NL-09-106, Response to Questions Regarding Buried Piping Inspections

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Response to Questions Regarding Buried Piping Inspections
ML092330120
Person / Time
Site: Indian Point  Entergy icon.png
Issue date: 07/27/2009
From: Dacimo F
Entergy Corp, Entergy Nuclear Northeast, Entergy Nuclear Operations
To:
Document Control Desk, Office of Nuclear Reactor Regulation
References
FOIA/PA-2010-0133, NL-09-106
Download: ML092330120 (29)
v • d • e


Text

Enteray Nuclear Northeast Indian Point Energy Center 450 Broadway, GSB P.O. Box249 SEntergy Buchanan, NY 10511-0249 Tel (914) 788-2055 Fred Dacimo Vice President License Renewal NL-09-106 July 27, 2009 U.S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, DC 20555-0001

SUBJECT:

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

REFERENCES:

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.

Dear Sir or Madam:

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 any questions, or require additional information, please contact Mr. Robert Walpole at 914-734-6710.

AoDi

NL-09-106 Page 2 of 2 I declare under penalty of perjury that the foregoing is true and correct. Executed on

001)

Sincerely, 00-ýý ram 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

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

Attachment 1 NL-09-106 Page 1 of 7 INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL APPLICATION CLARIFICATION AMENDMENT 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-1 801,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 IPEC 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 stainlesssteel 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 iron or carbon steel piping that runs from fire water pumps to and including the fire protection loop 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.

Attachment 1 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).

e 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.

9 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 IP2 with the remainder serving IP3.

  • Containment isolation support - -150 feet of carbon steel piping that provides pressurized air to support containment integrity for WP2.

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 2009 leak was the result of damaged pipe coating. Specifically, Entergy concluded that the root cause of the leak was 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 the piping damaged its protective coating ultimately leading to the leak in the piping caused by corrosion originating on the external'piping 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.

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.

Attachment 1 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 (i.e., 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 will-establish the priority for the first inspections and frequency for periodic followup

-inspections of the in-scope buried piping and tanks. For example, piping segments or tanks with a high impact-ranking and high corrosion risk will be scheduled for the earliest inspections and have the-highest frequency for 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 inaccordance with the program requirements. For example, as a result of the most recent operating experience with the leak in the condensate storage system, IPEC

Attachment 1 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.

Attachment 1 NL-09-106 Page 5 of 7 New Aqing Management Programs 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.

LRA Changes Changes are shown as strikethroughs for deletieii and underlines for additions.

B.1.6 Buried Piping and Tanks Inspection Proaram Descriotion 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 components in the following systems.

'Safety injection

  • Fire protection
  • Fuel oil
  • Security generator
  • City water
  • Plant drains

" Auxiliary feedwater

  • Containment isolation support

1ý Attachment 1 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 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 gualified 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-te Yrify that an inspections will be completed eeew*e4-within the past ten years. If an ins6pectionR did no-t occur, a focuse i nspection will be performned prior to the poriod of cxtended opeoation. Additional periodic A A ,,,Ued inspections will be performed within the first ten years of the period of extended operation., nless an... .. oppru

... t p.c...n.occur thin.

this ten , r ,period.

A.2.1.5 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 veify4hat*,- inspections will be completed eocu'-rd-within the past ten years. I ar iRnPectioR did o*,t odeur, a focused irnpection Will be performed prrior to the period e.

ex4ended operation. Additional periodic A ^eose4 inspections will be performed within the first ten years of the period of extended operation., unless.an o ut insecio ocur within this ton year peFred.

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

Attachment 1 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 classift pine 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 gualified inspection techniques with demonstrated effectiveness. Inspections will begin prior to the period of extended operation.

A.3.1.5 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 Yerfy that4a, inspections will be completed occurred-within the past ten years. l4 a*n inspctiRn did not occur, a f*csod *inpection will be pcrf. r 4md prior to the poriod Of xt4endcd operation. Additional periodic A.feo*sed inspections will be performed within the first ten years of the period of extended operation., unless an o...... ic in..cio occur. 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 pipinq 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.,

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

Attachment 2 NL-09-106 Page 1 of 18 List of Regulatory Commitments Rev. 10 The following table identifies those actions committed to by Entergy in this document.

