NL-14-147, Reply to Request for Additional Information Regarding the License Renewal Application

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Reply to Request for Additional Information Regarding the License Renewal Application
ML14365A069
Person / Time
Site: Indian Point  Entergy icon.png
Issue date: 12/16/2014
From: Dacimo F
Entergy Nuclear Northeast
To:
Document Control Desk, Office of Nuclear Reactor Regulation
References
NL-14-147
Download: ML14365A069 (99)
v • d • e


Text

Enter-gv Nuclear Northeast Indian Point Energy Center 450 Broadway, GSB

--- Entergy P.O. Box 249 Buchanan, NY 10511-0249 Tel (914) 254-2055 Fred Dacimno Vice President Operations License Renewal NL-14-147 December 16, 2014 U.S. Nuclear Regulatory Commission Document Control Desk 11545 Rockville Pike, TWFN-2 F1 Rockville, MD 20852-2738

SUBJECT:

Reply to Request for Additional Information Regarding the License Renewal Application Indian Point Nuclear Generating Unit Nos. 2 & 3 Docket Nos. 50-247 and 50-286 License Nos. DPR-26 and DPR-64

REFERENCES:

NRC letter, "Request for Additional Information for the Review of the Indian Point Nuclear Generating Unit Nos. 2 and 3, License Renewal Application, SET 2014-01 (TAC Nos. MD5407 and MD5408)" dated April 1,2014.

Dear Sir or Madam:

Entergy Nuclear Operations, Inc. is providing, in Attachment 1, the additional information requested in the referenced letter pertaining to NRC review of the License Renewal Application (LRA) for Indian Point 2 and Indian Point 3.

The response provided in Attachment 1 contains new regulatory commitments that are identified in the list of regulatory commitments provided in Attachment 3.

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

I declare under penalty of perjury that the foregoing is true and correct. Executed on 2014.

FRD/rI Al ý, E/

P44

Docket Nos. 50-247 & 50-286 NL-14-147 Page 2 of 2 Attachments:

1. Reply to NRC Request for Additional Information Regarding the License Renewal Application
2. License Renewal Application Changes Due To Responses To Requests For Information
3. License Renewal Application IPEC List of Regulatory Commitments Revision 25 cc: Mr. Daniel H. Dorman, Regional Administrator, NRC Region I Mr. Sherwin E. Turk, NRC Office of General Counsel, Special Counsel Mr. Dave Wrona, NRC Branch Chief, Engineering Review Branch I Ms. Kimberly Green, NRC Sr. Project Manager, Division of License Renewal Mr. Douglas Pickett, NRR Senior Project Manager Ms. Bridget Frymire, New York State Department of Public Service NRC Resident Inspector's Office Mr. John B. Rhodes, President and CEO NYSERDA

ATTACHMENT 1 TO NL-14-147 REPLY TO NRC REQUEST FOR ADDITIONAL INFORMATION REGARDING THE LICENSE RENEWAL APPLICATION ENTERGY NUCLEAR OPERATIONS, INC.

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

NL-14-147 Attachment 1 Page 1 of 8 REQUEST FOR ADDITIONAL INFORMATION, SET 2014-01 RELATED TO INDIAN POINT NUCLEAR GENERATING UNIT NOS. 2 AND 3 LICENSE RENEWAL APPLICATION RAI 3.0.3-1

Background:

Recent industry operating experience (OE) and questions raised during the staff's review of several license renewal applications (LRAs) have resulted in the staff concluding that several aging management programs (AMPs) and aging management review (AMR) items in the LRA may not or do not account for OE involving recurring internal corrosion, corrosion occurring under insulation, managing aging effects of fire water system components, and certain other issues. In order to provide updated guidance, the NRC staff has issued LR-ISG-2012-02, "Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation" (ADAMS Accession No. ML13227A361).

Issue:

The staff noted that the updated guidance may not have been incorporated into the respective AMPs and AMR items.

Request:

Provide details on how the updated guidance of LR-ISG-2012-02 has been accounted for in your AMPs and AMR items; or where the revised recommendations will not be incorporated, state an exception and the basis for the exception. If necessary, provide revisions to LRA Section 3 tables, Appendix A, and Appendix B.

Response to RAI 3.0.3-1 A response follows for each of the eight sections of LR-ISG-2012-02.

NL-14-147 Attachment 1 Page 2 of 8 Response to LR-ISG section A "Recurrinq Internal Corrosion" The updated guidance of LR-ISG-2012-02 Section A was reviewed with respect to the IPEC LRA. The past 10 years of plant-specific operating experience for IP2 and IP3 were reviewed to identify recurring internal corrosion as defined in LR-ISG-2012-02, Section A. Based on these reviews, loss of material due to general, pitting and crevice corrosion is considered recurring internal corrosion applicable to both IP2 and IP3. Loss of material due to general, pitting and crevice corrosion leading to through-wall leaks has occurred at least once in each of three refueling cycles for both units in the last 10 years. Piping components of the following systems for both IP2 and IP3 are susceptible to recurring internal corrosion.

" Fire protection - water

  • City water Service Water The Service Water Integrity Program implements the guidelines of NRC Generic Letter 89-13, including routine inspection and maintenance to ensure that degradation due to corrosion, erosion and biofouling cannot prevent safety-related systems cooled by service water from satisfactorily performing their intended functions. As concluded in NUREG-1930, the effects of aging are adequately managed by the Service Water Integrity Program so that the intended functions are maintained. However, minor corrosion issues that do not compromise the intended functions of the service water system still occur. Carbon steel service water system piping is internally lined with cement, which is very effective in protecting the carbon steel piping. Where discontinuities in the cement lining (such as at piping segment welds) allow the service water to directly contact the carbon steel, corrosion can occur. This corrosion can result in a through-wall leak. Stainless steel and copper alloy piping components also develop through-wall leaks due to localized pitting corrosion. Based on operating experience, such leaks have had no impact on system performance and have not threatened the structural integrity of the piping or the safety function of nearby equipment.

Through-wall leakage is identified and reported by plant personnel during their normal activities or by engineering personnel during system walkdowns. The leakage is then evaluated under the corrective action program, which includes operability or functionality assessment of structural integrity and determination of appropriate corrective action.

Repairs or replacements of safety-related piping are implemented under the Entergy ASME Section Xl Repair/Replacement Program, which implements the requirements of IWA-4000.

Fire Protection - Water The Fire Water System Program includes wall thickness evaluations of fire protection piping using volumetric testing to identify loss of material due to corrosion and ensure that wall thickness is within the required structural limits. These inspections were performed for IP2 before the end of its original operating term. The inspections identified no unacceptable wall thinning. However, minor corrosion issues that do not compromise the intended functions of the fire protection - water system have occurred in the carbon steel piping components exposed to city (potable) water. Localized corrosion has resulted in minor through-wall leaks that have no

NL-14-147 Attachment 1 Page 3 of 8 impact on system performance and do not threaten the structural integrity of the piping or the safety function of nearby equipment.

City Water The Periodic Surveillance and Preventive Maintenance Program will monitor corrosion of the city water system to assure it can perform its intended functions. However, minor corrosion issues that do not compromise the intended functions of the city water system have occurred in the carbon steel and copper alloy piping components exposed to city (potable) water. Localized corrosion has resulted in minor through-wall leaks that have no impact on system performance and do not threaten the structural integrity of the piping or the safety function of nearby equipment.

Through-wall leaks in the fire protection - water and city water systems meet the definition of recurring internal corrosion since they exceed the 50 percent wall thickness criterion in LR-ISG-2012-02, Section A. However, based on past operating experience, they do not compromise the intended functions of these or any other system, and do not warrant aging management program activities beyond those provided by established aging management programs and the corrective action program. Through-wall leakage in these systems is identified and reported by plant personnel during their normal activities or by engineering personnel during system walkdowns. When identified, the leak is documented in the corrective action program.

Depending on the size of the line, the size of the leak, and its proximity to other plant equipment, NDE may be used to characterize the extent of the corrosion in order to plan the best repair method, or the leak may be patched or repaired.

The service water, fire protection - water and city water systems for IP2 and IP3 include buried piping. Although leaks in buried piping are possible, underground leaks large enough to affect the function of these systems are not expected based on operating experience with the above-ground portions of these systems. If large leaks were to occur, they would be expected to develop slowly and would be detectable by changes in system performance (e.g., changes in instrumentation readings or reduced cooling capacity), changes in system operation (e.g., more frequent pressure maintenance / jockey pump operation), or by the appearance near the leak of wetted ground, sink holes, or other ground anomalies. Accessible portions of safety-related buried service water piping will be internally inspected by robotic crawler or manual crawl-through once during the first 10 years of the period of extended operation.

The actions used to manage the minor corrosion issues in the service water, fire protection -

water and city water systems at IP2 and IP3 have been effective. The through-wall leaks resulting from recurring internal corrosion in these systems have not resulted in a loss of system intended function, have not affected the structural integrity of system components, and have not caused a loss of a safety function in nearby equipment.

The Service Water Integrity Program described in LRA Section B.1.34 will be enhanced to incorporate the actions used to manage the minor corrosion issues in the service water system.

Revisions to LRA Sections A.2.1.33, A.3.1.33, B.1.34, and Section 3.3 tables are provided in Attachment 2.

NL-14-147 Attachment 1 Page 4 of 8 Response to LR-ISG section B "Representative Minimum Sample Size for Periodic Inspections in GALL Report AMP XI.M38, 'Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components'."

The updated guidance of LR-ISG-2012-02 Section B was reviewed with respect to the IPEC LRA. This section provides changes for NUREG-1 801 XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components," to ensure that inspections performed under this program include a representative sample on a periodic basis.

The IPEC programs credited for managing the effects of aging during the period of extended operation are described in IPEC LRA, Appendix B. None of the programs described in IPEC LRA Appendix B are compared to XI.M38. With respect to NUREG-1801 Section XI.M38, IPEC LRA Table B-2 states, "The External Surfaces Monitoring Program (B. 1.11] or the Periodic Surveillance and Preventive Maintenance Program [B.1.29] manage the effects of aging on internal surfaces of piping and ducting components."

The External Surfaces Monitoring Program described in IPEC LRA Section B.1.11 is credited with managing loss of material from internal surfaces, for situations in which internal and external material and environment combinations are the same such that external surface condition is representative of internal surface condition. This program contains provisions for inspection of surfaces at frequencies that assure the effects of aging are managed. In Section 3.0.3.2.5, "External Surfaces Monitoring Program," (page 3-78) of the SER for IPEC license renewal (NUREG-1.930 Volume 2, published November 2009), the NRC staff "concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended operation."

The Periodic Surveillance and Preventive Maintenance Program described in IPEC LRA Section B.1.29 includes periodic inspections of representative samples to manage aging effects not managed by other aging management programs. Section 3.0.3.3.7, "Periodic Surveillance and Preventive Maintenance Program," (page 3-216) of the SER for IPEC license renewal (NUREG-1930 Volume 2, published November 2009) states, "On the basis of its review of the applicant's Periodic Surveillance and Preventive Maintenance Program, the staff concludes that the applicant has demonstrated that the effects of aging will be adequately managed so that the intended functions will be maintained consistent with the CLB for the period of extended operation."

Because none of the programs described in IPEC LRA Appendix B are compared to XI.M38 and the programs used in lieu of XI.M38 provide for periodic inspections of representative samples of components, no changes to the IPEC LRA are necessary to account for the guidance of Section B of LR-ISG-2012-02.

NL-14-147 Attachment 1 Page 5 of 8 Response to LR-ISG section C "Flow Blockage of Water-Based Fire Protection System Piping."

The updated guidance of LR-ISG-2012-02 Section C was reviewed with respect to the IPEC LRA. Entergy will perform the tests and inspections for fire water system blockage at IP2 and IP3 as recommended by LR-ISG-2012-02, with exceptions listed in the revised LRA Section B.1.14.

Revisions to LRA Sections A.2.1.13, A.3.1.13, B.1.14 and Section 3.3 tables are provided in .

Response to LR-ISG section D "Revisions to the scope and inspection recommendations of GALL Report AMP XI.M29, "Aboveground Metallic Tanks."

The updated guidance of LR-ISG-2012-02 Section D was reviewed with respect to the IPEC LRA. The Aboveground Steel Tanks Program described in IPEC LRA Section B.1.1 will manage the aging effects for tanks in the scope of the program consistent with the guidance of LR-ISG-2012-02. There are no indoor tanks within the scope of this program as defined in the ISG.

The outdoor tanks within the scope of the program are the IP1 city water tank, IP1 condensate storage tanks, IP2 condensate storage tank, IP2 GT2/3 fuel oil tank (for managing exterior aging effects only), IP2 primary water storage tank, IP2 refueling water storage tank, IP3 condensate storage tank, IP3 primary water storage tank, and IP3 refueling water storage tank.

The Aboveground Steel Tanks Program does not manage the effects of aging on the fire water storage tanks. The Fire Water System Program (described in LRA Sections A.2.1.13, A.3.1.13 and B.1.14) manages the effects of aging on the fire water storage tanks in accordance with the recommendations of LR-ISG-2012-02. The Diesel Fuel Monitoring Program manages the effects of aging on the IP2 GT2/3 fuel oil tank interior.

Revisions to LRA Sections A.2.1.1, A.3.1.1, B.1.1, and Sections 3.2, 3.3 and 3.4 are provided in . These revisions remove operating experience discussion in Section B.1.1 related to tank surfaces that are no longer covered by the Aboveground Steel Tanks Program.

NL-14-147 Attachment 1 Page 6 of 8 Response to LR-ISG section E "Corrosion Under Insulation."

The updated guidance of LR-ISG-2012-02 Section E was reviewed with respect to the IPEC LRA. The following items discuss each applicable lettered paragraph under the summary of changes in LR-ISG-2012-02 Section E regarding corrosion under insulation (CUI).

a. LR-ISG-2012-02, Section E.iii.a recommends periodic inspections during each 10-year period of the period of extended operation (PEO). IPEC inspections for CUI will be conducted during each 10-year period of the PEO.
b. LR-ISG-2012-02, Section E.iii.b provides recommendations for inspection of insulated components, except for tanks. IPEC will inspect insulated components in accordance with those recommendations. For a representative sample of insulated indoor components exposed to condensation (because the component is operated below the dew point) and insulated outdoor components, insulation will be removed for visual inspection of component surfaces. Inspections will include a minimum of 20 percent of the in-scope piping length for each material type (e.g., steel, stainless steel, copper alloy, aluminum) or, for components with a configuration which does not conform to a 1-foot axial length determination (e.g., valve, accumulator), 20 percent of the surface area.

Alternatively, insulation will be removed and a minimum of 25 inspections will be performed that can be a combination of 1-foot axial length sections and individual components for each material type.

c. LR-ISG-2012-02, Section E.iii.c provides recommendations for inspection of indoor insulated tanks exposed to condensation and outdoor insulated tanks. Because IPEC in-scope indoor insulated tanks operate above the dew point, they are not subject to condensation on the external surface. In-scope outdoor insulated tanks at IPEC have tightly adhering insulation. See discussion of tightly adhering insulation in item e below.
d. LR-ISG-2012-02, Section E.iii.d recommends selecting inspection locations based on the likelihood of CUI. For example, CUI is more likely for components that are alternately wet and dry in environments where trace contaminants could be present and for components that operate for long periods of time below the dew point. IPEC inspection locations will be based on the likelihood of CUI.

Subsequent inspections will consist of an examination of the exterior surface of the insulation for indications of damage to the jacketing or protective outer layer of the insulation, if the following conditions are verified in the initial inspection:

  • No loss of material due to general, pitting or crevice corrosion, beyond that which could have been present during initial construction.
  • No evidence of cracking.

If the external visual inspections of the insulation reveal damage to the exterior surface of the insulation or there is evidence of water intrusion through the insulation (e.g., water seepage through insulation seams or joints), periodic inspections under the insulation will continue.

e. LR-ISG-2012-02, Section E.iii.e provides recommendations for inspecting components with tightly adhering insulation. IPEC will inspect components with tightly adhering

NL-14-147 Attachment 1 Page 7 of 8 insulation in accordance with the recommendations of the ISG. Tightly adhering insulation that is impermeable to moisture will be removed to allow for inspection if there is evidence of damage to the moisture barrier. If the moisture barrier is intact, the likelihood of CUI is low for tightly adhering insulation. Components with tightly adhering insulation constitute a separate population from the remainder of in-scope insulated components. The entire population of in-scope accessible component surfaces covered with tightly adhering insulation will be visually inspected for damage to the moisture barrier at the same frequency as inspections of components with other types of insulation. These inspections will not be credited towards the inspection quantities for components with other types of insulation.

Revisions to text and tables in LRA Sections 3.2, 3.3, 3.4, A.2.1.10, A.3.1.10, and B.1.11 are provided in Attachment 2. In these revisions, line items are added to the aging management review results tables for each IPEC system determined susceptible to CUI.

Response to LR-ISG section F "External Volumetric Examination of Internal Piping Surfaces of Underground Piping Removed from GALL Report AMP XI.M41, 'Buried and Underground Piping and Tanks'."

The updated guidance of LR-ISG-2012-02 Section F was reviewed with respect to the IPEC LRA. This section provides changes for NUREG-1801, XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components," to allow the condition of internal surfaces of buried and underground piping to be inferred from inspections of the interior surfaces of accessible piping where the material, environment, and aging effects of the buried or underground component are similar to those of the accessible component.

This change in the ISG provides an allowance to use this approach for interior surfaces of buried and underground piping. It neither recommends use of the approach nor prohibits another approach to managing the effects of aging. Therefore, no changes to the IPEC LRA are necessary to account for the guidance of Section F of LR-ISG-2012-02.

NL-14-147 Attachment 1 Page 8 of 8 Response to LR-ISG section G "Specific Guidance for Use of the Pressurization Option for Inspectingi Elastomers in GALL Report AMP XI.M38."

The updated guidance of LR-ISG-2012-02 Section G was reviewed with respect to the IPEC LRA. This section provides changes for NUREG-1801, XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components," to remove the term "hydrotesting" from the program description.

The IPEC programs credited for managing the effects of aging during the period of extended operation are described in IPEC LRA, Appendix B. None of the programs described in IPEC LRA Appendix B are compared to XI.M38. With respect to NUREG-1801, Section Xl.M38, IPEC LRA Table B-2 states, "The External Surfaces Monitoring Program [B. 1.11] or the Periodic Surveillance and Preventive Maintenance Program [B. 1.29] manage the effects of aging on internal surfaces of piping and ducting components." Neither of these programs provide for the use of hydrotesting.

Because none of the programs described in IPEC LRA Appendix B that are used in lieu of XI.M38 rely on or provide for the use of hydrotesting, no changes to the IPEC LRA are necessary to account for the guidance of Section G of LR-ISG-2012-02.

Response to LR-ISG section H "Key Miscellaneous Changqes to the GALL Report and SRP-LR."

The updated guidance of LR-ISG-2012-02 Section H was reviewed with respect to the IPEC LRA. Section H, subsection v, item e was the only item identified with a potential impact on the IPEC LRA. This item added a new aging effect for NUREG-1801. "Reduced thermal insulation resistance" in jacketed insulation of various types exposed to indoor or outdoor air was added for steam and power conversion systems.

