ML21076B025

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Update to Subsequent License Renewal Application, Supplement 2
ML21076B025
Person / Time
Site: North Anna  Dominion icon.png
Issue date: 03/17/2021
From: Mark D. Sartain
Virginia Electric & Power Co (VEPCO)
To:
Document Control Desk, Office of Nuclear Reactor Regulation
References
21-075
Download: ML21076B025 (70)
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Text

VIRGINIA ELECTRIC AND POWER COMPANY RICHMOND, VIRGINIA 23261 March 17, 2021 10 CFR 50 10 CFR 51 10 CFR 54 United States Nuclear Regulatory Commission Serial No.: 21-075 Attention: Document Control Desk NRA/DEA: R1 Washington, D.C. 20555-0001 Docket Nos.: 50-338/339 License Nos.: NPF-4/7 VIRGINIA ELECTRIC AND POWER COMPANY NORTH ANNA POWER STATION (NAPS) UNITS 1 AND 2 UPDATE TO SUBSEQUENT LICENSE RENEWAL APPLICATION (SLRA)

SUPPLEMENT 2 By letter dated August 24, 2020 [Agencywide Documents Access and Management System (ADAMS) Package Accession No. ML20246G697], Virginia Electric and Power Company (Dominion Energy Virginia) submitted an application for the subsequent license renewal of Renewed Facility Operating License Nos. NPF-4 and NPF-7 for the North Anna Power Station.

In January 2021 and February 2021, the Nuclear Regulatory Commission (NRC) issued the following final subsequent license renewal (SLR) interim staff guidance (ISG) documents:

NUMBER TITLE Updated Aging Management Criteria for SLR-ISG-2021-04-ELECTRICAL Electrical Portions of Subsequent License (ML20181A395)

Renewal Guidance Updated Aging Management Criteria for SLR-ISG-2021-03-STRUCTURES Structures Portions of Subsequent

{ML20181A381)

License Renewal Guidance Updated Aging Management Criteria for SLR-ISG-2021-02-M EC HAN ICAL Mechanical Portions of Subsequent (ML20181A434)

License Renewal Guidance Updated Aging Management Criteria for SLR-ISG-2021-01-PWRVI Reactor Vessel Internal Components for (ML20217L203)

Pressurized Water Reactors

Serial No.: 21-075 Docket Nos.: 50-338/339 SLRA Update - Supplement 2 Page 2 of 7 Proposed revisions to portions of guidance in NUREG-2191, "Generic Aging Lessons Learned for Subsequent License Renewal (GALL-SLR) Report," issued July 2017, and NUREG-2192, "Standard Review Plan for Review of Subsequent License Renewal Applications for Nuclear Power Plants," issued July 2017 (SRP-SLR) are provided in the final SLR-ISG documents.

Additional information necessary for the NRC staff to complete their technical review because of updated guidance in NUREG-2191 and NUREG-2192 is provided in Enclosures 1 and 2. provides a description of each of the topics that require the SLRA to be supplemented and identifies the affected SLRA section and/or table. Enclosure 2 includes mark-ups of affected SLRA sections and/or tables being supplemented, as described in Enclosure 1. It should be noted that changes to two commitments (Items

  1. 16 and #20) are provided in Table A4.0-1.

To aid the staff in assessing changes, Enclosure 2 shows new text as underlined and deleted text as lined through. Change bars are only shown for new text in the current supplement, Supplement 2. Change bars are not shown for deleted text in Supplement

2. Change bars are also shown for all changes from previous SLRA Supplements.

If there are any questions regarding this submittal or if additional information is needed, please contact Mr. Paul Aitken at (804) 273-2818.

Sincerely, Mark D. Sartain Vice President - Nuclear Engineering and Fleet Support CRAIG D SLY Notary Public COMMONWEALTH OF VIRGINIA Commonwealth of Virginia Reg.# 7518653 ~..i COUNTY OF HENRICO My Commission Expires December 31, 20!.i The foregoing document was acknowledged before me, in and for the County and Commonwealth aforesaid, today by Mark D. Sartain, who is Vice President - Nuclear Engineering and Fleet Support of Virginia Electric and Power Company. He has affirmed before me that he is duly authorized to execute and file the foregoing document in behalf of that Company, and that the statements in the document are true to the best of his knowledge and belief.

Acknowledged before me this \ ,+k day of Marci\. , 2021.

My Commission Expires: --'-I;}.--+1-......I l.-1~f____

Serial No.: 21-075 Docket Nos.: 50-338/339 SLRA Update - Supplement 2 Page 3 of 7 Commitments made in this letter:

The Licensee Commitments identified in Table A4.0-1 of Appendix A, Final Safety Analysis

  • Report Supplement, are proposed to support approval of the subsequent renewed operating licenses and may change during the NRG review period.

Enclosures:

Enclosure 1 - Topics that Require a SLRA Supplement Enclosure 2 - SLRA Mark-ups - Supplement 2

Serial No.: 21-075 Docket Nos.: 50-338/339 SLRA Update - Supplement 2 Page 4 of 7 cc: (w/o Enclosures except *)

U.S. Nuclear Regulatory Commission, Region II Marquis One Tower 245 Peachtree Center Avenue, NE Suite 1200 Atlanta, Georgia 30303-1257 Ms. Lois James

  • NRC Project Manager U.S. Nuclear Regulatory Commission One White Flint North Mail Stop O 11 F1 11555 Rockville Pike Rockville, Maryland 20852-2738 Mr. Tam Tran NRC Project Manager U. S. Nuclear Regulatory Commission One White Flint North Mail Stop O 11 F1 11555 Rockville Pike Rockville, Maryland 20852-2738 Mr. Vaughn Thomas NRC Project Manager U.S. Nuclear Regulatory Commission One White Flint North Mail Stop 04 F-12 11555 Rockville Pike Rockville, Maryland 20852-2738 Mr. G. Edward Miller NRC Senior Project Manager U. S. Nuclear Regulatory Commission One White Flint North Mail Stop 09 E-3 11555 Rockville Pike Rockville, Maryland 20852-2738 NRC Senior Resident Inspector North Anna Power Station

Serial No.: 21-075 Docket Nos.: 50-338/339 SLRA Update - Supplement 2 Page 5 of 7 Mr. Marcus Harris Old Dominion Electric Cooperative Innsbrook Corporate Center, Suite 300 4201 Dominion Boulevard Glen Allen, Virginia 23060 State Health Commissioner Virginia Department of Health James Madison Building - 7th Floor 109 Governor Street Room 730 Richmond, Virginia 23219 Mr. David K. Paylor, Director Virginia Department of Environmental Quality P.O. Box 1105 Richmond, VA 23218 Ms. Melanie D. Davenport, Director Water Permitting Division Virginia Department of Environmental Quality P.O. Box 1105 Richmond, VA 23218 Ms. Bettina Rayfield, Manager Office of Environmental Impact Review Virginia Department of Environmental Quality P.O. Box 1105 Richmond, VA 23218 Mr. Michael Dowd, Director Air Division Virginia Department of Environmental Quality P.O. Box 1105 Richmond, VA 23218 Mr. Justin Williams, Director Division of Land Protection and Revitalization Virginia Department of Environmental Quality P.O. Box 1105 Richmond, VA 23218 Mr. James Golden, Regional Director Virginia Department of Environmental Quality Piedmont Regional Office 4949-A Cox Road Glen Allen, VA 23060

Serial No.: 21-075 Docket Nos.: 50-338/339 SLRA Update Supplement 2 Page 6 of 7 Ms. Jewel Bronaugh, Commissioner Virginia Department of Agriculture & Consumer Services 102 Governor Street Richmond, Virginia 23219 Mr. Jason Bulluck, Director Virginia Department of Conservation & Recreation Virginia Natural Heritage Program 600 East Main Street, 24th Floor Richmond, VA 23219 Mr. Ryan Brown, Executive Director Director's Office Virginia Department of Wildlife Resources P.O. Box 90778 Henrico, VA 23228 Mr. Allen Knapp, Director Virginia Department of Health Office of Environmental Health Services 109 Governor St, 5th Floor Richmond, VA 23129 Ms. Julie Lagan, Director Virginia Department of Historic Resources State Historic Preservation Office 2801 Kensington Ave Richmond, VA 23221 Mr. Steven G. Bowman, Commissioner Virginia Marine Resources Commission 2600 Washington Ave Newport News, VA 23607 Dr. Mary Fabrizio, Professor Virginia Institute of Marine Science School of Marine Science 7509 Roper Rd, Nunnally Hall 135 Gloucester Point, VA 23062 Ms. Angel Deem, Director Virginia Department of Transportation Environmental Division 1401 East Broad St Richmond, VA 23219

Serial No.: 21-075 Docket Nos.: 50-338/339 SLRA Update - Supplement 2 Page 7 of 7 Mr. Stephen Moret, President Virginia Economic Development Partnership 901 East Byrd St Richmond, VA 23219 Mr. William F. Stephens, Director Virginia State Corporation Commission Division of Public Utility Regulation 1300 East Main St, 4th Fl, Tyler Bldg Richmond, VA 23219 Mr. Jeff Caldwell, Director Virginia Department of Emergency Management 10501 Trade Rd Richmond, VA 23236 Mr. Bruce Sterling, Chief Regional Coordinator Virginia Department of Emergency Management 1070 University Blvd Portsmouth, VA 23703

Supplement 2 Serial No.: 21-075 NAPS SLRA Docket Nos.: 50-338/339 Page 1 of 7 Enclosure 1 TOPICS THAT REQUIRE A SLRA SUPPLEMENT Virginia Electric and Power Company (Dominion Energy Virginia)

North Anna Power Station Units 1 and 2

Supplement 2 Serial No.: 21-075 NAPSSLRA Enclosure 1 Page 2 of 7 The following seven topics require the SLRA to be supplemented:

1. Incorporation of SLR-ISG-2021-04-ELECTRICAL: Updated Aging Management Criteria for Electrical Portions of Subsequent License Renewal Guidance
2. Incorporation of SLR-ISG-2021-03-STRUCTURES: Updated Aging Management Criteria for Structures Portions of Subsequent License Renewal Guidance
3. Incorporation of SLR-ISG-2021-02-MECHANICAL: Updated Aging Management Criteria for Mechanical Portions of Subsequent License Renewal Guidance
4. Incorporation of SLR-ISG-2021-01-PWRVI: Updated Aging Management Criteria for Reactor Vessel Internal Components for Pressurized-Water Reactors
5. Fire Water System program (B2.1.16): Enhancement 7 Completion
6. FER 3.5.2.2.1. 7, "Loss of Material (Scaling, Spalling) and Cracking Due to Freeze-Thaw," and FER 3.5.2.2.2.3, "Aging Management of Inaccessible Areas for Group 6 Structures,": Updated for freeze-thaw and leaching of calcium hydroxide and carbonation aging effects requiring aging management for concrete in inaccessible areas of structures
7. One-Time Inspection program: Table A4.0-1, Item 20, Commitment Updated Provided below are details of the seven topics requiring the SLRA to be supplemented.
1. Incorporation of SLR-ISG-2021-04-ELECTRICAL: Updated Aging Management Criteria for Electrical Portions of Subsequent License Renewal Guidance The following SLRA sections incorporated the guidance presented in the draft version of SLR-ISG-2021-04-ELECTRICAL:
  • Electrical Insulation for Inaccessible Medium-Voltage Power Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements program (B2.1.39)
  • Electrical Insulation for Inaccessible Instrument and Control Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements program (B2.1 .40)
  • Electrical Insulation for Inaccessible Low-Voltage Power Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements program (B2.1.41)
  • High Voltage Insulators program (B2.1.45), which includes High voltage insulator AMR lines in SLRA Section 3.6, Aging Management of Electrical and Instrumentation and Controls

Supplement 2 Serial No.: 21-075 NAPS SLRA Enclosure 1 Page 3 of 7 To be consistent with the final version of SLR-ISG-2021-04-ELECTRICAL, the program description of the High Voltage Insulators program (82.1.45) in SLRA Section B2.1.45 is revised to delete the loss of material due to impact of wind driven particles as an aging management consideration.

