ML16341C789

Lr Hearing - FW: IPEC Response to LRA RAI Set 2016-01

ML16341C789
Person / Time
Site:	Indian Point
Issue date:	12/06/2016
From:	NRC
To:	Division of License Renewal
References
Download: ML16341C789 (63)

Text

IPRenewal NPEmails From: Burton, William Sent: Tuesday, December 06, 2016 12:48 PM To: Holston, William; Gavula, James; Allik, Brian Cc: IPRenewal NPEmails

Subject:

FW: IPEC Response to LRA RAI SET 2016-01 Attachments: NL-16-122_signed.pdf Hi guys, Here is Entergys response to RAIs 3.0.3-9 and 3.0.3-10 for Indian Point.

From: Louie, Richard [1]

Sent: Monday, December 05, 2016 7:31 AM To: Burton, William <William.Burton@nrc.gov>

Subject:

[External_Sender] IPEC Response to LRA RAI SET 2016-01

Butch, Please find attached an advance copy of Energys response letter to IPEC LRA RAI SET 2016-01.

Thank you for verbally extending the due date.

Let me know if you have any questions.

Richard Louie rlouie@entergy.com Regulatory Assurance Indian Point Energy Center (914) 254-6618 1

Hearing Identifier: IndianPointUnits2and3NonPublic_EX Email Number: 8684 Mail Envelope Properties (7f537b7d273a45b8bf06182781416a5e)

Subject:

FW: IPEC Response to LRA RAI SET 2016-01 Sent Date: 12/6/2016 12:48:03 PM Received Date: 12/6/2016 12:48:05 PM From: Burton, William Created By: William.Burton@nrc.gov Recipients:

"IPRenewal NPEmails" <IPRenewal.NPEmails@nrc.gov>

Tracking Status: None "Holston, William" <William.Holston@nrc.gov>

Tracking Status: None "Gavula, James" <James.Gavula@nrc.gov>

Tracking Status: None "Allik, Brian" <Brian.Allik@nrc.gov>

Tracking Status: None Post Office: HQPWMSMRS03.nrc.gov Files Size Date & Time MESSAGE 676 12/6/2016 12:48:05 PM NL-16-122_signed.pdf 229729 Options Priority: Standard Return Notification: No Reply Requested: No Sensitivity: Normal Expiration Date:

Recipients Received:

Entergy Nuclear Northeast Indian Point Energy Center 450 Broadway, GSB P.O. Box 249 Buchanan, NY 10511-0249 Tel (914) 254-6700 Anthony J Vitale Site Vice President NL-16-122 December 2, 2016 U.S. Nuclear Regulatory Commission Document Control Desk 11545 Rockville Pike, TWFN-2 F1 Rockville, MD 20852-2738

SUBJECT:

Reply to Request for Additional Information for the Review of the Indian Point Nuclear Generating Unit Nos. 2 and 3, License Renewal Application, SET 2016-01 (CAC Nos. MD5407 and MD5408)

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

REFERENCES:

1) USNRC letter, Request for Additional Information for the Review of the Indian Point Nuclear Generating Unit Nos. 2 and 3, License Renewal Application, SET 2016-01 (CAC Nos. MD5407 and MD5408), dated July 25, 2016 (ML16208A277)

2) USNRC letter, Service Water and Fire Water Systems Aging Management Programs Audit Report for Indian Point Nuclear Generating Unit Nos. 2 and 3 License Renewal Application (CAC Nos. MD5407 and MD5408), dated June 15, 2016 (ML16133A459)

3) USNRC, Public Meeting Summary with Entergy Regarding Proposed Changes to the Service Water Integrity Program for the Indian Point Nuclear Generating Unit Nos. 2 and 3 License Renewal Application, October 4, 2016 (ML16285A179)

Dear Sir or Madam:

Entergy Nuclear Operations, Inc. (Entergy) is providing, in Attachment 1, the additional information requested by Reference 1 pertaining to the U.S. Nuclear Regulatory Commission (NRC) review of the License Renewal Application (LRA) for Indian Point Energy Center (IPEC) Unit Nos. 2 and 3. On February 23-25, 2016, the NRC staff conducted a supplemental regulatory audit to gain a better understanding of Entergys

NL-16-122 Docket Nos. 50-247 and 50-286 Page 3 of 3 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. Douglas Pickett, NRR Senior Project Manager Ms. Bridget Frymire, New York State Department of Public Service Mr. John B. Rhodes, President and CEO NYSERDA NRC Resident Inspectors Office

ATTACHMENT 1 TO NL-16-122 REPLY TO NRC REQUEST FOR ADDITIONAL INFORMATION REGARDING THE LICENSE RENEWAL APPLICATION ENTERGY NUCLEAR OPERATIONS, INC.

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

NL-16-122 Attachment 1 Page 1 of 21 RAI 3.0.3-9

Background

By letter dated December 16, 2014 (ML14365A069), Entergy Nuclear Operations, Inc.

(Entergy), stated the following:

The Fire Water System Program includes volumetric wall thickness measurements used to ensure that wall thickness is within required structural limits. Entergy also stated that wall thickness measurements conducted for IP2 prior to the end of its original operating term did not identify any unacceptable wall thinning. Entergy also stated that, [l]ocalized corrosion has resulted in minor through-wall leaks that have no impact on system performance and do not threaten the structural integrity of the piping or the safety function of nearby equipment. Entergy did not propose any changes to its Fire Water System Program to address recurring internal corrosion (RIC).

Loss of material in the city water system is managed by the Periodic Surveillance and Preventive Maintenance Program. Entergy also stated that, [h]owever, based on past operating experience, they [through-wall leaks] do not compromise the intended functions of these or any other system, and do not warrant aging management program activities beyond those provided by established aging management programs and the corrective action program. In its letter dated September 26, 2012 (ML12285A084), Entergy stated that visual inspection or other NDE techniques will be used to inspect a representative sample of the internals of city water piping, and piping components to manage loss of material. Entergy did not propose any changes to its Periodic Surveillance and Preventive Maintenance Program to address RIC.

It appears that two events have impacted the performance of the fire water system.

IP2 - NRC Integrated Inspection Report 050000247/2003011 (ML033140584) documents a September 10, 2003, 80 gallon per minute leak that resulted in the fire water header not being available to perform its intended function for approximately three hours. The apparent cause for this leak states, [t]he apparent cause for the pin-hole leak is age related corrosion degradation of the piping, specifically, high-oxygenation pitting corrosion. The piping is original Unit 1 equipment, schedule 40 un-lined black steel pipe that is approximately 45 years old. The follow-up UT inspections indicated that the corrosion mechanism that resulted in the pinhole was not general pipe corrosion but was localized in the pinhole. The periodic testing of the system introduces fresh oxygen to the system and such cyclic re-oxygenation results in pits caused by 'high-oxygenation corrosion.' These pits then grow to become thru wall pinhole leaks in the piping. Portions not subject to periodic flow are not subject to this corrosion mechanism.

NL-16-122 Attachment 1 Page 2 of 21 IP2 - NRC Integrated Inspection Report 05000247/2015001 and 05000286/2015001 (ML15133A264) documents a December 29, 2014, failure of a 10-inch piping spool piece in the IP1 high pressure fire protection header that resulted in the fire water header to IP2 not being available to perform its intended function for about two hours. The failure was as a result of a crack opening up along the longitudinal seam weld along the bottom of the pipe. Three previously identified pinhole leaks were located along the length of the cracked region.

Issue During the supplemental audit conducted on February 23-25, 2016, the U.S. Nuclear Regulatory Commission (NRC) staff reviewed a list of leaks in the fire water and city water systems provided by Entergy. These leaks encompassed those occurring from 2007 through 2015. During this timeframe, there were approximately 42 leaks in the fire water system and 14 in the city water system. Sixteen of the fire water leaks were inspected using ultrasonic thickness techniques. Ultrasonic inspections were conducted on an additional 14 locations at IP2. Based on Entergys evaluation of all of the thickness measurements, structural integrity requirements were met. The NRC staff reviewed Entergys analytical techniques. Entergy has generated a preventive maintenance activity to perform ultrasonic inspections at the additional 14 locations by 2023. The NRC staff reviewed the ultrasonic thickness reports for two of the leaks associated with the December 29, 2014 failure. The NRC staff projected potential loss of material based on corrosion rates documented in Entergys calculations. It would appear that structural integrity requirements would have been met on the day of the failure. Based on its review of documents during the audit, the NRC staff concluded that conducting ultrasonic wall thickness examinations will not provide sufficient information to result in prevention of potential future losses of intended function of the fire water and city water system.

The cause evaluation for the September 10, 2003, failure did not provide an explanation as to why the pinhole leak, unlike the numerous other pinhole leaks, resulted in a temporary loss of intended function of the fire water header. Entergy does not have or did not provide an apparent cause report for the December 29, 2014 failure.

Lacking an apparent cause of the failure on December 29, 2014, and the limited causal analysis of the failure on September 10, 2003, the NRC staff lacks sufficient information to conclude that Entergy has implemented effective means to provide reasonable assurance that future losses of intended function of the fire water and city water system will not occur.

RAI 3.0.3-9 Request 1

1) State the cause of the failure on December 29, 2014. If possible, provide additional information related to the cause of the failure on September 10, 2003. In particular, if

NL-16-122 Attachment 1 Page 3 of 21 possible, provide information related to why the pinhole leak, unlike numerous other pinhole leaks, resulted in a temporary loss of intended function of the fire water header during the September 10, 2003, failure.

Response

Based upon photographic evidence and contemporaneous field observations of the failed fire protection pipe section, the December 29, 2014 piping leak appears to have been caused by selective seam corrosion attack on the longitudinal seam weld. That seam weld was located along the bottom (6 oclock position) of the pipe, the same portion of the pipe from which the leakage was observed. Entergy personnel had observed previous leakage along the longitudinal seam weld on the bottom of the piping segment. The selective seam corrosion in the crevice formed by the seam may have been exacerbated by microbiologically influenced corrosion (MIC) or under-deposit corrosion. Entergy replaced the affected piping spool piece in the high-pressure fire protection water header.

