ML12334A720

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Official Exhibit - NYS000203-00-BD01 - Letter, Fred Dacimo (Entergy) to U.S. Nuclear Regulatory Commission, Attn: Document Control Desk, NL-09-106 (July 27, 2009)
ML12334A720
Person / Time
Site: Indian Point  Entergy icon.png
Issue date: 07/27/2009
From: Dacimo F
Entergy Nuclear Northeast
To:
Document Control Desk, Office of Nuclear Reactor Regulation, Atomic Safety and Licensing Board Panel
SECY RAS
References
RAS 21567, 50-247-LR, 50-286-LR, ASLBP 07-858-03-LR-BD01
Download: ML12334A720 (29)
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Text

United States Nuclear Regulatory Commission Official Hearing Exhibit In the Matter of:

Entergy Nuclear Operations, Inc.

(Indian Point Nuclear Generating Units 2 and 3)

ASLBP #: 07-858-03-LR-BD01 Docket #: 05000247 l 05000286 Exhibit #:

Identified:

Admitted:

Withdrawn:

Rejected:

Stricken:

Other:

NYS000203-00-BD01 10/15/2012 10/15/2012 NYS000203 Submitted: December 16, 2011 NL-09-106 July 27,2009 Entergy Nuclear Northeast Indian Point Energy Center 450 Broadway, GSB P.O. Box 249 Buchanan, NY 10511-0249 Tel (914) 788-2055 Fred Oacimo Vice President License Renewal U.S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, DC 20555-0001

SUBJECT:

REFERENCES:

Dear Sir or Madam:

Questions Regarding Buried Piping Inspections Indian Point Nudear Generating Unit Nos. 2 & 3 Docket Nos. 50-247 and 50'-286 License Nos. DPR-26 and DPR-64

1. NRC Teleconference of 7/22/09 Regarding Buried Piping Inspection Questions.
2. Entergy Letter NL-09-088, "Amendment 8, Revision 1 to License Renewal Application (LRA) Indian Point Nuclear Generating Unit Nos.

2 & 3," dated June 30, 2009.

In a recent teleconference, Reference 1, the NRC raised additional questions regarding buried piping and inspections. Entergy Nuclear Operations, Inc. is hereby responding to those questions in Attachment 1 and providing the appropriate amendment revision to the renewal of the Indian Point Energy Center operating license. The amendment revision is needed to provide updated and corrected information associated with Amendment 8 to the LRA, Reference 2, per the NRC telecom.

There are commitments in this submittal and Attachment 2 revises the commitment list to reflect these.

If you have ~ny questions, or require aldditional information, please contact Mr. Robert Walpole at 914-734-6710.

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NL-09-106 Page 2 of 2 I declare under Qenalty of perjury that the foregoing is true and correct. Executed on 7-2;- 2:01>~

Sincerely,

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--- F. DAc"no FRD/dmt

Attachment:

1. Aging Management Program Clarifications Amendment
2. IPEC Commitment List, Revision 10 cc:

Mr. Samuel J. Collins, Regional Administrator, NRC Region I Mr. Sherwin E. Turk, NRC Office of General Counsel, Special Counsel Mr. John Boska, NRR Senior Project Manager Ms. Kimberly Green, NRC Safety Project Manager NRC Resident Inspector's Office Mr. Paul Eddy, New York State Department of Public Service Mr. Francis J. Murray, President and CEO, NYSERDA IPEG PA OAG0001654

ATTACHMENT 1 TO NL-09-106 Aging Management Program Clarifications Amendment ENTERGY NUCLEAR OPERATIONS, INC.

INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 & 3 DOCKET NOS. 50-247 AND 50-286 LICENSE NOS. DPR-26 and DPR-64 IPEG PA OAG0001655

INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL APPLICATION CLARIFICATION AMENDMENT NL-09-106 Page 1 of 7 A new Buried Piping and Tanks Inspection Program was proposed for Indian Point as described in the license renewal application (LRA) in Section B.1.6. As explained in the LRA, the proposed program would be consistent with, that is, identical to, the program recommended in NUREG-1801,Section XI.M34, Buried Piping and Tanks Inspection. As part of this program, plant and industry operating experience are considered prior to and during program implementation. Entergy's evaluation of recent site operating experience at Indian Point has resulted in the identification of program modifications to further assure program effectiveness through the period of extended operation. The following sections describe the background and the modifications planned for the Buried Piping and Tanks Inspection Program.

Background

The Buried Piping and Tanks Inspection Program described in Section B.1.6 of the Indian Point license renewal application is identical to the program recommended in NUREG-1801,Section XI.M34, Buried Piping and Tanks Inspection. The IPEG program is a new program that includes (a) preventive measures to mitigate corrosion and (b) inspections to manage the effects of corrosion on the pressure-retaining capability of buried carbon steel, gray cast iron, and stainless steel components.