Based on the above, SLRA Section B2.1.45 is supplemented, as shown in Enclosure 2, to incorporate SLR-ISG-2021-04-ELECTRICAL In addition, as shown in Enclosure 2, SLRA Section 2.1.6, Interim Staff Guidance Discussion, is revised to incorporate the document number of the final issued SLR-ISG.

The NUREG-2191 consistency statements for SLRA Appendix B AMPs referencing the draft SLR-ISG have been updated with the document number of the final issued SLR-ISG. Since these are only editorial changes to update the draft SLR-ISG number (SLR-ISG-Electrical-2020-XX) with the document number of the final issued SLR-ISG (SLR-ISG-2021-04-ELECTRICAL), no SLRA mark-ups are provided in Enclosure 2 for those SLRA Appendix B AMPs.

2. Incorporation of SLR-ISG-2021-03-STRUCTURES: Updated Aging Management Criteria for Structures Portions of Subsequent License Renewal Guidance The following SLRA sections incorporated the guidance presented in the draft version of SLR-ISG-2021-03-STRUCTURES:
  • The Protective Coating Monitoring and Maintenance program (82.1.36)
  • Fatigue waiver further evaluation in SLRA Section 3.5, Aging Management of Containment, Structures, and Component Supports
  • Plant specific concrete aging further evaluation and AMR lines in SLRA Section 3.5, Aging Management of Containment, Structures, and Component Supports Based on the above, SLRA Section 2.1.6, Interim Staff Guidance Discussion, is revised to incorporate the document number of the final issued SLR-ISG, as shown in Enclosure 2.

The NUREG-2191 consistency statements for SLRA Appendix B AMPs referencing the draft SLR-ISG have been updated with the document number of the final issued SLR-ISG. Since these are only editorial changes to update the draft SLR-ISG number (SLR-ISG-Structures-2020-XX)'with the document number of the final issued SLR-ISG {SLR-ISG-2021-03-STRUCTURAL), no SLRA mark-ups are provided in Enclosure 2 for those SLRA Appendix B AMPs.

Supplement 2 Serial No.: 21-075 NAPS SLRA Enclosure 1 Page 4 of 7 There were no additional SLRA changes required because of the final issue of SLR-ISG-2021-03-STRUCTURES beyond the change in Section 2.1.6 and the editorial change associated Appendix B AMP NUREG-2191 consistency statements described above.

3. Incorporation of SLR-ISG-2021-02-MECHANICA:, Updated Aging Management Criteria for Mechanical Portions of Subsequent License Renewal Guidance The following SLRA sections incorporated the guidance presented in the draft version of SLR-ISG-2021-02-MECHANICAL:
  • The Neutron Fluence Monitoring program (B3.2)
  • The Water Chemistry program (B2.1.2) and associated UFSAR Supplement (A 1.2)
  • The Thermal Aging Embrittlement of Gast Austenitic Stainless Steel program (B2.1.6)
  • The Closed Treated Water System program (B2.1.12)
  • The Internal Coatings/Linings for In-Scope Piping, Piping Components Heat Exchangers, and Tanks program (B2.1.28)

To be consistent with the final version of SLR-ISG-2021-02-MECHANICAL, issued in February 2021, the following SLRA sections are revised to include the aging effects of cracking/delamination, change in material properties, and separation in fire barriers:

Table 3.3.1: Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report Table 3.5.2-39: Fire barrier AMR lines in Structures and Component Supports

- Miscellaneous Structural Commodities - Aging Management Evaluation Section 3.5.2.1.39: Summary of aging effects associated with miscellaneous structural commodities Section B2.1.15: Fire Protection program and associated UFSAR Supplement

{A1.15)

Based on the above; the SLRA is supplemented, as shown in Enclosure 2, to include the aging effects of cracking/delamination, change in material properties, and separation.

Supplement 2 Serial No.: 21-075 NAPSSLRA Enclosure 1 Page 5 of 7 In addition, as shown in Enclosure 2, SLRA Section 2.1.6, Interim Staff Guidance Discussion, is revised to incorporate the document number of the final issued SLR-ISG as shown in Enclosure 2.

The NUREG-2191 consistency statements for SLRA Appendix B AMPs referencing the draft SLR-ISG have been updated with the document number of the final issued SLR-ISG. Since these are only editorial changes to update the draft SLR-ISG number (SLR-ISG-Mechanical-2020-XX) with the document number of the final issued SLR-ISG (SLR-ISG-2021-02-MECHANICAL), no SLRA mark-ups are provided in Enclosure 2 for those SLRA Appendix B AMPs.

4. Incorporation of SLR-ISG-2021-01-PWRVI: Updated Aging Management Criteria for Reactor Vessel Internal Components for Pressurized-Water Reactors The SLRA and PWR Vessel Internals program (B2.1. 7) included the changes in inspection and evaluation criteria for PWR reactor vessel components made in MRP-227, Revision 1-A, and other relevant industry documents (e.g., EPRI MRP expert panel reports for 80-year RVI component assessments or relevant industry interim guidance documents).

Section 2.1.6.4 is added to SLRA Section 2.1.6, Interim Staff Guidance Discussion, to discuss SLR-ISG-2021-01-PWRVI, Updated Aging Management Criteria for Reactor Vessel Internal Components for Pressurized-Water Reactors, issued in January 2021.

Additionally, the following SLRA sections are revised to incorporate the guidance in SLR-ISG-2021-01-PWRVI:

FER Section 3.1.2.2.9: Aging Management of Pressurized Water Reactor Vessel Internals (Applicable to Subsequent License Renewal Periods Only)

Table 3.1.1: Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System Evaluated in Chapter IV of the GALL-SLR Report Table 3.1.2-2: Reactor Vessel, Internals, and React9r Coolant System -

Reactor Vessel Internals - Aging Management Evaluation Section B2.1.7: PWR Vessel Internals program and associated UFSAR Supplement (A1 .7)

Based on the above, the SLRA is supplemented, as shown in Enclosure 2, to include the guidance in SLR-ISG-2021-01-PWRVI.

Supplement 2 Serial No.: 21-075 NAPS SLRA Enclosure 1 Page 6 of 7

5. Fire Water System program (B2.1.16): Enhancement 7 Completion The Fire Water System program (82.1.16) Enhancement 7 noted below has been incorporated into procedures and is deleted from SLRA Section 82.1.16 and Table A4.0-1, Item 16.
7. Procedures will be revised for wet pipe sprinkler systems, a one-time test of sprinklers that have been exposed to water including the sample size, sample selection criteria, and minimum time in service of tested sprinklers will be performed. At each unit, a sample of 3% or a maximum of ten sprinklers with no more than four sprinklers per structure shall be tested. Testing is based on a minimum time in service of fifty years and severity of operating conditions for each population.

An editorial correction is made to relocate Enhancement 6 Uockey pump monitoring) in SLRA Section B2.1.16 and SLRA Table A4.0-1 to indicate the enhancement applies to program element 4, element 5 and element 6. The enhancements are renumbered accordingly.

SLRA Section 82.1.16 and Table A4.0-1, Item 16 are supplemented, as shown in , to delete Enhancement 7 and identify it as completed, and relocate Enhancement 6.

6. FER 3.5.2.2.1. 7, "Loss of Material (Scaling, Spa/ling) and Cracking Due to Freeze-Thaw, 11 and FER 3.5.2.2.2.3, "Aging Management of Inaccessible Areas for Group 6 Structures, 11: Updated for freeze-thaw and leaching of calcium hydroxide and carbonation aging effects requiring aging management for concrete in inaccessible areas of structures FER 3.5.2.2.1.7 and FER 3.5.2.2.2.3 are revised to be consistent with the AMR changes regarding freeze-thaw and leaching of calcium hydroxide and carbonation aging effects requiring aging management for concrete in inaccessible areas of structures shown in SLRA Supplement 1 that was provided to the NRC staff on February 4, 2021 [Agencywide Documents Access and Management System (ADAMS) No. ML21035A303] (SIN 20-416).
7. One-Time Inspection program: Table A4.0-1, Item 20, Commitment Updated The Subsequent License Renewal Commitment for the One-Time Inspection program (82.1.20) identified in SLRA Table A4.0-1, Item 20 is updated to incorporate the following

Supplement 2 Serial No.: 21-075 NAPS SLRA Enclosure 1 Page 7 of 7 one-time inspection of steam generator upper shell-to-transition cone welds to be consistent with SLRA Section B2.1.20:

The One-Time Inspection program will perform a magnetic particle test inspection of the continuous circumferential transition cone closure weld and the accessible portions of the upper shell-to-transition cone girth weld on each steam generator (essentially 100% examination coverage of each weld) prior to the subsequent period of extended operation.

SLRA Table A4.0-1, Item 20 is supplemented, as shown in Enclosure 2, to include the one-time inspection of steam generator upper shell-to-transition cone welds noted above.

Serial No.: 21-075 Page 1 of 56 Enclosure 2 SLRA MARK-UPS SUPPLEMENT 2 Virginia Electric and Power Company (Dominion Energy Virginia)

North Anna Power Station Units 1 and 2

Serial No: 21-075 Enclosure 2 North Anna Power Station , Units 1 and 2 Page 2 of 56 Application for Subsequent License Renewal Supplement 2 Scoping and Screening Methodology

  • Group (c) subcomponents (oil, grease, and component filters) : These subcomponents are short-lived and are periodically replaced . Various plant procedures are used in the replacement of oil , grease, and filters in components that are in scope for subsequent license renewal. Therefore, these subcomponents are not subject to an aging management review.
  • Group (d) consumables (system filters, fire extinguishers, fire hoses, and air packs): System filters are replaced in accordance with plant procedures based on vendor manufacturers' requirements and system testing . Fire extinguishers, self-contained breathing air packs, and fire hoses are within the scope of subsequent license renewal but are not subject to aging management because they are replaced based on condition. These components are periodically inspected in accordance with Branch Technical Position APSCB 9.5- 1, NFPA 10A for portable fire extinguishers, 29 CFR 1910.134 for self-contained breathing air packs, and NFPA 1962 for fire hoses. These standards require replacement of equipment based on their condition or performance during testing and inspection. These components are subject to replacements implemented by controlled procedures and are therefore not long-lived and not subject to aging management review.

2.1.6 INTERIM STAFF GUIDANCE DISCUSSION As discussed in NEI 17-01, the NRC has encouraged applicants to address Subsequent License Renewal Interim Staff Guidance (SLR-ISG) documents in the Subsequent License Renewal Applications (SLRA). The following &Fa# SLR-ISGs have been issued for use and comment but have not been incorporated as final and revise the guidance in NUREG-2191 or NUREG-2192~--at the time of submittal:

Serial No: 21-075 Enclosure 2 North Anna Power Station , Units 1 and 2 Page 3 of 56 Application for Subsequent License Renewal Supplement 2 Scoping and Screening Methodology

  • SLR-ISG-2021-01-PWRVI Updated Aging Management Criteria for Reactor (ML20217L203) Vessel Internal Components for Pressurized Water Reactors The following sub-sections provide summaries of how each of the SLR-ISGs are addressed in the SLRA.