The leak associated with the September 10, 2003 event began as a pinhole and grew to a nominal 3/8 hole, discharging approximately 80-90 gallons per minute (gpm). The rate of discharge and potential for runoff to adjacent safety-related equipment areas mandated that the fire water supply system be secured until a temporary clamp could be installed. For that reason, there was a temporary loss of intended function of the fire water header. However, during the clamp installation, the system could have been manually returned to service if necessary to combat fire.

RAI 3.0.3-9 Request 2

2) State how these causes of failure are related to age-related degradation.

Response

These two Indian Point Energy Center (IPEC) fire water system piping leaks are attributed to an aging effect, specifically, loss of material due to corrosion mechanisms, such as pitting, crevice corrosion and MIC.

RAI 3.0.3-9 Request 3

3) Propose changes to aging management programs, as applicable, to address recurring internal corrosion in the fire water and city water systems or provide the basis as to why changes are not necessary.

Response

If loss of material due to corrosion meets the criteria for recurring internal corrosion (defined in LR-ISG-2012-02), then Entergy will conduct wall thickness measurements

NL-16-122 Attachment 1 Page 4 of 21 on a representative sample of 25 locations every five years during the period of extended operation (PEO) until recurring internal corrosion has subsided. Procedures shall require wall thickness measurements at selected locations to provide a representative sample of the type of piping and environment where recurring internal corrosion is identified. The procedures should allow for selected grid locations to change based on the relevance and usefulness of the wall thickness measurements.

Additional wall thickness inspections will be performed based on the results of the 25 inspections performed during the five year interval mentioned above.

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

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

In 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.

In 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.

For the city water system, Entergys Periodic Surveillance and Preventive Maintenance Program will include periodic inspections, either internal visual or UT wall thickness measurements, of a representative sample of 25 components. The frequency of these inspections is once 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 as a minimum, 10 additional volumetric examinations of system welds will be performed during the following refueling interval.

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

In 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 program documents will be revised to reflect these enhancements by December 31, 2017.

NL-16-122 Attachment 1 Page 5 of 21 RAI 3.0.3-10

Background

The NRC staff issued the Safety Evaluation Report (SER) for License Renewal of Indian Point Nuclear Generating Unit Nos. 2 and 3 (IP2 and IP3) in August 2009. As documented in the SER, the NRC staff concluded that the Service Water Integrity Program was shown to adequately manage the effects of aging. Since the completion of its initial reviews for the SER, as part of its efforts to evaluate information for interim staff guidance in LR-ISG-2012-02, Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation, the NRC staff identified operating experience at IP2 and IP3 during the intervening years (i.e., after 2009) where, as a result of aging effects, licensing basis functions may have been impacted by certain service water system components or components supported by the service water system. In addition, during its reviews of the more recent events, the NRC staff identified another historical event in 2002 that was not previously described. Based on this recently identified operating experience, the NRC staff needs additional information to evaluate the adequacy of Entergys Service Water Integrity Program in addressing recurring internal corrosion.

Issue

1) Licensee Event Report (LER) 286/2002-001 documents corrosion in an 18-inch service water pipe where the remaining wall thickness did not provide sufficient structural integrity. The cement-lined pipe configuration did not appear to be unique, the prior visual inspections did not reveal any missing cement liner or biological growth that are precursors to corrosion of the pipe; however, the existing NRC Generic Letter (GL) 89-13 program did not prevent a loss of pressure boundary due to a known degradation mechanism. It is unclear to the NRC staff that effective changes have been made to ensure that future, similar losses of pressure boundary will not occur in other cement-lined piping

2) LER 286/2011-003 documents corrosion in a 10-inch service water pipe involving a prior repair that caused a safety system functional failure due to flooding.

Entergys August 18, 2015, letter states that the through-wall failure of the piping was not considered to be due to the effects of aging because the loss of material occurred due to an inadequate repair of the concrete lining. It is unclear to the NRC staff that effective changes have been made to ensure that future, similar loss of intended function involving flooding or prior repairs will not occur in other cement-lined piping.

3) LER 247/2011-003 documents inoperable containment fan cooler units due to silt in the service water intake bay and notes that similar silt levels had caused similar issues in 2007. According to Entergys August 2015 letter, the associated changes to the Service Water Integrity Program were not made to manage the

NL-16-122 Attachment 1 Page 6 of 21 effects of aging, but instead were made to manage the effects of weather-related events. In addition, as a separate action, Entergy changed its associated GL 89-13 program commitment, which potentially allows the service water intake bay silting inspections to be conducted less frequently than given in GL 89-13. Given the distinction made between age-related silting and event-driven silting, and the change to GL 89-13 commitment, it is unclear to the NRC staff that effective changes have been made to ensure that the effects of aging associated with silting in the service water intake bay are adequately managed.

4) LER 247/2013-004 documents inoperable service water piping that rendered radiation monitors R-49, R-46, and R-53 non-functional, requiring compensatory action to be taken. The NRC staff identified four subsequent condition reports (CR-IP2-2013-5053, CR-IP2-2014-1179, CR-IP2-2014-6504, and CR-IP2-2015-3500) documenting additional leaks with the same consequence. The LER states that full piping replacement was planned for the 2014 refueling outage, and Entergys August 2015 letter states that 200 feet of this piping was replaced in 2014. Given that leakage has occurred subsequent to the piping replacement, it is unclear to the NRC staff that effective changes have been made to the program to ensure that future, similar recurring leaks will not adversely impact the intended function(s) of the radiation monitors.

5) LER 286/2014-002 documents a leak in a socket welded service water pipe that resulted in an essential service water header being declared inoperable because the leak location did not meet the ASME Code Case N-513-3 criteria. The LER states that the service water piping and valve flush procedure, 3-PT-R185B, was specifically developed to address recurring leaks in stagnant vent and drain piping, and the procedure is the main barrier for preventing future leaks in carbon steel socket welded piping. In its August 2015 letter, Entergy states that a section was added to the Program governing procedure in July 2011, after Entergy identified that IP2 did not have an equivalent flushing procedure as IP3. Entergy also states that the IP3 flushing procedure has been effective since being instituted in 2001. It is unclear to the NRC staff that effective changes have been made to the program because the procedure for preventing leaks apparently does not prevent recurring leaks. It is also unclear whether a comprehensive review has been performed to identify other missing unit-specific procedures for managing the effects of aging.

6) The August 2015 response to RAI 3.0.3-4 states more than 600 weld examinations have been performed since 1997 with more than 90 percent of the welds meeting acceptance criteria. The approximately 10 percent of welds that did not meet acceptance criteria can be viewed as the program having prevented about 60 leaks over the span of 18 years. In contrast, the listing for the number of leaks in the response indicates there have been over 90 leaks that the program did not prevent in 11 years. Although Entergy has made efforts to manage the effects of aging associated with recurring leaks, it is unclear whether the

NL-16-122 Attachment 1 Page 7 of 21 significance (i.e., multiple instances of loss of intended function) of these leaks will be limited as ongoing corrosion occurs.

7) Entergys December 2014 letter included an enhancement to the Service Water Integrity Program to evaluate through-wall leakage using the corrective action program. Although all conditions adverse to quality should be entered into the corrective action program and evaluated, given the need for this enhancement, it is unclear to the NRC staff whether previous leaks were evaluated under the corrective action program and, consequently, considered during previous operating experience reviews of corrective action documents. In addition, the basis for the December 31, 2019, completion date for this enhancement is unclear.

Request

1) Regarding the issues discussed above in LER 286/2002-001, provide information to show that changes made to the program (since that time) provide reasonable assurance that recurrence of the loss of function in other cement-lined piping is unlikely.

2) For LER 286/2011-003:

a. Provide the bases for reasonable assurance that the Service Water Integrity Program compensates for all past liner repairs such that this degradation mechanism will not result in a loss of intended function of the service water system. Also, provide the bases for reasonable assurance that all locations where flooding due to system leakage could cause loss of intended function have been identified and evaluated for probable leak rates.

b. For the previous operating experience reviews for license renewal, identify past degradation involving through-wall leakage that was not considered to be due to the effects of aging, and provide the bases to demonstrate that the cause of through-wall leakage has been adequately addressed to prevent a recurrence of a loss of safety function.

3) For LER 247/2011-003, clarify whether silt monitoring of the intake bays is included as an aging management activity. Provide the basis to demonstrate that the Service Water Integrity program, as modified by the December 2010 commitment changes, provides reasonable assurance that silting cannot result in a loss of intended function of the service water system.

4) For LER 247/2013-004, and subsequently issued condition reports CR-IP2-2013-5053, CR-IP2-2014-1179, CR-IP2-2014-6504, and CR-IP2-2015-3500:

NL-16-122 Attachment 1 Page 8 of 21

a. Describe what aspects of the Service Water Integrity Program will provide reasonable assurance that the intended function of these in-scope components will not be lost during the period of extended operation.

b. Provide an explanation for the continuing non-functionality of the radiation monitoring system given that 200 feet of the associated piping was replaced in 2014.

5) As it pertains to LER 286/2014-002:

a. State the basis for why the current Service Water Piping and Valve Flush procedure will provide reasonable assurance that the intended function of the service water system will be met. Address the effectiveness of the procedure in mitigating the leaks that it is intended to prevent, and discuss the basis for not needing to change the procedure to address recurring leaks in stagnant vent and drain piping.

b. Provide the bases establishing reasonable assurance that there are no other missing unit-specific aging management procedures being credited in the Service Water Integrity Program.

6) For the specific recurring internal corrosion category of cement-lined piping, state the minimum number of augmented inspections that will be performed in response to any identified leakage associated with corrosion. If augmented inspections will not be performed, provide an assessment based on observed corrosion rate ranges to provide reasonable assurance that structural integrity of the service water piping will be maintained throughout the period of extended operation.

7) For components managed by the Service Water Integrity Program:

a) List the past degradation due to through-wall leakage issues that have not been evaluated under the corrective action program. Within the list provide the date, description of the issue, the basis for why it was not addressed in the corrective action program, and whether the issue was considered during the development of the program elements of the Service Water Integrity Program.

b) Provide the basis to justify the December 31, 2019 implementation date of this enhancement.

NL-16-122 Attachment 1 Page 9 of 21 RAI 3.0.3-10 Request 1 Regarding the issues discussed above in LER 286/2002-001, provide information to show that changes made to the program (since that time) provide reasonable assurance that recurrence of the loss of function in other cement-lined piping is unlikely.

