their anchorages) are inspected for each structure as applicable.

• cable trays and supports

• concrete portion of reactor vessel supports

• conduits and supports

• cranes, rails and girders

• equipment pads and foundations

• fire proofing (pyrocrete)

• HVAC duct supports

• jib cranes

• manholes and duct banks

• manways, hatches and hatch covers

• monorails

• new fuel storage racks

• sumps Enhance the Structures Monitoring Program for IP2 and IP3 to inspect inaccessible concrete areas that are exposed by excavation for any reason. IP2 and IP3 will also inspect inaccessible concrete areas in environments where observed conditions in accessible areas exposed to the same environment indicate that significant concrete degradation is occurrina. IMPLEMENTATION SCHEDULE ' NL-17-052 Attachment 3 Page 12 of 22 SOURCE RELATED LRA SECTION I AUDIT ITEM NL-14-146 NL-13-077

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

• Additionally, to assess potential indications of spent fuel pool .leakage, IPEC will sample for tritium in groundwater wells in close proximity to the IP2 spent fuel pool at least once every 3 months. Enhance the Structures Monitoring Program for IP2 and IP3 to perform inspection of normally submerged concrete portions of the intake structures at least once every 5 years. Inspect the baffling/grating partition and support platform of the IP3 intake structure at least once every 5 years. Enhance the Structures Monitoring Program for IP2 and IP3 to perform inspection of the degraded areas of the water control structure once per 3 years rather than the normal frequency of once per 5 years during the PEO. Enhance the Structures Monitoring Program to include more detailed quantitative acceptance criteria* for inspections of concrete structures in accordance with ACI 349.3R, "Evaluation of Existing Nuclear Safety-Related Concrete Structures" prior to the period of extended operation. , IMPLEMENTATION SCHEDULE \ J NL-17-052 Attachment 3 Page 13 of 22 SOURCE RELATED LRA SECTION I AUDIT ITEM NL-08-127 Audit Item 360 \ ---Audit Item 358 NL-11-032

1. COMMITMENT 26 Implement the Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) Program for IP2 and IP3 as described in LRA Section B.1.37. This new program will be implemented consistent with the corresponding program described in NUREG-1801, Section Xl.M12, Thermal Aging Embrittlement of Cast Austenitic Stainless Steel . (CASS) Program. 27 Implement the Thermal Aging and Neutron Irradiation Embrittlement of Cast Austenitic Stainless Steel (CASS) Program for IP2 and IP3 as described in LRA Section 8.1.38. -This new program will be implemented consistent with the corresponding program described in NUREG-1801 Section Xl.M13, Thermal Aging and Neutron Embrittlement of Cast Austenitic Stainless Steel <CASS) Proaram.

• 28 Enhance the Water Chemistry Control -Closed Cooling Water Program to maintain water chemistry . of the IP2 SBC/Appendix R diesel generator cooling system per EPRI guidelines. Enhance the Water Chemistry Control -Closed Cooling Water Program to maintain the IP2 and IP3 security generator and fire protection diesel cooling water pH and glycol within limits specified by EPRI auidelines. I 29 Enhance the Water Chemistry Control -Primary and Program for IP2 to test sulfates monthly m the RWSTwith a limit of <150 ppb. 30 For aging management of the reactor vessel internals, IPEC will (1) participate in the industry programs for investigating and managing aging effects on reactor internals; (2) evaluate and . the results of the programs as applicable to the reactor internals; and (3) upon completion of these but not less than 24 months before entering the period of extended operation, submit an inspection plan for reactor internals to the NRC for review and approval. IMPLEMENTATION SCHEDULE IP2: Complete I P3: Complete IP2: Complete IP3: Complete IP2: Complete IP3: Complete IP2: Complete-IP2: Complete IP3: Complete NL-17-052 Attachment 3 Page 14 of 22 SOURCE RELATED .LRA SECTION I AUDIT ITEM NL-11-101 NL-07-039 A.2.1.36 A.3.1.36 NL-13-122 B.1.37 NL-07-153 Audit item NL-15-121 173 NL-07-039 A.2.1.37 A.3.1.37 NL-13-122 8.1.38. NL-07-153 Audit item 173 NL-07-039 A.2.1.39 A.3.1.39 NL-13-122 8.1.40 NL-08-057 Audit item 509 NL-07-039 A.2.1.40 8.1.41 NL-13-122 NL-07-039 A.2.1.41 A.3.1.41 NL-13-122 NL-11-107