Preventive measures are in accordance with standard industry practice for maintaining external coatings and wrappings. In particular, the coating specification applicable during construction required a coal tar coating covered with a fiber-based wrap saturated with coal tar.

Inspections are opportunistic inspections of buried piping and tanks performed following excavations for maintenance activities. The program specifies one focused inspection prior to the period of extended operation and one focused inspection during the first ten years of the period of extended operation if opportunistic inspections do not occur during those periods.

The scope of the Buried Piping and Tanks Inspection Program includes buried piping and tanks in the following systems.

  • Safety injection (IP3 only) - -700 feet of stainless"steel piping running from the refueling water storage tank (RWST) to the auxiliary building that supplies borated water to the suction of the safety injection and containment spray pumps". "" ~""".
  • Fire protection - greater than 5000 feet of ductile ir~nOr carbon steel piping that runs from fire water pumps to and including the fire protection Iqop that circles the main plant building structure. The loop design and associated sectional isolation valves allow isolation of a leak in any segment of piping without disabling the remainder of the fire protection water system.

IPEG PA OAG0001656 NL-09-106 Page 2 of 7

  • Fuel oil - Eight buried carbon steel fuel oil storage tanks with -160 feet of carbon steel piping that carries the fuel oil from the tank to its associated diesel engine. Buried piping and tanks provide fuel oil for emergency diesel generators, as well as, the Appendix R diesel generator (IP3 only) and security diesel generator (IP2 only).
  • Security generator - -50 feet of carbon steel piping that provides the propane fuel to operate the Unit 3 security generator.
  • City water - greater than 4000 feet of carbon steel and gray cast iron piping that provides a backup source of water for auxiliary feedwater and fire protection systems.
  • Plant drains - greater than 1000 feet of carbon steel piping that provides a drainage flow path from floor drains in the lower elevations of certain plant structures.

Approximately 1000 feet is for I P2 with the remainder serving I P3.

  • Containment isolation support - -150 feet of carbon steel piping that provides pressurized air to support containment integrity for IP2.

NUREG-1801,Section XI.M28, Buried Piping and Tanks Surveillance Program, describes an alternative aging management program that relies on operation of cathodic protection systems for buried piping and tanks. The program described in NUREG-1801,Section XI.M34 was selected for Indian Point buried piping and tanks in lieu of the alternative program of Section XI.M28 due to the very limited installation of cathodic protection systems at Indian Point due to soil resistivity and drainage conditions observed during original plant construction.

Recent Indian Point Operating Experience For the Buried Piping and Tanks Inspection Program, plant and industry operating experience are integral to ensuring program effectiveness upon implementation and throughout the period of extended operation. Recent site operating experience at Indian Point involved a February 2009 leak on the return line to the condensate storage tank on Unit 2. The leak rate was estimated at less than fifteen gallons per minute. There was no safety significance to the plant from the leak primarily due to the fact that the normal inventory of the condensate storage tank is well above the minimum inventory required to support its safety function.

The February 2009Jeak was the result of damaged pipe coating. Specifically, Entergy conGllJded Jhat the root cause of the leak wa,s an original construction installation speCification which did not appropriately specify the type of fill to be used when covering piping and components after installation. As a, result, rocks in the original construction backfill surrounding thepJping,damag~d. its prote~tiYec.oat.ingultirna:tely leading to the leak in the piping caused by

... corrosion originating on the externaJpiping surface at a localized area where the coating was damaged. Moisture in the soil surrounding the pipe contributed to the corrosion as the elevation of the pipe is near the elevation of the water table in the area.

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Entergy replaced a section of the pipe containing the leak and performed weld overlays to repair

. nearby areas. exhibiting shallow corrosion and recoated the affected piping sections. Based on evaluation of the findings from this event, Entergy revised procedures for backfill after excavating piping to require the use of high quality backfill material that do not contain objects that can damage protective coatings on the piping.

IPEG PA OAG0001657 NL-09-106 Page 3 of 7 Additional recent operating experience involved examinations performed in the fall of 2008 on three ten-foot lengths of Unit 2 CST pipes (aux feed pump supply, CST return and CST overflow) at two separate locations. Visual examinations revealed areas which required coating repair and two locations with very minor coating defects. UT thickness measurements performed on those areas where the base metal was exposed confirmed that the pipe thickness remained at nominal thickness (Le., within the manufacturer's tolerance). The defective areas of coating observed during these inspections also were attributed to the backfill materials used when covering the piping during initial construction.

Another example of recent operating experience that Entergy considered for possible implications for the Buried Piping and Tanks Inspection Program is a steam leak-- documented in 2007-- on a buried 8" auxiliary steam line, which is not within the scope of license renewal.

The leak was due to the use of inappropriate insulation material for buried steam piping that allowed moisture intrusion resulting in corrosion of the piping causing the subsequent leak. The affected piping was replaced and reinsulated with a suitable material. None of the buried piping or tanks in the scope of license renewal are steam lines.