Changes are shown as strikethroughs for d4eetio*s and underlines for additions.

  1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION

/ AUDIT ITEM 1 Enhance the Aboveground Steel Tanks Program for IP2: NL-07-039 A.2.1.1 IP2 and IP3 to perform thickness measurements of September 28, A.3.1.1 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 2015 IP2 and IP3 to require trending of thickness measurements when material loss is detected.

2 Enhance the Bolting Integrity Program for IP2 and IP3 IP2: NL-07-039 A.2.1.2 to clarify that actual yield strength is used in selecting September 28, A.3.1.2 materials for low susceptibility to SCC and clarify the 013 B.1.2 prohibition on use of lubricants containing MoS 2 for IP& NL-07-153 Audit Items bolting. December 12, 201,241, The Bolting Integrity Program manages loss of 015 270 1 preload and loss of material for all external bolting. _ I I

Attachment 2 NL-09-106 Page 2 of 18 COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION I/ I I / AUDIT ITEM IP2: NL-07-039 A.2.1.5 3 Implement the Buried Piping and Tanks Inspection Program for IP2 and IP3 as described in LRA Section September 28, A.3.1.5 B.1.6. 2013 B.1.6 NL-07-153 Audit Item This new program will be implemented consistent with IP3: 173 the corresponding program described in NUREG- December 12, 1801 Section XI.M34, Buried Piping and Tanks 2015 Inspection.

Include in the Buried Piping and Tanks Inspection NL-09-106 Program described in LRA Section B.1.6 a risk assessment of in-scope buried piping and tanks that includes consideration of the impacts of buried piping or tank leakaae and of conditions affectina the risk for corrosion. Classifv pipe seaments and tanks as having a high, medium or low impact of leakage based on the safety class, the hazard nosed bv 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, drainaae, the presence of cathodic protection and the type of coating. Establish insoection priority and freauencv for oeriodic inspections of the in-scope piping and tanks based on the results of the risk assessment. Perform inspections using gualified inspection technigues with demonstrated effectiveness. .1. +/-

  1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION I I I/AUDIT ITEM Enhance the Diesel Fuel Monitoring Program to include IP2: NL-07-039 A.2.1.8 4

cleaning and inspection of the IP2 GT-1 gas turbine fuel oil September 28, A.3.1.8 storage tanks, IP2 and IP3 EDG fuel oil day tanks, IP2 2013 B.1.9 SBO/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 1P3: 128,129, ten years. December 12, 132, Enhance the Diesel Fuel Monitoring Program to include 2015 NL-08-057 491,492, quarterly sampling and analysis of the IP2 SBO/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/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.

Attachment 2 NL-09-106 Page 4 of 18

  1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION

/ AUDIT ITEM 5 Enhance the External Surfaces Monitoring Program IP2: NL-07-039 A.2.1.10 for IP2 and IP3 to include periodic inspections of September 28, A.3.1.10 systems in scope and subject to aging management 013 B.1.11 review for license renewal in accordance with 10 CFR lP3:

54.4(a)(1) and (a)(3). Inspections shall include areas surrounding the subject systems to identify hazards to De r1 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 IP2: NL-07-039 A.2.1.11 monitor steady state cycles and feedwater cycles or eptember 28, A.3.1.11 2013 B.1 .12, performran evaluation to determine monitoring is not 2L013 53 Ad Ite required. Review the number of allowed events and 164 resolve discrepancies between reference documents and monitoring procedures.

Enhance the Fatigue Monitoring Program for IP3 to IP3:

include all the transients identified. Assure all fatigue December 12, analysis transients are included with the lowest 2015 limiting numbers. Update the number of design transients accumulated to date.