1. COMMITMENT IMPLEMENTATION SCHEDULE I 31 Additional P-T curves will be submitted as required IP2: Complete per 10 CFR 50, Appendix G prior to the period of extended operation as part of the Reactor Vessel IP3: Complete Surveillance Program. ' 32 As required by 10 CFR 50.61(b)(4), IP3 will submit a IP3: plant-specific safety analysis for plate 82803-3 to the 6 NRC three years prior to reaching the RT PTs vears after entering screening criterion. Alternatively, the site may PEO choose to implement the revised PTS rule when approved. NL-17-052 Attachment 3 Page 15 of 22 SOURCE RELATED LRA SECTION I AUDIT --ITEM NL-07-039 A.2.2.1.2 A.3.2.1.2 NL-13-122 4.2.3 NL-15-121 NL-07-039 A.3.2.1.4 NL-07-140 4.2.5 NL-08-014 NL-08-127 I

1. COMMITMENT 33 At least 2 years prior to entering the period of extended operation, for the locations identified in LRA Table 4.3-13 (IP2) and LRA Table 4.3-14 (IP3), under the Fatigue Monitoring Program, IP2 and IP3 will implement one or more of the following: ,, (1) Consistent with the Fatigue Monitoring Program, Detection of Aging Effects, update the fatigue usage calculations using refined fatigue analyses to determine valid CUFs less than 1.0 when accounting for the effects of reactor water environment. This includes applying the appropriate Fen factors to valid CUFs determined in accordance with one of the following: 1. For locations in LRA Table .4.3-13 (IP2) and LRA Table 4.3-14 (IP3), with existing fatigue analysis valid for the period of extended operation, use the existing CUF. 2. Additional plant-specific locations with a valid CUF may be evaluated. In particular, the pressurizer lower shell will be reviewed to ensure the surge nozzle remains the limiting component. 3. Representative CUF-values from other plants, adjusted to or enveloping the IPEC plant specific external loads may be used if demonstrated applicable to IPEC. ' 4. An analysis using an NRG-approved version of the ASME code or NRG-approved alternative (e.g., NRG-approved code case) may be performed to determine a valid CUF. (2) Consistent with the Fatigue Monitoring Program, Corrective Actions, repair or replace the affected locations before exceeding a CUF of 1.0. 34 IP2 SBO I Appendix R diesel generator will be installed and operational by April 30, 2008. This committed change to the facility meets the requirements of 10 CFR 50.59(c)(1) aqd, therefore, a license amendment pursuant to 1 O CFR 50:90 is not required. IMPLEMENTATION SCHEDULE IP2: Complete IP3: Complete ' Complete NL-17-052 Attachment 3 Page 16 of 22 SOURCE RELATED LRA SECTION I AUDIT ITEM NL-07-039 A.2.2.2.3 A.3.2.2.3 NL-13-122 4.3.3 NL-07-153 Audit item 146 NL-08-021 NL-10-082 NL-13-122 2.1.1.3.5 NL-07-078 NL-08-074 NL-11-101