Entergy reviewed the steam and power conversion systems piping at IPEC. Piping insulation is not credited for thermal resistance in support of any safety function of these systems.

Consequently, reduction of thermal insulation resistance is not an aging effect requiring management, and no changes to the IPEC LRA are necessary to account for the guidance of Section H of LR-ISG-2012-02.

ATTACHMENT 2 TO NL-14-147 LICENSE RENEWAL APPLICATION CHANGES DUE TO RESPONSES TO REQUESTS FOR INFORMATION ENTERGY NUCLEAR OPERATIONS, INC.

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

NL-14-147 Attachment 2 Page 1 of 66 Revisions to LRA text and tables are provided below with additions underlined and deletions marked through.

3.2.2.1.4 Safety Injection System Aging Management Programs The following aging management programs manage the aging effects for safety injection system components.

" Aboveground Steel Tanks

" Bolting Integrity

" Buried Piping and Tanks Inspection

  • External Surfaces Monitoring
  • Heat Exchanger Monitoring
  • Oil Analysis

" Periodic Surveillance and Preventive Maintenance

  • Selective Leaching
  • Water Chemistry Control - Closed Cooling Water "Water Chemistry Control - Primary and Secondary 3.2.2.2.3 Loss of Material due to Pitting and Crevice Corrosion
5. Loss of material from pitting and crevice corrosion could occur for partially encased stainless steel tanks exposed to raw water due to cracking of the perimeter seal from weathering. At IPEC the bottom of outdoor stainRles steel tanks inthe ESE systems are not exposed to raw wator bocauco the dsign precaludes the entry of water under the tank. In addition to a perimneter real under the tank lip, the tanks have been grou ted behind thesa between the conrGete foudatonand the tank bottolm to a depth of eighteen Rinches. This desi6gn will not allow water leakage from" the outside to get under the tank. Inspections will be conducted in accordance with the Aboveground Steel Tanks Program to identify degradation of external surfaces of tank bottoms exposed to soil or concrete. This item is therefor-e nt applicable.

NL-14-147 Attachment 2 Page 2 of 66 Table 3.2.1, Summary of Aging Management Programs for Engineered Safety Features Evaluated in Chapter V of NUREG-1 801 Table 3.2.1: Engineered Safety Features, NUREG-1801 Vol. 1 Further Item Aging Effect/ Aging Management Evaluation Number Component Mechanism Programs Recommended Discussion 3.2.1-49 Stainless steel Loss of material Water Chemistry No Consistent with NUREG-1 801. The piping, piping due to pitting and Water Chemistry Control - Primary components, piping crevice corrosion and Secondary Program manages elements, and tanks loss of material of stainless steel exposed to treated components exposed to treated borated water borated water. Loss of material for the refueling water storage tanks is also managed by the Abovecqround Steel Tanks Program.

In Notes for Tables 3.2.2-1-1P2 through 3.2.2-5-1P3 at the end of LRA Table 3.2.1, add the following Plant-Specific Note 209.

209. Proqram provisions apply for outdoor insulated components.

NL-14-147 Attachment 2 Page 3 of 66 Table 3.2.2-2-1P2: Containment Spray System, Summary of Aging Management Review Table 3.2.2-2-1P2: Containment Spray System Aging Effect Aging NUREG-Component Intended Requiring Management 1801 Vol. 2 Table 1 Type Function Material Environment Management Programs Item Item Notes Insulated piping Pressure Stainless Air - outdoor Loss of material External Surfaces - - H209 components boundary steel (ext) Monitoring Insulated piping Pressure Stainless Air - outdoor Cracking External Surfaces - - H, 209 components boundary steel (ext) Monitoring Table 3.2.2-2-1P3: Containment Spray System, Summary of Aging Management Review Table 3.2.2-2-1P3: Containment Spray System Aging Effect Aging NUREG-Component Intended Requiring Management 1801 Vol. 2 Table 1 Type Function Material Environment Management Programs Item Item Notes Insulated piping Pressure Stainless Air - outdoor Loss of material External Surfaces - - H. 209 components boundary steel (ext) Monitoring.

Insulated piping Pressure Stainless Air - outdoor Cracking External Surfaces - H 209 components boundary steel (ext) Monitoring

NL-14-147 Attachment 2 Page 4 of 66 Table 3.2.2-4-1P2: Safety Injection Systems, Summary of Aging Management Review Table 3.2.2-4-1P2: Safety Injection Systems Aging Effect Aging NUREG-Component Intended Requiring Management 1801 Vol. 2 Table I Type Function Material Environment Management Programs Item Item Notes Insulated Pressure Stainless Air - outdoor (ext) Loss of material External Surfaces - - H 209 2ng boundary steel Monitoring components Insulated Pressure Stainless Air - outdoor (ext) Cracking External Surfaces -H 209 im boundary steel Monitorinq components Tank Pressure Stainless Air - outdoor Loss of material Extcrnal Surfaces G boundary steel (ext) Men,,itom,.,

Aboveground Steel Tanks Tank Pressure Stainless Concrete (ext) NeRe-Loss of Noe Aboveqround -V. F 14 -32.1 66 A-H boundary steel Material Steel Tanks (EP 20)

Tank Pressure Stainless Treated borated Loss of material AboveQround Steel V.D1-30 3.2.1-49 E boundary steel water (int) Tanks (EP-41)

NL-14-147 Attachment 2 Page 5 of 66 Table 3.2.2-4-1P3: Safety Injection Systems, Summary of Aging Management Review Table 3.2.2-4-1P3: Safety Injection Systems Aging Effect Aging NUREG-Component Intended Requiring Management 1801 Vol. 2 Table I Type Function Material Environment Management Programs Item Item Notes Insulated Pressure Stainless Air - outdoor Loss of material External Surfaces - -209 2i~jm boundary steel (ext) Monitoring components Insulated Pressure Stainless Air - outdoor Crackinq External Surfaces - H 209 i2Th* boundary steel ( Monitoring components Tank Pressure Stainless Air - outdoor Loss of material Abovegqround Steel G boundary steel (ext) Tanks Q-f(tepaI Sufaces Monitoring Tank Pressure Stainless Concrete (ext) Loss of Material Above-round Steel -V-F14 -3.2.1 56 HA boundary steel None Tanks Nonee Tank Pressure Stainless Treated borated Loss of material Above-ground Steel V.D1-30 3.2.1-49 E boundary steel water (int) Tanks (EP-41)

NL-14-147 Attachment 2 Page 6 of 66 3.3.2.1.7 Primary Makeup Water Aging Management Programs The following aging management programs manage the aging effects for primary makeup water system components.

  • Abovecqround Steel Tanks 0 Bolting Integrity 0 External Surfaces Monitoring
  • Water Chemistry Control - Primary and Secondary

NL-14-147 Attachment 2 Page 7 of 66 Table 3.3.1, Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of NUREG-1801 Table 3.3.1: Auxiliary Systems, NUREG-1801 Vol. 1 Further Item Aging Effect/ Aging Management Evaluation Number Component Mechanism Programs Recommended Discussion 3.3.1-58 Steel external Loss of material due External Surfaces No Consistent with NUREG-1 801 for most surfaces exposed to to general corrosion Monitoring steel components. The External Surfaces air - indoor Monitoring Program manages loss of uncontrolled material for external surfaces. For some (external), air - steel components of the fire protection -

outdoor (external), C02, halon, and RCP oil collection and condensation systems, the Fire Protection Program (external) manages loss of material using periodic visual inspections. For fire protection system tanks, the Fire Water System Proqram managqes loss of material using periodic visual and NDE inspections. The Periodic Surveillance and Preventive Maintenance Program periodically inspects external steel surfaces of components inside the fan cooler units of the containment cooling and filtration system to manage loss of material.

In Notes for Tables 3.3.2-1-1P2 through 3.3.2-19-62-1P3 at the end of LRA Table 3.3.1, add the following Plant-Specific Note 320.

320. Proaram provisions applV for indoor insulated components that operate below the dew point and outdoor insulated components.

NL-14-147 Attachment 2 Page 8 of 66 Table 3.3.2-2-1P2: Service Water System, Summary of Aging Management Review Table 3.3.2-2-1P2: Service Water System Aging Effect Aging NUREG-Component Intended Requiring Management 1801 Vol. 2 Table I Type Function Material Environment Management Programs Item Item Notes Insulated Pressure Carbon steel Condensation Loss of material External Surfaces - - H 320 piping boundary (ext) Monitoring components Insulated Pressure Copper alloy Condensation Loss of material External Surfaces - H, 320 1ing boundary ( Monitoring components Insulated Pressure Copper alloy Condensation Cracking External Surfaces - -H, 320 2!12ng boundary (ext) Monitoring cormponents Insulated Pressure Stainless Condensation Loss of material External Surfaces -, 320 QL12lf boundary steel (ext) Monitorinq components Insulated Pressure Stainless Condensation Cracking External Surfaces - - _320 2i~iAn boundary steel (extl Monitoring components Piing Pressure Carbon steel Raw water (int) Recurring internal Service Water - - H components boundary corrosion Integrity Ping Pressure Copper alloy Raw water (int) Recurring internal Service Water - - H components boundary corrosion Integrity Pipin Pressure Stainless Raw water (int) Recurring internal Service Water - - H components boundary steel corrosion Integrity

NL-14-147 Attachment 2 Page 9 of 66 Table 3.3.2-2-1P3: Service Water System, Summary of Aging Management Review Table 3.3.2-2-1P3: Service Water System Aging Effect Aging NUREG-Component Intended Requiring Management 1801 Vol. 2 Table 1 Type Function Material Environment Management Programs Item Item Notes Insulated Pressure Carbon Condensation Loss of material External Surfaces - H 320 boundary steel (ext) Monitorinig com ponents Insulated Pressure Copper Condensation Loss of material External Surfaces - H 320 boundary alloy (ext) Monitorinq components Insulated Pressure Copper Condensation Crackingq External Surfaces - - H 320 boundary alloy (ext) Monitoring components Insulated Pressure Stainless Condensation Loss of material External Surfaces - H 320 boundary steel (ext) Monitorinq components Insulated Pressure Stainless Condensation Cracking External Surfaces - - H 320 2ing boundary steel (ext) Monitorinq components Piin Pressure Carbon Raw water (int) Recurring internal Service Water - - H components boundary steel corrosion Integrit Pinin Pressure Copper Raw water (int) Recurring internal Service Water - - H components boundary alloy corrosion Integrity Pnin Pressure Stainless Raw water (int) Recurring internal Service Water - - H components boundary steel corrosion Integrity

NL-14-147 Attachment 2 Page 10 of 66 Table 3.3.2-7-1P2: Primary Water Makeup System, Summary of Aging Management Review Table 3.3.2-7-1P2: Primary Water Makeup System Aging Effect Aging NUREG-Component Intended Requiring Management 1801 Vol. 2 Table I Type Function Material Environment Management Programs Item Item Notes Insulated Pressure Stainless Air - outdoor Loss of material External Surfaces - -320 boundary steel (ext) Monitoring components Insulated Pressure Stainless Air - outdoor Crackinq External Surfaces -H. 320 pjljim boundary steel (ext) Monitoring components Insulated tank Pressure Stainless Air - outdoor Loss of material Aboveground Steel - H 320 boundary steel (ext) Tanks Insulated tank Pressure Stainless Air - outdoor Crackinq Abovecqround Steel - H 320 boundary steel (ext) Tanks Tai* P-essUie Stainlese Ai. cutdoee Loss of matcrial Ext-enal Surfaes -

be..daQ. steel (-e-) Ri-nR-"

Tank Pressure Stainless Concrete (ext) Loss of material Aboveground Steel -V-I--j 7 -3.3.1 96 HA boundary steel Nene Tanks-Nene (AP-49)

Tank Pressure Stainless Treated water Loss of material Aboveground Steel VIII.E-40 3.4.1-6 E boundary steel (int) Tanks (S-13)

NL-14-147 Attachment 2 Page 11 of 66 Table 3.3.2-7-1P3: Primary Water Makeup System, Summary of Aging Management Review Table 3.3.2-7-1P3: Primary Water Makeup System Aging Effect Aging NUREG-Component Intended Requiring Management 1801 Vol. 2 Table I Type Function Material Environment Management Programs Item Item Notes Insulated Pressure Stainless Air - outdoor Loss of material External Surfaces - - H 320 boundary steel (ext) Monitoring components Insulated Pressure Stainless Air - outdoor Crackinq External Surfaces - K 320 nipng boundary steel (ext) Monitorinq components Insulated tank Pressure Stainless Air - outdoor Loss of material Aboveground Steel - -H 320 boundary steel (ext) Tanks Insulated tank Pressure Stainless Air - outdoor Cracking Aboveqround Steel - K 320 boundary steel (ext) Tanks Ia* Pressure Stainless AF o-utdOOF Loss of material External SuFfaces -- G

___be nda y steel (ext) MeG-tc-""g Tank Pressure Stainless Concrete (ext) Loss of material Aboveqround Steel -vih-- -3.3.1-96 HA boundary steel Nene Tanks Nene (AP-1-9)

Tank Pressure Stainless Treated water Loss of material Above-ground Steel VIII.E-40 3.4.1-6 E boundary steel tint) Tanks tS-13)

Table 3.3.2-8-1P2: Heating, Ventilation and Cooling, Summary of Aging Management Review Table 3.3.2-8-1P2: Heating, Ventilation and Cooling Aging Effect Aging NUREG-Component Intended Requiring Management 1801 Vol. 2 Table I Type Function Material Environment Management Programs Item Item Notes Insulated Pressure Carbon Condensation Loss of material External Surfaces - H 320 piping boundary steel (ext) Monitoring components

NL-14-147 Attachment 2 Page 12 of 66 Table 3.3.2-8-1P3: Heating, Ventilation and Cooling, Summary of Aging Management Review Table 3.3.2-8-1P3: Heating, Ventilation and Cooling Aging Effect Aging NUREG-Component Intended Requiring Management 1801 Vol. 2 Table I Type Function Material Environment Management Programs Item Item Notes Insulated Pressure Carbon Condensation Loss of material External Surfaces - H 320 ping boundary steel (ext) Monitoring components Table 3.3.2-9-1P3: Containment Cooling and Filtration, Summary of Aging Management Review Table 3.3.2-9-1P3: Containment Cooling and Filtration Aging Effect Aging NUREG-Component Intended Requiring Management 1801 Vol. 2 Table I Type Function Material Environment Management Programs Item Item Notes Insulated Pressure Copper Condensation Loss of material External Surfaces - - H 320 2ing boundary alloy (ext) Monitoring components Insulated Pressure Copper Condensation Crackinq External Surfaces -H 320 2i~ing boundary alloy (ext) Monitoring components

NL-14-147 Attachment 2 Page 13 of 66 Table 3.3.2-10-1P2: Control Room Heating, Ventilation and Cooling, Summary of Aging Management Review Table 3.3.2-10-1P2: Control Room Heating, Ventilation and Cooling Aging Effect Aging NUREG-Component Intended Requiring Management 1801 Vol. 2 Table 1 Type Function Material Environment Management Programs Item Item Notes Insulated Pressure Copper Condensation Loss of material External Surfaces - - H320 2_"in boundary alloy (ext) Monitoring components Insulated Pressure Copper Condensation Cracking External Surfaces -, 320 20-im boundary alloy (ext) Monitorinq components Table 3.3.2-10-1P3: Control Room Heating, Ventilation and Cooling, Summary of Aging Management Review Table 3.3.2-10-1P3: Control Room Heating, Ventilation and Cooling Aging Effect Aging NUREG-Component Intended Requiring Management 1801 Vol. 2 Table I Type Function Material Environment Management Programs Item Item Notes Insulated Pressure CoDoer Condensation Loss of material External Surfaces - -H, 320 boundary alloy (ext) Monitoring components Insulated Pressure Copper Condensation Cracking External Surfaces H 320 2im boundary alloy (ext) Monitoring components

NL-14-147 Attachment 2 Page 14 of 66 Table 3.3.2-11-1P2: Fire Protection - Water, Summary of Aging Management Review Table 3.3.2-11-11P2: Fire Protection - Water Aging Effect Aging NUREG-Component Intended Requiring Management 1801 Vol. 2 Table I Type Function Material Environment Management Programs Item Item Notes Insulated Pressure Carbon Condensation Loss of material External Surfaces - - H 320 2i~jm boundary steel (ext) Monitorinq components Insulated Pressure Gray cast Condensation Loss of material External Surfaces - H 320 2ipin boundary iron (ext) Monitoring components Insulated Pressure Carbon Air - outdoor Loss of material External Surfaces - H 320 pipg boundary steel (ext) Monitoring components Tank Pressure Carbon Air- indoor (ext) Loss of material External Surfaces VII.I-8 3.3.1-58 A-E boundary steel Menit

-"'g-,Fire (A-77)

Water System Tank Pressure Carbon Air - outdoor Loss of material Ab^.egr.und Steel V1,,-,,t1 3.3-140 GE boundary steel (ext) Tanks-Fire Water (A-94) 3.3.1-58 System VII.I-9 Tank Pressure Carbon Concrete (ext) Loss of material AbovegrOUnd Steel, -. G boundary steel Tanks-Fire Water System

NL-14-147 Attachment 2 Page 15 of 66 Table 3.3.2-11-1P3: Fire Protection - Water, Summary of Aging Management Review Table 3.3.2-11-1P3: Fire Protection - Water Aging Effect Aging NUREG-Component Intended Requiring Management 1801 Vol. 2 Table 1 Type Function Material Environment Management Programs Item Item Notes Insulated Pressure Carbon Condensation Loss of material External Surfaces - - H 320 pi"in boundary steel (ext) Monitoring components Insulated Pressure Gray cast Condensation Loss of material External Surfaces - H, 320 21122 boundary iron (ext) Monitoring components Tank Pressure Carbon Air- indoor (ext) Loss of material External Surfaces VII.1-8 3.3.1-58 A-E boundary steel M..,R",Wi.Fire (A-77)

Water System Tank Pressure Carbon Air - outdoor Loss of material Aboveground Steel V-IkH-1,

,1 3,*3. 40 GE boundary steel (ext) Tanks-Fire Water WW 3.3.1-58 System VII.I-9 (A-78)

Tank Pressure Carbon Concrete (ext) Loss of material Aboveground Steel G boundary steel Fapks-Fire Water System Table 3.3.2-14-1P2: Emergency Diesel Generators, Summary of Aging Management Review Table 3.3.2-14-1P2: Emergency Diesel Generators Aging Effect Aging NUREG-Component Intended Requiring Management 1801 Vol. 2 Table I Type Function Material Environment Management Programs Item Item Notes Insulated Pressure Carbon Air - outdoor Loss of material External Surfaces -H 320 2ipim boundary steel (ext) Monitoring comrponents