Attachment 2 NL-09-106 Page 5 of 18

  1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION

/ AUDIT ITEM 7 Enhance the Fire Protection Program to inspect IP2: NL-07-039 A.2.1.12 external surfaces of the IP3 RCP oil collection September 28, A.3.1.12 systems for loss of material each refueling cycle. 013 B.1.13 Enhance the Fire Protection Program to explicitly IP3:

state that the IP2 and IP3 diesel fire pump engine December 12, sub-systems (including the fuel supply line) shall be 2015 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 C02 fire suppression system for signs of degradation, such as corrosion and mechanical damage at least once every six months.

Attachment 2 NL-09-106 Page 6 of 18

  1. COMMITMENT IMPLEMENTATION SOURCE I RELATED SCHEDULE LRA SECTION

/AUDIT ITEM 8 Enhance the Fire Water Program to include inspection IP2: NL-07-039 A.2.1.13 September 28, A.3.1.13 of IP2 and IP3 hose reels for evidence of corrosion.

Acceptance criteria will be revised to verify no 2013 B.1.14 unacceptable signs of degradation. NL-07-153 Audit Items IP3: 105,106 Enhance the Fire Water Program to replace all or test December 12, NL-08-014 a sample of IP2 and IP3 sprinkler heads required for 2015 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

.5.

sianificant corrosion.

- I- £ I

Attachment 2 NL-09-106 Page 7 of 18

  1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION

/ AUDIT ITEM IP2: NL-07-039 A.2.1.15 9 Enhance the Flux Thimble Tube Inspection Program September 28, A.3.1.15 for I P2 and IP3 to implement comparisons to wear 2013 B.1.16 rates identified in WCAP-12866. Include provisions to compare data to the previous performances and D 12, perform evaluations regarding change to test frequency and scope. 2015 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.

Attachment 2 NL-09-106 Page 8 of 18

  1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION I_ I /AUDIT ITEM IP2: NL-07-039 A.2.1.16 10 Enhance the Heat Exchanger Monitoring Program for IP2 and IP3 to include the following heat exchangers September 28, A.3.1.16 2013 B.1.17, in the scope of the program.

NL-07-153 Audit Item

  • Safety injection pump lube oil heat exchangers IP3: 52 December 12,
  • RHR heat exchangers 2015
  • 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
  • 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, NL-09-018 fouling, or scaling.

11 Delete commitment. NL-09-056

Attachment 2 NL-09-106 Page 9 of 18

  1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION

/ AUDIT ITEM 12 Enhance the Masonry Wall Program for IP2 and IP3 IP2: NL-07-039 A.2.1.18 to specify that the IP1 intake structure is included in September 28, A.3.1.18 the program. 2013 B.1.19 IP3:

December 12, 2015 Enhance the Metal-Enclosed Bus Inspection Program IP2: NL-07-039 A.2.1.19 13 to add IP2 480V bus associated with substation A to September 28, A.3.1.19 the scope of bus inspected. 2013 B.1.20 NL-07-153 Audit Items Enhance the Metal-Enclosed Bus Inspection Program IP3: 124, for IP2 and IP3 to visually inspect the external surface December 12, NL-08-057 133, 519 of MEB enclosure assemblies for loss of material at 2015 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 IrspectionProgram 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 achange:to applicable site procedure to remove the reference to "re-torquing" connections for phase bus maintenance and bolted connection maintenance.

Attachment 2 NL-09-106 Page 10 of 18

  1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION

/ AUDIT ITEM 14 Implement the Non-EQ Bolted Cable Connections IP2: NL-07-039 A.2.1.21 Program for IP2 and IP3 as described in LRA Section September 28, A.3.1.21 B.1.22. 2013 B.1.22 IP3:

December 12, 2_015 15 Implement the Non-EQ Inaccessible Medium-Voltage IP2: NL-07-039 A.2.1.22 Cable Program for IP2 and IP3 as described in LRA September 28, A.3.1.22 Section B.1.23. 2013 B.1.23 NL-07-153 Audit item This new program will be implemented consistent with IP3: 173 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: NL-07-039 A.2.1.23 Review Program for IP2 and IP3 as described in LRA September 28, A.3.1.23 Section B.1.24. 2013 B. 1.24 NL-07-153 Audit item This new program will be implemented consistent with IP3: 173 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 Insulated Cables and IP2: NL-07-039 A.2.1.24 Connections eto Program LR . for IP2 and IP3 as described in

.25.. September 013 28, A.3.1.24 B. 1.25 LRA Section B.1.25. NL-07-153 Audit item This new program will be implemented consistent with IP3: 173 the corresponding program described in NUREG- December 12, 1801 Section XI.E1, Electrical Cables and 2015 Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements.

Attachment 2 NL-09-106 Page 11 of 18

  1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION

/ AUDIT ITEM 18 Enhance the Oil Analysis Program for IP2 to sample IP2: NL-07-039 A.2.1.25 and analyze lubricating oil used in the SBO/Appendix September 28, A.3.1.25 R diesel generator consistent with oil analysis for 2013 B. 1.26 other site diesel generators. IP3:

Enhance the Oil Analysis Program for IP2 and IP3 to December 12, sample and analyze generator seal oil and turbine 2015 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 IP2: NL-07-039 A.2.1.26 and IP3 as described in LRA Section B.1.27. September 28, A.3.1.26 2013 B.1.27 This new program will be implemented consistent with NL-07-153 Audit item the corresponding program described in NUREG- IP3: 173 1801,Section XI.M32, One-Time Inspection. December 12, 2015 20 Implement the One-Time Inspection.- Small Bore IP2: NL-07-039 A.2.1.27 Piping Program for IP2 and IP3 as described in LRA September 28, A.3.1.27 Section B.1.28. 013 B.1.28 NL-07-153 Audit item This new program will be implemented consistent with IP3: 173

-the corresponding program described in NUREG- December 12, 1801,Section XI.M35, One-Time Inspection of ASME 2015 Code Class I Small-Bore Piping....

21 Enhance the Periodic Surveillance and Preventive IP2: NL-07-039 A.2.1.28 Maintenance Program for IP2 and IP3 as necessary September 28, A.3.1.28 2013 B. 1.29 to assure that the effects of aging will be managed such that applicable components will continue to IP3:

perform their intended functions consistent with the DP3 1 current licensing basis through the period of extended De r1 1 operation. I015

Attachment 2 NL-09-106 Page 12 of 18 COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION

/ AUDIT ITEM 22 Enhance the Reactor Vessel Surveillance Program for 1P2: NL-07-039 A.2.1.31 IP2 and IP3 revising the specimen capsule withdrawal September 28, A.3.1.31 schedules to draw and test a standby capsule to 013 B.1 32 cover the peak reactor vessel fluence expected IP3:

through the end of the period of extended operation. December 12, Enhance the Reactor Vessel Surveillance Program for 2015 IP2 and IP3 to require that tested and untested specimens from all capsules pulled from the reactor I vessel are maintained in storage.

23 Implement the Selective Leaching Program for IP2 IP2: NL-07-039 A.2.1.32 and IP3 as described in LRA Section B.1.33. September 28, A.3.1.32 2013 B.1.33 This new program will be implemented consistent with NL-07-153 Audit item the corresponding program described in NUREG- IP3: 173 1801,Section XI.M33 Selective Leaching of Materials. December 12, 2015 24 Enhance the Steam Generator Integrity Program for IP2: NL-07-039 A.2.1.34 IP2 and IP3 to require that the results of the condition September 28, A.3.1.34 monitoring assessment are compared to the 013 B.1.35 operational assessment performed for the prior IP3:

operating cycle with differences evaluated. December 12, 2015 25 Enhance the.Structures Monitoring Program to IP2: NL-07-039 A.2.1.35

- explicitly specify that the following structures are September 28, A.3.1.35 included in the program.. 2013 B.1.36