1. COMMITMENT 35 Perform a one-time inspection of representative sample area of IP2 containment liner affected by the 1973 event behind the insulation, prior to entering the period of extended operation, to assure liner degradation is not occurring in this area. Perform a one-time inspection of representative sample area of the IP3 containment steel liner at the juncture with the concrete floor slab, prior to entering the period of extended operation, to assure liner degradation is not occurring in this area. Any degradation will be evaluated for updating of the containment liner analvses as needed. 36 Perform a one-time insp,ection and evaluation of a sample of potentially affected IP2 refueling cavity concrete prior to the period of extended operation. ,The sample will be obtained by core boring the refueling cavity wall in an area that is susceptible to exposure to borated water leakage. The inspection will include an assessment of embedded reinforcing steel. Additional core bore samples will be taken, if the leakage is not stopped, prior to the end of the first ten years of the period of extended operation. A sample of leakage fluid will be analyzed to determine the composition of the fluid. If additional core samples are taken prior to the end of the first ten years of the period of extended operation, a sample of leakage fluid will be analyzed. 37 Enhance the Containment lnservice Inspection (Cll-IWL) Program to include inspections of the containment using enhanced characterization of degradation (i.e., quantifying the dimensions of noted indications through the use of optical aids) during the period of extended operation. The enhancement includes obtaining critical dimensional data of degradation where possible through direct , measurement or the use of scaling technologies for photographs, and the use of consistent vantage points for visual inspections. IMPLEMENTATION SCHEDULE IP2: Complete IP3: Complete IP2: Complete IP2: Complete IP3: Complete NL-17-052 Attachment 3 Page 17 of 22 SOURCE RELATED LRA SECTION I AUDIT ITEM NL-08-127 Audit Item 27 NL-13-122 NL-11-101 NL-15-121 NL-09-018 NL-08-127 Audit Item NL-11-101 359 NL-13-122 NL-09-056 NL-09-079 NL-08-127 Audit Item 361 NL-13-122

1. COMMITMENT IMPLEMENTATION SCHEDULE 38 For Reactor Vessel Fluence, should future core IP2: Complete loading patterns invalidate the basis for the projected IP3: Complete values of RTpts or CvUSE, updated calculations will be provided to the NRC. 39 Deleted 40 Evaluate plant specific and appropriate industry IP2: Complete operating experience and incorporate lessons !earned_ in establishing appropriate monitoring and IP3: Complete 1nspect1_on frequencies to assess aging effects for the new aging management programs. Documentation of the operating experience evaluated for each new program will be available on site for NRC review prior to the period of extended operation. 41 Deleted ! NL-17-052 Attachment 3 Page 18 of 22 SOURCE RELATED LRA SECTION I AUDIT ITEM NL-08-143 4.2.1 NL-13-122 NL-15-121 NL-09-079 NL-09-106 B.1.6 B.1.22 NL-13-122 B.1.23 NL-15-121 B.1.24 B.1.,25 B.1.27 B.1.28 B.1.33 B.1.37 B.1.38 NL-17-005 N/A

1. COMMITMENT 42 IPEC will develop a plan for each unit to address the potential for cracking of the primary to secondary pressure boundary due to PWSCC of tube-to-tubesheet welds using one of the following two options. Option 1 (Analysis) IPEC will perform an analytical evaluation of the steam generator tube-to-tubesheet welds in order to establish a technical basis for either determining that the tubesheet cladding and welds are not susceptible *to PWSCC, or redefining the pressure boundary in which the tube-to-tubesheet weld is no longer included and, therefore, is not required for reactor coolant pressure boundary function. The redefinition of the reactor coolant pressure boundary must be I approved by the NRC as a license amendment 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 i:ienerators. IMPLEMENTATION SCHEDULE IP2: Complete IP3: Complete IP2: Not Applicable IP3: Not App!icable NL-17-052 Attachment 3 Page 19 of 22 SOURCE RELATED LRA SECTION I AUDIT ITEM NL-11-032 N/A NL-11-074 NL-11-090 NL-11-096 NL-17-005 ' I