Response

Event Summary The event described in LER 286/2002-001 was the result of loss of material due to long-term crevice corrosion of the weld and piping base metal at a joint between two piping segments. The piping is carbon steel cement-lined piping. At the weld joints, there are small gaps between the ends of the cement liner on each side of the joint. The gap allows river water to contact the bare metal of the weld inside diameter (ID), which can cause corrosion of the weld metal over time. Furthermore, the gap can allow river water to seep under the cement liner causing corrosion of the base metal. Therefore, the program inspections specifically target weld locations.

Extent of Condition Review In response to the 2002 event, the piping of the service water header that remained in service was inspected to verify no leakage. Ultrasonic testing was performed on a similar weld on the in-service header, which demonstrated that the weld had acceptable thickness. The extent of condition review also included review of prior inspections of this 18-inch diameter line (line number 409) that was examined by a boroscope. This previous inspection revealed no signs of missing cement liner or biological growth which can be a precursor to corrosion of the piping or weld metal. The GL 89-13 corrosion monitoring program schedule was adjusted to include radiographic testing of four additional weld locations of similar pipe size and flow characteristics prior to the March 2003 refueling outage.

Program Changes since 2002 While no specific changes were made to the program directly as a result of the event reported in LER 286/2002-001, following the event reported in LER 286/2011-003, provisions were added to the program to ensure that nonsafety-related SW piping at locations where a leak can cause flooding, and where this flooding could prevent personnel from manually operating valves, is inspected on the same priority and frequency as safety-related SW piping. This program modification provides additional assurance that leakage from nonsafety-related cement-lined SW piping will not impact the ability of safety-related equipment to fulfill its intended functions.

Operating Experience Review

NL-16-122 Attachment 1 Page 10 of 21 A review of IPEC operating experience (OE) data, as documented in condition reports and Licensee Event Reports, for the period from January 2004 through August 2016, was performed. During this review, Entergy identified recurring internal corrosion (RIC) as defined in LR-ISG-2012-02. Some of the identified conditions in the SW system are similar to the condition described in LER 286/2002-001. Corrosion at the crevice of the cement lining on carbon steel system piping welds has occurred and, in some cases, has resulted in a loss of intended function.

Augmented Inspections The weld that leaked on 18-inch diameter line No. 408 (4/5/6 FCU supply header) described in LER 286/2002-001 had not been selected as an inspection sample prior to the leak. Following the 2002 leak, additional cement-lined piping welds on 18-inch diameter line No. 409 (1/2/3 FCU supply header) located in the primary auxiliary building SW pipe chase were inspected during the 2003 refueling outage. This ensured that all welds on the 1/2/3 FCU supply header had been inspected since the refueling outage in 1999. All welds in the 4/5/6 FCU header (18 inch - line No. 408) containing the leak described in LER 286/2002-001 were examined during the 2005 refueling outage.

A key element of the Service Water Integrity Program is the use of predictive monitoring. Entergy conducts an ongoing program of volumetric non-destructive examination (NDE) of SW system piping welds to obtain information on weld structural integrity. Since 2002, over 700 welds between both IPEC units have been inspected.

These inspections utilized volumetric techniques. An emphasis for inspection sample selection is placed on system welds that could place the plant in a short-term (72 hour8.333333e-4 days <br />0.02 hours <br />1.190476e-4 weeks <br />2.7396e-5 months <br /> or less) TS limiting condition for operation (LCO) completion time, as was the case for the event discussed in LER 286/2002-001. In addition to LCO considerations, the inspection schedule takes into account the required minimum wall thickness and the available margin. Welds with a lower calculated remaining service life would be scheduled for re-inspection accordingly. Of the welds inspected, a number have been identified for repair/replacement and a number are also being tracked for periodic follow-up NDE under the program. This would 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.

Additional Program Enhancements The following enhancements will be made to the Service Water Integrity Program.

1. A minimum number of volumetric weld examinations for safety-related 10 CFR 54.4(a)(1) cement-lined SW piping will be performed. The volumetric examinations will determine the extent of wall thinning. A degraded location, as defined in LR-ISG-2012-02, will be considered a location with a through-wall leak or a location with greater than 50 percent reduction of wall thickness from nominal thickness.

NL-16-122 Attachment 1 Page 11 of 21 Program procedures will be revised to specify a minimum of 10 volumetric weld examinations on each units SW system cement-lined piping during each refueling interval.

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

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

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.

2. The program will be enhanced to require a minimum of 5 additional volumetric weld examinations if a through-wall leak is discovered in non-safety related portions of the SW system that are within the scope of license renewal for the criterion of 10 CFR 54.4(a)(2).

3. The frequency of internal robotic inspections on the system headers at both units will be increased from once during the first 10 years of the period of extended operation to also include once during the second 10 years of the period of extended operation.

These program enhancements will include clarifying those activities that are required to satisfy licensing renewal requirements.

These enhancements will be implemented by December 31, 2017.

RAI 3.0.3-10 Request 2a For LER 286/2011-003:

a) Provide the bases for reasonable assurance that the Service Water Integrity Program compensates for all past liner repairs such that this degradation mechanism will not result in a loss of intended function of the service water system. Also, provide the bases for reasonable assurance that all locations where flooding due to system leakage could cause loss of intended function have been identified and evaluated for probable leak rates.

Response

The following activities provide the bases for reasonable assurance that loss of material, including loss of material resulting from improper liner repairs, will be adequately

NL-16-122 Attachment 1 Page 12 of 21 managed to preclude loss of intended function of the cement-lined service water piping during the period of extended operation1.

Operating Experience Review Entergy performed another review of site operating experience (OE) to determine whether there have been other instances of inadequate cement liner repairs that resulted in a loss of intended function of the SW system. Specifically, personnel reviewed OE for the SW systems at both IPEC units for the period from 2004 to the present to identify leaks similar to the leak described in LER 286/2011-003. The review identified no other instances of loss of safety function due to leakage resulting from improper repairs to internal linings. Because Entergy did not identify any other instances of loss of intended function due to an improperly repaired cement liner, and considering the program enhancements discussed in response to Request 1, there is a reasonable assurance that this condition will not result in loss of intended function in the future. The majority of the SW system leaks have been minor leaks that do not result in a leak rate large enough to result in a loss of the systems intended function.

External Inspections As documented in the condition report associated with LER 286/2011-003, visual inspections were performed on similar locations in the SW valve pits at both IPEC units where the potential for flooding is a concern. Those inspections did not identify any other leaking locations in the SW piping.

In addition, IPEC system engineers perform quarterly inspections of accessible portions of the SW system and operations personnel conduct routine field observations during operator rounds.

Internal Inspections As part of the Service Water Integrity Program, internal robotic inspections are performed of the main system headers and accessible piping in the primary auxiliary 1

Under 10 CFR § 54.29(a), the NRC may issue a renewed license upon finding that actions have been identified, and have been or will be taken, to manage the effects of aging on structures and components that perform license renewal intended functions, such that there is reasonable assurance that the activities authorized by the renewed license will continue to be conducted in accordance with the current licensing basis (CLB). The license renewal process is not intended to demonstrate absolute assurance that structures or components will not fail, but rather that there is reasonable assurance that they will perform such that the intended functions, as delineated in § 54.4, are maintained consistent with the CLB. Final Rule, Nuclear Power Plant License Renewal; Revisions, 60 Fed. Reg. 22,461, 22,479 (May 8, 1995). See also NUREG-1800, Rev. 2, Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants, App. A at A.1-1 (Dec. 2010). Thus, in this context, Entergy is not required to provide absolute assurance that SW piping will not leak. Instead, it must show, through appropriate preventive actions and/or condition monitoring, that there is reasonable assurance that it will adequately manage the loss of material due to internal corrosion, such that that intended safety functions of IPEC SW piping are maintained consistent with the CLB for the period of extended operation.

NL-16-122 Attachment 1 Page 13 of 21 building for each IPEC unit. These inspections of the large-bore cement-lined piping headers assess the material condition of the internal cement lining and provide additional assurance that a leak due to degraded liner material is unlikely.

To reduce the probability of an event similar to that reported in LER 286/2011-003, several changes were made to the SWI Program. As part of routine SW system heat exchanger maintenance activities, whenever a heat exchanger is opened, IPEC engineering is contacted to perform a visual inspection. These safety-related heat exchangers include the containment fan cooler units, component cooling water heat exchangers, emergency diesel generator jacket water and lube oil coolers. Accessible piping is examined as permitted by the opened component. Heat exchanger tubes and tubesheets are visually examined. These inspections include monitoring specifically for evidence of liner degradation, for example, loose cement pieces and damage to tube ends or tubesheets that may have been caused by impact from cement pieces. Similar visual inspections are performed whenever SW system components such as valves are removed.

Volumetric Inspections The following activities provide additional assurance that a SW system leak is unlikely to cause a loss of safety function in an area subject to flooding.

As a result of the LER, the Service Water Integrity Program was revised to specifically require inspections of non-safety related SW piping in locations where a leak can cause flooding, with the same priority and at the same frequency as safety-related SW piping.

Piping Material Upgrades At a number of plant locations, SW piping has been replaced with a material having corrosion resistance characteristics that are superior to those of the original cement-lined carbon steel piping. Using a proven corrosion-resistant pipe material greatly reduces the potential risk of leakage in an area where flooding is a concern. The Unit 3 switchgear room in the control building is an example of a location where flooding is a concern. Consequently, the service water piping to the instrument air compressor cooling water heat exchangers that passes through this room was replaced with more corrosion-resistant material.

Related Event In addition to the leak reported in LER 286/2011-003, a minor leak was identified in the same valve pit in 2013. The leak was not similar in nature (i.e., size or cause) to the leak reported in LER 286/2011-003. The leak rate was well within the capacity of sump pumps in the valve pit, such that flooding conditions sufficient to challenge the safety function of the SW system did not exist. The characteristics of the flaw were also

NL-16-122 Attachment 1 Page 14 of 21 different. The leak cause was identified as localized crevice corrosion. In contrast, the flaw discovered in 2011 was caused by extensive corrosion that resulted from the improper repair of the cement lining. Volumetric examination showed that the 2013 flaw did not impact the structural integrity of the affected piping. The flaw was evaluated under the corrective action program and did not result in a loss of system intended function. Cement liner degradation was not identified as a cause in the repair work order.