NL-14-147 Attachment 2 Page 16 of 66 Table 3.3.2-14-1P3: Emergency Diesel Generators, Summary of Aging Management Review Table 3.3.2-14-1P3: Emergency Diesel Generators Aging Effect Aging NUREG-Component Intended Requiring Management 1801 Vol. 2 Table 1 Type Function Material Environment Management Programs Item Item Notes Insulated Pressure Carbon Air - outdoor Loss of material External Surfaces - H 320 2ifl boundary steel (ext) Monitorino components Table 3.3.2-17-1P2: City Water, Summary of Aging Management Review Table 3.3.2-17-1P2: City Water Aging Effect Aging NUREG-Component Intended Requiring Management 1801 Vol. 2 Table 1 Type Function Material Environment Management Programs Item Item Notes Insulated Pressure Carbon Condensation Loss of material External Surfaces - - H 320 boundary steel (ext) Monitoring components Insulated Pressure Gray cast Condensation Loss of material External Surfaces - H 320 oifin boundary iron (ext) Monitoringq components Insulated Pressure Carbon Air - outdoor Loss of material External Surfaces - - H 320 Piping boundary steel text) Monitoring components Insulated Pressure Gray cast Air - outdoor Loss of material External Surfaces -H 320 boundary iron text) Monitoring components

NL-14-147 Attachment 2 Page 17 of 66 Tank Pressure Carbon Treated water Loss of material Abovegqround G, 305 boundary steel (int) Steel Tanks Pe-iediG Surveillanco and PFeventive MaentenanGe Table 3.3.2-17-1P3: City Water, Summary of Aging Management Review Table 3.3.2-17-1P3: City Water Aging Effect Aging NUREG-Component Intended Requiring Management 1801 Vol. 2 Table 1 Type Function Material Environment Management Programs Item Item Notes Insulated Pressure Carbon Condensation Loss of material External Surfaces - - H, 320 in boundary steel (ext) Monitoring components Insulated Pressure Gray cast Condensation Loss of material External Surfaces -H 320 boundary iron (ext) Monitoring components Insulated Pressure Carbon Air - outdoor Loss of material External Surfaces - -320 i!l2ing boundary steel (ext) Monitoring components Insulated Pressure Gray cast Air - outdoor Loss of material External Surfaces -H 320 i2Q!n boundary iron (ext) Monitorinq components Insulated Pressure CoDper Air - outdoor Loss of material External Surfaces - -320 in boundary alloy (ext) Monitoring components Insulated Pressure Copper Air - outdoor Cracking External Surfaces -H 320 22i boundary alloy (ext) Monitorinq components

NL-14-147 Attachment 2 Page 18 of 66 Table 3.3.2-19-1-1P2: Auxiliary Steam System, Nonsafety-Related -Components Potentially Affecting Safety Functions, Summary of Aginq Management Review Table 3.3.2-19-1-1P2: Auxiliary Steam System Aging Effect Aging NUREG-Component Intended Requiring Management 1801 Vol. 2 Table I Type Function Material Environment Management Programs Item Item Notes Insulated Pressure Carbon Condensation Loss of material External Surfaces - - H 320 pil boundary steel (ext) Monitoring components Insulated Pressure Stainless Condensation Loss of material External Surfaces H, 320 boundary steel (ext) Monitoring com ponents Insulated Pressure Stainless Condensation Cracking External Surfaces - - H, 320 boundary steel (ext) Monitoring components Table 3.3.2-19-2-1P2: Conventional Closed Cooling System, Nonsafety-Related Components Potentially Affecting Safety Functions, Summary of Aging Management Review Table 3.3.2-19-2-1P2: Conventional Closed Cooling System Aging Effect Aging NUREG-Component Intended Requiring Management 1801 Vol. 2 Table I Type Function Material Environment Management Programs Item Item Notes Insulated Pressure Carbon Condensation Loss of material External Surfaces - -320 2112n§ boundary steel (ext) Monitoring components Insulated Pressure Stainless Condensation Loss of material External Surfaces - -320 l boundary steel (ext) Monitoring components Insulated Pressure Stainless Condensation Cracking External Surfaces - H 320 boundary steel (ext) Monitoring com ponents

NL-14-147 Attachment 2 Page 19 of 66 Table 3.3.2-19-7-1P2: City Water System, Nonsafety-Related Components Potentially Affecting Safety Functions, Summary of Aging Management Review Table 3.3.2-19-7-1P2: City Water System Aging Effect Aging NUREG-Component Intended Requiring Management 1801 Vol. 2 Table 1 Type Function Material Environment Management Programs Item Item Notes Insulated Pressure Carbon Condensation Loss of material External Surfaces - - H, 320 boundary steel (ext) Monitoring corn ponents Insulated Pressure CoDper Condensation Loss of material External Surfaces - H 320 pipin boundary alloy (ext) Monitoring components Insulated Pressure CoDper Condensation Cracking External Surfaces - - H 320 2igim boundary alloy (ext) Monitoring components Table 3.3.2-19-11-1P2: Fire Protection System, Nonsafety-Related Components Potentially Affecting Safety Functions, Summary of Aging Management Review Table 3.3.2-19-11-1P2: Fire Protection System Aging Effect Aging NUREG-Component Intended Requiring Management 1801 Vol. 2 Table I Type Function Material Environment Management Programs Item Item Notes Insulated Pressure Carbon Condensation Loss of material External Surfaces - -320 pin boundary steel (ext) Monitoring components Insulated Pressure Stainless Condensation Loss of material External Surfaces - H 320 boundary steel (ext) Monitoring components

NL-1 4-147 Attachment 2 Page 20 of 66 Insulated Pressure Stainless Condensation Crackinq External Surfaces - - H 320 compoet boundary steel (ext) Monitoring cornponents Table 3.3.2-19-13-1P2: Fresh Water Cooling System, Nonsafety-Related Components Potentially Affecting Safety Functions, Summary of Aging Management Review Table 3.3.2-19-13-1P2: Fresh Water Cooling System Aging Effect Aging NUREG-Component Intended Requiring Management 1801 Vol. 2 Table I Type Function Material Environment Management Programs Item Item Notes Insulated Pressure Carbon Condensation Loss of material External Surfaces - - H 320 liping boundary steel (ext) Monitoring components Insulated Pressure Stainless Condensation Loss of material External Surfaces -H. 320 PjpM boundary steel (ext) Monitoring components Insulated Pressure Stainless Condensation Cracking External Surfaces - - 320 2WAM boundary steel (ext) Monitoring components Table 3.3.2-19-16-1P2: House Service Boiler System, Nonsafety-Related Components Potentially Affecting Safety Functions, Summary of Aging Management Review Table 3.3.2-19-16-1P2: House Service Boiler System Aging Effect Aging NUREG-Component Intended Requiring Management 1801 Vol. 2 Table I Type Function Material Environment Management Programs Item Item Notes Insulated Pressure Carbon Condensation Loss of material External Surfaces - H 320 2!12.ig boundary steel (ext) Monitoring components

NL-14-147 Attachment 2 Page 21 of 66 Table 3.3.2-19-17-1P2: Heating, Ventilation and Air Conditioning System, Nonsafety-Related Components Potentially Affecting Safety Functions, Summary of Aging Management Review Table 3.3.2-19-17-1P2: Heating, Ventilation and Air Conditioning System Aging Effect Aging NUREG-Component Intended Requiring Management 1801 Vol. 2 Table I Type Function Material Environment Management Programs Item Item Notes Insulated Pressure Carbon Condensation Loss of material External Surfaces - H, 320 2fg boundary steel (ext) Monitoring components Table 3.3.2-19-39-1P2: Service Water System, Nonsafety-Related Components Potentially Affecting Safety Functions, Summary of Aging Management Review Table 3.3.2-19-39-1P2: Service Water System Aging Effect Aging NUREG-Component Intended Requiring Management 1801 Vol. 2 Table 1 Type Function Material Environment Management Programs Item Item Notes Insulated Pressure Carbon Condensation Loss of material External Surfaces H,320 K-boundary steel (ext) Monitoring components Insulated Pressure Stainless Condensation Loss of material External Surfaces - H 320 2209 boundary steel (ext) Monitoringq components Insulated Pressure Stainless Condensation Cracking External Surfaces - H 320 RinD2 boundary steel (exft Monitoring components Pipin Pressure Carbon Raw water int) Recurring internal Service Water - - H components boundary steel corrosion Integrity Pii Pressure Conper Raw water (int) Recurring internal Service Water - - H corponents boundary alloy corrosion Integrity

NL-14-147 Attachment 2 Page 22 of 66 Piping Pressure Stainless Raw water (int) Recurring internal Service Water - - H components boundary steel corrosion Integrity Table 3.3.2-19-43-1P2: Water Treatment Plant System, Nonsafety-Related Components Potentially Affecting Safety Functions, Summary of Aging Management Review Table 3.3.2-19-43-1P2: Water Treatment Plant System Aging Effect Aging NUREG-Component Intended Requiring Management 1801 Vol. 2 Table I Type Function Material Environment Management Programs Item Item Notes Insulated Pressure Carbon Air - outdoor Loss of material External Surfaces - 320 3-boundary steel (ext) Monitoring components Insulated tank Pressure Carbon Air - outdoor Loss of material Aboveground Steel _- H, 320 boundary steel Lext) Tanks Table 3.3.2-19-13-lP3: City Water Makeup System, Nonsafety-Related Components Potentially Affecting Safety Functions, Summary of Aging Management Review Table 3.3.2-19-13-1P3: City Water Makeup System Aging Effect Aging NUREG-Component Intended Requiring Management 1801 Vol. 2 Table 1 Type Function Material Environment Management Programs Item Item Notes Insulated Pressure Carbon Condensation Loss of material External Surfaces - -320 2im boundary steel (ext) Monitorinq components Insulated Pressure Copper Condensation Loss of material External Surfaces - - H 320 boundary alloy (ext) Monitoring components Insulated Pressure Copper Condensation Cracking External Surfaces - H 320 itjijg boundary alloy (ext) Monitoring components

NL-14-147 Attachment 2 Page 23 of 66 Insulated Pressure Gray cast Condensation Loss of material External Surfaces - - H 320 2ipjig boundary iron (ext Monitoring components Table 3.3.2-19-20-1P3: Fire Water System, Nonsafety-Related Components Potentially Affecting Safety Functions, Summary of Aging Management Review Table 3.3.2-19-20-1P3: Fire Water System Aging Effect Aging NUREG-Component Intended Requiring Management 1801 Vol. 2 Table 1 Type Function Material Environment Management Programs Item Item Notes Insulated Pressure Carbon Condensation Loss of material External Surfaces -H, 320 2!12ng boundary steel (ext) Monitorinq comronents Insulated Pressure Gray cast Condensation Loss of material External Surfaces - - L320 kilQ boundary iron (ext) Monitoring corn ponents Table 3.3.2-19-56-1P3: Service Water System, Nonsafety-Related Components Potentially Affecting Safety Functions, Summary of Aging Management Review Table 3.3.2-19-56-1P3: Service Water System Aging Effect Aging NUREG-Component Intended Requiring Management 1801 Vol. 2 Table I Type Function Material Environment Management Programs Item Item Notes Insulated pipincq Pressure Carbon Condensation Loss of material External Surfaces - - H 320 components boundary steel (ext) Monitoring Insulated piping Pressure Stainless Condensation Loss of material External Surfaces - - H 320 components boundary steel (ext) Monitoring Insulated ippincq Pressure Stainless Condensation Cracking External Surfaces - H 320 components boundary steel (ext) Monitori ng

NL-14-147 Attachment 2 Page 24 of 66 Piping Pressure Carbon Raw water (int) Recurring internal Service Water - - H components boundary steel corrosion Intearity Piping Pressure Copper Raw water (int) Recurring internal Service Water - - H components boundary alloy corrosion Integrity Pping Pressure Stainless Raw water (int) Recurring internal Service Water - - H components boundary steel corrosion Intergrity Table 3.3.2-19-58-1P3: Turbine Hall Closed Cooling System, Nonsafety-Related Components Potentially Affecting Safety Functions, Summary of Aging Management Review Table 3.3.2-19-58-1P3: Turbine Hall Closed Cooling System Aging Effect Aging NUREG-Component Intended Requiring Management 1801 Vol. 2 Table I Type Function Material Environment Management Programs Item Item Notes Insulated piping Pressure Carbon Condensation Loss of material External Surfaces - -H, 320 components boundary steel (ext) Monitoring Insulated piping Pressure Stainless Condensation Loss of material External Surfaces - H 320 components boundary steel (ext) Monitoring Insulated piping Pressure Stainless Condensation Cracking External Surfaces - H 320 components boundary steel (ext) Monitoring Insulated piping Pressure Copper Condensation Loss of material External Surfaces - H 320 components boundary alloy (ext) Monitoring Insulated piping Pressure Copper Condensation Cracking External Surfaces - H, 320 components boundary alloy (ext) Monitoring

NL-14-147 Attachment 2 Page 25 of 66 Table 3.4.1: Summary of Aging Management Programs for the Steam and Power Conversion System Evaluated in Chapter VIII of NUREG-1801 Table 3.4.1: Steam and Power Conversion Systems, NUREG-1801 Vol. 1 Further Item Aging Effect/ Aging Management Evaluation Number Component Mechanism Programs Recommended Discussion 3.4.1-6 Steel and stainless Loss of material due Water Chemistry and Yes, detection of Consistent with NUREG-1801. Loss steel tanks exposed to general (steel One-Time Inspection aging effects is to of material in steel and stainless steel to treated water only) pitting and be evaluated tanks exposed to treated water is crevice corrosion managed by the Water Chemistry Control - Primary and Secondary Program. The One-Time Inspection Program will be used to verify the effectiveness of the water chemistry program. Loss of material for the primary makeup water tanks (Tables 3.3.2-7-1P2 and IP3) and condensate storagqe tanks is also managqed by the Aboveground Steel Tanks Program.

See Section 3.4.2.2.2 item 1 and Section 3.4.2.2.7 item 1.

3.4.1-30 Steel piping, piping Loss of material Inspection of Internal No The-en"y Steel components with components, and due to general, Surfaces in intended functions in the steam and piping elements pitting, and crevice Miscellaneous Piping power conversion systems with exposed to air corrosion and Ducting internal surfaces exposed to outdoor outdoor (internal) or Components air or condensation are the condensation condensate storage tanks, main (internal) steam safety valve (MSSV) tailpipes, and the atmospheric dump valve (ADV) silencers. The condensate storage tank vapor space is nitrogen blanketed but the environment is conservatively assumed to be

NL-14-147 Attachment 2 Page 26 of 66 Table 3.4.1: Steam and Power Conversion Systems, NUREG-1801 Vol. 1 Further Item Aging Effect/ Aging Management Evaluation Number Component Mechanism Programs Recommended Discussion condensation. Loss of material for these tank surfaces is managed by ccntrolling the tank water chcmist,;

with the Water Chemicstr; Control Primnary and Secondary Programn. The One Timc Inspectien Programn will be used to verify the effectivenes6 of the water chemistry prFgram. the Above-ground Steel Tanks Program.

Loss of material for the MSSV tailpipes and the ADV silencers will be managed by the Periodic Surveillance and Preventive Maintenance Program.

In Notes for Tables 3.4.2-1-1P2 through 3.4.2-4-1P3, at the end of LRA Table 3.4.1, add the following Plant-Specific Note 408.

408. Program provisions apply for indoor insulated components that operate below the dew point and outdoor insulated components.

NL-14-147 Attachment 2 Page 27 of 66 Table 3.4.2-3-1P2, Auxiliary Feedwater System, Summary of Aging Management Review Table 3.4.2-3-1P2: Auxiliary Feedwater System Aging Effect Aging NUREG-Component Intended Requiring Management 1801 Vol. 2 Table 1 Type Function Material Environment Management Programs Item Item Notes Insulated piping Pressure Carbon Condensation Loss of material External Surfaces - H, 408 components boundary steel (ext) Monitoring Insulated Piping Pressure Stainless Condensation Loss of material External Surfaces - - H 408 components boundary steel Lext) Monitorinq Insulated Piping Pressure Stainless Condensation Cracking External Surfaces - H 408 components boundary steel (ext) Monitoring Tank Pressure Carbon Condensation Loss of material Aboveground Steel VIII.G-34 3.4.1-30 E, 402 boundary steel (int) Tanks Water (SP-60)

Chcmicty Contro~l SeGcndary Tank Pressure Carbon Treated water Loss of material Aboveground Steel VIII.G-41 3.4.1-6 E boundary steel tint) Tanks (S-1 Table 3.4.2-3-1P3, Auxiliary Feedwater System, Summary of Aging Management Review Table 3.4.2-3-1P3: Auxiliary Feedwater System Aging Effect Aging NUREG-Component Intended Requiring Management 1801 Vol. 2 Table I Type Function Material Environment Management Programs Item Item Notes Insulated piping Pressure Carbon Condensation Loss of material External Surfaces - -H 408 components boundary steel Lext) Monitoring Insulated piping Pressure Stainless Condensation Loss of material External Surfaces - H 408 components boundary steel (ext) Monitoring

NL-14-147 Attachment 2 Page 28 of 66 Insulated piping Pressure Stainless Condensation Cracking External Surfaces - H 408 components boundary steel (ext) Monitoring Tank Pressure Carbon Condensation Loss of material Aboveground Steel VIII.G-34 3.4.1-30 E, 402 boundary steel (int) Tanks VVateF (SP-60)

Ghcmistry COntro P~imna.ryand Seeendary Tank Pressure Carbon Treated water Loss of material Aboveground Steel VIII.G-41 3.4.1-6 E boundary steel (intU Tanks (S-13)

Table 3.4.2-5-4-1P2, City Water System, Components Required to Support AFW Pump Room Fire Event, Summary of Aging Management Review Table 3.4.2-5-4-1P2: City Water System (CYW)

Aging Effect Aging NUREG-Component Intended Requiring Management 1801 Vol. 2 Table 1 Type Function Material Environment Management Programs Item Item Notes Insulated piping Pressure Carbon Condensation Loss of material External Surfaces - - H408 components boundary steel (ext) Monitoring Insulated piping Pressure Stainless Condensation Loss of material External Surfaces - 1--1408 components boundary steel Oextl Monitorinq Insulated piping Pressure Stainless Condensation Cracking External Surfaces - H, 408 components boundary steel (ext) Monitoring Insulated piping Pressure Carbon Air - outdoor Loss of material External Surfaces - - +/-408 components boundary steel (ext) Monitoring Insulated piping Pressure Stainless Air - outdoor Loss of material External Surfaces - - H 408 components boundary steel (ext) Monitoring Insulated piping Pressure Stainless Air- outdoor Cracking External Surfaces -H 408 components boundary steel (ext) Monitoring

NL-14-147 Attachment 2 Page 29 of 66 Table 3.4.2-5-5-1P2, Wash Water System, Components Required to Support AFW Pump Room Fire Event, Summary of Aging Management Review Table 3.4.2-5-5-1P2: Wash Water System (WW) Components Aging Effect Aging NUREG-Component Intended Requiring Management 1801 Vol. 2 Table 1 Type Function Material Environment Management Programs Item Item Notes Insulated piping Pressure Carbon Air - outdoor Loss of material External Surfaces - - _,408 components boundary steel (ext) Monitoring Insulated piping Pressure Gray cast Air - outdoor Loss of material External Surfaces - H, 408 components boundary iron (ext) Monitoring Insulated piping Pressure Stainless Air - outdoor Loss of material External Surfaces - -H 408 components boundary steel (ext) Monitoring Insulated pipinq Pressure Stainless Air - outdoor Cracking External Surfaces - - H, 408 components boundary steel (ext) Monitoring Table 3.4.2-5-9-1P2, Service Water System, Components Required to Support AFW Pump Room Fire Event, Summary of Aging Management Review Table 3.4.2-5-9-1P2: Service Water System (SW)

Aging Effect Aging NUREG-Component Intended Requiring Management 1801 Vol. 2 Table I Type Function Material Environment Management Programs Item Item Notes Insulated piping Pressure Carbon Condensation Loss of material External Surfaces - -H, 408 components boundary steel (ext) Monitoring Insulated piping Pressure Stainless Condensation Loss of material External Surfaces - -H, 408 components boundary steel (ext) Monitoring Insulated piping Pressure Stainless Condensation Cracking External Surfaces - H, 408 components boundary steel (extI Monitoring

NL-14-147 Attachment 2 Page 30 of 66 A.2.1.1 Aboveground Steel Tanks Program The Aboveground Steel Tanks Program is aRn existing pregram th3t manages loss of material on outdoor tanks situated on soil or concrete. The program includes preventive measures to mitigate corrosion by protecting the external surfaces of steel components per standard industry practice includina the use of sealant or caulkina at the concrete to tank interface of outdoor tanks. External visual examinations (supplemented with physical manipulation of caulking or sealant) are performed to monitor degradation of uncoated surfaces and of protective paint, coating, and sealants. Surface exams are conducted to detect cracking when susceptible materials are used (e.g., stainless steel. aluminum). A sample of the external surfaces of insulated tanks is inspected. Internal visual and surface (when necessary to detect cracking) examinations are conducted as well as measuring the thickness of the tank bottoms to ensure that sianificant dearadation is not occurrina and that the comoonent intended function is maintained during the period of extended operation., fro. extonal ,urfaces of abvegrund c--arbn-, Steol tanks b.... *idic ViSUal insRectimn of evtr...al surfaces and thickness li i P i I m.eau..remnt o IOctionRs thatt a.o inacce...... fr external vi.ual inspe.tio.