Program Improvements Resulting from Operating Experience As a result of the recent IPEC operating experience with degraded pipe coatings described above, the Buried Piping and Tanks Inspection Program (LRA Section B.1.6) will be modified to significantly increase the number of inspections on buried piping and tanks. The Buried Piping and Tanks Inspection Program as originally described in LRA Section B.1.6 entails primarily inspections of opportunity on buried piping and tanks and required only one inspection prior to the period of extended operation and one inspection during the first ten years of the period of extended operation. The modified program will entail multiple inspections of buried piping and tanks within the scope of the Buried Piping and Tanks Inspection Program, both prior to and during the period of extended operation. Based on priorities established through the risk assessment process that will be part of the modified program, fifteen IP2 inspections are planned prior to entering the IP2 period of extended operation (2013), and thirty IP3 inspections are planned prior to entering the IP3 period of extended operation (2015).

In accordance with the modified" program, the risk assessment of in-scope buried piping and tanks will include consideration of the impacts of buried piping or tank leakage and of conditions affecting the risk for corrosion. Piping segments and tanks will be classified as having a high, medium or low impact of leakage based on the safety classification, the hazard posed by fluid contained in the piping or tank and the potential impact of leakage on reliable plant operation.

Corrosion risk will be determined through consideration of piping or tank material, soil resistivity, "drainage; the presence of cathodic protection and the type of coating. The results of this analysis wilrestablishthe priority for the first inspections and frequency for periodic followup

"-inspeCtions of the in:":scbpebui'ied piping and tanks: For example, piping segments or tanks with ahighimpact-ranking and high corrosion risk will be scheduled for the earliest inspections and have the-highest frequencyfbr subsequent inspection. Operating experience will continue to be factored into the determination of priority and frequency through the period of extended

- operation."'

Any future degradation of piping or tanks will be evaluated and corrected under the corrective action program at IPEC in"accordance with the program requirements. For example, as a result of the most recent operating experience with the leak in the condensate storage system, IPEG IPEG PA OAG0001658 NL-09-106 Page 4 of 7 plans six additional inspections during 2009 on the service water and auxiliary feedwater (condensate storage) systems at lower site elevations where corrosion risk is highest. The number of inspections and inspection frequency for the Buried Piping and Tanks Inspection Program during the period of extended operation will be based on the results of these planned inspections and other applicable industry or plant-specific operating experience in addition to the risk assessment of piping segments and tanks.

Entergy will employ qualified inspection methods with demonstrated effectiveness for detection of aging effects during the period of extended operation The Electric Power Research Institute is evaluating a number of techniques for application to the commercial nuclear power industry, e.g., guided wave ultrasonic technology, Entergy is an active participant in the industry group established to address issues with degradation of buried components.

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

IPEG PA OAG0001659

New Aging Management Programs NL-09-106 Page 5 of 7 Operating experience for the programs and activities credited with managing the effects of aging has been reviewed. The operating experience review included a review of corrective actions resulting in program enhancements. For inspection programs, reports of recent inspections, examinations, or tests were reviewed to determine if aging effects have been identified on applicable components.

For monitoring programs, reports of sample results were reviewed to determine if parameters are being maintained as required by the program. Also, program owners contributed observations indicative of program success or weakness and identified applicable self-assessments, QA audits, peer evaluations, and NRC reviews.

Commitment IPEC will evaluate plant specific and appropriate industry operating experience and incorporate lessons learned in establishing appropriate monitoring and inspection frequencies to assess aging effects for the new aging management programs. Documentation of the operating experience evaluated for each new program will be available on site for NRC review prior to the period of extended operation.

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

B.l.6 Buried Piping and Tanks Inspection program Description The Buried Piping and Tanks Inspection Program is a new program that includes (a) preventive measures to mitigate corrosion and (b) inspections to manage the effects of corrosion on the pressure-retaining capability of buried carbon steel, gray cast iron, and stainless steel components. Preventive measures are in accordance with standard industry practice for maintaining external coatings and wrappings. Buried components are inspected when excavated during maintenance. If trending within the corrective action program identifies susceptible locations, the areas with a history of corrosion problems are evaluated for the need for additional inspection, alternate coating, or replacement.. The program applies to buried.

componentsin the following systems.

Safety injection Service water Fire protection Fuel oil Security generator City water Plant drains

  • . AuxiliarY feedwater Containment isolation support IPEG PA OAG0001660 NL-09-106 Page 6 of 7 Of these systems, only the safety injection system contains radioactive fluids during normal operations. The safety injection system buried components are stainless steel. Stainless steel is used in the safety injection system for its corrosion resistance.