Future Program Enhancements

1. Entergy will review the SW system to identify areas where leakage from nonsafety-related SW piping could result in unacceptable flooding. The SWI Program will be reviewed to verify that this nonsafety-related piping in locations subject to flooding concerns is clearly identified in the program document. The SWI Program will be revised to specify volumetric examination of at least 20 percent of (up to a maximum of 25) nonsafety-related welds located in areas subject to flooding of safety-related equipment within each 10-year period of the PEO. This enhancement will be completed by December 31, 2017.

2. The SWIP will be enhanced to specify a yearly OE review to look for any failure due to the effects of aging, specifically including any failures related to inadequate cement liner repairs which may have occurred in the prior year. This enhancement will be completed by December 31, 2017.

RAI 3.0.3-10 Request 2b For LER 286/2011-003:

For the previous operating experience reviews for license renewal, identify past degradation involving through-wall leakage that was not considered to be due to the effects of aging, and provide the bases to demonstrate that the cause of through-wall leakage has been adequately addressed to prevent a recurrence of a loss of safety function.

Response

During the previous operating experience (OE) reviews that were performed relative to LER 286/2011-003, Entergy looked for loss of material due to corrosion. The initial review, however, did not include OE related to this LER because the cause of the LER event was specifically identified as poor workmanship in performing the prior repair and, therefore, was not attributed to an aging effect. Upon further evaluation, it was determined that the LER 286/2011-003 leak was caused by loss of material due to corrosion. The poor workmanship during the previous repair resulted in exposure of the weld to the raw water environment, thereby increasing the materials susceptibility to corrosion.

NL-16-122 Attachment 1 Page 15 of 21 As a result of this new insight, a more comprehensive understanding of the issue was developed. The original OE review would have excluded issues attributed to causes other than the effects of aging. A subsequent review of the same site OE data was performed with a broader consideration of aging effects. No additional occurrences of a loss of intended function were found that had been previously excluded based on classifying the cause as unrelated to the effects of aging. Therefore, Entergy concludes that the causes of through-wall leakage observed in the OE review have been adequately considered in determining the appropriate actions to prevent loss of license renewal intended function.

RAI 3.0.3-10 Request 3 For LER 247/2011-003, clarify whether silt monitoring of the intake bays is included as an aging management activity. Provide the basis to demonstrate that the Service Water Integrity program, as modified by the December 2010 commitment changes, provides reasonable assurance that silting cannot result in a loss of intended function of the service water system.

Response

Silt monitoring of the SW intake bays is included in the IPEC Service Water Integrity Program. The program descriptions in the IP2 and IP3 UFSAR supplements (Appendix A) for license renewal will be revised to indicate that silt monitoring is a program activity.

Silt accumulation can be the result of acute (short-term) events such as storms or chronic (long-term) effects over an extended period of time. The original monitoring for silt described in the IPEC GL 89-13 response was established strictly on a time basis. It did not consider the higher short-term rates of silting that could result from excessive rainfall or storms. Via the corrective action program, corrective actions from the 2007 silting event, LER 247/2011-003, and SOER 07-2, Intake Cooling Water Blockage, were incorporated into the SWI Program. These changes were made to keep the SW system intakes clear of silt irrespective of the cause - i.e., short-term event or long-term chronic silt accumulation.

GL 89-13 Commitment Change In the original responses to GL 89-13, Required Action I, both Consolidated Edison and the New York Power Authority committed to implement a program to visually inspect the SW intake structure bays at a frequency of once per refueling outage at Indian Point Units 1, 2, and 3. The original tasks to visually inspect (via diver inspection) the intake bays at IP2 and IP3 were eliminated due to safety concerns related to entering the intake bays with any of the SW pumps running. In addition to the safety concerns, water turbidity and murkiness limited the efficacy of visual inspections in determining bay conditions. Consequently, in November 2010, the commitments to visually inspect

NL-16-122 Attachment 1 Page 16 of 21 the SW intake bays at IP2 and IP3 were replaced with commitments to perform silt mapping using a sonar technique.

In accordance with IPEC procedures, Entergy performs the following activities to manage silt accumulation in the intake bays.

1. At 3-month intervals, IP2 and IP3 perform silt mapping of the SW bays using sonar.

2. Every 24 months, divers inspect the IP1 intake structure for structural integrity of the bay components, biofouling, and silt and debris.

3. Full desilting and debris removal from the SW bays is performed at the following frequencies:

a. Unit 1: every 8 years with 25 percent grace

b. Unit 2: every 4 years with no grace

c. Unit 3: every 10 years with 25 percent grace Note: The different frequencies between Unit 2 and Unit 3 are due to differences in designs (i.e., the bottoms of the Unit 3 SW pump columns are further above the bottom of the bays than are the bottoms of the Unit 2 SW pump columns).

These activities provide reasonable assurance that silting will not cause a loss of intended function of the SW system.

RAI 3.0.3-10 Request 4a For LER 247/2013-004, and subsequently issued condition reports CR-IP2-2013-5053, CR-IP2-2014-1179, CR-IP2-2014-6504, and CR-IP2-2015-3500:

a) Describe what aspects of the Service Water Integrity Program will provide reasonable assurance that the intended function of these in-scope components will not be lost during the period of extended operation.

Response

The causes of the loss of intended function of the components addressed in LER 247/2013-004, and subsequently issued condition reports CR-IP2-2013-5053, CR-IP2-2014-1179, CR-IP2-2014-6504, and CR-IP2-2015-3500, were (1) loss of material due to pitting corrosion in service water piping and tubing, and (2) loosening of tubing fittings (Swagelok connections) due to freezing of the fluid in the tubing. During normal plant operations, the lines are in service. However, there are no provisions in place for proper lay-up of the system when the service water lines are secured. During the time the system was out of service following the event reported in LER 247/2013-004, stagnant conditions accelerated pitting corrosion in the 316 series stainless steel tubing.

Additionally, extreme cold weather conditions during this same time, in conjunction with failure of the heat trace system, led to freezing within the tubing. That freezing caused separation of Swagelok connections and thus additional leaks.

NL-16-122 Attachment 1 Page 17 of 21 All welded piping within the IP2 primary auxiliary building (PAB) SW pipe chase (i.e., for leaks documented under CR-IP2-2013-03759 and CR-IP2-2013-05053) has been replaced with a corrosion-resistant 6 percent molybdenum stainless steel alloy (AL6XN).

IPEC operating experience has shown that this material exhibits excellent corrosion resistance in brackish Hudson River water. This piping material upgrade provides reasonable assurance that the intended function of the welded piping will not be lost during the period of extended operation.

All leaks outside of the PAB within the guard pipe and radiation monitor house have been repaired by retightening the Swagelok tubing joints and replacing sections of tubing.

Plant procedures will be revised to include guidance for lay-up of the SW process radiation monitoring system to minimize exposure of susceptible tubing to stagnant conditions. This enhancement will be completed by December 31, 2017.

The enhancement, in conjunction with the SW piping material upgrades and repairs discussed above, provides reasonable assurance that the effects of aging will not cause a loss of intended function of susceptible tubing during the period of extended operation.

RAI 3.0.3-10 Request 4b For LER 247/2013-004, and subsequently issued condition reports CR-IP2-2013-5053, CR-IP2-2014-1179, CR-IP2-2014-6504, and CR-IP2-2015-3500:

b) Provide an explanation for the continuing non-functionality of the radiation monitoring system given that 200 feet of the associated piping was replaced in 2014.

Response

The non-functionality of the SW process radiation monitoring system that occurred after the spring of 2014 was not related to the approximately 200 feet of piping that was replaced in 2014 (2R21). The piping that was replaced in 2014 included only the welded portion of the system that was located within the primary auxiliary building (PAB). Leaks occurring subsequent to that replacement were in the stainless steel tubing of the SW lines.

Leaks from the tubing outside of the PAB within the guard pipe and radiation monitor house have been repaired by retightening the Swagelok tubing joints and replacing sections of tubing. Some of these repair activities occurred as recently as the first quarter of 2016 during the IP2 refueling outage.

NL-16-122 Attachment 1 Page 18 of 21 RAI 3.0.3-10 Request 5a As it pertains to LER 286/2014-002:

a) State the basis for why the current Service Water Piping and Valve Flush procedure will provide reasonable assurance that the intended function of the service water system will be met. Address the effectiveness of the procedure in mitigating the leaks that it is intended to prevent, and discuss the basis for not needing to change the procedure to address recurring leaks in stagnant vent and drain piping.

Response

The Hudson River is a natural water source that contains various minerals and silt.

These substances tend to deposit and accumulate in stagnant small-bore piping, such as vents and drains. This condition is seen more in carbon steel piping than in brass or stainless steel piping since brass and stainless steel piping have a smoother interior surface. However, all materials are susceptible to this condition.

After years of service, small bore piping with stagnant conditions (e.g., piping used for vents and drains) can become clogged if not flushed or otherwise cleared. Clogged, dead-ended, stagnant pipe creates favorable conditions for corrosive anaerobic bacteria (the cause of microbiologically influenced corrosion (MIC)), which is naturally present in the river. Biocides (e.g., sodium hypochlorite) injected into the SW systems are ineffective in these areas because the biocide cannot penetrate the clogged area. Most MIC manifests as pits that form underneath colonies of living organic matter, mineral, and bio-deposits. These deposits create an environment in which corrosion may be accelerated. To address this issue, piping vent and drain connections are periodically flushed to remove silt, organic matter, and other debris.

At IP3, these actions are accomplished utilizing a series of flushing procedures. At IP2, similar procedures were developed in 2012 and were scheduled for performance once every two years. The flushing procedures were developed at both units by identifying susceptible piping lines, valves, and branch connections via review of system flow diagrams. The acceptance criteria in the flushing procedures are satisfied when all locations identified are satisfactorily flushed, the valves closed, and the piping caps/flanges/plugs restored. If any components fail to meet these criteria, then work requests must be initiated for component repairs. Failure to flush one or more piping connections does not necessarily impact SW system operability.