The Aboveground Steel Tanks Program will be enhanced to include the following tank inspection details'.

I B II I I i~eviso aooIIcan!o nrocociurns to norrorm tflICKflOSS measurements or me nonom P il 0

surfaces Of the condnt tank, city water tank, and fire wator tank, once.

duFrig the first 10 years of the period of extended operation.

0 ReVise applicable procedures to require trending of thickness measurements when mIIerial Io cc Is aemectep.

Material Environment AERM Inspection Technique 2 Inspection Frequency Inspections to identify degradation of inside surfaces of tank shell, roof3 , and bottom inside surface (IS). outside surface (OS) 4' Loss of Volumetric from OS6 or One time prior to December 31, Steel Treated water material visual from IS 2019' Stainless Treated water Loss of Volumetric from OS 6 or One time prior to December 31, Steel material visual from IS 2019' Inspections to identify degradation of external surfaces of tank roof, tank shell, and bottom not exposed to soil or concrete' Air-indoor Steel uncontrolled material Visual from OS Each refueling outage interval Air-outdoor

NL-14-147 Attachment 2 Page 31 of 66 Material Environment AERM Inspection Technique2 Inspection Frequency Loss of material Visual from OS Each refueling outage interval material Stainless Air-outdoor Steel Cracking Surface 9' 10 Each 10-year period of the period of extended operation Inspections to identify degradation of tank bottoms and tank shells exposed to soil or concrete Loss of Each 10-year period of the Soil or concrete material Volumetric from IS Erio o ofe extendedoperation"1 Steel material period of extended Stainless Soil or concrete Loss of Volumetric from IS Each 10-year period of the Steel material period of extended operation1 1 Tank Inspection Table Notes

1. IPEC LRA Section B.1.9, "Diesel Fuel Monitoring," manages loss of material on the internal surfaces of fuel oil storaqe tanks.
2. Alternative inspection methods may be used to inspect both surfaces (i.e., internal, external) or the opposite surface (e.g. inspectinq the internal surfaces for loss of material from the external surface, inspectingq for corrosion under external insulation from the internal surfaces of the tank) as long as the method has been demonstrated effective at detecting the AERM and a sufficient amount of the surface is inspected to ensure that localized aging effects are detected. For example, in some cases, subiect to being demonstrated effective, the low-freguency electromagnetic technique (LFET) can be used to scan an entire surface of a tank. An LFET inspection can effectively detect loss of material in the tank shell, roof, or bottom if follow-up ultrasonic examinations are conducted in any areas where the wall thickness is below nominal.
3. Nonwetted surfaces on the inside of a tank (e.g., roof, surfaces above the normal waterline) are inspected in the same manner as the wetted surfaces.
4. Visual inspections to identify degradation of the inside surfaces of tank shell, roof, and bottom should cover all the inside surfaces.
5. Materials, if any, accumulated on the tank bottom (e.g., sediment, silt) are removed to allow for complete internal inspections of the tank's surfaces.
6. At least 25 percent of the tank surface is inspected using a method capable of precisely determining wall thickness. The inspection method should be demonstrated capable of detecting both general and pitting corrosion.
7. At least one tank for each material and environment combination should be inspected.
8. For tanks with tightly adhering insulation without evidence of damage to the moisture barrier.

inspections may consist of examination of the exterior surface of the insulation for indications of damage to the iacketinq or protective outer layer of the insulation. For tanks with caulking or sealant at the concrete to tank interface, visual inspection of the caulking or sealant is performed in coniunction with physical manipulation of the caulking or sealant.

9. An inspection will be performed prior to December 31, 2019. Subsequent inspections are not required if an evaluation conducted prior to December 31, 2019 and at the scheduled time of each subsequent inspection during the PEO demonstrates the absence of chlorides or other deleterious compounds at sufficient levels to cause pitting corrosion, crevice corrosion, or cracking. The evaluation should include soil sampling in the vicinity of the tank (because soil results indicate atmospheric fallout accumulating in the soil and potentially affecting tank surfaces) and sampling of residue on the top and sides of the tank.

NL-14-147 Attachment 2 Page 32 of 66

10. A minimum of either 25 sections of the tank's surface (eq.., 1-square-foot sections for tank surfaces, 1-linear-foot sections of weld lengqth) or 20 percent of the tank's surface are examined. The sample inspection points are distributed in such a way that inspections occur in those areas most susceptible to deqradation (i.e., areas where contaminants could collect, inlet and outlet nozzles, welds).
11. The first inspection will be performed during the first 10 years of the period of extended operation.

Subsequent inspections are not required ifevaluations conducted at the time of the first inspection and at the scheduled time of each subsequent inspection during the PEO demonstrate that the soil under the tank is not corrosive usinq actual soil samples that are analyzed for each individual parameter (e.g., resistivity, pH, redox potential, sulfides, sulfates, moisture) and overall soil corrosivity. The evaluation should include soil sampling from underneath the tank.

Enhancements will be implemented prior to December 31, 2019to , of-Axtend period 9Pefee9R.

NL-14-147 Attachment 2 Page 33 of 66 A.2.1.10 External Surfaces Monitoring Program The External Surfaces Monitoring Program is an existing program that inspects external surfaces of components subject to aging management review. The program is also credited with managing loss of material from internal surfaces, for situations in which internal and external material and environment combinations are the same such that external surface condition is representative of internal surface condition.

Surfaces that are inaccessible during plant operations are inspected during refueling outages.

Surfacoc, that aro insulatod aro inSPected when the oxternal eurfaco is exposod (i.e., durin~g maeRtnce)G Periodic representative surface condition inspections of the in-scope mechanical indoor components under insulation (with process fluid temperature below the dew point) and outdoor components under insulation will be performed during each 10-year period of the period of extended operation. Surfaces are inspected at frequencies to assure the effects of aging are managed such that applicable components will perform their intended function during the period of extended operation.

The External Surfaces Monitoring Program will be enhanced to include the following.

  • Procedures will be revised to specify the following for insulated components.

o Periodic representative inspections for CUI will be conducted during each 10-year period of the PEO.

o For a representative sample of insulated indoor components exposed to condensation (because the component is operated below the dew point) and insulated outdoor components, insulation will be removed for visual inspection of component surfaces. Inspections will include a minimum of 20 percent of the in-scope piping length for each material type (e.g., steel, stainless steel, copper alloy, aluminum) or for components with a configuration which does not conform to a 1-foot axial length determination (e.g., valve, accumulator), 20 percent of the surface area.

Alternatively, insulation will be removed and a minimum of 25 inspections will be performed that can be a combination of 1-foot axial length sections and individual components for each material type.

o Inspection locations will be based on the likelihood of corrosion under insulation (CUI). For example, CUI is more likely for components that are alternately wet and dry in environments where trace contaminants could be present and for components that operate for long periods of time below the dew point.

Subsequent inspections will consist of an examination of the exterior surface of the insulation for indications of damage to the iacketing or protective outer layer of the insulation, if the following conditions are verified in the initial inspection:

NL-1 4-147 Attachment 2 Page 34 of 66

> No loss of material due to general, pitting or crevice corrosion, beyond that which could have been present during initial construction.

> No evidence of cracking If the external visual inspections of the insulation reveal damage to the exterior surface of the insulation or there is evidence of water intrusion through the insulation (e.g. water seepage through insulation seams/goints), periodic inspections under the insulation will continue.

Removal of tightly adhering insulation that is impermeable to moisture is not required unless there is evidence of damage to the moisture barrier. Tightly adhering insulation that is impermeable to moisture will be removed to allow for inspection if there is evidence of damage to the moisture barrier. If the moisture barrier is intact, the likelihood of CUI is low for tightly adhering insulation. Components with tightly adhering insulation constitute a separate population from the remainder of in-scope insulated components. The entire population of in-scope accessible component surfaces covered with tightly adhering insulation will be visually inspected for damage to the moisture barrier at the same frequency as inspections of components with other types of insulation. These inspections will not be credited towards the inspection quantities for components with other types of insulation.

Enhancements will be implemented prior to December 31, 2019 th,. p....d of,xtndo epeFat .

NL-14-147 Attachment 2 Page 35 of 66 A.2.1.13 Fire Water System Program The Fire Water System Program is an existing program that manages water-based fire protection systems that consist of sprinklers, nozzles, fittings, valves, hydrants, hose stations, fire pump casings, water storage tanks, standpipes, piping, and components that are tested in accordance with applicable National Fire Protection Association (NFPA) codes and standards.

Such testing assures functionality of systems. To determine if- .,1ifiýa,, abnormal corrosion has occurred in water-based fire protection systems, periodic flushing, system performance testing, and inspections are conducted. In addition to NFPA codes, portions of the water-based fire protection system (a) that are normally dry but periodically subiect to flow (e.g., dry-pipe or preaction sprinkler system piping and valves) and (b) that cannot be drained or allow water to collect are subiect to augmented testing and inspections. Also, many of these systems are normally maintained at required operating pressure and monitored such that leakage resulting in loss of system pressure is immediately detected and corrective actions initiated.

In addition, visual inspection results that identify excessive accumulation of corrosion products and appreciable localized corrosion (e.g., pitting) beyond a normal oxide layer will be entered into the corrective action program, and a follow-up volumetric wall thickness examination will be performed, wall thickn*, s o.....tons of fire *potoct*ont pipg aro periodically performed. n systemR compoenet6 using non intrus6iVe techniques (e.g., vouerctesting) to identify loss ot A sample of sprinkler heads required for 10 CFR 50.48 will be inspected using the guidance of NFPA 25 (201102 Edition) Section 5.3.1.1.1, which states, "Where sprinklers have been in place service for 50 years, they shall be replaced or representative samples from one or more sample areas shall be tested .ubmitted to a recognized testing laborato-y

,r*.-ic*, for field teethR." This sampling will be repeated every 10 years after initial field service testing.

The Fire Water System Program will be enhanced to include the following.

  • Revise applicable procedures to include inspection of hose reels for corrosion. In addition, revise the Aacceptance criteria wM9-1 be reyrie to verify no unacceptable signs of degradation.

" Revise Fire Water System Program procedures to replace or test closed Ssprinkler heads required for 10 CFR 50.48 will be replaced Or a sample tested using gu..idanc o. in accordance with NFPA 25 (201102 eEdition), Section 5.3.1.1.1 befovre the end of the 50 ear, sprinkler head sevoice lIfe and at 10 year intevals thereafter during the exteinde period of operation to ensure thatsg o dgradation, such as corrosion, are detected in a

  • Wall thickness evalu-iations Of fire protection pPipin will be performed OR system compnP9ents us~ing non intrus6iVe techniques (e.g., volumetric testing) to identify loss of material due to corrosionR. Those inrspections, will be performed before the end- Of the- current op~erating termn and at intervals thereafter duFrin the period of eXtended operation. Results of the initial evaluatinsn will be used to determnine the appropriate isetoinealto ensure aging effects are identified prior to loss Of intended function.

NL-1 4-147 Attachment 2 Page 36 of 66

  • Revise Fire Water System Program applieable-procedures to inspect the internal surface of the foam-based fire suppression tanks at least once every 10 years. Acceptance criteria will be enhanced to verify no-igifleant abnormal corrosion.
  • Revise Fire Water System Program procedures acceptance criteria for the primary auxiliary building exhaust, containment building purge exhaust, and containment building pressure relief charcoal units to ensure partial flow blockage can be detected during air flow testing.

(Refer to NFPA-25 (2011 Edition), Section 13.4.3.2.2)

  • Revise Fire Water System Program procedures to inspect the nozzles in the charcoal filter units for abnormal corrosion when the charcoal is replaced. (Refer to NFPA-25 (2011 Edition), Sections 13.4.3.2.2 and 14.2)
  • Revise Fire Water System Program procedures to inspect for and require replacement of sprinkler heads (nozzles) if they show signs of abnormal corrosion, excessive loading, leakage, or if the glass bulb heat responsive element is found empty. (Refer to NFPA-25 (2011 Edition), Section 5.2.1.1.)
  • Revise Fire Water System Program procedures to perform main drain testing in accordance with NFPA 25 (2011 Edition), Section 13.2.5, on 20 percent of the testable automatic standpipes with at least one main drain test in each building. (Refer to NFPA-25 (2011 Edition) Sections 6.3.1.5 and 13.2.5.)
  • Revise Fire Water System Program procedures to inspect the interior and exterior of the fire water storage tanks in accordance with NFPA 25 (2011 Edition), Sections 9.2.5.5. 9.2.6 and 9.2.7. with the exception of NFPA Sections 9.2.7.1 and 9.2.7.6. In lieu of testing specified in Section 9.2.7.1. perform holiday testing. In lieu of testing specified in Section 9.2.7.6, perform ultrasonic thickness checks or mechanical measurements of any identified corroded areas at least once every five years.
  • Revise Fire Water System Program procedures to inspect and test the deluge system for the boric acid building filter units every two years in accordance with NFPA 25 (2011 Edition),

Section 13.4.3.2.2.

" Revise Fire Water System Pro-gram procedures to perform an air flow test each refueling outage through the foam system open-head nozzles to ensure there is no blockage, and in the event blocka-ge is identified, provide instruction that the system shall be cleaned and retested. (Refer to NFPA-25 (2011 Edition), Section 13.4.3.2.2.)

  • Revise Fire Water System Program procedures to remove, inspect for damage and corroded parts, and clean the strainers associated with the supply line to the electric tunnel, and in the line downstream of the deluge valve for the primary auxiliary building exhaust and containment building purge filtration units every five years or after each flow test. (Refer to NFPA-25 (2011 Edition), Section 10.2.1.7.)
  • Revise Fire Water System Program procedures to perform an internal inspection of wet fire water system piping conditions every five years, or after an extended shutdown of greater than one year, by opening a flushing connection at the end of one main and by removing a closed sprinkler toward the end of one branch line for the r)urpose of inspectinq the interior

NL-1 4-147 Attachment 2 Page 37 of 66 for evidence of loss of material and the presence of foreign organic and inorganic material that could result in flow obstructions or blockage of sprinkler heads or nozzles. In the event there are multiple wet pipe systems in a structure, one third will be inspected every five years such that all systems will be inspected during each 15-year period. The procedures will include (1) guidance to perform an evaluation for MIC in the event tubercles or slime are identified, and (2) acceptance criteria that states "no abnormal debris" (i.e., no corrosion products that could impede flow or cause downstream components to become clogged).

Corrective actions will specify that any signs of abnormal corrosion or blockage will be removed, the source and extent of condition determined and corrected, and entered into the corrective action program. (Refer to NFPA-25 (2011 Edition), Section 14.2.)

Revise Fire Water System Program procedures to perform an internal inspection of dry piping every five years, or after an extended shutdown of greater than one year, for the preaction systems associated with the technical support center computer and uninterruptible power supply room, and the preaction system associated with the electric tunnels by removing a sprinkler toward the end of one branch line or using the inspectors test valve for the purpose of inspecting for the presence of foreign organic and inorganic material. The procedures will include (1) guidance to perform an evaluation for MIC in the event tubercles or slime are identified, and (2) acceptance criteria that states "no abnormal debris" (i.e., no corrosion products that could impede flow or cause downstream components to become clogged). Corrective actions will specify that any signs of abnormal corrosion or blockage will be removed, the source and extent of condition determined and corrected, and entered into the corrective action program. (Refer to NFPA-25 (2011 Edition), Section 14.2.)

Revise Fire Water System Program procedures to perform an internal inspection of the most remote dry piping downstream of the deluge valves every five years, or after an extended shutdown of greater than one year, for the deluge systems associated with the for the primary auxiliary building, containment purge, containment ventilation, and boric acid building charcoal filters, and the foam deluge systems by removing a sprinkler toward the end of one branch line or using the inspectors test valve for the purpose of inspecting for the presence of foreign organic and inorganic material. The procedures will include (1) guidance to perform an evaluation for MIC in the event tubercles or slime are identified, and (2) acceptance criteria that states "no abnormal debris" (i.e., no corrosion products that could impede flow or cause downstream components to become clogged). Corrective actions will specify that any signs of abnormal corrosion or blockage will be removed, the source and extent of condition determined and corrected, and entered into the corrective action program. (Refer to NFPA-25 (2011 Edition), Section 14.2.)

  • Revise Fire Water System Program procedures to perform an obstruction evaluation if any of the following conditions exist. (Refer to NFPA-25 (2011 Edition), Section 14.3.1.)

o There is an excessive discharge of material during routine flow tests.

" An inspector's test valve is clogged during routine testing.

o Foreign materials are identified during internal inspections.

" Sprinkler heads are found clogged during removal or testing.

NL-14-147 Attachment 2 Page 38 of 66 o Pin hole leaks are identified in fire water piping.

" After an extended shutdown.

o There is a 50 percent increase in time it takes for water to flow out the inspector test valve after the associated dry valve is tripped when compared to the original acceptance criteria or last test.