2.1.6.1 Updated Aging Management Criteria for Electrical Portions of Subsequent License Renewal Guidance (SLR ISG Eleotrioal 2929 XX)SLR-ISG-2021-04-ELECTRICAL This SLR-ISG provides interim guidance to subsequent license renewal applicants for the following NUREG-2191 and NUREG-2192 Sections:

  • XI.E3A/B/C , Electrical Insulation for Inaccessible Medium Voltage/Instrument and Control/Low-Voltage Power Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements The AMPs are revised to allow 5-year inspections of manholes with water level monitoring and alarms . In addition , there is no need for event-driven inspections if there is no water accumulation in the manholes. The Electrical Insulation for Inaccessible Medium-Voltage Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements program (B2.1.39) , Electrical Insulation for Inaccessible Instrument and Control Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements program (B2 .1.40) , and Electrical Insulation for Inaccessible Low-Voltage Power Cables Not Subject to 1 0 CFR 50.49 Environmental Qualification Requirements program (B2.1.41) .incorporate the guidance presented in this SLR-ISG.
  • XI.E7, High Voltage Insulators The AMP is revised to add polymer and toughened glass high-voltage insulators to the scope and program elements and include all insulators operating at or above medium voltage. The High Voltage Insulators program (B2 .1.45) incorporates the guidance presented in this SLR-ISG.

Page2-36

Serial No: 21-075 Enclosure 2 North Anna Power Station, Units 1 and 2 Page 4 of 56 Application for Subsequent License Renewal Supplement 2 Scoping and Screening Methodology 2.1.6.2 Updated Aging Management Criteria for Structures Portions of Subsequent License Renewal Guidance (SLR ISG Struetures 2929 XX)SLR-ISG-2021-03-STRUCTURES This SLR-ISG provides interim guidance to subsequent license renewal applicants for the following NUREG-2191 and NUREG-2192 Sections:

  • XI.SB, Protective Coating Monitoring and Maintenance The AMP revises the frequency of inservice coating inspection monitoring to no later than 6 years based on trending of the total amount of permitted degraded coatings. The Protective Coating Monitoring and Maintenance program (B2.1.36) incorporates the guidance presented in this SLR-ISG.

An option is provided to perform a further evaluation based on ASME Code, Section Ill ,

Division 1, Subsection NE, fatigue waiver analysis for containment metallic pressure-retaining boundary components that are subject to cyclic loading but have no current licensing basis (CLB) fatigue analysis . If the ASME Code fatigue waiver acceptance criteria are met then cracking due to cyclic loading does not require aging management. Further evaluation and AMR lines are provided in Section 3.5, Aging Management of Containment, Structures and Components Supports.

NUREG-2191 Chapters II and Ill and NUREG-2192, Table 3.5-1 are modified to reflect the option of using plant-specific enhancements to GALL-SLR XI.S2 and XI.S6 AMPs to manage the effects of aging in concrete in lieu of recommended plant-specific aging management programs. Further evaluation and AMR lines are provided in Section 3.5, Aging Management of Containment, Structures and Components Supports.

2.1.6.3 Updated Aging Management Criteria for Mechanical Portions of Subsequent License Renewal Guidance i (SLR ISG Meel=lanieal 2929 XX)SLR-ISG-2021-02-MECHANICAL This SLR-1$. G provides interim guidance to subsequent license renewalI applicants for the following NUREG-2191 and NUREG-2192 Sections:

  • X.M2, Neutron Fluence Monitoring The AMP is revised to reference approaches that have been found to be acceptable in recent staff reviews of extended beltline and reactor vessel internals fluence calculations , as RG Page2-37

Serial No: 21-075 Enclosure 2 North Anna Power Station, Units 1 and 2 Page 5 of 56 Application for Subsequent License Renewal Supplement 2 Scoping and Screening Methodology 1.190 is not applicable. The Neutron Fluence Monitoring program (83 .2) incorporates the guidance presented in this SLR-ISG.

  • XI.M2, Water Chemistry The AMP and UFSAR Supplement are revised to include the latest revision of EPRI guidelines for 8WRs and PWRs. The Water Chemistry program (82.1.2) and UFSAR Supplement (A 1.2) incorporate the guidance presented in this SLR-ISG .
  • XI.M12, Thermal Aging Embrittlement of Cast Austenitic Stainless Steel The AMP was revised to add the 2019 Edition of ASME Code,Section XI, Non-mandatory Appendix C, which provides flaw evaluation procedures for CASS with ferrite content
?
20 percent. The Thermal Aging Embrittlement of Cast Austenitic Stainless Steel program (82.1.6) incorporates the guidance presented in this SLR-ISG
  • XI.M21A, Closed Treated Water System The AMP was revised to include the latest revision of EPRI closed cooling water chemistry guidelines. The Closed Treated Water System program (82. 1.12) incorporates the guidance presented in this SLR-ISG.
  • XI.M26, Fire Protection The SLR-ISG adds new fire barrier AMR Items VII.G.A-805, VII.G.A-806, and VII.G.A-807 to NUREG-2191, Table VII.G, "Fire Protection" and makes conforming changes to NUREG-2192, Table 3 .3-1. AMR lines have been provided in Section 3 .5 , Aging Management of Containment, Structures, and Component Supports. The Fire Protection program (82 .1.15) incorporates the guidance presented in this SLR-ISG.

! oil and include a line item for managing loss of materipl for nickel alloy externally exposed to

  • diesel fuel oil. AMR lines have been provided in Section 3.3, Aging Management of Auxiliary Systems.
  • XI.M42, Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks The AMP was revised to recommend opportunistic inspections, in lieu of periodic inspections, as an acceptable alternative for buried internally coated/lined fire water system piping if certain conditions are met. The Internal Coatings/Linings for In-Scope Piping, Piping Components, Page2-38

Serial No: 21-075 Enclosure 2 North Anna Power Station, Units 1 and 2 Page 6 of 56 Application for Subsequent License Renewal Supplement 2 Scoping and Screening Methodology Heat Exchangers, and Tanks program (82 .1.28) incorporates the guidance presented in this SLR-ISG.

2.1.6.4 Updated Aging Management Criteria for Reactor Vessel Internal Components for Pressurized-Water Reactors SLR-ISG-2021-01-PWRVI The PWR Vessel Internals program (82 .1.7) and associated gap analysis incorporates the guidance presented in this SLR-ISG . The AMP was revised to account for changes in inspection and evaluation criteria for PWR reactor vessel components made in MRP-227, Revision 1-A and in other relevant industry documents (e .g . EPRI MRP expert panel reports for 80-year RVI component assessments or in relevant industry interim guidance documents) . Further evaluation and AMR lines are provided in Section 3.1, Aging Management of Reactor Vessel, Internals, and Reactor Coolant System 2.1.7 GENERIC SAFETY ISSUES In accordance with the guidance in NEI 17-01 and Appendix A.3 of NUREG-2192, review of NRC generic safety issues (GSls) as part of the subsequent license renewal process is required to satisfy 10 CFR 54.29. GS ls designated as unresolved safety issues (USls) and high- and medium-priority issues in NUREG-0933, Appendix 8, that involve aging effects for structures and components subject to an aging management review or time-limited aging analysis evaluation are to be addressed in the LRA. A review of the version of NUREG-0933 current six months prior to the subsequent license renewal application submittal, including the applicable Generic Issue Management Control System Report, determined that there were no outstanding USls, or high- or medium-priority GSls. The GSls noted below were reviewed to assure they did not involve aging effects for structures and components subject to an aging management review or time-limited aging analysis evaluation:

  • GSl-186, Potential Risk and Consequences of Heavy Load Drops in Nuclear Power Plants - This GSI addresses heavy load issues related to crane design and operation .

Aging effects are not central to these issue~. The issue does not involve time limited aging analysis evaluations. This issue is now closed (Reference ML113050589).

  • GSl -189, Susceptibility of Ice Condenser Containments to Early Failure from Hydrogen Combustion during a Severe Accident - This GSI is not applicable to NAPS, which does not have ice condenser containments. This issue is now closed (Reference ML13190A244).
  • GSl-191, Assessment of Debris Accumulation on PWR Sump Performance - This GSI addresses the potential for blockage of containment sump strainers that filter debris from cooling water supplied to the safety injection and containment spray pumps following a Page2-39

Serial No: 21-075 Enclosure 2 North Anna Power Station, Units 1 and 2 Page 7 of 56 Application for Subsequent License Renewal Supplement 2 Aging Management Review 3.1.2.2.9 Aging Management of Pressurized Water Reactor Vessel Internals (Applicable to Subsequent License Renewal Periods Only)

Electric Po 1Ner Research Institute (EPRI) Topical Report {TR) 1022863, "Materials Reliability Program: Pressurized ~"later Reactor Internals Inspection and E~1aluation Guidelines (.0.4RP 227

,11,)" (Agencywide Documents Access and Management System (ADAMS) Accession Nos .

ML12017A191 through ,Di4L12017A197 and ML12017A199), provides the industry's current aging management recommendations for the reactor 1, 1essel internal (RVl) components that a.r:e included in the design of a PWR facility. In this report, the EPRJ Materia,is Re/,iab,Wty Program identified that the foJ.,1ovAng aging mechanisms may be applicable to the design ol the RV! components in these types of facit#ies: (a) SCC, (b) irradiation assisted stress corrosion cracking (JASCC), (c) fatigue, (d) v11ear, (c) neutron irradiat,ion embriWement, (f) thermal aging embriWement, (g) 1, 1oid B'Ne/.,1ing and irradiation growth, or (h) thermal or irradiation enhanced stress rdrnwtion or irradiation enhanced creep. Tho methodology in MRP 227 A was approved by the lVRC in a safety 0~ 1aluation dated December 16, 2011 (ADAMS Accession t1Jo. ML11308/\770), which includes those plant specific appticantl/icensee action items that a licensee or applicant applying the MRP 227 A report wou,1d need to address and reso/~ 10 and apply to its ,(fcensing basis.

The EPRI MRP's functionality ana!yais and failure modes, effects, and critica,(fty analysis bases for grouping Westinghouse designed, B&W designed and Combustion Engineering (CE) designed RVl components into these inspection categories 1Nas based on an assessment of aging effecta and re!e 1* 1ant Nme dependent aging parameters through a cumulative 60 year Ncensing period (i.e.,

40 ,'ears for the initial operating Ncense period plus an additional 20 years during the initial period of 0)(tended operation) . The EPRI MRP has not assessed 'Nhether operation of Westinghouse designed, B&W designed and CE designed reactors during an SLR operating period would ha*,<e any impact on the e><isting susceptibility rankings and inspection categorizations for the RV! components in these designs, as defined in MR,o 227 A or its applicable ,0,4RP bac.lfground documents (e .g ., MRP 191 for ~lilestinghouse designed or CE designed RV! components or MRP 189 for B& W designed components).

As described in GALL SLR ReportAMPXI.M16A, the appNcant may use the MRP 227 A based AMP as an initial reference basis for deve,1oping and defining the AMP that w,iU be applied to the R'.4 components for the subsequent period of o>ctonded operation. J=l.owe*, 1er, to use this altemati~10 basis, GALL SLR Report AMP XJ .M16A recommends that the MRP 227 A based AMP be enhanced to include a gap analysis of the components that are 'Nifhin the scope of the AMP. The gap analysis is a basis for identifying and justifying any potential changes to the MRP 227 A based program that may be necessary to provide reasonab,1e assurance that the effecta of age related degradation *.vii! be managed during the subsequent period of e><tended operation. The criteria for the gap ana/y-sis are described in GALL SLR ReportAMPX!.M16A .

Page3-29

Serial No: 21-075 Enclosure 2 North Anna Power Station , Units 1 and 2 Page 8 of 56 Application for Subsequent License Renewal Supplement 2 Aging Management Review Altemati*lely, the PWR SLRA may define a plant specific AMP for the R'I! components to demonsfl:ate that the R'.4 components b*,~i,1/ be managed in accordance w-ith the requirements of 10 GFR e4.21(a)(3) during the proposed subsequent period of e~ctended operation. Components to be inspected, parameters monitored, monitoring methods, inspection sample size, frequencies, mcpansion criteria, and acceptance criteria are justified in the SLR/',. The t".1RG staff will assess the adequaCJ' of the plant specific AMP against the criteria for the 10 AMP wogram elements that are defined in Section A.1.2.3 of SRP SLR Append/)( A .1.