The Buried Piping and Tanks Inspection Program will be modified based on operating experience to include a risk assessment of in-scope buried piping and tanks that includes consideration of the impacts of buried piping or tank leakage and of conditions affecting the risk for corrosion. The program will classifv 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. Corrosion risk will be determined through consideration of piping or tank material. soil resistivity, drainage, the presence of cathodic protection and the type of coating. Inspection priority and frequency for periodic inspections of the in-scope piping and tanks will be based on the results of the risk assessment.

Inspections will be performed using qualified inspection techniques with demonstrated effectiveness. Inspections will begin prior to the period of extended operation.

Prior to entering the period of extended operation, plant operating experience will be reviewed and multiple to verify that an inspections will be completed occurred within the past ten years. #

an inspection did not occur, a focused inspection 'Nill be performed prior to the period of extended operation. Additional periodic A focused inspection§. will be performed within the first ten years of the period of extended operation~, unless an opportunistic inspection occurs within this ten year period.

A.2.1.S Buried Piping and Tanks Inspection Program The Buried Piping and Tanks Inspection Program is a new program that includes (a) preventive measures to mitigate corrosion and (b) inspections to manage the effects of corrosion on the pressure-retaining capability of buried carbon steel, gray cast iron, and stainless steel components. Preventive measures are in accordance with standard industry practice for maintaining external coatings and wrappings. Buried components are inspected when excavated during maintenance. If trending within the corrective action program identifies susceptible locations, the areas with a history of corrosion problems are evaluated for the need for additional inspection, alternate coating, or replacement.

Prior to entering the period of extended operation, plant operating experience will be reviewed and multiple to verify that an inspections will be completed occurred within the past ten years. #

an inspection did not occur, a focused inspection will be performed prier to the period of oxtondod operation. Additional periodic A fOGused inspection§. will be performed within the first ten years of the period of extended operation~, unless an opportunistic inspection occurs within this ten year period.

.. The Buried Piping and Tanks Inspection Program will be implemented prior to the period of extended operation. This new program will be implemented consistent with the corresponding program described in NUREG-1801 Section XI.M34, Buried Piping and Tanks Inspection with the following modification.

The Buried Piping and Tanks Inspection Program will be modified based on operating experience to include a risk assessment of in-scope buried piping and tanks that includes IPEG PA OAG0001661 NL-09-106 Page 7 of 7 consideration of the impacts of buried piping or tank leakage and of conditions affecting the risk for corrosion. The program will classifv 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. Corrosion risk will be determined through consideration of piping or tank material, soil resistivity. drainage. the presence of cathodic protection and the type of coating. Inspection priority and freguency for periodic inspections of the in-scope piping and tanks will be based on the results of the risk assessment.

Inspections will be performed using qualified inspection techniques with demonstrated effectiveness. Inspections will begin prior to the period of extended operation.

A.3.1.S Buried Piping and Tanks Inspection Program The Buried Piping and Tanks Inspection Program is a new program that includes (a) preventive measures to mitigate corrosion and (b) inspections to manage the effects of corrosion on the pressure-retaining capability of buried carbon steel, gray cast iron, and stainless steel components. Preventive measures are in accordance with standard industry practice for maintaining external coatings and wrappings. Buried components are inspected when excavated during maintenance. If trending within the corrective action program identifies susceptible locations, the areas with a history of corrosion problems are evaluated for the need for additional inspection, alternate coating, or replacement.

Prior to entering the period of extended operation, plant operating experience will be reviewed and multiple to verify that an inspections will be completed occurred within the past ten years. #

an inspection did not occur, a focused inspection will be performed prior to the period of extended operation. Additional periodic A focused inspection,§ will be performed within the first ten years of the period of extended operation.:., unless an opportunistic inspection occurs within this ten year period.

The Buried Piping and Tanks Inspection Program will be implemented prior to the period of extended operation. This new program will be implemented consistent with the corresponding program described in NUREG-1801 Section XI,M34, Buried Piping and Tanks Inspection with the following modification.

.... The Buried Piping and Tanks Inspection Program will be modified based on operating experience to include a risk assessment of in-scope buried piping and tanks that includes consideration of the impacts of buried piping or tank leakage and of conditions affecting the risk

, for corrosion. The program will 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. Corrosion risk will be determined through consideration of piping or tank material, soil resistivity. drainage. the'presence of' cathodic protection and the type of coating. Inspection priority and frequency for periodic inspections of the in-scope piping and tanks will be based on the results of the risk assessment.

Inspections will be performed using qualified inspection techniques with demonstrated

.. effectiveness. Inspections will begin prior to the period of extended operation.'*:-~. "",,'.. -

IPEG PA OAG0001662

ATTACHMENT 2 TO NL-09-106 IPEC Commitment List, Revision 10

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ENTERGY NUCLEAR OPERATIONS, INC..

INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 & 3 DOCKET NOS. 50-247 AND 50-286 LICENSE NOS. DPR-26 and DPR-64 IPEG PA OAG0001663

1 2

List of Regulatory Commitments Rev. 10 NL-09-106 Page 1 of 18 The following table identifies those actions committed to by Entergy in this document.