1. COMMITMENT 43 IPEC will'review design basis ASME Code Class 1 fatigue evaluations to determine whether the NUREG/CR-6260 locations that have been evaluated for the effects of the reactor coolant environment on fatigue usage are the limiting locations for the IP2 and IP3 configurations. If more limiting locations are identified, the most limiting location will be evaluated for the effects of the reactor coolant environment on fatigue usage. IPEC will use the NUREG/CR-6909 methodology in the evaluation of the limiting locations consisting of nickel alloy, if any. 44. IPEC will include written explanation and justification of any user intervention in future evaluations using the WESTEMS "Design CUF" module. 45 IPEC will not use the NB-3600 option of the WESTEMS program in future design calculations until the issues identified during the NRC review of the program have been resolved. 46 Include in the IP2 ISi Program that IPEC will perform twenty-five volumetric weld metal inspections of socket welds during each 10-year ISi interval scheduled as specified by IWB-2412 of the ASME Section XI Code during the period of extended operation. In lieu of volumetric examinations, destructive examinations may be performed, where one destructive examination may be substituted for two volumetric examinations. 47 Deleted. IMPLEMENTATION SCHEDULE IP2: Complete IP3: Complete IP2: Cpmplete IP3: Complete IP2:Complete IP3: Complete IP2: Complete NL-17-052 Attachment 3 Page 20of22 SOURCE RELATED LRA SECTION I AUDIT ITEM NL-11-032 4.3.3 NL-13-122 NL-11-101 NL-15-121 NL-11-032 N/A NL-11-101 NL-13-122 NL-15-121 NL-11-032 N/A NL-11-101 NL-13-122 NL-15-121 NL-11-032 N/A NL-11-074 NL-13-122 NL-14-093 N/A

1. COMMITMENT ' '° 48 Entergy will visually inspect IPEC underground piping within the scope of license renewal and subject to aging management review prior to the period of extended operation and then on a frequency of at least once every two years during the period of extended operation. This inspection frequency will be maintained unless the piping is subsequently coated in accordance with the preventive actions specified in NUREG-1801 Section Xl.M41 as modified by LR-ISG-2011-03. Visual inspections will be supplemented with surface or volumetric non-destructive testing if indications of significant loss of material are observed. Consistent with revised NUREG-1801 Section Xl.M41, such adverse indications will be entered into the plant corrective action program for evaluation of extent of condition and for determination of appropriate corrective actions (e.g., increased inspection frequency, repair, replacement). 49 Recalculate each of the limiting CUFs provided in section 4.3 of the LRA for the reactor vessel internals to include the reactor coolant environment effects (Fen) as provided in the IPEC Fatigue Monitoring Program using NUREG/CR-5704 or NUREG/CR-6909. In accordance with the corrective actions specified in the Fatigue Monitoring Program, corrective actions include further CUF re-analysis, and/or repair or replacement of the affected components prior to the CUFen reaching 1.0. 50 Replace the IP2 split pins during the 2016 refueling outage (2R22). 51 Enhance the Service Water Integrity Program by implementing LRA Sections A.2.1.33, A.3.1.33 and B.1.34, as shown in NL-14-147. Implement LRA Sections A.2.1.33, A.3.1.33 and B.1.34, as shov.m in NL 16 122 IMPLEMENTATION SCHEDULE IP2: Complete I IP3: Complete IP2: Complete IP3: Complete IP2: Complete IP3: N/A \ IP2 & IP3: December 31, 2017 10.-, 0 ---* I"\ -"""'"7 --r --NL-17-052 Attachment 3 Page 21of22 SOURCE RELATED LRA SECTION I AUDIT ITEM . NL-12-174 N/A NL-13-122 NL-15-121 ; '* NL-13-052 A.2.2.2 ' A.3.2.2 NL-13-122 NL-15-121 I NL-13-122 A.2.1.41 B.1.42 NL-14-067 NL-14-147 A.2.1.33 A.3.1.33 B.1.34 NL 16 122 A.2.1.33 A.3.1.33 B.1.34

1. COMMITMENT IMPLEMENTATION SCHEDULE lmglement LRA Sections A.2.1.33, A.3.1 :33 and IP2 & IP3: 8.1.34, as shown in NL-17-052 December 31 2017 52 Implement the Coating Integrity Program for IP2 and IP2 & IP3: IP3 as described in LRA Section 8.1.42, as shown in December 31, 2024 NL-15-019. NL-17-052 Attachment 3 Page 22 of 22 SOURCE RELATED LRA SECTION I AUDIT ITEM NL-17-052 A.2.1.33 A.3.1.33 8.1.34 NL-15-019 A.2.1.42 A.3.1.42 8.1.43 .--