Revise Fire Water System Program procedures to perform a wall thickness evaluation of any areas identified with excessive accumulation of corrosion products or appreciable localized pitting beyond a normal oxide layer and enter the condition into the corrective action program. (Refer to LR-ISG-2012-02, Section C. iii, (c).)

Enhancements will be implemented prior to the period of extended operation December 31, 2019.

NL-14-147 Attachment 2 Page 39 of 66 A.2.1.33, Service Water Integrity Program The Service Water Integrity Program will be enhanced to include the following.

  • Revise the appropriate procedures to incorporate actions to manage corrosion issues.

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

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

The enhancement will be implemented Drior to December 31. 2019.

NL-14-147 Attachment 2 Page 40 of 66 A.3.1.1 Aboveground Steel Tanks Program The Aboveground Steel Tanks Program is an oxicting program that manages loss of material on outdoor tanks situated on soil or concrete. The program includes preventive measures to mitioate corrosion by protecting the external surfaces of steel components per standard industry practice including the use of sealant or caulking at the concrete to tank interface of outdoor tanks. External visual examinations (supplemented with physical manipulation of caulking or sealant) are performed to monitor degradation of uncoated surfaces and of protective paint, coatina. and sealants. Surface exams are conducted to detect crackina when susceptible materials are used (e.g., stainless steel. aluminum). A sample of the external surfaces of insulated tanks is inspected. Internal visual and surface (when necessary to detect cracking) examinations are conducted as well as measurina the thickness of the tank bottoms to ensure that significant degradation is not occurring and that the component intended function is maintained during the period of extended operation. from oxtenal , Sur-face 9of ab..ogrond

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The Aboveground Steel Tanks Program will be enhanced to include the following tank inspection details 1 .

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!le ttd ~ - *Mmd Material Environment AERM Inspection Techniguez Inspection Frequency Inspections to identify degradation of inside surfaces of tank shell, roof3 , and bottom Inside Surface (IS). Outside Surface (OS)"'

  • Loss of Volumetric from OS 6 or One time prior to December 31, Steel Treated water material visual from IS 2019' Stainless Treated water Loss of Volumetric from OS 6 One time prior to December 31, Steel material or Visual from IS 2019' Inspections to identify degradation of external surfaces of tank roof, tank shell, and bottom not exposed to soil or concrete*

Air-indoor Loss of Steel uncontrolled material Visual from OS Each refueling outage interval Air-outdoor Stainless Air-outdoor Loss of Visual from OS Each refuelincq outage interval Steel material

NL-1 4-147 Attachment 2 Page 41 of 66 Material Environment AERM Inspection Technique2 Inspection Frequency Cracking Surface 9 , 10 Each 10-year period of the period of extended operation Inspections to identify degradation of tank bottoms and tank shells exposed to soil or concrete Steel Soil or concrete L Volumetric from IS Each 10-year period of the material period of extended operation" Stainless Loss of Volumetric from IS Each 10-year period of the Steel Soil or concrete material period of extended operation" Tank Inspection Table Notes

1. IPEC LRA section B.1.9, "Diesel Fuel Monitoring" manages loss of material on the internal surfaces of fuel oil storage tanks.
2. Alternative inspection methods may be used to inspect both surfaces (i.e., internal, external) or the opposite surface (e.g. inspecting the internal surfaces for loss of material from the external surface, inspecting for corrosion under external insulation from the internal surfaces of the tank) as long as the method has been demonstrated effective at detecting the AERM and a sufficient amount of the surface is inspected to ensure that localized aging effects are detected. For example, in some cases, subiect to being demonstrated effective by the applicant, the low-frequency electromagnetic technique (LFET) can be used to scan an entire surface of a tank. An LFET inspection can effectively detect loss of material in the tank shell, roof, or bottom if follow-up ultrasonic examinations are conducted in any areas where the wall thickness is below nominal.
3. Nonwetted surfaces on the inside of a tank (e.g., roof, surfaces above the normal waterline) are inspected in the same manner as the wetted surfaces.
4. Visual inspections to identify degradation of the inside surfaces of tank shell, roof, and bottom should cover all the inside surfaces.
5. Materials, if any, accumulated on the tank bottom (e.g., sediment, silt) are removed to allow for complete inspections of the tank's surfaces.
6. At least 25 percent of the tank's surface is inspected using a method capable of precisely determining wall thickness. The inspection method should be demonstrated capable of detecting both general and pitting corrosion.
7. At least one tank for each material and environment combination should be inspected.
8. For tanks with tightly adhering insulation without evidence of damage to the moisture barrier, inspections may consist of examination of the exterior surface of the insulation for indications of damage to the iacketing or protective outer layer of the insulation. For tanks with caulking or sealant at the concrete to tank interface, visual inspection of the caulking or sealant is performed in coniunction with physical manipulation of the caulking or sealant.
9. An inspection will be performed prior to December 31, 2019. Subsequent inspections are not required if an evaluation conducted prior to December 31, 2019 and at the scheduled time of each subsequent inspection during the PEO demonstrates the absence of chlorides or other deleterious compounds at sufficient levels to cause pitting corrosion, crevice corrosion, or cracking. The evaluation should include soil sampling in the vicinity of the tank (because soil results indicate atmospheric fallout accumulating in the soil and potentially affecting tank surfaces) and sampling of residue on the top and sides of the tank.
10. A minimum of either 25 sections of the tank's surface (e.g., 1-square-foot sections for tank surfaces, 1-linear-foot sections of weld length) or 20 percent of the tank's surface are examined. The sample inspection Doints are distributed in such a way that inspections occur in those areas most suscep)tible to degradation (i.e., areas where contaminants could collect, inlet and outlet nozzles, welds).

NL-14-147 Attachment 2 Page 42 of 66

11. The first inspection will be performed duringq the first 10 years of the period of extended operation.

Subsequent inspections are not required ifevaluations conducted at the time of the first inspection and at the scheduled time of each subsequent inspection during the PEO demonstrate that the soil under the tank is not corrosive using actual soil samples that are analyzed for each individual parameter (e.g., resistivity, pH, redox potential, sulfides, sulfates, moisture) and overall soil corrosivity. The evaluation should include soil sampling from underneath the tank.

Enhancements will be implemented prior to prior to December 31, 2019 tho period of extonded epeFatR.

NL-14-147 Attachment 2 Page 43 of 66 A.3.1.10 External Surfaces Monitoring Program The External Surfaces Monitoring Program is an existing program that inspects external surfaces of components subject to aging management review. The program is also credited with managing loss of material from internal surfaces, for situations in which internal and external material and environment combinations are the same such that external surface condition is representative of internal surface condition.

Surfaces that are inaccessible during plant operations are inspected during refueling outages.

Surfacoc that are inSulated arc inSPocGto-d when the external surface is exposed ([pe., during Riaw~efiee Periodic representative surface condition inspections of the in-scope mechanical indoor components under insulation (with process fluid temperature below the dew point) and outdoor components under insulation will be performed during each 1 0-year period of the period of extended operation. Surfaces are inspected at frequencies to assure the effects of aging are managed such that applicable components will perform their intended function during the period of extended operation.

The External Surfaces Monitoring Program will be enhanced to include the following.

Guidance documents will be revised to require 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).

  • Procedures will be revised to specify the following for insulated components.

o Periodic representative inspections for CUI will be conducted during each 10-year period of the PEO.

o For a representative sample of insulated indoor components exposed to condensation (because the component is operated below the dew point), and insulated outdoor components, insulation will be removed for visual inspection of component surfaces. Inspections will include a minimum of 20 percent of the in-scope piping length for each material type (e.g., steel, stainless steel, copper alloy, aluminum) or for components with a configuration which does not conform to a 1-foot axial length determination (e.g., valve, accumulator), 20 percent of the surface area.

Alternatively, insulation will be removed and a minimum of 25 inspections will be performed that can be a combination of 1-foot axial length sections and individual components for each material type.

o Inspection locations will be based on the likelihood of corrosion under insulation (CUI). For example, CUI is more likely for components that are alternately wet and dry in environments where trace contaminants could be present and for components that operate for Iong periods of time below the dew point.

NL-14-147 Attachment 2 Page 44 of 66 Subsequent inspections will consist of an examination of the exterior surface of the insulation for indications of damage to the iacketing or protective outer layer of the insulation, if the following conditions are verified in the initial inspection:

> No loss of material due to general, pitting or crevice corrosion, beyond that which could have been present during initial construction.

> No evidence of cracking.

If the external visual inspections of the insulation reveal damage to the exterior surface of the insulation or there is evidence of water intrusion through the insulation (e.g.. water seepage through insulation seams/ioints), periodic inspections under the insulation will continue.

  • Removal of tightly adhering insulation that is impermeable to moisture is not required unless there is evidence of damage to the moisture barrier. Tightly adhering insulation that is impermeable to moisture will be removed to allow for inspection if there is evidence of damage to the moisture barrier. If the moisture barrier is intact, the likelihood of CUI is low for tightly adhering insulation. Components with tightly adhering insulation constitute a separate population from the remainder of in-scope insulated components. The entire population of in-scope accessible component surfaces covered with tightly adhering insulation will be visually inspected for damage to the moisture barrier at the same frequency as inspections of components with other types of insulation. These inspections will not be credited towards the inspection quantities for components with other types of insulation.

Enhancements will be implemented prior to December 31, 2019 the p.r-id of oxtondd*

epe~atie.

NL-14-147 Attachment 2 Page 45 of 66 A.3.1.13 Fire Water System Program The Fire Water System Program is an existing program that manages water-based fire protection systems that consist of sprinklers, nozzles, fittings, valves, hydrants, hose stations, fire pump casings, water storage tanks, standpipes, piping, and components that are tested in accordance with applicable National Fire Protection Association (NFPA) codes and standards.

Such testing assures functionality of systems. To determine if Gi*"ifiGa... abnormal corrosion has occurred in water-based fire protection systems, periodic flushing, system performance testing, and inspections are conducted. In addition to NFPA codes, portions of the water-based fire protection system (a) that are normally dry but periodically subiect to flow (e.g., dry-pipe or preaction sprinkler system piping and valves) and (b) that cannot be drained or allow water to collect are subiect to augmented testing and inspections. Also, many of these systems are normally maintained at required operating pressure and monitored such that leakage resulting in loss of system pressure is immediately detected and corrective actions initiated.

In addition, visual inspection results that identify excessive accumulation of corrosion products and appreciable localized corrosion (e.g.. pitting) beyond a normal oxide layer will be entered into the corrective action program, and a follow-up volumetric wall thickness examination will be performed, wall thicnocs e.aluations of fire p"eotction piping a. . per'iodially perfoFrmed on systemR copnP9ents using non intrusiVe techniques (e.g., volumetric testing) to identify loss ot material duo to corrosion.

A sample of sprinkler heads required for 10 CFR 50.48 will be inspected using the guidance of NFPA 25 (201102 Edition) Section 5.3.1.1.1, which states, "Where sprinklers have been in plaGe-service for 50 years, they shall be replaced or representative samples from one or more sample areas shall be tested submitted to ard testing laborato"'- for field 6"rVice tetiRg." This sampling will be repeated every ten years after initial field service testing.

The Fire Water System Program will be enhanced to include the following.

" Revise applicable procedures to include inspection of hose reels for corrosion. In addition, revise the Aacceptance criteria will be revie to verify no unacceptable signs of degradation.

" Revise Fire Water System Program procedures to replace or test closed Ssprinkler heads required for 10 CFR 50.48 will be replaced or a sample tested using guidance t in accordance with NFPA 25 (201102 eEdition), Section 5.3.1 .1 .1 before the end of the 50 year sprinkler head *s.e.r.vie lifed at 10 year intevals thereafter durn*g the extended period of operation to ensu re that signs of degradation, such as corrosion, are detected in a timely -ma~Rer

" Wall thickness evaluations of fire proetectio piping will be performed OR system components using non itrusive techniques (e.g., volumetric testing) to ffidentify o6ss of material due toe corrosion. These inspection6 will be pernfred before the end of the current operating te*rm and at intervals thereafter durwing the period Of extended operation;. Results of the initial evaluations, Will be used to determine the appropriate inpcini tervlt ens6ure gn UIIuU~z. 11u Iu~:ItIIIuu .. :IuI ILl :~A. UI :I:~jIIutIu Iu:x~::Ll:;.

_iV . . . . . .

NL-1 4-147 Attachment 2 Page 46 of 66

  • Revise Fire Water System Program app!lGab'e-procedures to inspect the internal surface of the foam-based fire suppression tanks at least once every 10 years. Acceptance criteria will be enhanced to verify no,'ig",ifiaR, abnormal corrosion.
  • Revise Fire Water System Program procedures to inspect the nozzles in the charcoal filter units for abnormal corrosion when the charcoal is replaced. (Refer to NFPA-25 (2011 Edition), Sections 13.4.3.2.2 and 14.2.)

" Revise Fire Water System Program procedures to inspect for and require replacement of sprinkler heads (nozzles) if they show signs of abnormal corrosion, excessive loading, leakage, or if the glass bulb heat responsive element is found empty. (Refer to NFPA-25 (2011 Edition), Section 5.2.1.1.)

  • Revise Fire Water System Program procedures to perform main drain testing in accordance with NFPA 25 (2011 Edition), Section 13.2.5, on 20 percent of the testable automatic standpipes with at least one main drain test in each building. (Refer to NFPA-25 (2011 Edition), Sections 6.3.1.5 and 13.2.5)

" Revise Fire Water System Program procedures to inspect the interior and exterior of the fire water storage tanks in accordance with NFPA 25 (2011 Edition), Section 9.2.5.5. 9.2.6 and 9.2.7, with the exception of NFPA Sections 9.2.7.1 and 9.2.7.6. In lieu of testing specified in Section 9.2.7.1, perform holiday testing. In lieu of testing specified in Section 9.2.7.6, perform ultrasonic thickness checks or mechanical measurements of any identified corroded areas at least once every five years.

  • Revise Fire Water System Program procedures to perform an air flow test each refueling outage through the foam system open-head nozzles to ensure there is no blockage, and in the event blockage is identified provide instruction that the system shall be cleaned and retested. (Refer to NFPA-25 (2011 Edition), Section 13.4.3.2.2.)

" Revise Fire Water System Program procedures to perform an internal inspection of wet fire water system piping conditions every five years, or after an extended shutdown of greater than one year, by opening a flushing connection at the end of one main and by removing a closed sprinkler toward the end of one branch line for the purpose of inspecting the interior for evidence of loss of material and the presence of foreign organic and inorganic material that could results in flow obstructions or blockage of sprinkler heads or nozzles. In the event there are multiple wet pipe systems in a structure, one third will be inspected every five years such that all systems will be inspected during each 15-year period. The procedures will include (1) guidance to perform an evaluation for MIC in the event tubercles or slime are identified, and (2) acceptance criteria that states "no abnormal debris" (i.e., no corrosion products that could impede flow or cause downstream components to become clogged).

Corrective actions will specify that any signs of abnormal corrosion or blockage will be removed, the source and extent of condition determined and corrected, and entered into the corrective action program. (Refer to NFPA-25 (2011 Edition), Section 14.2.)

  • Revise Fire Water System Program procedures to perform an obstruction evaluation if any of the followina conditions exist. (Refer to NFPA-25 (2011 Edition). Section 14.3.1.)

NL-1 4-147 Attachment 2 Page 47 of 66 o There is an excessive discharge of material during routine flow tests.

o An inspector's test valve is clogged durinq routine testing.

o Foreign materials are identified during internal inspections.

o Sprinkler heads are found clogged during removal or testing.

o Pin hole leaks are identified in fire water piping.

o After an extended shutdown.

o There is a 50 percent increase in time it takes for water to flow out the inspector test valve after the associated dry valve is tripped when compared to the original acceptance criteria or last test.

  • Revise Fire Water System Program procedures to perform a wall thickness evaluation of any areas identified with excessive accumulation of corrosion products or appreciable localized pitting beyond a normal oxide layer and enter the condition into the corrective action program. (Refer to LR-ISG-2012-02, Section C, iii, (c).)
  • Revise Fire Water System Program procedure(s) to test and inspect the water spray system
  1. 11 - charcoal filters associated with the containment purge exhaust, primary auxiliary building exhaust system, and containment pressure relief filtration units in accordance NFPA 25 (2011 Edition) Section 13.4.3.2.2, and the associated sub-steps.
  • Revise Fire Water System Program procedure(s) to fully open hydrants, flush at least for one minute, flush until the water is clear, and verify the hydrants drainage takes no longer than 60 minutes. Where drainage is longer than 60 minutes, provide procedural steps to address the situation (e.g., unclog the drain or pump out the hydrant). (Refer to NFPA-25 (2011 Edition), Section 7.3.2)

" Revise Fire Water System Program procedure(s) to perform an air test to ensure spray patterns are not affected by plugged nozzles associated with the hydrogen seal oil unit, main boiler feed pump oil reservoir, main lube oil storage, and main lube oil reservoir foam deluge systems. Where plugged nozzles are identified, the procedure(s) should include a requirement to clean and retest. (Refer to NFPA-25 (2011 Edition), Section 13.4.3.2.2.)

  • Revise Fire Water System Program procedure(s) to remove, clean and inspect the strainers associated with electric tunnels and the containment purge exhaust system, primary auxiliary building exhaust system, and containment pressure relief filtration unit for damage and abnormal corrosion. (Refer to NFPA-25 (2011 Edition), Section 10.2.1.7.)

" Revise Fire Water System Program procedure(s) to perform an internal inspection every five years of the dry portion of the preaction system associated with the electric tunnels by removing a sprinkler toward the end of one branch line or using the inspector test valve for the purpose of inspecting for the presence of foreign organic and inorganic material. The procedure that governs inspection of the normally dry piping will include (1) guidance to perform an evaluation for MIC in the event tubercles or slime are identified, and (2)

NL-14-147 Attachment 2 Page 48 of 66 acceptance criteria that states "no abnormal debris" (i.e., no corrosion products that could impede flow or cause downstream components to become clogged). Corrective actions will specify that any signs of abnormal corrosion or blockage will be removed, the source and extent of condition determined and corrected, and entered into the corrective action program. (Refer to NFPA-25 (2011 Edition), Section 14.2.)

Revise Fire Water System Program procedure(s) to perform an internal inspection every five years of the most remote dry piping downstream of the deluge valves in the deluge systems for the primary auxiliary building exhaust, containment purge, containment pressure relief, and foam systems by removing a sprinkler toward the end of one branch line for the purpose of inspecting for the presence of foreign organic and inorganic material. The procedure that governs inspection of the normally dry piping will include (1) guidance to perform an evaluation for MIC in the event tubercles or slime are identified, and (2) acceptance criteria that states "no abnormal debris" (i.e., no corrosion products that could impede flow or cause downstream components to become clogged). Corrective actions will specify that any signs of abnormal corrosion or blockage will be removed, the source and extent of condition determined and corrected, and entered into the corrective action program. (Refer to NFPA-25 (2011 Edition), Section 14.2.)

Enhancements will be implemented prior to December 31, 2019 the period of extended

.- PeGGmo.