Thus, the strategy to manage MIC at IPEC includes: 1) flushing the lines, 2) inspecting for leaks, and 3) replacing sections of piping that are susceptible to corrosion with improved material types. Additionally, Operations and Engineering personnel perform periodic system inspections, during which leaks, if any, are identified. Although small leaks have occurred, these actions provide reasonable assurance that loss of material

NL-16-122 Attachment 1 Page 19 of 21 in the small-bore SW system piping will be managed such that the systems intended functions are maintained consistent with the current licensing basis (CLB) during the period of extended operation. Some leaks have occurred in sections of piping that cannot be evaluated as operable from a structural point of view because the configuration does not match acceptable code case evaluation configurations. For those cases where NDE techniques are not suitable to demonstrate structural integrity, the system is declared inoperable and repairs are undertaken.

Future Program Enhancements An enhancement will be made to 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.

RAI 3.0.3-10 Request 5b As it pertains to LER 286/2014-002:

b) Provide the bases establishing reasonable assurance that there are no other missing unit-specific aging management procedures being credited in the Service Water Integrity Program.

Response

A condition report was generated in October 2010 upon discovery that there was no IP2 procedure similar to IP3 procedure 3PT-R185 for flushing small bore vents and drains in the SW system. The issue at IP2 was identified shortly after Entergy combined the IP2 and IP3 programs. In developing a combined program document for both units, Entergy performed a side-by-side evaluation of each unit's programs. No other differences between units were identified related to implementing procedures for the program.

RAI 3.0.3-10 Request 6 For the specific recurring internal corrosion category of cement-lined piping, state the minimum number of augmented inspections that will be performed in response to any identified leakage associated with corrosion. If augmented inspections will not be performed, provide an assessment based on observed corrosion rate ranges to provide reasonable assurance that structural integrity of the service water piping will be maintained throughout the period of extended operation.

NL-16-122 Attachment 1 Page 20 of 21

Response

The additional program enhancements described in the response to Request 1 specify the numbers of inspections for cement-lined piping. The enhancements establish a minimum number of inspections per refueling cycle interval and provide for augmented (additional) inspections depending on the number of degraded piping locations found during the period.

RAI 3.0.3-10 Request 7a For components managed by the Service Water Integrity Program:

a) List the past degradation due to through-wall leakage issues that have not been evaluated under the corrective action program. Within the list provide the date, description of the issue, the basis for why it was not addressed in the corrective action program, and whether the issue was considered during the development of the program elements of the Service Water Integrity Program.

Response

The Corrective Action Program procedure provides instructions for the prompt identification, reporting, evaluation, and correction of adverse conditions and conditions adverse to quality. The enhancement included in Entergys December 2014 letter was intended to make explicit in the Service Water Integrity Program procedures the requirement to identify and evaluate through-wall leakage in the SW system using the Corrective Action Program. Through-wall piping leakage, regardless of plant system, or nuclear safety or ISI classification, is a condition that is entered into the Corrective Action Program. Entergy has identified no past SW system through-wall leakage issues at either IP2 or IP3 that have not been evaluated under the Corrective Action Program.

RAI 3.0.3-10 Request 7b For components managed by the Service Water Integrity Program:

b) Provide the basis to justify the December 31, 2019 implementation date of this enhancement.

Response

The timing of program activities recommended in LR-ISG-2012-02 is tied to the date a unit will enter the period of extended operation (PEO). At the time Entergy filed its response to RAIs associated with LR-ISG-2012-02 on December 16, 2014, IP2 had entered the PEO and IP3 was less than a year away from entering the PEO. Therefore, the date of entering the PEO was not a realistic date for implementing the program enhancements described in the response to the ISG-related RAIs. Consequently, in the

NL-16-122 Attachment 1 Page 21 of 21 RAI responses submitted on December 16, 2014, Entergy identified December 31, 2019, as the implementation date, which it viewed as an appropriate surrogate to the date for entering the PEO. Thus, where the ISG specifies activities to be completed "prior to the period of extended operation," Entergy intends to complete those activities at IPEC for both units prior to December 31, 2019.

The ISG provided a ten-year window in which to perform the first inspections prior to the PEO. Since IPEC did not have ten years from the time the RAI was received, a five-year period was deemed reasonable. The five-year period (December 2014 through December 2019) allows two outages for each unit in which to perform the specified inspections, some of which can only be performed during an outage. The scope of an outage is established many months in advance to allow for adequate planning and coordination, including coordination with system and train outages that may only occur during alternate refueling outages. Given that the ISG provided a ten-year window for the first inspections, the five-year window for IPEC is reasonable to allow for adequate planning and scheduling around and within outage windows.

The implementation date of "prior to December 31, 2019," allows for the following activities to occur:

Planning the activities specified in the ISG as ordinarily being performed prior to the PEO.

Revising procedures to include the enhancements described in the LRA.

Ensuring availability of test equipment as needed.

Scheduling and completing the activities specified in the ISG as ordinarily being performed prior to the PEO.

Working with two units, each with two-year operating cycles affecting opportunities for inspections.

Assessing the results from the activities specified in the ISG as ordinarily being performed prior to the PEO.

Determining corrective actions as needed.

Establishing scope and frequency for future activities.

Planning and scheduling the activities specified in the ISG to be performed during the PEO.

Scheduling inspections for refueling outages.

Scheduling 10-year inspections as specified.

ATTACHMENT 2 TO NL-16-122 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-16-122 Attachment 2 Page 1 of 9 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 Revise Fire Water System Program procedures by December 31, 2017 to address recurring internal corrosion at least once every five years during the PEO until recurring internal corrosion has subsided:

a) Require wall thickness measurements at selected locations to provide a representative sample of 25 locations.

b) Require additional wall thickness measurements based on the following:

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

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

c) 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.

d) Allow for selected grid locations to change based on the relevance and usefulness of the wall thickness measurements.

e) 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.

A.2.1.28 Periodic Surveillance and Preventive Maintenance Program 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.

A.2.1.33 Service Water Integrity Program The Service Water Integrity Program is an existing program that relies on implementation of the recommendations of GL 89-13 to ensure that the effects of aging on the service water system are managed through the period of extended operation. The program includes component

NL-16-122 Attachment 2 Page 2 of 9 inspections for erosion, corrosion, and biofouling to verify the heat transfer capability of safety-related heat exchangers cooled by service water and monitoring of the silt levels in the intake bays. Chemical treatment using biocides and sodium hypochlorite and periodic cleaning and flushing of infrequently used loops are methods used to control fouling within the heat exchangers and to manage loss of material in service water components. Scheduling of nonsafety-related piping examinations is determined by trending of examination results.

Selection of large bore service water pipe points for volumetric inspection is based on piping configuration, results from previous inspections, consideration of follow-ups to previous repairs, and condition assessments when components are opened during preventive maintenance activities. Scope expansion for indications found by program inspections of nonsafety-related piping is based on engineering analysis, judgment and program experience. The factors that are considered include piping location, severity of use, piping materials, previous inspection results, and repair history.

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

a) Perform a minimum number of volumetric weld examinations for safety-related cement-lined SW piping. The volumetric examinations will determine the extent of wall thinning.

A degraded location will be considered a location with a through-wall leak or with greater than 50 percent reduction of wall thickness from nominal thickness.

Perform a minimum of 10 volumetric weld examinations for cement-lined piping on the IP2 SW system during each refueling interval.

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

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

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

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

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

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

NL-16-122 Attachment 2 Page 3 of 9 f) Specify a yearly OE review to identify any effects of aging reported on the SW system, specifically including any conditions that may have occurred in the prior year related to inadequate cement liner repairs.

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

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

A.3.1.13 Fire Water System Program Revise Fire Water System Program procedures by December 31, 2017 to address recurring internal corrosion at least once every five years during the PEO until recurring internal corrosion has subsided:

a) Require wall thickness measurements at selected locations to provide a representative sample of 25 locations.

b) Require additional wall thickness measurements based on the following:

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

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

c) 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.

d) Allow for selected grid locations to change based on the relevance and usefulness of the wall thickness measurements.

e) 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.

A.3.1.28 Periodic Surveillance and Preventive Maintenance Program 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 as a minimum, 10 additional volumetric examinations of system welds will be performed during the following refueling interval.

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

NL-16-122 Attachment 2 Page 4 of 9 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.

A.3.1.33 Service Water Integrity Program The Service Water Integrity Program is an existing program that relies on implementation of the recommendations of GL 89-13 to ensure that the effects of aging on the service water system are managed through the period of extended operation. The program includes component inspections for erosion, corrosion, and biofouling to verify the heat transfer capability of safety-related heat exchangers cooled by service water and monitoring of the silt levels in the intake bays. Chemical treatment using biocides and chlorine and periodic cleaning and flushing of infrequently used loops are methods used to control fouling within the heat exchangers and to manage loss of material in service water components. Scheduling of nonsafety-related piping examinations is determined by trending of examination results. Selection of large bore service water pipe points for volumetric inspection is based on piping configuration, results from previous inspections, consideration of follow-ups to previous repairs, and condition assessments when components are opened during preventive maintenance activities. Scope expansion for indications found by program inspections of nonsafety-related piping is based on engineering analysis, judgment and program experience. The factors that are considered include piping location, severity of use, piping materials, previous inspection results, and repair history.

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

a) Perform a minimum number of volumetric weld examinations for safety-related cement-lined SW piping. The volumetric examinations will determine the extent of wall thinning.

A degraded location will be considered a location with a through-wall leak or with greater than 50 percent reduction of wall thickness from nominal thickness.

Perform a minimum of 10 volumetric weld examinations for cement-lined piping on the IP3 SW system during each refueling interval.

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

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

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

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

NL-16-122 Attachment 2 Page 5 of 9 d) Increase the frequency of internal robotic inspections on the system headers at both units from once during the first 10 years of the period of extended operation to also include once during the second 10 years of the period of extended operation.