Electric Power Research Institute (EPRI) Topical Report (TR)-1022863, "Materials Reliabilitv Program : Pressurized Water Reactor Internals Inspection and Evaluation Guidelines (MRP 227 A) " (Agencvwide Documents Access and Management Svstem (ADAMS) Accession Nos .

ML12017A191 through ML12017A197 and ML12017A199). provided the industry's initial set of aging management inspection and evaluation (l&E) recommendations for the reactor vessel internal (RV!) components that are included in the design of a PWR facility. Since the issuance of MRP-227-A on January 9, 2012, EPRI updated its l&E guidelines for the PWR RV/ components in Topical Report No . 3002017168, "Materials Reliabilitv Program : Pressurized Water Reactor Internals Inspection and Evaluation Guidelines (MRP-227, Revision 1-A) " (ADAMS Accession No. ML20175A112). MRP-227, Revision 1-A, incorporated the industry's bases for resolving operating experience and industry lessons learned resulting from component-specific inspections performed since the issuance of MRP-227-A in January 2012. The staff found the guidelines in MRP-227, Revision 1-A, acceptable, as documented in a staff-issued safetv evaluation dated April 25, 2019 (ADAMS Accession No. ML19081A001 / and approved the topical report for use as documented in the staff's letters to the EPRI Materials Reliabilitv Program (MRP) dated February 19, 2020 and Julv 7. 2020 (ADAMS Accession Nos. ML20006D152 and ML20175A149/.

In MRP-227, Revision 1-A, the EPRI MRP identified that the following aging mechanisms mav be applicable to the design of the RV/ components in these tvpes of facilities: (a) stress corrosion cracking (SCCJ, (b) irradiation-assisted stress corrosion cracking (IASCC), (c) fatigue, (d) wear:

(e) neutron irradiation embrittlement, (f) thermal aging embrittlement, (g) void swelling and irradiation growth or component distortion, and (h) thermal or irradiation-enhanced stress relaxation or irradiation enhanced creep.

Page3-30

Serial No: 21-075 Enclosure 2 North Anna Power Station , Units 1 and 2 Page 9 of 56 Application for Subsequent License Renewal Supplement 2 Aging Management Review The EPRI MRP's functionality analysis and failure modes. effects, and criticality analysis bases for grouping Westinghouse-designed, B& W-designed and Combustion Engineering (CE)-designed RV/ components into the applicable inspection categories (as evaluated in MRP-227. Revision 1-A) were based on an assessment of aging effects and relevant time-dependent aging parameters through a cumulative 60-year licensing period (i.e. , 40 years for the initial operating license period plus an additional 20 years during the initial period of extended operation) . The EPRI MRP's assessment in MRP-227, Revision 1-A. did not evaluate whether operation of Westinghouse-designed, B&W designed and CE designed reactors during an SLR operating period (60 to 80 years) would have any impact on the existing susceptibility rankings and inspection categorizations for the RV/ components in these designs. as defined in MRP-227.

Revision 1-A or the applicable MRP background documents (e .g .* MRP-191. Revision 1. for Westinghouse-designed or CE-designed RV/ components or MRP-189. Revision 2 . for B&W-designed components) .

As described in GALL-SLR Report AMP XI.M16A. the applicant may use the MRP-227. Revision 1-A based AMP as an initial reference basis for developing and defining the AMP that will be applied to the RV/ components for the subsequent period of extended operation. However. to use this alternative basis. GALL-SLR Report AMP XI.M16A recommends that the MRP-227. Revision 1-A based AMP be enhanced to include a gap analysis of the components that are within the scope of the AMP The gap analysis is a basis for identifying and iustifying any potential changes to the MRP-227. Revision 1-A based program that are necessary to provide reasonable assurance that the effects of age-related degradation will be managed during the subsequent period of extended operation. The criteria for the gap analysis are described in GALL-SLR Report AMP XI.M16A. If a gap analysis is needed to establish the appropriate aging management criteria for the RV/ components. the applicant has the option of including the gap analysis in the SLRA or making the gap analysis and any supporting gap analysis documents available in the in-office audit portal for the SLRA review.

Subsequent license renewal (SLR) applicants for units of a PWR design will no longer need to include separate SLRA Appendix C section responses in resolution of the AILA/s previously issued on MRP-227-A because the AILA/s were resolved and closed by the staff in the April 25.

2019. safety evaluation for MRP-227. Revision 1-A. The sole AILA/ issued by the staff in the safety evaluation dated April 25, 2019. relates to an applicant's methods and timing of inspections that will be applied to the baffle-to-former bolts or core shroud bolts in the plant design . Since an applicant's resolution of this AILA/ can be appropriately addressed in the "Operating Experience" program element discussion for the AMP and in the applicant's basis document for the AMP. a separate SLRA Appendix C response for the AILA/ is unnecessary.

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Serial No: 21 -075 Enclosure 2 North Anna Power Station , Units 1 and 2 Page 10 of 56 Application for Subsequent License Renewal Supplement 2 Aging Management Review Alternatively, the PWR SLRA may define a plant-specific AMP for the RV! components to demonstrate that the RV/ components will be managed in accordance with the requirements of 10 CFR 54.21(a)(3) during the proposed subsequent period of extended operation. Components to be inspected. parameters monitored. monitoring methods. inspection sample size. frequencies.

expansion criteria, and acceptance criteria are iustified in the SLRA. If the AMP is a plant-specific program, the NRG staff will assess the adequacy of the plant-specific AMP against the criteria for the 10 AMP program elements that are defined in Section A.1 .2.3 of SRP-SLR Appendix A.1 .

[3 .1.1 028] [3 .1.1-053a] [3.1 .1-053b] [3 .1.1-053c] [3 .1.1-055c] [3.1 .1-059a] [3 .1.1-059b]

[3 . 1.1-059c] [3.1.1-1191 - Electric Power Research Institute (EPRI) Topical Report (TR) 10228633002017168, "Materials Reliability Program: Pressurized Water Reactor Internals Inspection and Evaluation Guidelines (MRP-227, Revision 1-A)" provides the industry's current aging management recommendations for the reactor vessel internal (RVI) components that are included in the design of a PWR facility. MRP-227, Revision 1-A incorporated the industry's bases for resolving operating experience and industry lessons learned resulting from component-specific inspections performed since the issuance of MRP-227-A in January 2012 . The methodology and guidelines in MRP-227 , Revision 1-A ',¥as approvedwere-found acceptable by the NRC ...-as documented in a staff-issued safety evaluation dated December 16 , 2011 , which includes those plant specific applicant/licensee action items that a licensee or applicant April 5, 2019, and approved for use as documented in the staff's letters to the EPRI Materials Reliability Program (MRP) dated February 19, 2020 and July 7, 2020applying the MRP 227 /\. report 'A'ould need to address and resolve and apply to its licensing basis.

The approved MRP-227, Revision 1-A guidelines are based on an assessment of aging effects and relevant time-dependent aging parameters through a cumulative 60-year licensing period (i.e., 40 years for the initial operating license period plus an additional 20 years during the initial period of extended operation)analysis of the reactor ','essel internals that considers the operating conditions up to a 60 year operating period . To address an 80-year operating period, the guidelines have been supplemented with a gap analysis that identifies enhancements to the PWR Vessel Internals (82.1.7) pr.ogram. The MRP-227 , Revision 1-A Gap Analysis for ,PWR Vessel Internals Aging Management provides a basis for identifying and justifying any potential changes to the MRP-227 , Revision ~-A based program that are necessary to provide reasonable assurance that the effects of: age-related degradation will be managed during the subsequent period of extended operation.

The PWR Vessel Internals (82.1.7) program manages the applicable aging effects for the reactor vessel internal components and the Water Chemistry (82.1 .2) program monitors and controls water environments consistent with industry guidelines to ensure that the reactor coolant water environment is favorable to mitigate sec in RVI components.

Page3-32

Serial No: 21-075 Enclosure 2 Page 11 of 56 Table 3.1.1 Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System Evaluated in Chapter IV of the GALL-SLR Report Item Aging Aging Management Further Evaluation Component Discussion Number Effect/Mechanism Program Recommended 3.1.1-028 EelEis!iR§ FIFB§FaR'IS Loss of material due AMP XI.M16A, PWR Vessel Yes (SRP-SLR GeRsisleR! wi!R ~l61~EeG ~~ 9~ . +Ris ileFR is a13f3liee ta SBR'lflBReR!s: StaiRless to wear; cracking due Internals, and AMP XI.M2, Section 3.1.2.2.9) less ef R'!a!eFial feF !Re Risl,el alley sle,..is iRseF! sell a Re steel , Risl,el alley toSCC, Water Chemistry (for sec ea ....*el elEJ38S99 le FeasleF seelaRI aRe R9l:llF8R fll:llE.

WesliR§R8l:lSe 68RIFel F89 iFFaeiatieR assislee mechanisms only) GFasl,iR§ feF !Rese SBR'lflBReA!s aFe aeeFessee 13y Few

§l:liee !1,113e Sl:lf3J39R J3iAS , IASCC, fatigue a.~-~ Q§;3s . See fl:lF!ReF e...aI1,1atieA iA SestieA a.~.~-~-9.

aAe GeR'113l:lstieA Not agglicable. NAPS stainless steel control rod guide EeA§iAeeFiA§ !ReFR'lal SRiele tube sugQQrt gins_(sglil Qins) are "No addi!ional f38SitieAiA§ f3iAs; ~iFsaley 4 m!;lasures" CQmgonents and are addressed b~ rQw GeR'!Bl:lS!ieA EeA§iAeeFiA§ 3.1.1-055c. The associated NUREG-2191 items are not iA69Fe iAS!Fl:lR'leA!atieA used .

!RiR'!l3Ie t1,113es elEflBSee le FeasteF seelaA! aAEl Ael:l!FeA

~Westinghouse-sQecific "Exil!!ing Programs" comQonents : Stainless steel, nickel ;;illo~ and X-750 QontrQI rQQ g!,J iQ!;l

!!.!be suggoct Qins (l!Qiil gins) exgosed to reactor coolant and neutron flux 3.1.1-029 Nickel alloy core shroud and Cracking due to sec, AMP XI.M9, BWR Vessel Yes (SRP-SLR Not applicable - BWR only.

core plate access hole IGSCC, Internals, and AMP XI.M2, Section 3.1.2.2.12) cover (welded covers) irradiation-assisted Water Chemistry exposed to reactor coolant sec 3.1.1-030 Stainless steel, nickel alloy Cracking due to sec, AMP XI.M1, ASME Code, No Not applicable - BWR only.

penetration : drain line IGSCC, cyclic loading Section XI lnservice exposed to reactor coolant Inspection, Subsections IWB,

- IWC, and IWD, and AMP XI.M2, Water Chemistry (SCC, IGSCC mechanisms only)

North Anna Power Station, Units 1 and 2 Page 3-49 Supplement 2 Application for Subsequent License Renewal

Serial No: 21-075 Enclosure 2 Page 12 of 56 Table 3.1.1 Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System Evaluated in Chapter IV of the GALL-SLR Report Item Aging Aging Management Further Evaluation Component Discussion Number Effect/Mechanism Program Recommended 3.1.1-059c Stainless steel (SS , Loss of fracture AMP XI.M16A, PWR Vessel Yes (SRP-SLR Consistent with NUREG-2191 . See further evaluation in including CASS, PH SS or _ toughness due to Internals Section 3.1.2.2.9) Section 3.1.2.2.9.

martensitic SS~ nickel neutron irradiation alloy.-or stellite embrittlement and for Westinghouse reactor CASS, martensitic internal Existing Programs SS, and PH SS due to components exposed to thermal aging reactor coolant and neutron embrittlement; flux changes in dimensions due to void swelling ,

distortion; loss of pre load due to thermal and irradiation-enhanced stress relaxation ,

creep; loss of material due to wear 3.1.1-060 Steel piping , piping Wall thinning due to AMP XI.M17, No Not applicable - BWR only.

components exposed to flow-accelerated Flow-Accelerated Corrosion reactor coolant corros ion 3.1.1-061 Steel steam generator Wall thinning due to AMP XI.M17, No Consistent with NUREG-2191 .

steam nozzle and safe end , flow-accelerated Flow-Accelerated Corrosion feedwater nozzle and safe corrosion end , AFW nozzles and safe ends exposed to secondary feedwater/steam North Anna Power Station, Units 1 and 2 Page 3-64 Supplement 2 Application for Subsequent License Renewal

Serial No: 21 -075 Enclosure 2 Page 13 of 56 Table 3. 1.1 Summary of Aging Management Programs for Reactor Vessel, Internals, and Reacto r Coolant System Evaluated in Chapter IV of the GALL-SLR Report Item Aging Aging Management Further Evaluation Component Discussion Number Effect/Mechanism Program Recommended 3.1 .1-083 Steel steam generator shell Loss of material due AMP XI.M2, Water No Not applicable. Loss of material of the steel steam assembly exposed to to general, pitting, Chemistry, and AMP XI.M32, generator shell assembly exposed to secondary secondary feedwater or crevice corrosion One-Time Inspection feedwater or steam is addressed by item 3.1.1-012 . The steam associated NUREG-2191 aging items are not used .