NL-1 4-147 Attachment 2 Page 49 of 66 A.3.1.33 Service Water Integrity Program The Service Water Integrity Program will be enhanced to include the following.

  • Revise the appropriate procedures to incorporate actions to manage corrosion issues.

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

o Accessible portions of safety-related buried service water piping will be internally inspected by robotic crawler or manual crawl-through once during the first 10 years of the period of extended operation The enhancement will be implemented orior to December 31. 2019.

NL-14-147 Attachment 2 Page 50 of 66 B.1.1 ABOVEGROUND STEEL TANKS Program Description The Aboveground Steel Tanks Program is an existing program that manages loss of material and cracking of the outside and inside from externa surfaces of aboveground GaFbemnstee4-tanks constructed on concrete or soil. by poridic visual inspection Et cXtVrnal su.faces and thiGckess measurement Of Iocation)s that areFin.ccesible for external visual

" nspoc,, n.. Outdoor tanks (except fire water storage tanks) are included (IPEC has no indoor tanks that meet the criteria of LR-ISG-2012-02 for inclusion in this program). For tanks where the exterior surface is fully visible, that surface may be inspected under the program for inspection of external surfaces (Ref. Section B.1.11) in lieu of the visual inspections recommended in this AMP; surface examinations are conducted in accordance with the provisions of this AMP. This program credits the standard industry practice of coating or painting the external surfaces of steel tanks as a preventive measure to mitigate corrosion. The program relies on periodic inspections to monitor degradation of the protective paint or coating. Tank inside surfaces are inspected by visual or surface examinations as required to detect applicable aging effects.

For storage tanks supported on earthen or concrete foundations, corrosion may occur at inaccessible locations, such as the tank bottom. Accordingly, verification is performed to ensure that significant degradation in inaccessible locations is not occurring and that the function is maintained during the period of extended operation. An acceptable verification consists of thickness measurements of the tank bottom surface.

The Aboveground Steel Tanks Program will be enhanced to include the following tank inspection details 1 .

NL-14-147 Attachment 2 Page 51 of 66 Material Environment AERM Inspection Technique2 Inspection Frequency Air-indoor Steel uncontrolled Loss of Airoutd material Visual from OS Each refueling outage interval Air-outdoor mtra Loss of material Visual from OS Each refueling outage interval material Stainless Air-outdoor Steel Cracking Surface 9, 10 Each 10-year period of the period of extended operation Inspections to identify degradation of tank bottoms and tank shells exposed to soil or concrete Loss of Each 10-year period of the Steel Soil or concrete material material Volumetric from IS Erio oof extended period ofe extendedoperation"1 Stainless Loss of Volumetric from IS Each 10-year period of the Steel Soil or concrete material period of extended operation11 Tank Inspection Table Notes

1. IPEC LRA section B.1.9, "Diesel Fuel Monitoring" manages loss of material on the internal surfaces of fuel oil storage tanks.
2. Alternative inspection methods may be used to inspect both surfaces (i.e., internal, external) or the opposite surface (e.g. inspecting the internal surfaces for loss of material from the external surface, inspecting for corrosion under external insulation from the internal surfaces of the tank) as long as the method has been demonstrated effective at detecting the AERM and a sufficient amount of the surface is inspected to ensure that localized aging effects are detected. For example, in some cases, subiect to being demonstrated effective by the applicant, the low-frequency electromagnetic technique (LFET) can be used to scan an entire surface of a tank. An LFET inspection can effectively detect loss of material in the tank shell, roof, or bottom if follow-up ultrasonic examinations are conducted in any areas where the wall thickness is below nominal.
3. Nonwetted surfaces on the inside of a tank (e.g., roof, surfaces above the normal waterline) are inspected in the same manner as the wetted surfaces.
4. Visual inspections to identify degradation of the inside surfaces of tank shell, roof, and bottom should cover all the inside surfaces.
5. Materials, if any, accumulated on the tank bottom (e.g., sediment, silt) are removed to allow for complete inspections of the tank's surfaces.
6. At least 25 percent of the tank's surface is inspected using a method capable of precisely determining wall thickness. The inspection method should be demonstrated capable of detecting both general and pitting corrosion.
7. At least one tank for each material and environment combination should be inspected.
8. For tanks with tightly adhering insulation without evidence of damage to the moisture barrier.

inspections may consist of examination of the exterior surface of the insulation for indications of damage to the jacketing or protective outer layer of the insulation. For tanks with caulking or sealant at the concrete to tank interface, visual inspection of the caulking or sealant is performed in coniunction with physical manipulation of the caulking or sealant.

9. An inspection will be performed prior to December 31, 2019. Subsequent inspections are not required if an evaluation conducted prior to December 31, 2019 and at the scheduled time of each subsequent inspection during the PEO demonstrates the absence of chlorides or other deleterious compounds at sufficient levels to cause pitting corrosion, crevice corrosion, or cracking. The

NL-14-147 Attachment 2 Page 52 of 66 evaluation should include soil samplinq in the vicinity of the tank (because soil results indicate atmospheric fallout accumulating in the soil and potentially affecting tank surfaces) and sampling of residue on the top and sides of the tank.

10. A minimum of either 25 sections of the tank's surface (e.g., 1-square-foot sections for tank surfaces, 1-linear-foot sections of weld length) or 20 percent of the tank's surface are examined. The sample inspection points are distributed in such a way that inspections occur in those areas most susceptible to degradation (i.e., areas where contaminants could collect, inlet and outlet nozzles, welds).
11. The first inspection will be performed during the first 10 years of the period of extended operation.

Subsequent inspections are not required ifevaluations conducted at the time of the first inspection and at the scheduled time of each subsequent inspection during the PEO demonstrate that the soil under the tank is not corrosive using actual soil samples that are analyzed for each individual parameter (e.g., resistivity, pH, redox potential, sulfides, sulfates, moisture) and overall soil corrosivity. The evaluation should include soil sampling from underneath the tank.

NUREG-1801 Consistency The Aboveground Steel Tanks Program is consistent with the program described in NUREG-1801,Section XI.M29, Aboveground Steel-Metallic Tanks, as modified by LR-ISG-2012-02 with exceptions and enhancements.

Exceptions to NUREG-1801 None The Aboveground Steel Tanks Program is consistent with the program described in NUREG-1801,Section XI.M29, Aboveground Steel Tanks, as modified by LR-ISG-2012-02. with the followina exception.

Attributes Affected Exception

4. Detection of Aging Effects The timing of inspections under detection of aging effects is not consistent with LR-ISG-2012-02 recommendations. 1 Exception Note
1. The issue date of the ISG upon which program changes are based precluded the performance of the added inspections prior to the period of extended operation.

Operating experience, including tank inspections results, to date indicates that aging effects are being adequately managed and supports the acceptability of performing inspections as specified in the program description.

Enhancements The following enhancements will be implemented prior to the peFi*d-*of-extende eperation December 31, 2019.

NL-14-147 Attachment 2 Page 53 of 66 Attributes Affected Enhancement

4. Detection of Aging Effects Revise app..cablo procedures to
6. Acceptance Criteria pero*rm thickness measu..m.nts of the bottom surf-ace of the condensate g ta lt~ ks Gil wate I ta. k 1122-,v4,,

(.Oll*4 tanks, Once during the first ten years ot the period of extended operation.-

Develop or revise program implementing documents as necessary to incorporate the tank inspection details delineated in the table in the program description.

5. Monitoring and Trending Revise applicable-prGedu implementing documents to require trending of thickness measurements when material loss is detected.

Operating Experience Thickness measurements of portions of the city water tank were performed in 2003 with satisfactory results (tank was determined to be in qood condition). Thickness measurements of the IP2 condensate storale tank in 2008 identified minor corrosion.

There was no loss of intended function.

The visual inspection and thickness measurement methods used in this proqram to detect aging effects are proven industry techniques that have been effectively used at IPEC. Operating experience with these techniques assures that implementation of the Aboveground Steel Tanks Program will manage the effects of aging such that applicable components will continue to perform their intended functions consistent with the current licensing basis for the period of extended operation.

T-hickness mneasurements of the gas turbine fuel storage tanks in April 2002 found pitting up to 60% throughwall, with no loss of intnded func*tio. This was repaired wAth a weld-hveF lhl Internal inspections Of the 1122 fire wateFr torFage tank and the training center fire water storage tank in 2003 detected failure of the coating inseveral places, but no appreciable metal loss was identified. Corrective actions wer issued to repair tho coating.

Identiffication of degradation and performance of correctfive action prior to loGs Of n;4. i-Inj~

Al~ Ai ; -44 ;Ara n . r nn *L, a* *. a a ra-F . a +.,  ;-n4.d m n'. i

" V- " e-- " " "" "r"IV "T r-2 ri .-. el"I""

............. F- -- *#-

el,*ecS mr passive compoRents.

NL-14-147 Attachment 2 Page 54 of 66 B.1.11 EXTERNAL SURFACES MONITORING Surfaces that are inaccessible during plant operations are inspected during refueling outages. Surfacos that are insulated are inspected when the x*tXonal suface is exposed (i.o., during ma"nte.anc. Periodic representative surface condition inspections of the in-scope mechanical indoor components under insulation (with process fluid temperature below the dew point) and outdoor components under insulation will be performed during each 10-year period of the period of extended operation. Surfaces are inspected at frequencies to assure the effects of aging are managed such that applicable components will perform their intended function during-the period of extended operation.

NUREG-1801 Consistency The External Surfaces Monitoring Program is consistent with the program described in NUREG-1801,Section XI.M36, External Surfaces Monitoring with aP,-enhancements.

Exceptions to NUREG-1801 None Enhancements The following enhancements will be implemented prior to tho period of v ,,onded operatien-December 31, 2019.

Attributes Affected Enhancement

4. Detection of Aging Revise External Surfaces Monitoring Program procedures Effects to specify the followinq for insulated components.

" Periodic representative inspections for CUI will be conducted during each 10-year period of the PEO.

" For a representative sample of insulated indoor components exposed to condensation (because the component is operated below the dew point) and insulated outdoor components, insulation will be removed for visual inspection of component surfaces.

Inspections will include a minimum of 20 percent of the in-scope piping length for each material type (e.g.,

steel, stainless steel, copper alloy, aluminum) or for components with a configuration which does not conform to a 1-foot axial length determination (e.g.,

valve, accumulator). 20 oercent of the surface area.

Alternatively, insulation will be removed and a

NL-14-147 Attachment 2 Page 55 of 66 minimum of 25 inspections will be performed that can be a combination of 1-foot axial length sections and individual components for each material type.

Inspection locations will be based on the likelihood of corrosion under insulation (CUI). For example, CUI is more likely for components that are alternately wet and dry in environments where trace contaminants could be present and for components that operate for long periods of time below the dew point.

Subsequent inspections will consist of an examination of the exterior surface of the insulation for indications of damage to the iacketinq or protective outer layer of the insulation, if the following conditions are verified in the initial inspection:

No loss of material due to general, pitting or crevice corrosion, beyond that which could have been present during initial construction.

) No evidence of cracking.

If the external visual inspections of the insulation reveal damage to the exterior surface of the insulation or there is evidence of water intrusion through the insulation (e.g. water seepage through insulation seams/ioints),

periodic inspections under the insulation will continue.

Removal of tightly adhering insulation that is impermeable to moisture is not required unless there is evidence of damage to the moisture barrier. Tightly adhering insulation that is impermeable to moisture will be removed to allow for inspection if there is evidence of damage to the moisture barrier. If the moisture barrier is intact, the likelihood of CUI is low for tightly adhering insulation. Components with tightly adhering insulation constitute a separate population from the remainder of in-scope insulated components. The entire population of in-scope accessible component surfaces covered with tightly adhering insulation will be visually inspected for damage to the moisture barrier at the same frequency as inspections of components with other types of insulation. These inspections will not be credited towards the inspection quantities for components with other types of insulation.

NL-14-147 Attachment 2 Page 56 of 66 B.1.14 FIRE WATER SYSTEM Program Description The Fire Water System Program is an existing program that manages water-based fire protection systems consisting of sprinklers, nozzles, fittings, valves, hydrants, hose stations, fire pump casings, water storage tanks, standpipes, piping, and components that are tested in accordance with applicable National Fire Protection Association (NFPA) codes and standards. Such testing assures functionality of systems. To determine if -siifiGai*t abnormal corrosion has occurred in water-based fire protection systems, periodic flushing, system performance testing, and inspections are conducted.

In addition to NFPA codes, portions of the water-based fire protection system (a) that are normally dry but periodically subiect to flow (e.g., dry-pipe or preaction sprinkler system piping and valves) and (b) that cannot be drained or allow water to collect are subject to augmented testing and inspections. Also, many of these systems are normally maintained at required operating pressure and monitored such that leakage resulting in loss of system pressure is immediately detected and corrective actions initiated.

In addition, visual inspection results that identify excessive accumulation of corrosion products and appreciable localized corrosion (e.g., pitting) beyond a normal oxide layer will be entered into the corrective action program, and a follow-up volumetric wall thickness examination will be performed.,wall thickness ovaluato.s of firo protection ppn priodically perf*ormed o1;n ystemcomo vre Ui*n1

.nents nn *1intrusiVe technique (e.g., volumetric testing) to identify loss of mnaterial due to corrosion A sample of sprinkler heads required for 10 CFR 50.48 will be inspected using the guidance of NFPA 25 (201102 Eedition) Section 5.3.1.1.1, which states, "Where sprinklers have been in plaGe-service for 50 years, they shall be replaced or representative samples from one or more sample areas shall be tested submitted recognized testing lab-, ato'*, for field serVice testing." This sampling will be repeated every 10 years after initial field service testing.

NUREG-1801 Consistency The Fire Water System Program is with enhancements will be consistent with the program described in NUREG-1801,Section XI.M27, Fire Water System, as modified by LR-ISG-2012-02, with an exceptions and enhal;ements.

Exceptions to NUREG-1801 The Fire Water System Program is with enhancements will be consistent with the program described in NUREG-1801,Section XI.M27, Fire Water System, as modified by LR-ISG-2012-02 with the following exceptions.

NL-1 4-147 Attachment 2 Page 57 of 66 Attributes Affected Exception

4. Detection of Aging Effects 1. NUREG-1 801 specifies annual fire hose hydrostatic tests and gasket inspections. Fire hoses and hose station gaskets are not subject to aging management review and not included in the program. 1
2. NFPA 25 (2011 Edition), Section 5.2.1 specifies annual sprinkler inspections.

IP2 performs inspections of the EDG wet pipe sprinklers on 18-month intervals. 2

3. NFPA 25 (2011 Edition), Section 13.4.3.2.2 specifies trip testing deluge valves on an annual basis. The deluge valve for the IP2 primary auxiliary building exhaust, containment building pur-ge exhaust and containment building pressure relief charcoal units are tested each refueling outage, which is every two years.3
4. NFPA 25 (2011 Edition), Section 5.2.1.1 specifies inspections for sprinkler orientation, foreign material, physical damage, paint, and loadingL due to dust or debris. Sprinkler orientation, foreign material, physical damage, and paint are event driven.

Therefore, inspections for these conditions are not included in the Fire Water System Aging Management Program.4

5. During an inspection in accordance with NFPA 25 (2011 Edition), Sections 9.2.6.4 and 9.2.7.1 specify an evaluation of interior tank coatings in accordance with the adhesion test of ASTM D 3359. Standard Test Methods for Measuring Adhesion by Tape Test, generally referred to as the "cross-hatch test," when indications are identified in the fire water, tank coating. IPEC performs holiday testing. In addition, IPEC performs ultrasonic thickness

NL-1 4-147 Attachment 2 Page 58 of 66 checks or mechanical measurements of any identified corroded areas at least once every five years. IPEC does not apply the cross-hatch test.5

6. NFPA 25 (2011 Edition), Section 9.7.2.1 specifies vacuum box testing of fire water tanks that are designed with a flat bottom. The IPEC fire water tanks were designed to have flat bottom.

However, performing vacuum box testing to identify leakage may not be possible in the event the bottom of the tanks is uneven.6

7. NFPA 25 (2011 Edition), Sections 6.3.1.5 and 13.2.5 specifies main drain testing on all standpipes and risers in the water-based fire suppression system with automatic water supplies to determine if there has been a change in the water supply piping and control valves. IPEC does not perform main drain testing on all standpipes and risers. 7
8. NFPA 25 (2011 Edition), Section 13.4.3.2.3 specifies performing preaction valve trip testing with the control valve fully open. IP2 does not perform the preaction valve with the control valve fully open for the electric tunnels. 8
9. NFPA 25 (2011 Edition), Section 14.2.1 specifies an internal inspection for blockage every five years of normally dry fire water piping that may experience periodic wetting. IPEC does not perform these interior inspections of the dry piping downstream of the deluge valves for the transformers. 9
10. NFPA 25 (2011 Edition), Section 5.3.1 requires an annual inspection of sprinkler heads for leakage. IPEC does not inspect open sprinkler heads for leakaqe. 1 °

NL-14-147 Attachment 2 Page 59 of 66 Exception Notes 1 Fire hoses are periodically inspected, hydrotested, and replaced as required in accordance with plant procedures. Gaskets in couplings are replaced during hose station inspections.

2 Inspection once every 18 months has been effective at maintaining component intended functions.

3 Testing is feasible only during refueling outages, which occur once every 24 months. Testing once every 24 months has been effective at maintaining component intended functions.

4 IP2 and IP3 address the identified conditions during design, installation and operation of the fire water system rather than in an aging management program because they are not issues attributable to the effects of aging.

5 The fire water tanks at IPEC have a capacity of 300,000 and 350,000 gallons with continuous monitoring through instrumentation with alarms in the control room. The adhesion testing suggested in NFPA 25 (2011 Edition), Section 9.2.7, Item #1 (ASTM D 3359) is a destructive test that requires cutting an 'X' in the coating down to the substrate in a number of locations. According to ASTM D 3359, this testing of coating adhesion is not a precise test of coating adhesion and it is not unexpected to get different test results from different personnel performing the same test.

Different test results occur because the test depends on (1) the peel angle and rate, (2) subiective visual assessment of any coating removed, and (3) humidity and temperature. The repair of the coating adhesion test locations would require a specific humidity and temperature. For these reasons, the adhesion test is not considered a prudent inspection method.

6 The fire water tanks at IPEC have a capacity of 300,000 and 350,000 gallons with continuous monitoring through instrumentation with alarms in the control room. Jockey pumps provide makeup to compensate for leakage from the system. Leakage in excess of jockey pump makeup capacity would be obvious to the operating staff and would result in corrective actions to identify and repair the source of the leakage. Therefore, the vacuum box testing is not necessary to ensure the tanks remain capable of fulfilling their license renewal intended functions.

7 IPEC has committed to performing main drain tests in accordance with NFPA 25 (2011 Edition),

Section 13.2.5. on 20 percent of the testable automatic standpipes and risers with at least one main drain test per building. Additional main drain testing in radiologically controlled areas and areas that contain equipment critical for normal and shutdown operations creates additional radwaste and increases operational risk.