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

COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRASECTION I AUDIT ITEM Enhance the Aboveground Steel Tanks Program for IP2:

NL-07-039 A.2.1.1 September 28, A.3.1.1 IP2 and IP3 to perform thickness measurements of 12013 B.1.1 the bottom surfaces of the condensate storage tanks, city water tank, and fire water tanks once during the IP3:

first ten years of the period of extended operation.

December 12, Enhance the Aboveground Steel Tanks Program for 12015 IP2 and IP3 to require trending of thickness measurements when material loss is detected.

Enhance the Bolting Integrity Program for IP2 and IP3 IP2:

NL-07-039 A.2.1.2 September 28, A.3.1.2 to clarify that actual yield strength is used in selecting 12013 B.1.2 materials for low susceptibility to sec and clarify the prohibition on use of lubricants containing MoS2 for IP3:

NL-07-153 Audit Items bolting.

December 12, 201,241, The Bolting Integrity Program manages loss of 12015 270 preload and loss of material for all external bolting.

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IPEG PA OAG0001664

COMMITMENT 3

Implement the Buried Piping and Tanks Inspection Program for I P2 and I P3 as described in LRA Section B.1.6.

This new program will be implemented consistent with the corresponding program described in NUREG-1801 Section XI,M34, Buried Pipin~1 and Tanks Inspection.

Include in the Buried Piging and Tanks Insgection Program described in LRA Section B.1.6 a risk assessment of in-scoge buried giging and tanks that includes consideration of the imgacts of buried giging or tank leakage and of conditions affecting the risk for corrosion. Classify gige segments and tanks as having a high, medium or low imgact of leakage based on the safety class, the hazard gosed by fluid contained in the giging and the imgact of leakage on reliable giant ogeration. Determine corrosion risk through consideration of giging or tank material, soil resistivity, drainage, the gresence of cathodic grotection and the tyge of coating. Establish insgection griority and freguency for geriodic insgections of the in-scoge giging and tanks based on the results of the risk assessment. Perform insgections using gualified insgection technigues with demonstrated effectiveness.

IMPLEMENTATION SCHEDULE IP2:

September 28, 12013 IP3:

December 12, 12015 NL-09-106 Page 2 of 18 SOURCE RELATED LRA SECTION I AUDIT ITEM NL-07-039 A.2.1.5 A.3.1.5 B.1.6 NL-07-153 Audit Item 173 NL-09-106 IPEG PA OAG0001665

COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION I AUDIT ITEM 4

Enhance the Diesel Fuel Monitoring Program to include IP2:

NL-07-039 A.2.1.B cleaning and inspection of the IP2 GT-1 gas turbine fuel oil September 2B, A.3.1.B storage tanks, IP2 and IP3 EDG fuel oil day tanks, IP2 2013 B.1.9 SS~/Appendix R diesel generator fuel oil day tank, and IP3 NL-07-153 Audit items Appendix R fuel oil storage tank and day tank once every

  • IP3:

12B,129, ten years.

December 12,

132, Enhance the Diesel Fuel Monitoring Program to include 2015 NL-OB-057 491,492, quarterly sampling and analysis of the IP2 SS~/Appendix R 510 diesel generator fuel oil day tank, IP2 security diesel fuel oil storage tank, IP2 security diesel fuel oil day tank, and IP3 Appendix R fuel oil storage tank. Particulates, water and sediment checks will be performed on the samples.

Filterable solids acceptance criterion will be less than or equal to 10mg/1. 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, SS~/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.

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IPEG PA OAG0001666

COMMITMENT 5

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

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

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

IMPLEMENTATION SCHEDULE IP2:

September 28, 2013 IP3:

December 12, 2015 IP2:

September 28, 2013 IP3:

December 12, 2015 NL-09-106 Page 4 of 18 SOURCE RELATED.

LRASECTION I AUDIT ITEM NL-07-039 A.2.1.10 A.3.1.10 B.1.11 NL-07-039 A.2.1.11 A.3.1.11 B.1.12, NL-07-153 Audit Item 164 IPEG PA OAG0001667

COMMITMENT 7

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

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

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

Enhance the Fire Protection Program for IP3 to visually inspect the cable spreading room, 480V switchgear room, and EDG room CO2 fire suppression system for signs of degradation, such as corrosion and mechanical damage at least once every six months.

IMPLEMENTATION SCHEDULE IP2:

September 28,

~O13 IP3:

December 12,

~O15 NL-09-106 Page 5 of 18 SOURCE RELATED LRA SECTION I AUDIT ITEM NL-07-039 A.2.1.12 A.3.1.12 B.1.13 IPEG PA OAG0001668

COMMITMENT 8

Enhance the Fire Water Program to include inspection of IP2 and IP3 hose reels for evidence of corrosion.