3.1.1-084 Steel top head enclosure Loss of material due AMP XI.M2, Water No Not applicable - BWR only.

(without cladding): top head , to general , pitting, Chemistry, and AMP XI.M32, top head nozzles (vent, top crevice corrosion One-Time Inspection head spray, RCIC, spare) exposed to reactor coolant 3.1.1-085 Stainless steel, nickel alloy, Loss of material due AMP XI.M2, Water No Not applicable - BWR only.

and steel with nickel alloy or to pitting , crevice Chemistry, and AMP XI.M32, stainless steel cladding corrosion One-Time Inspection reactor vessel flanges, nozzles , penetrations, safe ends, vesselshel~, heads and welds exposed to reactor coolant 3.1.1-086 Stainless steel steam Cracking due to SCC AMP XI.M2, Water Chemistry No Not applicable. NAPS has no in-scope stainless steel generator primary side steam generator primary side divider plate exposed to divider plate exposed to reactor coolant in the Reactor Vessel , Internals , and reactor coolant Reactor Coolant System . The associated NUREG-2191 aging items are not used .

3.1 .1-087 Stainless steel, nickel alloy Loss of material due AMP XI.M2, Water Chemistry No Not applicable. Loss of material for reactor vessel PWR reactor internal to pitting, crevice internal components exposed to reactor coolant and components exposed to corrosion neutron flux is addressed by rows d.1.1 028 , 3.1.1-054, reactor coolant, neutron flux 3.1.1-059a , 3.1.1-059b, and 3.1.1-059c. The associated NUREG-2191 aging items are not used.

North Anna Power Station, Units 1 and 2 Page 3-69 Supplement 2 Application for Subsequent License Renewal

Serial No: 21-075 Enclosure 2 Page 14 of 56 Table 3. 1.1 Summary of Aging Management Programs for Reactor Vessel, Internals, and Reactor Coolant System Evaluated in Chapter IV of the GAl,.L-SLR Report Item Aging Aging Management Further Evaluation Component Discussion Number Effect/Mechanism Program Recommended 3.1 .1-116 Nickel alloy control rod drive Loss of material due Plant-specific aging Yes (SRP-SLR Consistent with NUREG-2191 . Loss of material of nickel penetration nozzles to wear management program Section 3.1 .2.2.10.1) alloy control rod drive components exposed to reactor exposed to reactor coolant coolant is managed by the ASME Code,Section XI lnservice Inspection , Subsections IWB, IWC, and IWD (B2 .1.1) program. See further evaluation in Section 3.1.2.2.10.1.

3.1 .1 -117 Stainless steel, nickel alloy Loss of material due Plant-specific aging Yes (SRP-SLR Not applicable. Loss of material due to wear for stainless control rod drive penetration to wear management program Section 3 .1.2.2.10.2) steel control rod drive penetration nozzle thermal sleeves nozzle thermal sleeves exposed to reactor coolant is addressed by item exposed to reactor coolant 3.1.1-059a. The associated NUREG-2191 aging items are not used.

3.1.1-118 Stainless steel, nickel alloy Cracking due to sec, Plant-specific aging Yes (SRP-SLR Not applicable. Cracking of stainless steel and nickel PWR reactor vessel internal irradiation-assisted management program Section 3.1 .2.2.9) alloy PWR reactor vessel internal components exposed components exposed to sec, cyclic loading, to reactor coolant and neutron flux is addressed by items reactor coolant, neutron flux fatigue 3.1.1-053a, 3.1.1-053b and 3.1.1-053c. The associated NUREG-2191 aging items are not used.

3.1.1-119 Stainless steel, nickel alloy. Loss of fracture Plant-specific aging Yes (SRP-SLR ~lei af3f3lisaele . bass el: fFasli;Fe lei;§RAess , sRaA51es iA stellite PWR reactor vessel toughness due to management program..QL Section 3.1 .2.2.9) eliFAeAsieAs , less el: f3Feleael , aAel less el: FAaleFial el:

internal components QL ne.utron irradiation AMP XI.M16A "PWR Vessel s!aiAless sleel aAel Aisl1el alley PWR FeasleF ~*essel LRA/SLRA-sgecified reactor embrittlement or Internals," with an adjusted iAleFAa l 68FAf38A8A!S 8lEf38588 le FeasleF seelaAI aAel vessel internal comgonent thermal aging site-sgecific or Aei;!FeA fli;ii aFe aele!Fesseel ey ileFAs ;u .1 Qe9a ,

exposed to reactor coolant, embrittlement; comgonent-sgecific aging <l .1.1 Qe9i3 aAEI <l .1.1 Qe9s. TRe assesialeel neutron flux changes in management basis for a ~lbJR~G ~rn1 a§iA§ ileFAs aFe Rel i;seel .Consistent with dimensions due to sgecified reactor vessel NUREG-2191 . Loss of material of stainless steel reactor void swelling or internal comgonent vessel internal comgonents exgosed to reactor coolant, distortion; loss of neutron flu x is manag§d b~ the PWR Vessel Interna ls preload due to thermal (B2.1.7) grogram . See further evaluation in Section and 3.1.2.2.9.

irradiation-enhanced stress relaxation or creep; loss of material due to wear North Anna Power Station, Units 1 and 2 Page 3-75 Supplement 2 Application for Subsequent License Renewal

Serial No: 21-075 Enclosure 2 Page 15 of 56 Table 3. 1.2-2 Reactor Vessel, Internals, and Reactor Coolant System - Reactor Vessel Internals - Aging Management Evaluation Intended Aging Effect Requiring NUREG-2191 Table 1 Subcomponent Material Environment Aging Management Programs Notes Function(s) Management Item Item Alignment and ss StelliterM (E) Reactor coolant Loss of material PWR Vessel Internals (B2 .1.7) IV.B2 .RP-285Ne 3.1.1-059c 6~. 5 interfacing (clevis and neutron flux fle ~

bearing wear Cracking PWR Vessel Internals (B2 .1.7) IV.B2.RP-399 3.1.1-053c M surface)

Water Chemi§l!Y (B2 .1.2) IV.B2.RP-399 3.1.1-053c M Alignment and ss Nickel alloy (E) Reactor coolant Cracking PWR Vessel Internals (B2 .1.7) IV.B2.RP-399 3.1.1-053c A interfacing (clevis and neutron flux Water Chemistry (B2 .1.2) IV.B2.RP-399 3.1.1-053c A insert bolt and Loss of material PWR Vessel Internals (B2 .1.7) IV.B2.RP-~ ~ 3.1.1-059c 6..,_

dowel)

@ a.u g~g §G Alignment and ss Stainless (E) Reactor coolant Loss of preload; changes in PWR Vessel Internals (B2.1.7) IV.B2.RP-300 3.1.1-059a A, 3 interfacing steel and neutron flux dimensions; loss of material (internals hold Cracking PWR Vessel ln!ernals (B2 .1.7) IV.B2.RP-399 3.1.1 -053c .c.

down spring)

Alignment and ss Stainless (E) Reactor coolant Loss of material PWR Vessel Internals (B2.1 .7) IV.B2.RP-424~ 3.1.1-119&.- 6G interfacing steel and neutron flux ~ ~ -~ 9!i9a (thermal sleeve)

Alignment and ss Stainless (E) Reactor coolant Loss of material PWR Vessel Internals (B2 .1.7) IV.B2.RP-299 3.1.1-059c A interfacing (upper steel *and n eutron flux Cracking PWR Vess~I Internals (B2 .1.7) IV.B2.RP-301 3.1.1 -053c 6 core plate Waler Ch~mi§l!Y (B2 .1.2) IV.B2.RP-301 J 1 1-053c 6 alignment pin)

Baffle former ss Stainless (E) Reactor coolant Cracking PWR Vessel Internals (B2 .1.7) IV.B2.RP-275 3.1.1-053a A (baffle edge bolt) steel and neutron flux Water Chemistry (B2 .1.2) IV.B2.RP-275 3.1.1-053a A Loss of fracture toughness; PWR Vessel Internals (B2.1.7) IV.B2.RP-354 3.1.1-059a A changes in dimensions; loss of preload loss of material bass af A9aleFial PWR l,iessel IAleFAals (8~ .~.7) IVB~.RP ~9e a.~-~9e9a G Baffle former ss Stainless (E) Reactor coolant Cracking PWR Vessel Internals (B2 .1.7) IV.B2.RP-271 3.1.1-053a A (baffle former steel and neutron flux Water Chemistry (B2 .1.2) IV.B2.RP-271 3.1.1-053a A bolt)

Loss of fracture toughness; PWR Vessel Internals (B2.1.7) IV.B2.RP-272~ 3.1.1-059a A,-4 changes in dimensions; loss 4 of preload loss of material bass af A9aleFial l=lWR ¥essel IAl9FAals /8~ .~.7) IVB~.RP ~9@ a.u 9e9a G North Anna Power Station, Units 1 and 2 Page 3-88 Supplement 2 Application for Subsequent License Renewal

Serial No: 21-075 Enclosure 2 Page 16 of 56 Table 3.1.2-2 Reactor Vessel, Internals, and Reactor Coolant System - Reactor Vessel Internals - Aging Management Evaluation Intended Aging Effect Requiring NUREG-2191 Table 1 Subcomponent Material Environment Aging Management Programs Notes Function(s) Management Item Item Baffle former FD;SS Stainless (E) Reactor coolant Changes in dimensions PWR Vessel Internals (B2 .1.7) IV. B2. RP-270 3.1.1-059a A (baffle plate) steel and neutron flux Cracking PWR Vessel Internals (B2 .1.7)_ IV.B2 .RP-270a 3.1.1-053a A Water Chemistry (B2.1 .2) IV.B2.RP-270a 3.1.1 -053a A Loss of fracture toughness PWR Vessel Internals (B2 .1.7) IV.B2.RP-270J% 3.1.1-059a A g.