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

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

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

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

B.1.14 Fire Water System Attributes Affected Enhancement

4. Detection of Aging Effects Revise IP2 and IP3 Fire Water Program procedures by December 31, 2017 to address recurring internal corrosion at least once every five years during the PEO until recurring internal corrosion has subsided:

a) Require wall thickness measurements at selected locations to provide a representative sample of 25 locations b) Require additional wall thickness measurements based on the following:

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

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

NL-16-122 Attachment 2 Page 6 of 9 refueling interval.

c) 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.

d) Allow for selected grid locations to change based on the relevance and usefulness of the wall thickness measurements e) 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

NL-16-122 Attachment 2 Page 7 of 9 B.1.29 Periodic Surveillance and Preventive Maintenance Program Description The Periodic Surveillance and Preventive Maintenance Program is an existing program that includes periodic inspections and tests that manage aging effects not managed by other aging management programs. In addition to specific activities in the plant's preventive maintenance program and surveillance program, the Periodic Surveillance and Preventive Maintenance Program includes enhancements to add new activities. The preventive maintenance and surveillance testing activities are generally implemented through repetitive tasks or routine monitoring of plant operations. Credit for program activities has been taken in the aging management review of the following systems and structures. All activities are new unless otherwise noted.

City water system Use visual or other NDE 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.

B.1.34 Service Water Integrity Program Description The Service Water Integrity Program is an existing program that relies on implementation of the recommendations of GL 89-13 to ensure that the effects of aging on the service water system are managed through the period of extended operation. The program includes component inspections for erosion, corrosion, and biofouling to verify the heat transfer capability of safety-related heat exchangers cooled by service water and monitoring of the silt level in the intake bays. Chemical treatment using biocides and sodium hypochlorite and periodic cleaning and flushing of infrequently used loops are methods used to control fouling within the heat

NL-16-122 Attachment 2 Page 8 of 9 exchangers and to manage loss of material in service water components. Prioritization of internal examinations of SW piping is based on safety classification. Scheduling of nonsafety-related piping examination is determined by trending of examination results. Selection of large bore service water pipe points for volumetric inspection is based on piping configuration, results from previous inspections, consideration of follow-ups to previous repairs, and condition assessments when components are opened during preventive maintenance activities. Scope expansion for indications found by program inspections of nonsafety-related piping is based on engineering analysis, judgment and program experience. The factors that are considered include piping location, severity of use, piping materials, previous inspection results, and repair history.

Attributes Affected Enhancements

4. Detection of Aging Effects Revised Service Water Integrity Program procedures by December 31, 2017 to address the following:

a) Perform a minimum number of volumetric weld examinations for safety-related cement-lined SW piping. The volumetric examinations will determine the extent of wall thinning. A degraded location will be considered a location with a through-wall leak or with greater than 50 percent reduction of wall thickness from nominal thickness.

Perform a minimum of 10 volumetric weld examinations for cement-lined piping on each units SW system during each refueling interval.

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

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

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

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

NL-16-122 Attachment 2 Page 9 of 9 d) Increase the frequency of internal robotic inspections on the system headers at both units from once during the first 10 years of the period of extended operation to also include once during the second 10 years of the period of extended operation.

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

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

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

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

ATTACHMENT 3 TO NL-16-122 LICENSE RENEWAL APPLICATION IPEC LIST OF REGULATORY COMMITMENTS Rev. 29 ENTERGY NUCLEAR OPERATIONS, INC.

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

NL-16-122 Attachment 3 Page 1 of 25 List of Regulatory Commitments Rev. 29 The following table identifies those actions committed to by Entergy in this document.

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

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AUDIT ITEM IP2: NL-07-039 A.2.1.1 1 Enhance the Aboveground Steel Tanks Complete A.3.1.1 Program for IP2 and IP3 to perform thickness NL-13-122 B.1.1 measurements of the bottom surfaces of the condensate storage tanks, city water tank, and fire water tanks once during the first ten years of the period of extended operation.

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

IP2 & IP3: NL-14-147 A.2.1.1 Implement LRA Sections, A.2.1.1, A.3.1.1 and December 31, A.3.1.1 B.1.1, as shown in NL-14-147.

2019 B.1.1 NL-15-092 Implement LRA Sections, A.2.1.1 and B.1.1, as IP2 & IP3: A.2.1.1 December 31, B.1.1 shown in NL-15-092 2019 IP2: NL-07-039 A.2.1.2 2 Enhance the Bolting Integrity Program for IP2 Complete A.3.1.2 and IP3 to clarify that actual yield strength is B.1.2 used in selecting materials for low susceptibility IP3:

to SCC and clarify the prohibition on use of Complete NL-07-153 Audit Items lubricants containing MoS2 for bolting.

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

NL-16-122 Attachment 3 Page 2 of 25

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AUDIT ITEM IP2: NL-07-039 A.2.1.5 3 Implement the Buried Piping and Tanks Complete A.3.1.5 Inspection Program for IP2 and IP3 as described in LRA Section B.1.6. NL-13-122 B.1.6 IP3: NL-07-153 Audit Item This new program will be implemented December 12, NL-15-121 173 consistent with the corresponding program 2015Complete described in NUREG-1801 Section XI.M34, Buried Piping and Tanks Inspection.

Include in the Buried Piping and Tanks NL-09-106 Inspection Program described in LRA Section B.1.6 a risk assessment of in-scope buried NL-09-111 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 NL-11-101 inspection techniques with demonstrated effectiveness.

IP2: NL-07-039 A.2.1.8 4 Enhance the Diesel Fuel Monitoring Program to Complete A.3.1.8 include cleaning and inspection of the IP2 GT-1 gas turbine fuel oil storage tanks, IP2 and IP3 NL-13-122 B.1.9 IP3: NL-07-153 Audit items EDG fuel oil day tanks, IP2 SBO/Appendix R December 12, NL-15-121 128, 129, diesel generator fuel oil day tank, and IP3 Appendix R fuel oil storage tank and day tank 2015Complete 132, once every ten years. NL-08-057 491, 492, 510 Enhance the Diesel Fuel Monitoring Program to include quarterly sampling and analysis of the IP2 SBO/Appendix R diesel generator fuel oil day tank, IP2 security diesel fuel oil storage tank, IP2 security diesel fuel oil day tank, and IP3 Appendix R fuel oil storage tank.

NL-16-122 Attachment 3 Page 3 of 25

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AUDIT ITEM Particulates, water and sediment checks will be performed on the samples. Filterable solids acceptance criterion will be less than or equal to 10mg/l. Water and sediment acceptance criterion will be less than or equal to 0.05%.

Enhance the Diesel Fuel Monitoring Program to include thickness measurement of the bottom of the following tanks once every ten years. IP2:

EDG fuel oil storage tanks, EDG fuel oil day tanks, SBO/Appendix R diesel generator fuel oil day tank, GT-1 gas turbine fuel oil storage tanks, and diesel fire pump fuel oil storage tank; IP3: EDG fuel oil day tanks, EDG fuel oil storage tanks, Appendix R fuel oil storage tank, and diesel fire pump fuel oil storage tank.

Enhance the Diesel Fuel Monitoring Program to change the analysis for water and particulates to a quarterly frequency for the following tanks.

IP2: GT-1 gas turbine fuel oil storage tanks and diesel fire pump fuel oil storage tank; IP3:

Appendix R fuel oil day tank and diesel fire pump fuel oil storage tank.

Enhance the Diesel Fuel Monitoring Program to specify acceptance criteria for thickness measurements of the fuel oil storage tanks within the scope of the program.

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

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

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

NL-16-122 Attachment 3 Page 4 of 25

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AUDIT ITEM IP2: NL-07-039 A.2.1.10 5 Enhance the External Surfaces Monitoring Complete A.3.1.10 Program for IP2 and IP3 to include periodic NL-13-122 B.1.11 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).

IP2 & IP3: NL-14-147 A.2.1.10 Implement LRA Sections A.2.1.10, A.3.1.10 and December 31, A.3.1.10 B.1.11, as shown in NL-14-147.

2019 B.1.11 IP2: NL-07-039 A.2.1.11 6 Enhance the Fatigue Monitoring Program for Complete A.3.1.11 IP2 to monitor steady state cycles and feedwater cycles or perform an evaluation to NL-13-122 B.1.12, determine monitoring is not required. Review NL-07-153 Audit Item 164 the number of allowed events and resolve discrepancies between reference documents NL-15-121 IP3:

and monitoring procedures.

December 12, Enhance the Fatigue Monitoring Program for 2015Complete 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.

NL-16-122 Attachment 3 Page 5 of 25

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AUDIT ITEM IP2: NL-07-039 A.2.1.12 7 Enhance the Fire Protection Program to inspect Complete A.3.1.12 external surfaces of the IP3 RCP oil collection NL-13-122 B.1.13 systems for loss of material each refueling IP3:

cycle.

December 12, NL-15-121 Enhance the Fire Protection Program to 2015Complete 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 EDG room CO2 fire suppression system for signs of degradation, such as corrosion and mechanical damage at least once every six months.

NL-16-122 Attachment 3 Page 6 of 25

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AUDIT ITEM IP2: NL-07-039 A.2.1.13 8 Enhance the Fire Water Program to include Complete A.3.1.13 inspection of IP2 and IP3 hose reels for NL-13-122 B.1.14 evidence of corrosion. Acceptance criteria will NL-07-153 Audit Items be revised to verify no unacceptable signs of degradation. 105, 106 NL-08-014 Enhance the Fire Water Program to replace all or test a sample of IP2 and IP3 sprinkler heads required for 10 CFR 50.48 using guidance of NFPA 25 (2002 edition), Section 5.3.1.1.1 before the end of the 50-year sprinkler head service life and at 10-year intervals thereafter during the extended period of operation to ensure that signs of degradation, such as corrosion, are detected in a timely manner.

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

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

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

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

NL-16-122 Attachment 3 Page 7 of 25

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AUDIT ITEM NL-15-092 Implement LRA Sections A.2.1.13, A.3.1.13 and IP2 & IP3: A.2.1.13 December 31, A.3.1.13 B.1.14, as shown in NL-15-092 2019 B.1.14 IP2 & IP3: NL-16-122 A.2.1.13 Implement LRA Sections A.2.1.13, A.3.1.13, December 31, A.3.1.13 and B.1.14, as shown in NL-16-122 2017 B.1.14 IP2: NL-07-039 A.2.1.15 9 Enhance the Flux Thimble Tube Inspection Complete A.3.1.15 Program for IP2 and IP3 to implement comparisons to wear rates identified in WCAP- NL-13-122 B.1.16 IP3: NL-15-121 12866. Include provisions to compare data to December 12, the previous performances and perform evaluations regarding change to test frequency 2015Complete 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.