Acceptance criteria will be revised to verify no unacceptable signs of degradation.

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

Enhance the Fire Water Program to perform wall thickness evaluations of IP2 and IP:3 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.

IMPLEMENTATION SCHEDULE IP2:

September 28,

~013 IP3:

December 12, 12015 NL-09-106 Page 6 of 18 SOURCE RELATED LRA SECTION I AUDIT ITEM NL-07-039 A.2.1.13 A.3.1.13 8.1.14 NL-07-153 Audit Items 105, 106 NL-08-014 IPEG PA OAG0001669

COMMITMENT 9

Enhance the Flux Thimble Tube Inspection Program for I P2 and I P3 to implement comparisons to wear rates identified in WCAP-12866. Include provisions to compare data to the previous performances and perform evaluations regarding change to test frequency and scope.

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

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

IMPLEMENTATION SCHEDULE IP2:

September 28, 12013 IP3:

December 12, 12015 NL-09-106 Page 7 of 18 SOURCE RELATED LRA SECTION I AUDIT ITEM NL-07-039 A.2.1.15 A.3.1.15 B.1.16 IPEG PA OAG0001670

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

Safety injection pump lube oil heat exchangers RHR heat exchangers RHR pump seal coolers

  • Non-regenerative heat exchangers
  • Charging pump seal water heat exchangers
  • Charging pump fluid drive coolers Charging pump crankcase oil coolers
  • Spent fuel pit heat exchangers
  • Waste gas compressor heat exchangers S80/ Appendix R diesel jacket water heat exchanger (IP2 only)

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

11 Delete commitment.

IMPLEMENTATION SCHEDULE IP2:

September 28, 2013 IP3:

December 12, 2015 NL-09-106 Page 8 of 18 SOURCE RELATED LRA SECTION I AUDIT ITEM NL-07-039 A.2.1.16 A.3.1.16 8.1.17, NL-07-153 Audit Item 52 NL-09-018 NL-09-056 IPEG PA OAG0001671

COMMITMENT 12 Enhance the Masonry Wall Program for IP2 and IP3 to specify that the I P1 intake structure is included in the program.

13 Enhance the Metal-Enclosed Bus Inspection Program to add I P2 480V bus associated with substation A to the scope of bus inspected.

Enhance the Metal-Enclosed Bus Inspection Program for IP2 and IP3 to visually inspect the external surface of MEB enclosure assemblies for loss of material at least once every 10 years. The first inspection will occur prior to the period of extended operation and the acceptance criterion will be no significant loss of material.

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

Enhance the Metal-Enclosed Bus !nspectionProgram 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.c.hange:to applicable site procedure to remove the reference to ~Ire~torquing".

connections for phase bus maintenance and bolted connection maintenance...

IMPLEMENTATION SCHEDULE IP2:

September 28,

~013 IP3:

December 12,

~015 IP2:

September 28, 12013 IP3:

December 12,

~015 NL-09-106 Page 9 of 18 SOURCE RELATED LRASECTION I AUDIT ITEM NL-07-039 A.2.1.18 A.3.1.18 B.1.19 NL-07-039 A.2.1.19 A.3.1.19 B.1.20 NL-07-153 Audit Items

124, NL-08-057 133,519 IPEG PA OAG0001672

COMMITMENT IMPLEMENTATION SCHEDULE 14 Implement the Non-EQ Bolted Cable Connections IP2:

September 28, Program for IP2 and IP3 as described in LRA Section 2013 B.1.22.

IP3:

December 12, 2015 15 Implement the Non-EQ Inaccessible Medium-Voltage IP2:

September 28, Cable Program for IP2 and IP3 as described in LRA 2013 Section B.1.23.

This new program will be implemented consistent with IP3:

the corresponding program described in NUREG-December 12, 1801 Section XI.E3, Inaccessible Medium-Voltage 2015 Cables Not Subject To 10 CFR 50.49 Environmental Qualification Requirements.

16 Implement the Non-EQ Instrumentation Circuits Test IP2:

September 28, Review Program for IP2 and IP3 as describecl in LRA 2013 Section B.1.24.

This new program will be implemented consistent with IP3:

the corresponding program described in NUREG-December 12, 1801 Section XI.E2, Electrical Cables and 2015 Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits.

17 Implement the Non-EQ Insula!~d. Cables and IP2:

September 28, Connections Program for IP2 C!nd IP3 as described in

~013 LRA Section B.1.25.

This new program will be implemented consistent with IP3:

the corresponding program described in NUREG-December 12, 1801 Section-XI.E1, Electrical Cables and 12015.

Connections Not Subject to 10 CFR: 50.49 Environmental Qualification RequirElments.

. -. ~..",.