Baffle former ss Stainless (E) Reactor coolant Changes in dimensions PWR Vessel Internals (B2 .1.7) IV.B2.RP-270 3.1.1-059a A (former plate) steel and neutron flux Cracking PWR Vesse l Internals (B2 .1.7) IV.B2.RP-270a 3.1.1-053a A Water Chemistry (B2.1.2) IV.B2.RP-270a 3.1. 1-053a A Loss of fracture toughness PWR Vessel Internals (B2 .1.7l IV.B2 .RP-270 3.1.1-059a 6 Bottom mounted ss Stainless (E) Reactor coolant Cracking PWR Vesse l Internals (B2 .1.7) IV.B2.RP-293 3.1.1-053b A instrumentation steel and neutron flux Loss of fracture toughness;_ PWR Vessel Interna ls (B2.1.7) IV. B2. RP-292~ 3.1.1-059b A (column body) loss of material ~

Bottom-mounted ss Stainless (E) Reactor coolant Loss of material Flux Thimble Tube Inspection (B2.1.24) IV.B2.RP-284 3.1.1-054 A instrumentation steel and neutron flux (flux thimble tube)

Control rod guide ss Stainless (E) Reactor coolant Loss of material PWR Vesse l Internals (B2 .1.7) IV.B2.RP-290b 3.1.1-059b C tube (continuous steel and neutron flux Cracking PWR Vessel Internals (B2 .1.7) IV.B2.RP-296a 3.1.1-053a 6 section sheath and C-tube)

Control rod guide ss Cast (E) Reactor coolant Cracking bass ef fFasti;Fe PWR Vessel Internals (B2.1.7) IV.B2.RP-296a2' 3.1.1-053a 6G tube (guide plate austenitic >250°C (>482°F) !Slcl§hRCSS g:;z. a.u 9!i9a

- Unit 2 only) stainless and neutron flux Water Chemistry (B2 .1.2) IV.B2 .RP-296a 3.1.1-053a 6 steel Loss of fracture toughness* PWR Vesse l Internals (B2 .1.7) IV.B2.RP-296 3.1.1-059a A loss~ of material Control rod guide ss Stainless (E) Reactor coolant Loss of material PWR Vesse l Internals (B2 .1.7) IV.B2.RP-296 3.1.1-059a A tube (guide plate) steel and neutron flux Cracking PWR Vessel Internals (B2 .1.7) IV.B2 .RP-296a 3.1.1-053a 6 Water Chemistry (B2 .1.2) IV.B2 .RP-296a 3.1.1-053a A North Anna Power Station, Units 1 and 2 Page 3-89 Supplement 2 Application for Subsequent License Renewal

Serial No: 21-075 Enclosure 2 Page 17 of 56 Table 3. 1.2-2 Reactor Vessel, Internals, and Reactor Coolant System - Reactor Vessel Internals - Ag ing Management Evaluation Intended Aging Effect Requiring NUREG-2191 Table 1 Subcomponent Material Environment Aging Management Programs Notes Function(s) Management Item Item Control rod guide ss Cast (E) Reactor coolant Cracking PWR Vessel Internals (B2 .1.7) IV.B2.RP-298 3.1.1-053a C tube (lower austenitic >2so 0 c (>482°F) Water Chemistry (B2.1 .2) IV. B2.RP-298 3.1.1-053a C flange - Unit 2 stainless and neutron flux Loss of fracture toughness PWR Vessel Internals (B2 .1.7) IV.B2.RP-297 3.1.1-059a C only) (i;ierii;iheral) steel Control rod guide ss Stainless (E) Reactor coolant Cracking PWR Vessel Internals (B2 .1.7) IV.B2.RP-298 3.1 .1-053a C tube (lower steel and neutron flux Water Chem istry (B2.1.2) IV.B2.RP-298 3.1.1-053a C flange)_

Loss of fracture toughness PWR Vessel Internals (B2.1 .7) IV.B2.RP-297 3.1.1-059a C (i;ierii;iheral)

Control rod guide ss Cast (El Reactor coolant Cracking PWR Vesse l Internals (B2 .1.7) IV.B2.RP-298a 3.1.1-053b .Q tube (lower austenitic >2so*c (>482°Fl Water Chemistry (82 .1.2) IV.B2 .RP-298a 3.1.1-0S~b .Q flange - Unit 2 stainless and ne!,!tron flux Q!]Jy)_ steel (non-i;ierii;iheral)

Loss of fractu re toughness PWR Vessel Internals (B2.1 .7) IV.B2 RP-297a 3.1.1-059b .Q Control rod guide ss Stainless (El Reactor coola nt Cracking PWR Vessel Interna ls (B2 .1.7) IV.B2 .RP-298a 3.1.1-053b .Q tube (lower steel and neutron flux f!aD.g&

(non -i;ierii;iheral) Water Chemistry (B2 .1.2) IV.B2 .RP-298a 3.1.1-053b .Q Loss of fracture toughness PWR Vessel Internals (B2 .1.7) IV.B2 .RP-297a 3.1.1-059b .Q Core barrel ss Stainless (E) Reactor coolant Cracking PWR Vessel Internals (B2 .1.7) IV.B2.RP-273 3.1.1-053b A (barrel former steel and neutron flux Water Chemistry (B2 .1.2) IV.B2.RP-273 3.1.1-053b A bolt)

Loss of fracture toughness; PWR Vessel Internals (B2.1.7) IV.B2.RP-274 3.1.1-059b A changes in dimensions; loss of preload; loss of material Core barrel (core FD;SS Stainless (E) Reactor coolant Loss of material PWR Vessel Internals (B2.1.7) IV.B2.RP-345 3.1.1-059c A barrel flange) steel and neutron flux Cracking PWR Vessel Internals (B2 .1.7) IV.B2 .RP-345a 3.1.1-053c 6.

Water Chemistry (B2 .1.2) IV.B2.RP-345a 3.1.1-053c A North Anna Power Station, Units 1 and 2 Page 3-90 Supplement 2 Application for Subsequent License Renewal

Serial No: 21-075 Enclosure 2 Page 18 of 56 Table 3.1.2-2 Reactor Vessel, Internals, and Reactor Coolant System - Reactor Vessel Internals - Aging Management Evaluation Intended Aging Effect Requiring NUREG-2191 Table 1 Subcomponent Material Environment Aging Management Programs Notes Function(s) Management Item Item Core barrel ss Stainless (E) Reactor coolant Cracking PWR Vessel Internals (B2.1.7) IV.B2.RP-387a 3.1.1-053b A (lower axial weld) steel and neutron flux Water Chemistry (B2 .1.2) IV.B2.RP-387a 3.1.1-053b A Loss of fracture toughness;_ PWR Vessel Internals (B2 .1.7) IV.B2.RP-388a 3.1.1-059b A changes in dimensions Core barrel ss Stainless (E) Reactor coolant Cracking PWR Vessel Internals (B2 .1.7) IV.B2.RP-280 3.1.1-053b A (lower flange steel and neutron flux a.~-~Geaa weld) Water Chemistry (B2.1 .2) IV. B2. RP-280 3.1.1-053b A a.u Geaa Loss of fracture toughness

  • PWR Vessel Internals (B2 .1.7) IV.B2.RP-280a 3.1.1-059b 6 changes in dimensions Core barrel ss Stainless (E) Reactor coolant Cracking PWR Vessel Internals (B2 .1.7) IV.B2 .RP-387 3.1 .1-053a A (lower girth weld) steel and neutron flux Water Chemistry (B2 .1.2) IV.B2.RP-387 3.1.1-053a A Loss of fracture toughness;_ PWR Vessel Internals (B2.1.7) IV.B2.RP-388 3.1.1-059a A ghanges in dimensions Core barrel ss Stainless (E) Reactor coolant Cracking PWR Vessel Internals (B2 .1.7) IV.B2.RP-387a 3.1.1-053b A (middle axial steel and neutron flux Water Chemistry (B2.1.2) IV.B2.RP-387a 3.1.1-053b A weld)

Loss of fracture toughness;_ PWR Vessel Internals (B2.1.7) IV.B2.RP-388a 3.1.1-059b A changes in dimensions Core barrel ss Stainless (E) Reactor coolant Cracking PWR Vessel Internals (B2 .1.7) IV.B2.RP-280~ 3.1.1-053b A (upper axial weld) steel and neutron flux 7a Water Chemistry (B2 .1.2) IV.B2.RP-280~ 3.1.1-053b A 7a Core barrel ss Stainless (E) Reactor coolant Cracking PWR Vessel Internals (B2 .1.7) IV.B2.RP-276 3.1.1-053a A (upper flange steel and neutron flux Water Chemistry (B2.1.2) IV.B2.RP-276 3.1.1-053a A weld)

Core barrel ss Stainless (E) Reactor coolant Cracking PWR Vessel Internals (B2.1 .7) IV.B2.RP-280~ a.u Geaa A (upper girth weld) steel and neutron flux + 3.1.1-053b Water Chemistry (B2.1.2) IV. B2. RP-280~ a.u Geaa A

+ 3.1.1-053b North Anna Power Station, Units 1 and 2 Page 3-91 Supplement 2 Application for Subsequent License Renewal

Serial No: 21-075 Enclosure 2 Page 19 of 56 Table 3.1 .2-2 Reactor Vessel, Internals, and Reactor Coolant System - Reactor Vessel Internals - Ag ing Management Evaluation Intended Aging Effect Requiring NUREG-2191 Table 1 Subcomponent Material Environment Aging Management Programs Notes Function(s) Management Item Item Lower internals ss Stainless (E) Reactor coolant Cracking PWR Vessel Internals (82 .1.7) IV.82.RP-301 3.1.1-053c ~

(fuel alignment steel and neutron flux Water Chemistry (82 .1.2) IV.82 .RP-301 3.1.1 -053c ~

pin)

Loss of material* loss of PWR Vessel Internals (82 .1.7) IV.82.RP-288~ 3.1.1-059c C frag\ur~ tQughne§§. gh 2nges G in dimensions Lower internals FD;SS Stainless (E) Reactor coolant Cracking PWR Vessel Internals (82 .1.7) IV.82.RP-289 3.1.1-053c A (lower core plate) steel and neutron flux Water Chemistry (82 .1.2) IV.82.RP-289 3.1.1-053c A Cumulative fatigue damage TLAA IV 82.RP-303 3.1.1-003 A, 2 Loss of fracture toughness; PWR Vessel Internals (82 .1.7) IV.82.RP-288 3.1.1-059c A changes in dimensions

  • loss of material Lower internals ss StelliteTM (E) Reactor coolant Loss of material PWR Vessel Internals (82 .1.7) IV.82.RP-285Nt. 3.1.1-059c ~~. s (radial support and neutron flux He ~

key wear surface)

Lower support ss Cast (E) Reactor coolant Cracking PWR Vessel Internals (82 .1.7) IV.82.RP-291 3.1.1-053b A (column body) austenitic >250°C (>482°F) Water Chemistry (82 .1.2) IV.82.RP-291 3.1.1-053b A stainless and neutron flux Loss of fracture toughness;_ PWR Vessel Internals (82.1.7) IV.82.RP-290 3.1.1-059b A steel changes in dimensions Lower support ss Stainless (E) Reactor coolant Cracking PWR Vessel Internals (82.1.7) IV.82.RP-286 3.1.1-053b A (column bolt} steel and neutron flux Water Chemistry (82.1.2) IV.82.RP-286 3.1.1-053b A Loss of fracture toughness; PWR Vessel Internals (82.1.7) IV.82.RP-287 3.1.1-059b A loss of preload* changes in dimensions* loss of material Lower support ss Stainless (E) Reactor coolant Cracking PWR Vessel Internals (82 .1 .7) IV.82 .RP-291 a 3.1.1-053b A (lower support steel and neutron flux forging)

North Anna Power Station, Units 1 and 2 Page 3-92 Supplement 2 Application for Subsequent License Renewal