NL-16-122 Attachment 3 Page 8 of 25

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AUDIT ITEM IP2: NL-07-039 A.2.1.16 10 Enhance the Heat Exchanger Monitoring Complete A.3.1.16 Program for IP2 and IP3 to include the following heat exchangers in the scope of the program. NL-13-122 B.1.17, IP3: NL-07-153 Audit Item Safety injection pump lube oil heat December 12, NL-15-121 52 exchangers 2015Complete RHR heat exchangers RHR pump seal coolers Non-regenerative heat exchangers Charging pump seal water heat exchangers Charging pump fluid drive coolers Charging pump crankcase oil coolers Spent fuel pit heat exchangers Secondary system steam generator sample coolers Waste gas compressor heat exchangers SBO/Appendix R diesel jacket water heat exchanger (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. NL-09-018

NL-16-122 Attachment 3 Page 9 of 25

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

IP3:

Complete IP2: NL-07-039 A.2.1.19 13 Enhance the Metal-Enclosed Bus Inspection Complete A.3.1.19 Program for IP2 and IP3 to visually inspect the external surface of MEB enclosure assemblies NL-13-122 B.1.20 IP3: NL-07-153 Audit Items for loss of material at least once every 10 years.

December 12, NL-15-121 124, The first inspection will occur prior to the period of extended operation and the acceptance 2015Complete NL-08-057 133, 519 criterion will be no significant loss of material.

NL-13-077 Enhance the Metal-Enclosed Bus Inspection Program to add acceptance criteria for MEB internal visual inspections to include the absence of indications of dust accumulation on the bus bar, on the insulators, and in the duct, in addition to the absence of indications of moisture intrusion into the duct.

Enhance the Metal-Enclosed Bus Inspection Program for IP2 and IP3 to inspect bolted connections at least once every five years if performed visually or at least once every ten years using quantitative measurements such as thermography or contact resistance measurements. The first inspection will occur prior to the period of extended operation.

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

NL-16-122 Attachment 3 Page 10 of 25

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AUDIT ITEM IP2: NL-07-039 A.2.1.21 14 Implement the Non-EQ Bolted Cable Complete A.3.1.21 Connections Program for IP2 and IP3 as NL-13-122 B.1.22 described in LRA Section B.1.22.

IP3: NL-15-121 December 12, 2015Complete IP2: NL-07-039 A.2.1.22 15 Implement the Non-EQ Inaccessible Medium-Complete A.3.1.22 Voltage Cable Program for IP2 and IP3 as described in LRA Section B.1.23. NL-13-122 B.1.23 IP3: NL-07-153 Audit item This new program will be implemented December 12, NL-15-121 173 consistent with the corresponding program 2015Complete NL-11-032 described in NUREG-1801 Section XI.E3, Inaccessible Medium-Voltage Cables Not NL-11-096 Subject To 10 CFR 50.49 Environmental Qualification Requirements. NL-11-101 IP2: NL-07-039 A.2.1.23 16 Implement the Non-EQ Instrumentation Circuits Complete A.3.1.23 Test Review Program for IP2 and IP3 as described in LRA Section B.1.24. NL-13-122 B.1.24 IP3: NL-07-153 Audit item This new program will be implemented December 12, NL-15-121 173 consistent with the corresponding program 2015Complete described in NUREG-1801 Section XI.E2, Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits.

IP2: NL-07-039 A.2.1.24 17 Implement the Non-EQ Insulated Cables and Complete A.3.1.24 Connections Program for IP2 and IP3 as described in LRA Section B.1.25. NL-13-122 B.1.25 IP3: NL-07-153 Audit item This new program will be implemented December 12, NL-15-121 173 consistent with the corresponding program 2015Complete described in NUREG-1801 Section XI.E1, Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements.

NL-16-122 Attachment 3 Page 11 of 25

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AUDIT ITEM IP2: NL-07-039 A.2.1.25 18 Enhance the Oil Analysis Program for IP2 to Complete A.3.1.25 sample and analyze lubricating oil used in the NL-13-122 B.1.26 SBO/Appendix R diesel generator consistent IP3: NL-11-101 with the oil analysis for other site diesel December 12, NL-15-121 generators.

2015Complete 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.

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

NL-16-122 Attachment 3 Page 12 of 25

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AUDIT ITEM IP2: NL-07-039 A.2.1.26 19 Implement the One-Time Inspection Program Complete A.3.1.26 for IP2 and IP3 as described in LRA Section B.1.27. NL-13-122 B.1.27 IP3: NL-07-153 Audit item This new program will be implemented December 12, NL-15-121 173 consistent with the corresponding program 2015Complete described in NUREG-1801,Section XI.M32, One-Time Inspection.

IP2: NL-07-039 A.2.1.27 20 Implement the One-Time Inspection - Small Complete A.3.1.27 Bore Piping Program for IP2 and IP3 as described in LRA Section B.1.28. NL-13-122 B.1.28 IP3: NL-07-153 Audit item This new program will be implemented December 12, NL-15-121 173 consistent with the corresponding program 2015Complete described in NUREG-1801,Section XI.M35, One-Time Inspection of ASME Code Class I Small-Bore Piping.

IP2: NL-07-039 A.2.1.28 21 Enhance the Periodic Surveillance and Complete A.3.1.28 Preventive Maintenance Program for IP2 and IP3 as necessary to assure that the effects of NL-13-122 B.1.29 IP3: NL-15-121 aging will be managed such that applicable December 12, components will continue to perform their intended functions consistent with the current 2015Complete licensing basis through the period of extended operation.

Implement LRA Sections A.2.1.28, A.3.1.28 and IP2 & IP3: NL-16-122 A.2.1.28 December 31, A.3.1.28 B.1.29, as shown in NL-16-122 2017 B.1.29 IP2: NL-07-039 A.2.1.31 22 Enhance the Reactor Vessel Surveillance Complete A.3.1.31 Program for IP2 and IP3 revising the specimen capsule withdrawal schedules to draw and test NL-13-122 B.1.32 IP3: NL-15-121 a standby capsule to cover the peak reactor December 12, vessel fluence expected through the end of the period of extended operation. 2015Complete 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.

NL-16-122 Attachment 3 Page 13 of 25

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AUDIT ITEM IP2: NL-07-039 A.2.1.32 23 Implement the Selective Leaching Program for Complete A.3.1.32 IP2 and IP3 as described in LRA Section B.1.33. NL-13-122 B.1.33 IP3: NL-07-153 Audit item This new program will be implemented December 12, NL-15-121 173 consistent with the corresponding program 2015Complete described in NUREG-1801,Section XI.M33 Selective Leaching of Materials.

IP2: NL-07-039 A.2.1.34 24 Enhance the Steam Generator Integrity Complete A.3.1.34 Program for IP2 and IP3 to require that the NL-13-122 B.1.35 results of the condition monitoring assessment IP3:

are compared to the operational assessment Complete performed for the prior operating cycle with differences evaluated.

Enhance the Structures Monitoring Program to IP2: NL-07-039 A.2.1.35 25 explicitly specify that the following structures Complete A.3.1.35 are included in the program. NL-13-122 B.1.36 Appendix R diesel generator foundation IP3: NL-07-153 (IP3) December 12, NL-15-121 Audit items Appendix R diesel generator fuel oil tank 2015Complete 86, 87, 88, vault (IP3) NL-08-057 417 Appendix R diesel generator switchgear and enclosure (IP3) city water storage tank foundation NL-13-077 condensate storage tanks foundation (IP3) containment access facility and annex (IP3) discharge canal (IP2/3) emergency lighting poles and foundations (IP2/3) fire pumphouse (IP2) fire protection pumphouse (IP3) fire water storage tank foundations (IP2/3) gas turbine 1 fuel storage tank foundation 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)

NL-16-122 Attachment 3 Page 14 of 25

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AUDIT ITEM service water pipe chase (IP2/3) service water valve pit (IP3) NL-14-146 superheater stack 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 NL-13-077 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 occurring.

Enhance the Structures Monitoring Program for IP2 and IP3 to perform inspections of elastomers (seals, gaskets, seismic joint filler, and roof elastomers) to identify cracking and change in material properties and for inspection

NL-16-122 Attachment 3 Page 15 of 25

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AUDIT ITEM of aluminum vents and louvers to identify loss of material.

NL-08-127 Audit Item Enhance the Structures Monitoring Program for 360 IP2 and IP3 to perform an engineering evaluation of groundwater samples to assess aggressiveness of groundwater to concrete on a periodic basis (at least once every five years).

IPEC will obtain samples from at least 5 wells that are representative of the ground water surrounding below-grade site structures and perform an engineering evaluation of the results from those samples for sulfates, pH and chlorides. Additionally, to assess potential indications of spent fuel pool leakage, IPEC will sample for tritium in groundwater wells in close proximity to the IP2 spent fuel pool at least once every 3 months.

Enhance the Structures Monitoring Program for IP2 and IP3 to perform inspection of normally submerged concrete portions of the intake structures at least once every 5 years. Inspect the baffling/grating partition and support Audit Item platform of the IP3 intake structure at least once 358 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 NL-11-032 frequency of once per 5 years during the PEO.

Enhance the Structures Monitoring Program to include more detailed quantitative acceptance NL-11-101 criteria for inspections of concrete structures in accordance with ACI 349.3R, Evaluation of Existing Nuclear Safety-Related Concrete Structures prior to the period of extended operation.

NL-16-122 Attachment 3 Page 16 of 25

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AUDIT ITEM IP2: NL-07-039 A.2.1.36 26 Implement the Thermal Aging Embrittlement of Complete A.3.1.36 Cast Austenitic Stainless Steel (CASS)

Program for IP2 and IP3 as described in LRA NL-13-122 B.1.37 IP3: NL-07-153 Audit item Section B.1.37.

December 12, NL-15-121 173 This new program will be implemented 2015Complete consistent with the corresponding program described in NUREG-1801,Section XI.M12, Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) Program.