8 Performing trip testing of the preaction valves for the IPEC electrical tunnels with the control valve in a closed or throttled position limits the amount of water that enters the piping designed to be dry downstream of the preaction valve.

9 The deluge systems for the transformers are full flow tested every refueling outage and any blockage would be identified during that testing.

10 Leakage from an open sprinkler head indicates a leaking deluge or control valve. Such leakage is due to degradation of the active subcomponents of the valves which are not subject to aging management review for license renewal. The Fire Water System Aging Management Program is not appropriate for managing degradation of active subcomponents.

Enhancements The following enhancements will be implemented prior to the -pe-*d of*extesi4ed epeatioR December 31, 2019.

NL-14-147 Attachment 2 Page 60 of 66 Attributes Affected Enhancements

3. Parameters Monitored Revise applicable procedures to include inspection of hose or Inspected reels for corrosion. Acceptance criteria will be revised to
6. Acceptance Criteria verify no unacceptable signs of degradation.
3. Parameters Monitored Revise appf)iabGeIP2 and IP3 Fire Water System Program or Inspected procedures to inspect the internal surface of the foam based
4. Detection of Aging fire suppression tanks at least once every 10 years.

Effects Acceptance criteria will be enhanced to verify no sigRifiea*t

6. Acceptance Criteria abnormal corrosion.
4. Detection of Aging Revise IP2 and IP3 Fire Water System Pro-gram procedures Effects to replace or test closed Ssprinkler heads required for 10 CFR 50.48 will be replaced Or a sample tested using guidaRe-ef-in accordance with NFPA 25 (201102 eEdition),

Section 5.3.1.1.1 beforo the ond of the 50 year ,p"i"kle.

head Serv'ico life and at 10-year intervxals- the-re-after during the oxtonded period of operation to ensure that signs o9 degradation, 6such as corG on r dtetoted in a timely FnaRPR-F.

4. Detection of Aging Wall thickn*ss evaluations of fire protection piping will be

~Ffe~tS performed on system components using non intrusiVe techniques (e.g., volumet*i* testing) to identify loss o m.atei*al due to coro*sion. These inspecti*on. ill bi performned beforFe the end Of the current operating termn and at intervals thereafte duOrin the period of extende operation. Results; of the initial evaluations will be used to determ~ine the appropriate inspection interval to nue agn effecsts are identified prior to less of intended function.

4. Detection of Aging Revise IP2 and IP3 Fire Water System Program procedures Effects to inspect for and require replacement of sprinkler heads (nozzles) if they show signs of abnormal corrosion, excessive loading, leakage, or if the glass bulb heat responsive element is found empty. (Refer to NFPA-25 (2011 Edition), Section 5.2.1.1.)
4. Detection of Aging Revise IP2 Fire Water System Program procedures Effects acceptance criteria for the primary auxiliary building exhaust, containment building purge exhaust, and containment building pressure relief charcoal units to ensure partial flow blockage can be detected during air flow testing. (Refer to NFPA-25 (2011 Edition), Section 13.4.3.2.2.)

NL-14-147 Attachment 2 Page 61 of 66 Attributes Affected Enhancements

4. Detection of Aging Revise IP2 Fire Water System Program procedures to Effects inspect the nozzles in the charcoal filter units for abnormal corrosion when the charcoal is replaced. (Refer to NFPA-25 (2011 Edition), Sections 13.4.3.2.2 and 14.2.)
4. Detection of Aging Revise IP2 and IP3 Fire Water System Program procedures Effects to perform main drain testing in accordance with NFPA 25 (2011 Edition), Section 13.2.5, on 20 percent of the testable automatic standpipes with at least one main drain test in each building. (Refer to NFPA-25 (2011 Edition), Sections 6.3.1.5 and 13.2.5.)
4. Detection of Aging Revise Fire Water System Program procedures to inspect Effects the interior and exterior of the fire water storage tanks in accordance with NFPA 25 (2011 Edition), Sections 9.2.5.5, 9.2.6 and 9.2.7, with the exception of NFPA Sections 9.2.7.1 and 9.2.7.6. In lieu of testing specified in Section 9.2.7.1, perform holiday testing. In lieu of testing specified in Section 9.2.7.6, perform ultrasonic thickness checks or mechanical measurements of any identified corroded areas at least once every five years.
4. Detection of Aging Revise IP2 Fire Water System Program procedures to Effects inspect and test the deluge system for the boric acid building filter units every two years in accordance with NFPA 25 (2011 Edition) 13.4.3.2.2.
4. Detection of Aging Revise IP2 and IP3 Fire Water System Program procedures Effects to perform an air flow test each refueling outage through the foam system open head nozzles to ensure there is no blockage, and in the event blockage is identified provide instruction that the system shall be cleaned and retested.

(Refer to NFPA-25 (2011 Edition), Section 13.4.3.2.2.)

4. Detection of Aging Revise IP2 Fire Water System Program procedures to Effects remove, inspect for damage and corroded parts, and clean the strainers associated with the supply line to the electric tunnel (refer to DWG LRA-227551-0, Detail B, Coordinate (D-6)), and in the line downstream of the delugqe valve for the primary auxiliary building exhaust and containment building purge filtration units ((refer to DWG LRA-227551-0. Detail E.

Coordinate (E-4)) every five years, or after each flow test.

(Refer to NFPA-25 (2011 Edition), Section 10.2.1.7.)

NL-14-147 Attachment 2 Page 62 of 66 Attributes Affected Enhancements

4. Detection of Aging Revise IP2 and IP3 Fire Water System Program procedures Effects to perform an internal inspection of wet fire water system piping conditions every five years, or after an extended shutdown of greater than one year, by openinq a flushing connection at the end of one main and by removing a closed sprinkler toward the end of one branch line for the purpose of inspecting the interior for evidence of loss of material and the presence of foreigqn organic and inorganic material that could result in flow obstructions or blocka-ge of sprinkler head or nozzles. In the event there are multiple wet pipe systems in a structure, one third will be inspected every five years such that all systems will be inspected during each 15-year period. The procedures will include (1) guidance to perform an evaluation for MIC in the event tubercles or slime are identified, and (2) acceptance criteria that states "no abnormal debris" (i.e., no corrosion products that could impede flow or cause downstream components to become clogged.) Corrective actions will specify that any signs of abnormal corrosion or blockage will be removed, the source and extent of condition determined and corrected, and entered into the corrective action program. (Refer to NFPA-25 (2011 Edition), Section 14.2.)
4. Detection of Aging Revise IP2 Fire Water System Program procedures to Effects perform an internal inspection of dry piping every five years, or after an extended shutdown of greater than one year, for the preaction systems associated with the technical support center computer and uninterruptible power supply room, and the preaction system associated with the electric tunnels by removing a sprinkler toward the end of one branch line or using the inspectors test valve for the purpose of inspecting for the presence of foreign organic and inorganic material.

The procedures will include (1) guidance to perform an evaluation for MIC in the event tubercles or slime are identified, and (2) acceptance criteria that states "no abnormal debris" (i.e., no corrosion products that could impede flow or cause downstream components to become clogged.) Corrective actions will specify that any signs of abnormal corrosion or blockage will be removed, the source and extent of condition determined and corrected, and entered into the corrective action program. (Refer to NFPA-25 (2011 Edition), Section 14.2.)

NL-14-147 Attachment 2 Page 63 of 66 Attributes Affected Enhancements

4. Detection of Aging Revise IP2 Fire Water System Program procedures to Effects perform an internal inspection of the most remote dry piping downstream of the deluge valves every five years, or after an extended shutdown of greater than one year, for the deluge systems associated with the for the primary auxiliary building, containment purge, containment ventilation, and boric acid building charcoal filters, and the foam deluge systems by removing a sprinkler toward the end of one branch line or using the inspectors test valve for the purpose of inspecting for the presence of foreign organic and inorganic material. The procedures will include (1) guidance to perform an evaluation for MIC in the event tubercles or slime are identified, and (2) acceptance criteria that states "no abnormal debris" (i.e., no corrosion products that could impede flow or cause downstream components to become clogged.) Corrective actions will specify that any signs of abnormal corrosion or blockage will be removed, the source and extent of condition determined and corrected, and entered into the corrective action program. (Refer to NFPA-25 (2011 Edition), Section 14.2.)
4. Detection of Aging Revise IP2 and IP3 Fire Water System Program procedures Effects to perform an obstruction evaluation if any of the following conditions exist. (Refer to NFPA-25 (2011 Edition), Section 14.2.)
  • There is an excessive discharge of material during routine flow tests.

" An inspector's test valve is clogged during routine testing.

  • Foreign materials are identified during internal inspections.
  • Sprinkler heads are found clogged during removal or testing.
  • Pin hole leaks are identified in fire water piping.

" After an extended shutdown.

  • There is a 50% increase in time it takes for water to flow out the inspector test valve after the associated dry valve is tripped when compared to the original acceptance criteria or last test.
4. Detection of Aging Revise IP2 and IP3 Fire Water System Program procedures Effects to perform a wall thickness evaluation of any areas identified with excessive accumulation of corrosion products or appreciable localized pitting beyond a normal oxide layer and enter the condition into the corrective action program.

NL-14-147 Attachment 2 Page 64 of 66 Attributes Affected Enhancements (Refer to LR-ISG-2012-02, Section C. iii, (c).)

4. Detection of Aging Revise IP3 Fire Water System Program procedure(s) to test Effects and inspect the water spray system #11 - Charcoal filters associated with the containment purge exhaust, primary auxiliary building exhaust system, and containment pressure relief filtration units in accordance NFPA 25(2011 Edition)

Section 13.4.3.2.2, and the associated sub-steps.

4. Detection of Aging Revise IP3 Fire Water System Program procedure(s) to fully Effects open hydrants, flush at least for one minute, flush until the water is clear, and verify the hydrants drainage takes no longer than 60 minutes. Where drainage is longer than 60 minutes, provide procedural steps to address the situation (e.g., unclog the drain or pump out the hydrant). (Refer to NFPA-25 (2011 Edition), Section 7.3.2.)
4. Detection of Aging Revise IP3 Fire Water System Program procedure(s) to Effects perform an air test to ensure spray patterns are not affected by pluaged nozzles associated with the hydrogen seal oil unit, main boiler feed pump oil reservoir, main lube oil storage, and main lube oil reservoir foam deluge systems.

Where plugged nozzles are identified, the procedure(s) should include a requirement to clean and retest. (Refer to NFPA-25 (2011 Edition), Section 13.4.3.2.2.)

4. Detection of Aging Revise IP3 Fire Water System Program procedure(s) to Effects remove, clean and inspect the strainers associated with electric tunnels and the containment purge exhaust system, primary auxiliary building exhaust system, and containment pressure relief filtration unit for damage and abnormal corrosion. (Refer to NFPA-25 (2011 Edition), Section 10.2.1.7.)
4. Detection of Aging Revise IP3 Fire Water System Program procedure(s) to Effects perform an internal inspection every five years of the remote normally dry portion of the preaction system associated with the with the electric tunnels by removing a sprinkler toward the end of one branch line or using the inspector test valve for the purpose of inspecting for the presence of foreign organic and inorganic material. The procedure that governs

NL-14-147 Attachment 2 Page 65 of 66 Attributes Affected Enhancements inspection of the normally dry pipinq will include (1) guidance to perform an evaluation for MIC in the event tubercles or slime are identified, and (2) acceptance criteria that states "no abnormal debris" (i.e., no corrosion products that could impede flow or cause downstream components to become clogged.) Corrective actions will specify that any signs of abnormal corrosion or blockage will be removed, the source and extent of condition determined and corrected, and entered into the corrective action program. (Refer to NFPA-25 (2011 Edition), Section 14.2.)

4. Detection of Aging Revise IP3 Fire Water System Program procedure(s) to Effects perform an internal inspection every five years of the most remote dry piping downstream of the deluge valves in the deluge systems for the primary auxiliary building exhaust, containment purge, containment pressure relief, and foam systems by removing a sprinkler toward the end of one branch line for the purpose of inspecting for the presence of foreign organic and inorganic material. The procedure that governs inspection of the normally dry piping will include (1) guidance to perform an evaluation for MIC in the event tubercles or slime are identified, and (2) acceptance criteria that states "no abnormal debris" (i.e., no corrosion products that could impede flow or cause downstream components to become clogged.) Corrective actions will specify that any signs of abnormal corrosion or blockage will be removed, the source and extent of condition determined and corrected, and entered into the corrective action program. (Refer to NFPA-25 (2011 Edition), Section 14.2.)

NL-14-147 Attachment 2 Page 66 of 66 B.1.34 SERVICE WATER INTEGRITY Enhancements NORe The following enhancement will be implemented prior to December 31, 2019.

Attributes Affected Enhancements

4. Detection of Aging Effects Revise the appropriate procedures to incorporate actions to manage corrosion issues.

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

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

ATTACHMENT 3 TO NL-14-147 LICENSE RENEWAL APPLICATION IPEC LIST OF REGULATORY COMMITMENTS Rev. 25 ENTERGY NUCLEAR OPERATIONS, INC.

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

NL-14-147 Attachment 3 Page 1 of 20 List of Regulatory Commitments Rev. 25 The following table identifies those actions committed to by Entergy in this document.

Changes are shown as strikethroughs for deletiens 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 Complete A.3.1.1 the bottom surfaces of the condensate storage tanks, NL-13-122 B.1.1 city water tank, and fire water tanks once during the first ten years of the period of extended operation. Deseber.12, Enhance the Aboveground Steel Tanks Program for IP2 and IP3 to require trending of thickness measurements when material loss is detected.

IP2 & IP3: NL-14-147 A.2.1.1 Implement LRA Sections, A.2.1.1, A.3.1.1 and B.1.1, December 31, A.3.1.1 as shown in NL-14-147. 019 31_ A.1.1 2019 B. 1. 1 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 Complete A.3.1.2 B.1.2 materials for low susceptibility to SCC and clarify the IP3:

prohibition on use of lubricants containing MoS 2 for omplete NL-07-153 Audit Items bolting. 201,241, The Bolting Integrity Program manages loss of NL-13-122 270 preload and loss of material for all external bolting. I I

NL-14-147 Attachment 3 Page 2 of 20

  1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION I AUDIT ITEM 3 Implement the Buried Piping and Tanks Inspection 1P2: NL-07-039 A.2.1.5 Program for IP2 and IP3 as described in LRA Section Complete A.3.1.5 NL-13-122 B.1.6 B.1.6.

IP3: NL-07-153 Audit Item This new program will be implemented consistent with December 12, 173 the corresponding program described in NUREG- 2015 1801 Section XI.M34, Buried Piping and Tanks Inspection.

Include in the Buried Piping and Tanks Inspection NL-09-106 Program described in LRA Section B.1.6 a risk assessment of in-scope buried piping and tanks that NL-09-111 includes consideration of the impacts of buried piping or tank leakage and of conditions affecting the risk for corrosion. Classify pipe segments and tanks as having a high, medium or low impact of leakage based on the safety class, the hazard posed by fluid contained in the piping and the impact of leakage on reliable plant operation. Determine corrosion risk through consideration of piping or tank material, soil resistivity, drainage, the presence of cathodic protection and the type of coating. Establish inspection priority and frequency for periodic inspections of the in-scope piping and tanks based on the results of the risk assessment. Perform inspections using inspection techniques with NL1 1-101 demonstrated effectiveness. NL-11-101 4 Enhance the Diesel Fuel Monitoring Program to IP2: NL-07-039 A.2.1.8 include cleaning and inspection of the IP2 GT-1 gas Complete A.3.1.8 NL-13-122 B.1.9 turbine fuel oil storage tanks, IP2 and IP3 EDG fuel oil NL-13-122 Adtie day tanks, IP2 SBO/Appendix R diesel generator fuel December 12, 128, 129, oil day tank, and IP3 Appendix R fuel oil storage tank 2015 132, and day tank once every ten years. NL-08-057 491,492, Enhance the Diesel Fuel Monitoring Program to 510 include quarterly sampling and analysis of the IP2 SBO/Appendix R diesel generator fuel oil day tank, IP2 security diesel fuel oil storage tank, IP2 security diesel fuel oil day tank, and IP3 Appendix R fuel oil storage tank. Particulates, water and sediment checks will be performed on the samples. Filterable solids acceptance criterion will be less than or equal to 10mg/I. 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 1 following tanks once every ten years. IP2: EDG fuel I

NL-14-147 Attachment 3 Page 3 of 20

  1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION

_ AUDIT ITEM 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.

5 Enhance the External Surfaces Monitoring Program 1P2: NL-07-039 A.2.1.10 for IP2 and IP3 to include periodic inspections of Complete A.3.1.10 systems in scope and subject to aging management W NL-13-122 B.1.11 review for license renewal in accordance with 10 CFR 54.4(a)(1) and (a)(3). Inspections shall include areas surrounding the subject systems to identify hazards to those systems. Inspections of nearby systems that could impact the subject systems will include SSCs that are in scope and subject to aging management review for license renewal in accordance with 10 CFR 54.4(a)(2).

IP2& IP3: NL-14-147 A.2.1.10 D m31 A.2.1.10 Implement LRA Sections A.2.1.10. A.3.1.10 and B. 1.11, as shown in NL-14-147. December 31, A.3.1.10 2019 B. 1. 11

NL-14-147 Attachment 3 Page 4 of 20

  1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION I AUDIT ITEM 6 Enhance the Fatigue Monitoring Program for IP2 to oP2: NL-07-039 A.2.1.11 monitor steady state cycles and feedwater cycles or Complete B.1.11 perform an evaluation to determine monitoring is not NL-13-122 B. 1.t12, required. Review the number of allowed events and NL-07-153 Audit Item resolve discrepancies between reference documents 164 and monitoring procedures. IP3:

Enhance the Fatigue Monitoring Program for IP3 to December 12, include all the transients identified. Assure all fatigue 2015 analysis transients are included with the lowest limiting numbers. Update the number of design transients accumulated to date.

7 Enhance the Fire Protection Program to inspect oP2: NL-07-039 A.2.1.12 external surfaces of the IP3 RCP oil collection omplete A.3.1.12 NL-13-122 B.1.13 systems for loss of material each refueling cycle. IP3:

Enhance the Fire Protection Program to explicitly December 12, state that the IP2 and IP3 diesel fire pump engine 015 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 CO 2 fire suppression system for signs of degradation, such as corrosion and mechanical damage at least once every six months.

NL-14-147 Attachment 3 Page 5 of 20

  1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION I__ I/ AUDIT ITEM IP2: NL-07-039 A.2.1.13 8 Enhance the Fire Water Program to include inspection

,omplete A.3.1.13 of IP2 and IP3 hose reels for evidence of corrosion.

NL-13-122 B.1.14 Acceptance criteria will be revised to verify no NL-07-153 Audit Items unacceptable signs of degradation.

Docombor 12L, 105, 106 Enhance the Fire Water Program to replace all or test NL-08-014 a sample of IP2 and IP3 sprinkler heads required for 10 CFR 50.48 using guidance of NFPA 25 (2002 edition), Section 5.3.1.1.1 before the end of the 50-year sprinkler head service life and at 10-year intervals thereafter during the extended period of operation to ensure that signs of degradation, such as corrosion, are detected in a timely manner.