Serial No: 21-075 Enclosure 2 Page 20 of 56 Table 3.1.2-2 Reactor Vessel, Internals, and Reactor Coolant System - Reactor Vessel Internals - Aging Management Evaluation Intended Aging Effect Requiring NUREG-2191 Table 1 Subcomponent Material Environment Aging Management Programs Notes Function(s) Management Item Item No additional FD;SP ;SS Cast (E) Reactor coolant None PWR Vessel Internals (82 .1.7) IV.82.RP-265 3.1.1-055c A, 1 measures austenitic >250°C (>482°F) components stainless and neutron flux steel Nickel alloy (E) Reactor coolant None PWR Vessel Internals (82 .1.7) IV.82.RP-265 3.1.1-055c A, 1 and neutron flux Stainless (E) Reactor coolant None PWR Vessel Internals (82 .1.7) IV.82.RP-265 3.1.1-055c A, 1 steel and neutron flux StelliterM (E) Reactor coolant None PWR Vessel Internals (82 .1.7) None None F, 1 and neutron flux Thermal shield ss Stainless (E) Reactor coolant Cracking PWR Vessel Internals (82.1 .7) IV.82.RP-302 3.1.1-053a A (flexure) steel and neutron flux Water Chemistry (82 .1.2) IV.82.RP-302 3.1.1-053a A Loss of material PWR Vessel Internals (82 .1.7) IV.82.RP-302a 3.1.1-059a A Upper internals ss Stainless (E) Reactor coolant Cracking PWR Vessel Internals (82 .1.7) IV. B2.RP-301 3.1.1-0Q3C Q (fuel alignment steel and neutron flux Water Chemistry /B2 .1.2) IV. 82 .RP-30 1 ~.1.1-0S~c Q pin)

Loss of material: loss of PWR Vessel Internals (82.1.7) IV.82.RP-288~ 3.1.1-059c C._A fracture touqhn~s~ 9 Upper internals ss Stainless (E) Reactor coolant Cracking PWR Vessel Internals (82.1.7) IV.82.RP-291 b 3.1.1-053b A (upper core plate) steel and neutron flux Water Chemistry (82.1 .2) IV.82.RP-291 b 3.1.1-053b A Cumulative fatigue damage TLAA IV.82.RP-303 3.1.1 -003 A ,2 Loss of fracture toughness PWR Vessel Internals (82.1.7) IV.82.RP-290b~ 3.1.1-059b t,r;;.

Upper internals ss Stainless (E) Reactor coolant Cracking PWR Vessel Internals (82.1 .7) IV.82.RP-346 3.1.1-053c A (upper support steel and neutron flux Water Chemistry (82 .1.2) IV.82.RP-346 3.1.1-053c A ring)

Table 3.1.2-2 Plant-Specific Notes:

1. No additional measures components are itemiz:ed in the MRP 227 A Gap Analysis.include-the following : Alignment and interfacing (clevis inserts.

clevis insert locking devices. head and vessel alignment pin (bolts. lock caps. pins). Baffle former (baffle bolting lock bars). BMI (column bolts. collars .

cruciforms. extension bars and tubes. locking devices. nuts: flux thimble tube plugs). CRGT (anti-rotation studs and nuts. enclosure pins. guide tube enclosures. intermediate flanges. guide tube support pins (split pins). housing plates. lock bars. support pin nuts. water flow slot ligaments) . Head North Anna Power Station. Units 1 and 2 Page 3-93 Supplement 2 Application for Subsequent License Renewal

Serial No: 21-075 Enclosure 2 Page 21 of 56 cooling spray nozzles, Irradiation specimen guides. Lower support (column nuts and sleeves). Mixing devices, Radial support key (bolts and lock keys) .

Secondary core support assembly, Upper internals (upper instrumentation conduit and supports). Upper internals (upper support column assemblies).

Upper support plate assembly {upper support plate. deep beam ribs and stiffeners. bolts. locking device). Thermal sh ield {bolts and dowels) .

2. Fatigue analyses were performed for the upper and lower core plates. as described in Section 4.3, Metal Fatigue.
3. Changes in dimensions and loss of materialpreload are not applicable aging effects for the internals hold down spring.
4. Changes in dimensions is not an applicable aging effect for the baffle former boltUpper internals {fuel alignment pin) .
5. The clevis bearing wear surface and the radial support key wear surface are "Primary" inspection components.fabricated of Stellite' . Loss of material due to wear is identified in the MR.P 227 A Gap Analysis for these components. and is managed by the PWR V-essel Internals (82 .1.7) program .
6. The clevis insert bolts and dowels are "Primary" inspection components. Cracking due to SCC or fatigue and loss of material due to wear are the only aging effects requiring management identified in the MRP-227. Revision 1-A, Gap Analysis for these components.

North Anna Power Station. Units 1 and 2 Page 3-94 Supplement 2 Application for Subsequent License Renewal

Serial No: 21-075 Enclosure 2 Page 22 of 56 Table 3.3.1 Summary of Aging Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report Item Aging Aging Management Further Evaluation Component Discussion Number Effect/Mechanism Program Recommended 3.3.1-263 Polymeric piping, piping Hardening or loss of AMP XI.M36, External No Consistent with NUREG-2191, with a different program components, ducting, strength due to Surfaces Monitoring of for some components. The Buried and Underground ducting components, seals polymeric Mechanical Components, or Piping and Tanks (82.1.27) program manages aging of exposed to air, degradation; loss of AMP XI.M38, Inspection of the external surface of underground polymer piping in the condensation, raw water, material due to Internal Surfaces in security system. The Structures Monitoring (82.1.34) raw water (potable), treated peeling, delamination , Miscellaneous Piping and program manages aging of polymeric components in the water, waste water, wear; cracking or Ducting Components Structures and Component Supports (SBO structures for underground, concrete, soil blistering due to offsite power) are aligned to this item.

exposure to ultraviolet light, ozone, radiation ,

or chemical attack; flow blockage due to fouling 3.3.1-265 Steel heat exchanger Reduction of heat AMP XI.M30, Fuel Oil No Not applicable. Reduction of heat transfer of steel heat radiator tubes exposed to transfer due to fouling Chemistry, and XI.M32, exchanger tubes in fuel oil is address in row 3.3.1-266 fuel oil One-Time Inspection because the tubes are of the same material as the fuel oil storage tank, The associated NUREG-2191 aging items are not used.

3.3.1-266 Steel heat exchanger Reduction of heat AMP XI.M30, Fuel Oil No Consistent with NUREG-2191.

radiator tubes exposed to transfer due to fouling Chemistry fuel oil 3.3.1-267 Subliming compound Loss of material due AMP XI.M26, Fire Protection No Consistent with NUREG-2191 . Only components in fireproofing/fire barriers IQ a!;1ra~iQn flaking , Structures and Component Supports (miscellaneous (Thermo_~Lag, Darmatt', vibration; structural commodities) are aligned to this item .

3M' lnteram' , and other cracking/delamin 2!iQn similar materials) exposed due to chemical to air reaction , settlement*

  • change in material grogerties due to g;;imma irradiation exgosure* segaration, sl=laR§e iR R'lateFial 13Fe13efties, sFasl~iR§ ,

elelaR'liRatieR , aREl s013aFatieR North Anna Power Station, Units 1 and 2 Page 3-331 Supplement 2 Application for Subsequent License Renewal

Serial No: 21-075 Enclosure 2 Page 23 of 56 Table 3.3. 1 Summary of Ag ing Management Programs for Auxiliary Systems Evaluated in Chapter VII of the GALL-SLR Report Item Aging Aging Management Further Evaluation C,omponent Discussion Number *Effect/Mechanism Program Recommended 3.3.1-268 Cementitious coating Loss of material due AMP XI.M26 , Fire Protection No Consistent with NUREG-2191. Only components in fireproofing/fire barriers to abrasion Structures and Component Supports (miscellaneous (Pyrocrete, BIO ' K-1 O exfoliation elevated structural commodities) are aligned to this item.

Mortar, Cafecote, and other tem12erature flaking similar materials) exposed s12a lling :

to air cracking/delam ination due jo ghemical reaction elevated tem12erature settlement, vibration

  • change in material 12ro12erties due to elevat!;ld t!;lm[lerature, gamma irradiajion ex12osure* se12aration, 6AaA§e iA fl'laleFial J3F8J3eF!ies , 6Fa6lliA§ ,

elel fl'liA lieA , aAel 59J30FlieA 3.3.1-269 Silicate fireproofing/fire Loss of material due AMP XI.M26, Fire Protection No Consistent with NUREG-2191. Only components in barriers (Marinite, to abrasion, flaking

  • Structures and Component Supports (miscellaneous Kaowool' , Cerafiber, cracking/delamination structural commodities) are aligned to this item .

Cera blanket, or other du!;l jo ~ettlement:

similar materials) exposed change in material to air 12ro12erties due to gamma irradiation ex12osure* se12ara!ion, 6A0A§e iA fl'l !eFi I J3FeJ3eF!ies, eFael1iA§ ,

elel fl'liA lieA , ORB se13 FlieA North Anna Power Station, Units 1 and 2 Page 3-332 Supplement 2 Application for Subsequent License Renewal

Serial No: 21-075 Enclosure 2 North Anna Power Station, Units 1 and 2 Page 24 of 56 Application for Subsequent License Renewal Supplement 2 Aging Management Review 3.5.2.1.39 Miscellaneous Structural Commodities Materials The materials of construction for the miscellaneous structural commodities subcomponents are:

  • Cementitious coatings (Pyrocrete, BIO' K-10 Mortar, Cafecote, and other similar materials)
  • Elastomer
  • Elastomer, rubber and other similar materials
  • Silicates (Marinite, Kaowool', Cerafiber, Cera blanket, or other similar materials)
  • Stainless steel
  • Steel
  • Subliming compound fireproofing/fire barriers (Thermo-Lag, Darmatt', 3M' lnteram', and other similar materials)

Environment The miscellaneous structural commodities subcomponents are exposed to the following environments:

  • Air
  • Air - indoor uncontrolled
  • Air - outdoor
  • Air with borated water leakage
  • Groundwater
  • Soil Page 3-748

Serial No: 21-075 Enclosure 2 North Anna Power Station, Units 1 and 2 Page 25 of 56 Application for Subsequent License Renewal Supplement 2 Aging Management Review Aging Effects Requiring Management The following aging effects, associated with the miscellaneous structural commodities subcomponents, require management:

  • Change in material properties
  • Cracking
  • Cracking/delamination
  • Hardening, loss of strength, shrinkage
  • Loss of material
  • Loss of preload
  • Loss of sealing
  • Separation Aging Management Programs The following aging management programs manage the aging effects for the miscellaneous structural commodities subcomponents:
  • Fire Protection (82.1.15)
  • Structures Monitoring (82.1 .34)

Page 3-749

Serial No: 21-075 Enclosure 2 Page 26 of 56 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Supplement 2 Aging Management Review

[3 .5 .1-011] - NAPS is located in a severe weathering region, as defined in ASTM C-33.

Reinforced concrete for the Containments was designed, constructed, and inspected in accordance with ACI and ASTM standards, which provide for a good quality, dense, well-cured, and low permeability concrete. The concrete mix designs for the Containments contained an air-entraining admixture capable of entraining three to six percent air. Procedural controls ensured quality throughout the batching, mixing, and placement processes. Plant operating experience has not identified any aging effects related to freeze-thaw in accessible areas and the Structures Monitoring (82 .1.34) program and the ASME Section XI, Subsection IWL (82.1.30) program confirm the absence of aging effects by examining normally inaccessible structural components when scheduled maintenance work and planned plant modifications permit access.

Therefore, aging effeots due to freeze tha,.., in inaooessible areas are not applioable , and a plant-specific aging management program or plant-specific enhancements to ASME Section XI, Subsection IWL and/or Structures Monitoring aging management programs are not required for inaccessible areas to manage loss of material and cracking due to freeze thaw.

3.5.2.2.1.8 Cracking Due to Expansion From Reaction With Aggregates Cracking due to expansion from reaction with aggregates could occur in inaccessible areas of concrete elements of PWR and BWR concrete and steel containments. The GALL-SLR Report recommends further evaluation to determine the need for a plant-specific AMP or plant-specific enhancements to ASME Code,Section XI, Subsection IWL, and/or Structures Monitoring AMPs, to manage this aging effect. Acceptance criteria are described in BTP RLSB-1 (Appendix A.1 of SRP-SLR).