NL-09-106 Page 10 of 18 SOURCE RELATED LRASECTION I AUDIT ITEM NL-07-039 A.2.1.21 A.3.1.21 B.1.22 NL-07-039 A.2.1.22 A.3.1.22 B.1.23 NL-07-153 Audit item 173 NL-07-039 A.2.1.23 A.3.1.23 B.1.24 NL-07-153 Audit item 173 NL-07-039 A.2.1.24 A.3.1.24 B.1.25 NL-07-153 Audit item 173 IPEG PA OAG0001673

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

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

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

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

19 Implement the One-Time Inspection Program for IP2 and IP3 as described in LRA Section B.1.27.

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

20 Implement the One~Timelnspection....,Small Bore Piping Program for IP2 and IP3 as described in LRA Section B.1.28.

~::..... -.

This new program will be implemented consistent with the corresponding program desGribed in NUHEG-..

1801,Section XI.M35, One-Time Inspection of ASME Code Class I Small-Bore Piping.

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

IMPLEMENTATION SCHEDULE IP2:

September 28,

~013 IP3:

December 12, 12015 IP2:

September 28,

~013 IP3:

December 12, 12015 IP2:

September 28, 2013 IP3:

December 12, 2015 IP2:

September 28, 2013 IP3:

December 12, 2015 NL-09-106 Page 11 of 18 SOURCE RELATED LRA SECTION I AUDIT ITEM NL-07-039 A.2.1.25 A.3.1.25 B.1.26 NL-07-039 A.2.1.26 A.3.1.26 B.1.27 NL-07-153 Audit item 173 NL-07-039 A.2.1.27 A.3.1.27 B.1.28 NL-07-153 Audit item 173 NL-07-039 A.2.1.28 A.3.1.28 B.1.29 IPEG PA OAG0001674

COMMITMENT 22 Enhance the Reactor Vessel Surveillance Program for IP2 and IP3 revising the specimen capsule withdrawal schedules to draw and test a standby capsule to cover the peak reactor vessel fluence expected through the end of the period of extended operation.

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

23 Implement the Selective Leaching Program for IP2 and I P3 as described in LRA Section 8.1.33.

This new program will be implemented consistent with the corresponding program described in NUREG-1801,Section XI.M33 Selective Leaching of Materials.

24 Enhance the Steam Generator Integrity Program for IP2 and IP3 to require that the results of the condition monitoring assessment are compared to the operational assessment performed for the prior operating cycle with differences evaluated.

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

  • Appendix R diesel generator foundation (IP3)
  • Appendix R diesel generator fuel oil tank vault (IP3)
  • . Appendix H die*sel generator switGhgear and enclosure (IP3).

- city water storage tank foundation

.... condensate s~orage 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 (lP3)*
  • fire water storage tank foundations (IP2/3)
  • gas turbine 1 fuel storage tank foundation maintenance and outage building-elevated IMPLEMENTATION SCHEDULE IP2:

September 28,

~013 IP3:

December 12,

~015 IP2:

September 28, 12013 IP3:

December 12, 12015 IP2:

September 28,

~013 IP3:

December 12,

~015 IP2:

September 28, 12013 IP3:

December 12, 12015 NL-09-106 Page 12 of 18 SOURCE RELATED LRASECTION I AUDIT ITEM NL-07-039 A.2.1.31 A.3.1.31 8.1.32 NL-07-039 A.2.1.32 A.3.1.32 B.1.33 NL-07-153 Audit item 173 NL-07-039 A.2.1.34 A.3.1.34 8.1.35 NL-07-039 A.2.1.35 A.3.1.35 8.1.36 NL-07-153 Audit items 86,87,88, NL-08-057 417 IPEG PA OAG0001675

COMMITMENT passageway (IP2) new station security building (IP2) nuclear service building (I P1) primary water storage tank foundation (IP3) refueling water storage tank foundation (IP3) security access and office building (IP3) service water pipe chase (IP2/3) service water valve pit (I P3) superheater stack transformerlswitchyard support structures (I P2) waste holdup tank pits (I P2/3)

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

cable trays and supports concrete portion of reactor vessel supports conduits and supports cranes, rails and girders equipment pads and foundations fire proofing (pyrocrete)

HVAC duct supports jib cranes*

manholes and duct banks manways,hatches and hatch covers monorails

  • . new fuel storage'racks,

sumps, sump screens, strainers and flow barriers Enhance the Structures Monitoring Program for IP2 and I P3 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 FJrogram for IP2 NL-09-106 Page 13 of 18 IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION I AUDIT ITEM IPEG PA OAG0001676

COMMITMENT and IP3 to perform inspections of elastomers (seals, gaskets, seismic joint filler, and roof elastomers) to identify cracking and change in material properties and for inspection of aluminum vents and louvers to identify loss of material.

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

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

Enhance the Structures Monitoring Program for IP2 and IP3 to perform inspection of normally submerged concrete portions of the intake structures at least once every 5 years. Inspect the baffling/grating partition and support platform of the I P3 intake structure at least once every 5 years.