IP2: NL-07-039 A.2.1.37 27 Implement the Thermal Aging and Neutron Complete A.3.1.37 Irradiation Embrittlement of Cast Austenitic NL-13-122 B.1.38 Stainless Steel (CASS) Program for IP2 and IP3: NL-07-153 Audit item IP3 as described in LRA Section B.1.38.

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

Program.

IP2: NL-07-039 A.2.1.39 28 Enhance the Water Chemistry Control - Closed Complete A.3.1.39 Cooling Water Program to maintain water NL-13-122 B.1.40 chemistry of the IP2 SBO/Appendix R diesel IP3: NL-08-057 Audit item generator cooling system per EPRI guidelines.

Complete 509 Enhance the Water Chemistry Control - Closed Cooling Water Program to maintain the IP2 and IP3 security generator and fire protection diesel cooling water pH and glycol within limits specified by EPRI guidelines.

IP2: NL-07-039 A.2.1.40 29 Enhance the Water Chemistry Control -

Complete B.1.41 Primary and Secondary Program for IP2 to test sulfates monthly in the RWST with a limit of NL-13-122

<150 ppb.

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AUDIT ITEM IP2: NL-07-039 A.2.1.41 30 For aging management of the reactor vessel Complete A.3.1.41 internals, IPEC will (1) participate in the industry NL-13-122 programs for investigating and managing aging IP3:

effects on reactor internals; (2) evaluate and Complete implement the results of the industry programs as applicable to the reactor internals; and (3) upon completion of these programs, but not less than 24 months before entering the period of extended operation, submit an inspection NL-11-107 plan for reactor internals to the NRC for review and approval.

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

December 12, 2015Complete As required by 10 CFR 50.61(b)(4), IP3 will IP3: NL-07-039 A.3.2.1.4 32 submit a plant-specific safety analysis for plate Approximately 6 NL-07-140 4.2.5 B2803-3 to the NRC three years prior to years after NL-08-014 reaching the RTPTS screening criterion. entering the PEO NL-08-127 Alternatively, the site may choose to implement the revised PTS rule when approved.

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AUDIT ITEM IP2: NL-07-039 A.2.2.2.3 33 At least 2 years prior to entering the period of Complete A.3.2.2.3 extended operation, for the locations identified NL-13-122 4.3.3 in LRA Table 4.3-13 (IP2) and LRA Table 4.3-IP3: NL-07-153 Audit item 14 (IP3), under the Fatigue Monitoring Program, Complete 146 IP2 and IP3 will implement one or more of the NL-08-021 following:

(1) Consistent with the Fatigue Monitoring Program, Detection of Aging Effects, update the fatigue usage calculations using refined fatigue NL-10-082 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 NRC-approved version of the ASME code or NRC-approved alternative (e.g., NRC-approved code case) may be performed to determine a valid CUF.

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

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AUDIT ITEM Complete NL-13-122 2.1.1.3.5 34 IP2 SBO / Appendix R diesel generator will be NL-07-078 installed and operational by April 30, 2008.

This committed change to the facility meets the requirements of 10 CFR 50.59(c)(1) and, NL-08-074 therefore, a license amendment pursuant to 10 CFR 50.90 is not required. NL-11-101 IP2: NL-08-127 Audit Item 35 Perform a one-time inspection of representative Complete 27 sample area of IP2 containment liner affected by the 1973 event behind the insulation, prior to NL-13-122 entering the period of extended operation, to assure liner degradation is not occurring in this IP3: NL-11-101 area.

December 12, NL-15-121 Perform a one-time inspection of representative 2015Complete 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 NL-09-018 area.

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

IP2: NL-08-127 Audit Item 36 Perform a one-time inspection and evaluation of Complete NL-11-101 359 a sample of potentially affected IP2 refueling NL-13-122 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 NL-09-056 the leakage is not stopped, prior to the end of the first ten years of the period of extended operation. NL-09-079 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.

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AUDIT ITEM IP2: NL-08-127 Audit Item 37 Enhance the Containment Inservice Inspection Complete 361 (CII-IWL) Program to include inspections of the NL-13-122 containment using enhanced characterization of IP3:

degradation (i.e., quantifying the dimensions of Complete 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.

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

December 12, 2015Complete NL-09-079 39 Deleted IP2: NL-09-106 B.1.6 40 Evaluate plant specific and appropriate industry Complete B.1.22 operating experience and incorporate lessons NL-13-122 B.1.23 learned in establishing appropriate monitoring IP3: NL-15-121 B.1.24 and inspection frequencies to assess aging December 12, B.1.25 effects for the new aging management 2015Complete B.1.27 programs. Documentation of the operating B.1.28 experience evaluated for each new program will B.1.33 be available on site for NRC review prior to the B.1.37 period of extended operation.

B.1.38

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AUDIT ITEM IP2: NL-11-032 N/A 41 IPEC will inspect steam generators for both After the units to assess the condition of the divider plate beginning of the assembly. The examination technique used will PEO and prior to be capable of detecting PWSCC in the steam September 28, generator divider plate assembly. The IP2 2023 NL-11-074 steam generator divider plate inspections will be completed within the first ten years of the period IP3: NL-11-090 of extended operation (PEO). The IP3 steam Prior to the end generator divider plate inspections will be of the first NL-11-101 completed within the first refueling outage refueling outage following the beginning of the PEO.

following the beginning of the PEO.

NL-16-122 Attachment 3 Page 22 of 25

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AUDIT ITEM NL-11-032 N/A 42 IPEC will develop a plan for each unit to address the potential for cracking of the primary to secondary pressure boundary due to PWSCC of tube-to-tubesheet welds using one of the following two options.

Option 1 (Analysis)

IPEC will perform an analytical evaluation of the steam generator tube-to-tubesheet welds in IP2: NL-11-074 order to establish a technical basis for either Prior to March determining that the tubesheet cladding and 2024 NL-11-090 welds are not susceptible to PWSCC, or IP3: Prior to the redefining the pressure boundary in which the end of the first NL-11-096 tube-to-tubesheet weld is no longer included refueling outage and, therefore, is not required for reactor following the coolant pressure boundary function. The beginning of the redefinition of the reactor coolant pressure PEO.

boundary must be approved by the NRC as a license amendment request.

Option 2 (Inspection) IP2:

IPEC will perform a one-time inspection of a Between March representative number of tube-to-tubesheet 2020 and March welds in each steam generator to determine if 2024 PWSCC cracking is present. If weld cracking is identified: IP3: Prior to the end of the first

a. The condition will be resolved through refueling outage repair or engineering evaluation to justify following the continued service, as appropriate, and beginning of the

b. An ongoing monitoring program will be PEO.

established to perform routine tube-to-tubesheet weld inspections for the remaining life of the steam generators.

NL-16-122 Attachment 3 Page 23 of 25

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AUDIT ITEM IP2: NL-11-032 4.3.3 43 IPEC will review design basis ASME Code Complete Class 1 fatigue evaluations to determine whether the NUREG/CR-6260 locations that IP3: Prior to NL-13-122 have been evaluated for the effects of the reactor coolant environment on fatigue usage December 12, NL-11-101 are the limiting locations for the IP2 and IP3 2015Complete NL-15-121 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.

IP2: NL-11-032 N/A 44 IPEC will include written explanation and Complete justification of any user intervention in future evaluations using the WESTEMS Design CUF NL-11-101 IP3: Prior to NL-13-122 module.

December 12, NL-15-121 2015Complete IP2: NL-11-032 N/A 45 IPEC will not use the NB-3600 option of the Complete WESTEMS program in future design calculations until the issues identified during the NL-11-101 IP3: Prior to NL-13-122 NRC review of the program have been resolved. December 12, NL-15-121 2015Complete IP2: NL-11-032 N/A 46 Include in the IP2 ISI Program that IPEC will Complete perform twenty-five volumetric weld metal inspections of socket welds during each 10-year NL-11-074 ISI interval scheduled as specified by IWB-2412 NL-13-122 of the ASME Section XI Code during the period of extended operation.

In lieu of volumetric examinations, destructive examinations may be performed, where one destructive examination may be substituted for two volumetric examinations.

47 Deleted. NL-14-093 N/A

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AUDIT ITEM IP2: NL-12-174 N/A 48 Entergy will visually inspect IPEC underground Complete piping within the scope of license renewal and subject to aging management review prior to IP3: Prior to NL-13-122 the period of extended operation and then on a frequency of at least once every two years December 12, NL-15-121 during the period of extended operation. This 2015Complete inspection frequency will be maintained unless the piping is subsequently coated in accordance with the preventive actions specified in NUREG-1801 Section XI.M41 as modified by LR-ISG-2011-03. Visual inspections will be supplemented with surface or volumetric non-destructive testing if indications of significant loss of material are observed. Consistent with revised NUREG-1801 Section XI.M41, such adverse indications will be entered into the plant corrective action program for evaluation of extent of condition and for determination of appropriate corrective actions (e.g., increased inspection frequency, repair, replacement).

IP2: NL-13-052 A.2.2.2 49 Recalculate each of the limiting CUFs provided Complete A.3.2.2 in section 4.3 of the LRA for the reactor vessel internals to include the reactor coolant IP3: Prior to NL-13-122 environment effects (Fen) as provided in the IPEC Fatigue Monitoring Program using December 12, NL-15-121 NUREG/CR-5704 or NUREG/CR-6909. In 2015Complete accordance with the corrective actions specified in the Fatigue Monitoring Program, corrective actions include further CUF re-analysis, and/or repair or replacement of the affected components prior to the CUFen reaching 1.0.

Replace the IP2 split pins during the 2016 IP2: NL-13-122 A.2.1.41 50 refueling outage (2R22). Prior to B.1.42 completion of NL-14-067 2R22Complete IP3: N/A

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AUDIT ITEM IP2 & IP3: NL-14-147 A.2.1.33 51 Enhance the Service Water Integrity Program December 31, A.3.1.33 by implementing LRA Sections A.2.1.33, 2017 B.1.34 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 IP2 & IP3: NL-16-122 A.2.1.33 December 31, A.3.1.33 B.1.34, as shown in NL-16-122 2017 B.1.34 IP2 & IP3: NL-15-019 A.2.1.42 52 Implement the Coating Integrity Program for IP2 December 31, A.3.1.42 and IP3 as described in LRA Section B.1.42, as 2024 B.1.43 shown in NL-15-019.