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

Enhance the Fire Water Program to inspect the internal surface of foam based fire suppression tanks.

Acceptance criteria will be enhanced to verify no siqnificant corrosion.

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

2019 B.1.14

NL-14-147 Attachment 3 Page 6 of 20

  1. COMMITMENT IMPLEMENTATION1 SOURCE RELATED SCHEDULE LRA SECTION I AUDIT ITEM IP2: NL-07-039 A.2.1.15 9 Enhance the Flux Thimble Tube Inspection Program Complete A.3.1.15 for IP2 and IP3 to implement comparisons to wear NL-13-122 B.1.16 rates identified in WCAP-12866. Include provisions to IP3:

compare data to the previous performances and December 12, perform evaluations regarding change to test 2015 frequency and scope.

Enhance the Flux Thimble Tube Inspection Program for IP2 and IP3 to specify the acceptance criteria as outlined in WCAP-1 2866 or other plant-specific values based on evaluation of previous test results.

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

NL-14-147 Attachment 3 Page 7 of 20

  1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION

/ AUDIT ITEM IP2: NL-07-039 A.2.1.16 10 Enhance the Heat Exchanger Monitoring Program for Complete A.3.1.16 IP2 and IP3 to include the following heat exchangers NL-13-122 B.1.17, in the scope of the program.

IP3: NL-07-153 Audit Item

  • Safety injection pump lube oil heat exchangers December 12, 52 2015
  • 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
  • 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, I NL-09-018 foulinc, or scalina.

11 Deleted NL-09-056 NL-11-101

NL-14-147 Attachment 3 Page 8 of 20

  1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION I AUDIT ITEM 12 Enhance the Masonry Wall Program for IP2 and IP3 oP2: NL-07-039 A.2.1.18 to specify that the IP1 intake structure is included in omplete A.3.1.18 the program. IP3:NL-13-122 B.1.19

____Complete 13 Enhance the Metal-Enclosed Bus Inspection Program P2: NL-07-039 A.2.1.19 for IP2 and IP3 to visually inspect the external surface Complete A.3.1.19 NL-13-122 B.1.20 of MEB enclosure assemblies for loss of material at IP3: NL-07-153 Audit Items least once every 10 years. The first inspection will 1P3:

occur prior to the period of extended operation and December 12, 124, the acceptance criterion will be no significant loss of 015 NL-08-057 133,519 material. NL-13-077 Enhance the Metal-Enclosed Bus Inspection Program to add acceptance criteria for MEB internal visual inspections to include the absence of indications of dust accumulation on the bus bar, on the insulators, and in the duct, in addition to the absence of indications of moisture intrusion into the duct.

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

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

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 Complete A.3.1.21 B.1 .22. B. .2. I3:NL-13-122 1P3: B.1.22 December 12,

_015

NL-14-147 Attachment 3 Page 9 of 20

  1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION I AUDIT ITEM 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 Complete A.3.1.22 Section B.1.23. NL-13-122 B.1.23 IP3: NL-07-153 Audit item This new program will be implemented consistent with December 12, 173 the corresponding program described in NUREG- 2015 NL-11-032 1801 Section Xl.E3, Inaccessible Medium-Voltage Cables Not Subject To 10 CFR 50.49 Environmental NL-1 1-096 Qualification Requirements.

NL-1 1-101 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 Complete A.3.1.23 Section B.1.24. NL-13-122 B.1.24 IP3: NL-07-153 Audit item This new program will be implemented consistent with December 12, 173 the corresponding program described in NUREG- 2015 1801 Section XI.E2, Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits.

17 Implement the Non-EQ Insulated Cables and 1P2: NL-07-039 A.2.1.24 Connections Program for IP2 and IP3 as described in Complete A.3.1.24 LRA Section B.1.25. NL-13-122 B.1.25 IP3: NL-07-153 Audit item This new program will be implemented consistent with December 12, 173 the corresponding program described in NUREG- 2015 1801 Section XI.E1, Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements.

NL-14-147 Attachment 3 Page 10 of 20 COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION

_ AUDIT ITEM 18 Enhance the Oil Analysis Program for IP2 to sample lP2: NL-07-039 A.2.1.25 and analyze lubricating oil used in the SBO/Appendix Complete A.3.1.25 R diesel generator consistent with the oil analysis for NL-13-122 B.1.26 diesel generator IP3: NL-11-101 other site diesel generators. December 12, Enhance the Oil Analysis Program for IP2 and IP3 to 2015 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.

IP2: NL-07-039 A.2.1.26 19 Implement the One-Time Inspection Program for IP2 oplete A.2.1.26 and IP3 as described in LRA Section B.1.27. Complete A.3.1.26 NL-13-122 B.1.27 This new program will be implemented consistent with IP3: NL-07-153 Audit item the corresponding program described in NUREG- December 12, 173 1801,Section XI.M32, One-Time Inspection. 2015 20 Implement the One-Time Inspection - Small Bore IP2: NL-07-039 A.2.1.27 Piping Program forSecioIP2 and IP3 as described in LRA Complete A.3.1.27 B1.8.NL-13-122 B.1.28 Section B.1.28. IP3: NL-07-153 Audit item This new program will be implemented consistent with December 12, 173 the corresponding program described in NUREG- 2015 1801,Section XI.M35, One-Time Inspection of ASME I Code Class I Small-Bore Piping.

21 Enhance the Periodic Surveillance and Preventive 1P2: NL-07-039 A.2.1.28 Maintenance Program for IP2 and IP3 as necessary Complete A.3.1.28 to assure that the effects of aging will be managed IP3:

such that applicable components will continue to perform their intended functions consistent with the De r1 current licensing basis through the period of extended I operation.

NL-14-147 Attachment 3 Page 11 of 20

  1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION

/ AUDIT ITEM 22 Enhance the Reactor Vessel Surveillance Program for IP2: NL-07-039 A.2.1.31 IP2 and IP3 revising the specimen capsule withdrawal Complete A.3.1.31 NL-13-122 B.1.32 IP3:

schedules to draw and test a standby capsule to cover the peak reactor vessel fluence expected December 12, through the end of the period of extended operation. 2015 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.

IP2: NL-07-039 A.2.1.32 23 Implement the Selective Leaching Program for IP2 omPlete A.2.1.32 and IP3 as described in LRA Section B.1.33. Complete A.3.1.32 NL-13-122 B.1.33 This new program will be implemented consistent with IP3: NL-07-153 Audit item the corresponding program described in NUREG- December 12, 173 1801,Section XI.M33 Selective Leaching of Materials. 2015 24 Enhance the Steam Generator Integrity Program for 1P2: NL-07-039 A.2.1.34 IP2 and IP3 to require that the results of the condition Complete A.3.1.34 NL-13-122 B.1.35 monitoring assessment are compared to the IP3:

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

25 Enhance the Structures Monitoring Program to IP2: NL-07-039 A.2.1.35 explicitly specify that the following structures are Complete A.3.1.35 included in the program. NL-13-122 B.1.36

  • Appendix R diesel generator foundation (IP3) IP3: NL-07-153
  • Appendix R diesel generator fuel oil tank vault December 12, Audit items (1P3) 2015 86, 87, 88,
  • Appendix R diesel generator switchgear and NL-08-057 417 enclosure (IP3)
  • city water storage tank foundation
  • condensate storage tanks foundation (1P3) NL-13-077
  • containment access facility and annex (1P3)
  • discharge canal (IP2/3)

" emergency lighting poles and foundations (IP2/3)

" fire pumphouse (1P2)

  • fire protection pumphouse (IP3)
  • fire water storage tank foundations (1P2/3)
  • gas turbine 1 fuel storage tank foundation
  • maintenance and outage building-elevated passageway (IP2)
  • new station security building (IP2)
  • nuclear service building (IP1)
  • primary water storage tank foundation (IP3) io refueling water storage tank foundation (IP3)

NL-14-147 Attachment 3 Page 12 of 20 COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION II/

I AUDIT ITEM

" security access and office building (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 NL-13-077 Enhance the Structures Monitoring Program for IP2 and IP3 to inspect inaccessible concrete areas that are exposed by excavation for any reason. IP2 and IP3 will also inspect inaccessible concrete areas in environments where observed conditions in accessible areas exposed to the same environment indicate that significant concrete degradation is occurring.

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

Enhance the Structures Monitoring Program for IP2

NL-1 4-147 Attachment 3 Page 13 of 20 COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION I AUDIT ITEM and IP3 to perform an engineering evaluation of NL-08-127 Audit Item groundwater samples to assess aggressiveness of 360 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 and IP3 to perform inspection of the degraded areas Audit Item of the water control structure once per 3 years rather 358 than the normal frequency of once per 5 years during the PEO.

Enhance the Structures Monitoring Program to include more detailed quantitative acceptance criteria for inspections of concrete structures in accordance NL-1 1-032 with ACI 349.3R, "Evaluation of Existing Nuclear Safety-Related Concrete Structures" prior to the period of extended operation.

NL-1 1-101 26 Implement the Thermal Aging Embrittlement of Cast IP2: NL-07-039 A.2.1.36 Austenitic Stainless Steel (CASS) Program for IP2 Complete A.3.1.36 and IP3 as described in LRA Section B.1.37. NL-13-122 B.1.37 IP3: NL-07-153 Audit item This new program will be implemented consistent with December 12, 173 the corresponding program described in NUREG- 2015 1801,Section XI.M12, Thermal Aging Embrittlement I of Cast Austenitic Stainless Steel (CASS) Program.

NL-1 4-147 Attachment 3 Page 14 of 20 COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION

/ AUDIT ITEM 27 Implement the Thermal Aging and Neutron Irradiation 1P2: NL-07-039 A.2.1.37 Embrittlement of Cast Austenitic Stainless Steel Complete A.3.1.37 NL-13-122 B.1.38 (CASS) Program for IP2 and IP3 as described in LRA 1P3: NL-07-153 Audit item Section B.1.38. opet 173 C.omplete 173 This new program will be implemented consistent with the corresponding program described in NUREG-1801 Section XI.M13, Thermal Aging and Neutron Embrittlement of Cast Austenitic Stainless Steel (CASS) Program.

28 Enhance the Water Chemistry Control - Closed oP2 e NL-07-039 A.2.1.39 Cooling Water Program to maintain water chemistry of Complete A.3.1.39 the IP2 SBO/Appendix R diesel generator cooling 1P3: NL-08-057 Audit item system per EPRI guidelines. Iomplete 509 Enhance the Water Chemistry Control - Closed Cooling Water Program to maintain the IP2 and IP3 security generator and fire protection diesel cooling water pH and glycol within limits specified by EPRI guidelines.

29 Enhance the Water Chemistry Control - Primary and 1P2: NL-07-039 A.2.1.40 Secondary Program for IP2 to test sulfates monthly in Complete B.1.41 the RWST with a limit of <1 50 ppb. NL-13-122 30 For aging management of the reactor vessel internals, P2: NL-07-039 A.2.1.41 IPEC will (1) participate in the industry programs for Complete A.3.1.41 investigating and managing aging effects on reactor IP3: N-31 internals; (2) evaluate and implement the results of omplete 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 NL-1 1-107 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 Complete A.3.2.1.2 extended operation as part of the Reactor Vessel P3:NL-13-122 4.2.3 Surveillance Program. December 12, 2015 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.

NL-1 4-147 Attachment 3 Page 15 of 20 COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION II / AUDIT ITEM P2: NL-07-039 A.2.2.2.3 33 At least 2 years prior to entering the period of

,omplete A.3.2.2.3 extended operation, for the locations identified in LRA NL-13-122 4.3.3 Table 4.3-13 (IP2) and LRA Table 4.3-14 (IP3), under P3: NL-07-153 Audit item the Fatigue Monitoring Program, IP2 and IP3 will 3omplete 146 implement one or more of the following:

NL-08-021 (1) Consistent with the Fatigue Monitoring Program, Detection of Aging Effects, update the fatigue usage calculations using refined fatigue analyses to determine valid CUFs less than 1.0 when accounting NL-10-082 for the effects of reactor water environment. This includes applying the appropriate Fen factors to valid CUFs determined in accordance with one of the following:

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

34 IP2 SBO /Appendix R diesel generator will be NL-13-122 2.1.1.3.5 installed and operationaesel gy erator wi bemplet NL-07-078 committed change to the facility meets the NL-08-074 requirements of 10 CFR 50.59(c)(1) and, therefore, a license amendment pursuant to 10 CFR 50.90 is not NL-1 1-101 required. NL-11-101

NL-14-147 Attachment 3 Page 16 of 20

  1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION I AUDIT ITEM 35 Perform a one-time inspection of representative P2: NL-08-127 Audit Item Complete 27 sample area of IP2 containment liner affected by the 1973 event behind the insulation, prior to entering the period of extended operation, to assure liner degradation is not occurring in this area. 1P3: NL-1 1-101 Perform a one-time inspection of representative December 12, sample area of the IP3 containment steel liner at the 2015 juncture with the concrete floor slab, prior to entering the period of extended operation, to assure liner degradation is not occurring in this area.

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

lP2: NL-08-127 Audit Item Perform a one-time inspection and evaluation of a mpNete 36 sample of potentially affected IP2 refueling cavity NL-11-101 359 concrete prior to the period of extended operation. NL-13-122 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.

P2: NL-08-127 Audit Item 37 Enhance the Containment Inservice Inspection (CII- Iomplete 361 IWL) Program to include inspections of the NL-13-122 containment using enhanced characterization of lP3:

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

NL-14-147 Attachment 3 Page 17 of 20

  1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION

/ AUDIT ITEM IP2: NL-08-143 4.2.1 core 38 For Reactor Vessel Fluence, should future loading patterns invalidate the basis for the projected Complete NL-13-122 values of RTpts or CvUSE, updated calculations will lP3:

be provided to the NRC. December 12, 2015 39 Deleted NL-09-079 Evaluate plant specific and appropriate industry oP2: NL-09-106 B.1.6 40 operating experience and incorporate lessons learned Complete B.1.22 in establishing appropriate monitoring and inspection NL-1 3-122 B.1.23 IP3: B. 1.24 frequencies to assess aging effects for the new aging December 12, B.1.25 management programs. Documentation of the 015 B.1.27 operating experience evaluated for each new program B.1.28 will be available on site for NRC review prior to the B.1.33 period of extended operation. B.1.37 B.1.38 IPEC will inspect steam generators for both units to NL-11-032 N/A 41 t.rth assess the condition of the divider plate assembly.

The examination technique used will be capable of Pegiandingiorthe detecting PWSCC in the steam generator divider plate eptember 28, assembly. The IP2 steam generator divider plate .- e 181-074 inspections will be completed within the first ten years of the period of extended operation (PEO). The IP3 NL-1 1-090 steam generator divider plate inspections will be completed within the first refueling outage following Prior to the end the beginning of the PEO. f the first NL-o1-101 refueling outage following the beginning of the IPEO.II

NL-14-147 Attachment 3 Page 18 of 20 COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION

__

1 1 1'/ AUDIT ITEM 42 IPEC will develop a plan for each unit to address the NL-1 1-032 N/A potential for cracking of the primary to secondary pressure boundary due to PWSCC of tube-to-tubesheet welds using one of the following two options.

Option 1 (Analysis)

IPEC will perform an analytical evaluation of the steam generator tube-to-tubesheet welds in order to IP2: NL-1 1-074 establish a technical basis for either determining that Prior to March the tubesheet cladding and welds are not susceptible 2024 NL-1 1-090 to PWSCC, or redefining the pressure boundary in IP3: Prior to the which the tube-to-tubesheet weld is no longer *nd of the first NL-1 1-096 included and, therefore, is not required for reactor "efueling outage coolant pressure boundary function. The redefinition following the of the reactor coolant pressure boundary must be beginning of the approved by the NRC as a license amendment PEO.

request.

Option 2 (Inspection) IP2:

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

a. The condition will be resolved through repair and of the first or engineering evaluation to justify continued refueling outage service, as appropriate, and following the beginning of the
b. An ongoing monitoring program will be PEO.

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

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

IPEC will use the NUREG/CR-6909 methodology in the evaluation of the limiting locations consisting of nickel alloy, if any.

NL-1 4-147 Attachment 3 Page 19 of 20

  1. COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION

/ AUDIT ITEM IP2: NL-1 1-032 N/A 44 IPEC will include written explanation and justification P of any user intervention in future evaluations using the Complete NL-1 1-101 WESTEMS "Design CUF" module. IP3: Prior to NL-13-122 December 12, 2015 45 IPEC will not use the NB-3600 option of the P2: NL-1 1-032 N/A WESTEMS program in future design calculations until omplete NL-1 1-101 the issues identified during the NRC review of the IP3: Prior to NL-13-122 program have been resolved. December 12, 2015 46 Include in the IP2 ISI Program that IPEC will perform IP2: NL-1 1-032 N/A twenty-five volumetric weld metal inspections of Complete NL-1 1-074 socket welds during each 10-year ISI interval NL-1122 scheduled as specified by IWB-2412 of the ASME NL-13-122 Section XI Code during the period of extended operation.

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

47 Deleted. NL-14-093 N/A

NL-14-147 Attachment 3 Page 20 of 20 COMMITMENT IMPLEMENTATION SOURCE RELATED SCHEDULE LRA SECTION i/AUDIT ITEM IP2: NL-12-174 N/A 48 Entergy will visually inspect IPEC underground piping Iomplete within the scope of license renewal and subject to aging management review prior to the period of IP3: Prior to NL-13-122 extended operation and then on a frequency of at December 12, least once every two years during the period of extended operation. This inspection frequency will be maintained unless the piping is subsequently coated in accordance with the preventive actions specified in NUREG-1801 Section XI.M41 as modified by LR-ISG-2011-03. Visual inspections will be supplemented with surface or volumetric non-destructive testing if indications of significant loss of material are observed. Consistent with revised NUREG-1 801 Section XI.M41, such adverse indications will be entered into the plant corrective action program for evaluation of extent of condition and for determination of appropriate corrective actions (e.g., increased inspection frequency, repair, replacement).

49 Recalculate each of the limiting CUFs provided in 1P2: NL-13-052 A.2.2.2 section 4.3 of the LRA for the reactor vessel internals Complete A.3.2.2 to include the reactor coolant environment effects (Fen) as provided in the IPEC Fatigue Monitoring December 12, Program using NUREG/CR-5704 or NUREG/CR- 015 6909. In accordance with the corrective actions specified in the Fatigue Monitoring Program, corrective actions include further CUF re-analysis, and/or repair or replacement of the affected components prior to the CUFen reaching 1.0.

50 Replace the IP2 split pins during the 2016 IP2: NL-13-122 A.2.1.41 refueling outage (2R22). Prior to B.1.42 completion of NL-14-067 2R22 IP3: N/A IP2 & IP3: NL-14-147 A.2.1.33 51 Implement the enhancements to the Service Water December 31, A.3.1.33 Integrity Program described in LRA Section B.1.34, as 019 3.1.33 shown in NL-14-147. 2019 B.1.34

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