Enhance the.Structures Monitoring Program lor IP2 and I P3 to perform inspection of the degraded areas of tDe yvater.control structure once per 3 years rather than the.normal frequency of once per 5 years during the PE~.

26 Implement the Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) Program for IP2 and IP3 as described in LRA Section 8.1.37.

This rie~program will be implemented consistent with

~. the corresponding program described in NUREG-180(Section XI.M12, Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) Program.

IMPLEMENTATION SCHEDULE IP2:

September 28,

~013 IP3:

December 12,

~015 NL-09-106 Page 14 of 18 SOURCE RELATED LRASECTION I AUDIT ITEM NL-08-127 Audit Item 360 Audit Item 358 NL-07-039 A.2.1.36 A.3.1.36 8.1.37 NL-07-153 Audit item 173 IPEG PA OAG0001677

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

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

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

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

29 Enhance the Water Chemistry Control-Primary and Secondary Program for IP2 to test sulfates monthly in the RWST with a limit of <150 ppb.

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

31 Additional P-T curves will be submitted as required peri 0 CFR 50, Appendix G prior to the period of

-extended operation as part of the Reactor Vessel Surveillance Program.

IMPLEMENTATION SCHEDULE IP2:

September 28,

~O13 IP3:

December 12,

~O15 IP2:

September 28,

~O13 IP3:

December 12,

~O15 IP2:

September 28,

~O13 IP2:

September 28,

~O11 IP3:

December 12,

~O13 IP2:

September 28,

~O13 IP3:

December 12,

~Oi5 NL-09-106 Page 15 of 18 SOURCE RELATED LRASECTION I AUDIT ITEM NL-07-039 A.2.1.37 A.3.1.37 B.1.38 NL-07-153 Audit item 173 NL-07-039 A.2.1.39 A.3.1.39 B.1.40 NL-08-057 Audit item 509 NL-07-039 A.2.1.40 B.1.41 NL-07-039 A.2.1.41 A.3.1.41 NL-07-039 A.2.2.1.2 A.3.2.1.2 4.2.3 IPEG PA OAG0001678

COMMITMENT 32 As required by 10 CFR 50.61 (b)(4), IP3 will submit a plant-specific safety analysis for plate B2803-3 to the NRC three years prior to reaching the RT PTS screening criterion. Alternatively, the site may choose to implement the revised PTS rule when approved.

33 At least 2 years prior to entering the period of extended operation, for the locations identified in LRA Table 4.3-13 (IP2) and LRA Table 4.3-14 (IP3), under the Fatigue Monitoring Program, IP2 and IP3 will implement one or more of the following:

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

1. For locations in LRA Table 4.3-13 (IP2) and LRA Table 4.3-14 (IP3), with existing fatigue analysis valid for the period of Elxtended 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) maybe 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.

IMPLEMENTATION SCHEDULE IP3:

December 12,

~015 IP2:

September 28,

~011 IP3:

December 12,

~013 NL-09-106 Page 16 of 18 SOURCE RELATED LRA SECTION I AUDIT ITEM NL-07-039 A.3.2.1.4 4.2.5 NL-08-127 NL-07-039 A.2.2.2.3 A.3.2.2.3 4.3.3 NL-07-153 Audit item*

146 NL-08-021 IPEG PA OAG0001679

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

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

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

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

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

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

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

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

IMPLEMENTATION SCHEDULE April 30, 2008 Complete IP2:

September 28, 2013 IP3:

December 12, 2015 IP2:

September 28,

~013 NL-09-106 Page 17 of 18 SOURCE RELATED LRASECTION I AUDIT ITEM NL-07-078 2.1.1.3.5 NL-08-074 NL-08-127 Audit Item 27 NL-09-018 NL-08-127 Audit Item 359 NL-09-056 NL-09-079 IPEG PA OAG0001680

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

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

39 Deleted 40 Evaluate giant sgecific and aggrogriate industry oQerating eXQerience and incorQorate lessons learned in establishing aQgrogriate monitoring and insgection freguencies to assess aging effects for the new aging management grograms. Documentation of the oQerating eXQerience evaluated for each new Qrogram will be available on site for NRC review grior to the Qeriod of extended oQeration.

r

._).. _

"~.-'

IMPLEMENTATION SCHEDULE IP2:

September 28, 2013 IP3:

December 12, 2015 IP2:

September 28, 2013 IP3:

December 12, 2015 IP2:

September 28, 2013 IP3:

December 12, 2015 NL-09-106 Page 18 of 18 SOURCE RELATED LRA SECTION I AUDIT ITEM NL-08-127 Audit Item 361 NL-08-143 4.2.1 NL-09-079 NL-09-106 B.1.6 B.1.22 B.1.23 B.1.24 B.1.25 B.1.27 B.1.28 B.1.33 B.1.37 B.1.38 IPEG PA OAG0001681

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