  • Appendix R diesel generator foundation (IP3) NL-07-153
  • Appendix R diesel generator fuel oil tank vault IP3: Audit items (IP3) December 12, 86, 87, 88,

- Appendix R diesel generator switchgear and 2015 NL-08-057 417 enclosure (IP3) -

  • city water storage tank foundation 0 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

Attachment 2 NL-09-106 Page 13 of 18

  1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION I / AUDIT ITEM passageway (IP2)
  • new station security building (IP2)
  • nuclear service building (IP1)
  • primary water storage tank foundation (IP3)
  • refueling water storage tank foundation (IP3)
  • security access and office building (IP3)

" service water pipe chase (IP2/3)

" service water valve pit (IP3)

  • 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)
  • 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 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

Attachment 2 NL-09-106 Page 14 of 18 COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION I I_ I I/ AUDIT ITEM 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 NL-08-127 Audit Item and IP3 to perform an engineering evaluation of 360 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 IP3 intake structure at least once every 5 years.

Enhance the.Structures Monitoring Program for IP2 Audit Item and IP3 to perform inspection of the degraded areas 358 of the water control structure once per 3 years rather than the normal frequency of once per 5 years during the PEO.

IP2: N L-07-039 A.2.1.36 A.2.1.36 26 Implement the Thermal Aging Embrittlement of Cast Austenitic Stainless Steel (CASS) Program for IP2 September 28, A.3.1.36 and IP3 as described in LRA Section B.1.37. 2013 1.37 B.A NL-07-153 Audit item This new program will be implemented consistent with IP3: 173 the corresponding program described in NUREG- December 12, 1801,Section XI.M12, Thermal Aging Embrittlement 015 of Cast Austenitic Stainless Steel (CASS) Program. r

Attachment 2 NL-09-106 Page 15 of 18

  1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION

/ AUDIT ITEM 27 Implement the Thermal Aging and Neutron Irradiation IP2: NL-07-039 A.2.1.37 Embrittlement of Cast Austenitic Stainless Steel September 28, A.3.1.37 2013 B. 1.38 (CASS) Program for IP2 and IP3 as described in LRA 013 B.1Ait Audit item Section B.1.38.173 SecionB.138.NL-07-153 This new program will be implemented consistent with December 12, the corresponding program described in NUREG- 2015 1801 Section XI.M13, Thermal Aging and Neutron Embrittlement of Cast Austenitic Stainless Steel (CASS) Program.

28 Enhance the Water Chemistry Control - Closed IP2: NL-07-039 A.2.1.39 Cooling Water Program to maintain water chemistry of September 28, A.3.1.39 2013 B.1.40 the IP2 SBO/Appendix R diesel generator cooling NL-08-057 Audit item system per EPRI guidelines. IP3: 509 Enhance the Water Chemistry Control - Closed December 12, Cooling Water Program to maintain the IP2 and IP3 015 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 IP2: NL-07-039 A.2.1.40 Secondary Program for IP2 to test sulfates monthly in September 28, B.1.41 the RWST with a limit of <150 ppb. 2013 30 For aging management of the reactor vessel internals, IP2: NL-07-039 A.2.1 41 IPEC will (1) participate in the industry programs for September 28, A.3.1.41 investigating and managing aging effects on reactor 011 internals; (2) evaluate and implement the results of IP&

the industry programs as applicable to the reactor December 12, internals; and (3) upon completion of these programs, 2013 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 IP2: NL-07-039 A.2.2.1.2 per 10 CFR 50, Appendix G prior to the period of September 28, A.3.2.1.2 extended operation as part of the Reactor Vessel 013 4.2.3 Surveillance Program. IP3:

December 12, 2015

Attachment 2 NL-09-106 Page 16 of 18 COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION

/ AUDIT ITEM 32 As required by 10 CFR 50.61 (b)(4), IP3 will submit a IP3: NL-07-039 A.3.2.1.4 plant-specific safety analysis for plate B2803-3 to the December 12, 4.2.5 NRC three years prior to reaching the RTPTS 2015 NL-08-127 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 IP2: NL-07-039 A.2.2.2.3 extended operation, for the locations identified in LRA September 28, A.3.2.2.3 Table 4.3-13 (1P2) and LRA Table 4.3-14 (1P3), under 2011 4.3.3 the Fatigue Monitoring Program, IP2 and IP3 will NL-07-153 Audit item implement one or more of the following: IP3: 146 December 12, NL-08-021 (1) Consistent with the Fatigue Monitoring Program, 2013 Detection of Aging Effects, update the fatigue usage calculations using refined fatigue analyses to determine valid CUFs less than 1.0 when accounting for the effects of reactor water environment. This includes applying the appropriate Fen factors to valid CUFs determined in accordance with one of the following:

1. For locations in LRA Table 4.3-13 (IP2) and LRA Table 4.3-14 (IP3), with existing fatigue analysis valid for the period of extended operation, use the existing CUF.
2. Additional plant-specific locations with a valid CUF may be evaluated. In particular, the pressurizer lower shell will be reviewed to ensure the surge nozzle remains the limiting component.
3. Representative CUF values from other plants, adjusted to or enveloping the IPEC plant specific external loads may be used if demonstrated applicable to IPEC.
4. An analysis using an 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.

Attachment 2 NL-09-106 Page 17 of 18

  1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION

/ AUDIT ITEM 34 1P2 SBO / Appendix R diesel generator will be April 30, 2008 NL-07-078 2.1.1.3.5 installed and operational by April 30, 2008. This Complete NL-08-074 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 IP2: NL-08-127 Audit Item sample area of IP2 containment liner affected by the September 28, 27 1973 event behind the insulation, prior to entering the 013 extended period of operation, to assure liner degradation is not occurring in this area.

Perform a one-time inspection of representative IP3:

sample area of the IP3 containment steel liner at the December 12, juncture with the concrete floor slab, prior to entering 015 the extended period of operation, to assure liner degradation is not occurring in this area.

Any degradation will be evaluated for updating of the NL-09-018 containment liner analyses as needed.

IP2: NL-08-127 Audit 359Item 36 Perform a one-time Inspection and evaluation of a Sptb 28, sample of potentially affected IP2 refueling cavity September 28, 359 concrete prior to the period of extended operation. 013 The sample will be obtained by core boring the refueling cavity wall in an area that is susceptible to exposure to borated water leakage. The inspection will include an assessment of embedded reinforcing steel.

Additional core bore samples will be taken, if the NL-09-056 leakage is not stopped, prior to the end of the first ten years of the period of extended operation.

A sample of leakage fluid will be analyzed to NL-09-079 determine the composition of the fluid. If additional core samples are taken prior to the end of the first ten years of the period of extended operation, a sample of leakage fluid will be analyzed.

Attachment 2 NL-09-106 Page 18 of 18

  1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION

/ AUDIT ITEM 37 Enhance the Containment Inservice Inspection (CII- P2: NL-08-127 Audit Item IWL) Program to include inspections of the September 28, 361 containment using enhanced characterization of 013 degradation (i.e., quantifying the dimensions of noted 1P3:

indications through the use of optical aids) during the December 12, period of extended operation. The enhancement 015 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.

1P2: NL-08-143 4.2.1 38 For Reactor Vessel Fluence, should future core loading patterns invalidate the basis for the projected September 28, values of RTpts or CvUSE, updated calculations will 013 be provided to the NRC. IP3:

December 12, 2_015 39 Deleted NL-09-079 40 Evaluate plant specific and appropriate industry IP2: NL-09-106 B.1.6 operating experience and incorporate lessons learned September 28, B.1.22 in establishing appropriate monitoring and inspection 013 B.1.23 frequencies to assess aging effects for the new agingq P3: B.1.25 management programs. Documentation of the operating experience evaluated for each new program December 12, B.1.27 will be available on site for NRC review prior to the 015 B.1.28 period of extended operation. B.1.33 B.1.37 B.1.38

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