[3.5.1-012] - Inspection for Alkali-Silica Reaction (ASR) has been incorporated into the ASME Section XI, Subsection IWL (82.1.30) program. Augmented inspections for the ASME Section XI, Subsection IWL (82.1.30) program include examination for pattern cracking with darkened crack edges, water ingress, and misalignment inspections. ASR inspection results are evaluated by the responsible engineer each inspection cycle to identify changes that could be indicative of ASR development. Such indications will be entered into the Corrective Action Program. The ASME Section XI, Subsection IWL (82 .1.30) program requires that evaluation of inspection results includes consideration of the acceptability of inaccessible areas when conditions exist in accessible areas that could indicate the presence of, or result in, degradation to inaccessible areas. Plant operating experience has not identified any indications of ASR for concrete associated with the Containments. Therefore, a plant-specific aging management program or plant-specific enhancements to ASME Section XI, Subsection IWL and/or Structures Monitoring aging management programs for inaccessible areas are not required to manage cracking due to expansion from reaction with aggregates.

Page 3-760

Serial No: 21-075 Enclosure 2 North Anna Power Station, Units 1 and 2 Page 27 of 56 Application for Subsequent License Renewal Supplement 2 Aging Management Review No other issues related to elevated temperatures affecting concrete structures exposed to air have been identified. Therefore, the aging effects due to elevated temperatures are not applicable for NAPS, and a plant-specific aging management program or plant-specific enhancements to Structures Monitoring aging management program are not required.

3.5.2.2.2.3 Aging Management of Inaccessible Areas for Group 6 Structures Further evaluation is recommended for inaccessible areas of certain Group 6 structure/aging effect combinations as identified below, whether or not they are covered by inspections in accordance with the GALL-SLR Report, AMP XI.S7, "Inspection of Water-Control Structures Associated with Nuclear Power Plants," or Federal Energy Regulatory Commission (FERC)/U.S.

Army Corp of Engineers dam inspection and maintenance procedures.

(1) Loss of material (spa/ling, scaling) and cracking due to freeze-thaw could occur in below-grade inaccessible concrete areas of Group 6 structures. Further evaluation is recommended to determine the need for a plant-specific AMP or plant-specific enhancements to Structures Monitoring AMP, to manage these aging effects of this aging effects for inaccessible areas for plants located in moderate to severe weathering conditions. Acceptance criteria are described in BTP RLSB-1 (Appendix A 1 of SRP-SLR).

(1) [3.5.1-049] - Freeze-Thaw - Reinforced concrete for water-control structures (Group 6) was designed, constructed, and inspected in accordance with ACI and ASTM standards, which provide for a good quality, dense, well-cured, and low permeability concrete. Procedural controls ensured quality throughout the batching, mixing, and placement processes. The concrete mix designs for water-control structures (Group 6) constructed during initial construction contained an air-entraining agent capable of entraining three to five percent air. The concrete mix designs for water-control structures (Group 6) constructed subsequent to initial construction contain an air-entraining agent for freeze-thaw protection consistent with ACI 301 or ACI 318. Plant operating experience has not identified any aging effects related to freeze-thaw in accessible areas and the Structures Monitoring (B2.1.34) program confirms the absence of aging effects by examining normally inaccessible structural components when scheduled maintenance work and planned plant modifications permit 'access. Therefore, aging effects due to freeze th '* in inaccessible areas are not applicable , and a plant-specific aging management program or plant-specific enhancements to Structures Monitoring aging management program are not required for inaccessible areas to manage loss of material and cracking due to freeze thaw.

(2) Cracking due to expansion and reaction with aggregates could occur in inaccessible concrete areas of Group 6 structures. Further evaluation is recommended to determine the need for a plant-specific AMP or plant-specific enhancements to Structures Monitoring AMP, to manage this aging effect. Acceptance criteria are described in BTP RLSB-1 (Appendix A.1 of SRP-SLR).

Page 3-766

Serial No: 21-075 Enclosure 2 Page 28 of 56 Table 3.5.2-39 Structures and Component Supports - Miscellaneous Structural Commodities - Aging Management Evaluation Structural Intended Aging Effect Requiring NUREG-2191 Table 1 Material Environment Aging Management Programs Notes Member Function(s) Management Item Item Fireproofing and EN ;FB;FLB Cementitious (E)Air Qhsingsl in msitslrial Fire Protection (B2.1.15) VII.G.A-806 3.3.1-268 A , 1, fire barriers coatings properties: 2J (Pyrocrete, cracking/delamination

  • loss BIO' K-10 of material*

Mortar, separationGFael1iA§ ; bass af Cafecote, and ffiatefia+

other similar materials)

Elastomer (E)Air Hardening, loss of strength, Fire Protection (B2 .1.15) VII.G.A-19 3.3.1-057 A, 1 shrinkage

, (E)Air Change in material Fire Protection (B2.1.15)

Silicates -- VII.G.A-807 3.3.1-269 A , 1, (Marinite, properties* 2..A_

Kaowool', cracking/delamination

  • loss Cerafiber, of material
  • Cera blanket, separationGFael1iA§ ; bass af or other similar ffiatefia+

materials}

Stainless steel (E)Air Loss of material : cracking Structures Monitoring (B2.1.34) III.B2.T-37b 3.5.1-100 C, 1 Subliming (E)Air Change in material Fire Protection (B2 .1.15) VII.G .A-805 3.3.1-267 A, 1, compounds properties* 2 (Thermo-Lag, cra!;;king/g5llamination

  • loss Darmatt', of material
  • 3M ' s5lparationGFael1iA§ : bass af lnteram' , and ffiatefia+

other similar materials)

Penetration seals EN;FB;FLB;PB Elastomer (E)Air Hardening, loss of strength, Fire Protection (B2 .1.15) VII.G .A-19 3.3.1-057 A shrinkage Elastomer, (E) Air - indoor Loss of sealing Structures Monitoring (B2.1.34) III.A6.TP-7 3.5.1-072 A rubber and uncontrolled other similar (E) Air - outdoor Loss of sealing Structures Monitoring (B2.1 .34) III.A6.TP-7 3.5.1-072 A materials (E) Groundwater Loss of sealing Structures Monitoring (B2 .1.34) III.A6.TP-7 3.5.1-072 A (E) Soil Loss of sealing Structures Monitoring (B2.1.34) II1.A6.TP-7 3.5.1-072 A North Anna Power Station, Units 1 and 2 Page 3-895 Supplement 2 Application for Subsequent License Renewal

Serial No: 21-075 Enclosure 2 Page 29 of 56 Table 3.5.2-39 Structures and Component Supports - Miscellaneous Structural Commodities - Aging Management Evaluation Structural Intended Aging Effect Requiring NUREG-2191 Table 1 Material Environment Aging Management Programs Notes Member Function(s) Management Item Item Penetration ss Steel (E) Air - indoor Loss of material Structures Monitoring (B2.1.34) 111.B3.TP-43 3.5 .1-092 A sleeves uncontrolled (E) Air - outdoor Loss of material Structures Monitoring (B2.1.34) 111.B3.TP-43 3.5.1-092 A (E) Air with borated Loss of material Boric Acid Corrosion (B2 .1.4) 111.B3.T-25 3.5.1-089 C water leakage Seismic gap EN;FB Aluminum (E)Air Loss of material; cracking Structures Monitoring (B2.1.34) III.B2.T-37b 3.5.1-100 C covers Elastomer (E)Air Hardening, loss of strength, Fire Protection (B2 .1.15) VII.G.A-19 3.3.1-057 C

- shrinkage Elastomer, (E) Air - indoor Loss of sealing Structures Monitoring (B2.1.34) III.A6.TP-7 3.5.1-072 A rubber and uncontrolled other similar (E) Air - outdoor Loss of sealing Structures Monitoring (B2.1 .34) III.A6.TP-7 3.5.1-072 A materials Steel (E)Air Loss of material Fire Protection (B2.1.15) VII.G .A-21 3.3.1-059 C (E) Air - indoor Loss of material Structures Monitoring (B2.1.34) III.A3.TP-302 3.5.1-077 A uncontrolled (E) Air - outdoor Loss of material Structures Monitoring (B2 .1.34) 111.A3.TP-302 3.5.1-077 A Seismic gap filler EN Elastomer, (E) Air - indoor Loss of sealing Structures Monitoring (B2.1.34) III.A6.TP-7 3.5.1-072 A material rubber and uncontrolled other similar (E) Air - outdoor Loss of sealing Structures Monitoring (B2.1.34) III.A6.TP-7 3.5.1-072 A materials Table 3.5.2-39 Plant-Specific Notes:

1. Fireproofing and fire barriers include fire stops, fire wraps, fire barrier seals, coatings, and radiant energy shields.
2. Aging management of change of material properties is applicable to fireproofing and fire barriers exposed to radiation dose greater than 1 x 1ofr_

rads .Change in material properties is an aging effeet not being managed .

3. Change of material properties and loss of material due to elevated temperature are not applicable to cementitious coatings since these fireproofing and fire barrier materials are not exposed to an environment where the general area temperature exceeds 150°F (65 .6°C) or the local area temperature exceeds 200°F (93.3°C) .
4. Separation is the destruction of adhesion between a fireproofing or fire barrier material and an adjacent surface. Adhesion to adjacent surfaces is not relied upon for fireproofing and fire barrier silicate materials; therefore, separation is not an aging effect that requires aging management for silicates.

North Anna Power Station, Units 1 and 2 Page 3-896 Supplement 2 Application for Subsequent License Renewal

Serial No: 21-075 Enclosure 2 North Anna Power Station, Units 1 and 2 Page 30 of 56 Application for Subsequent License Renewal Supplement 2 Appendix B -Aging Management Programs 82.1.7 PWR Vessel Internals Program Description The PWR Vessel Internals program is an existing condition monitoring program that manages change in dimensions due to void swelling, cracking, loss of fracture toughness, loss of material, and loss of preload for the reactor vessel internals (RVI) . The aging effect of cracking includes stress corrosion cracking, primary water stress corrosion cracking, irradiation-assisted stress corrosion cracking, and cracking due to fatigue/cyclic loading. Degradation due to loss of material can be induced by wear, and loss of fracture toughness is the result of thermal aging and neutron irradiation embrittlement. Potential causes for the aging effect of changes in dimensions are void swelling or distortion, and loss of preload can result from thermal and irradiation-enhanced stress relaxation or creep.

SLR-ISG-2021-01-PWRVI includes provisions for a PWR Vessel Internals program to rely on implementation of guidelines from either MRP-227, Revision 1- A as supplemented by a gap analysis, or an acceptable generic report such as an NRC-approved version of MRP-227 that addresses 80 years of operation . -=R=teThis PWR Vessel Internals program relies on implementation of the inspection and evaluation guidelines in Electric Power Research Institute (EPRI) Technical Report 3002017168, "Materials Reliability Program: Pressurized Water Reactor Internals Inspection and Evaluation Guidelines (MRP-227, Revision 1-A)," (ADAMS Accession No. ML19339G364) and EPRI Technical Report 3002010399, "Materials Reliability Program: Inspection Standard for Pressurized Water Reactor Internals - 2018 Update (MRP-228, Rev. 3)," (ADAMS Accession No . ML19081A057) to manage the aging effects on the reactor vessel internal components, as supplemented by a gap analysis. The guidelines listed in MRP-227, Revision 1-A, provide an appropriate aging management methodology for the RVI components up to a 60-year operating period. The EPRI basis document that provides functionality analyses for the aging management methodology is Technical Report 3002007955, "Materials Reliability Program:

Functionality Analysis for Westinghouse and Combustion Engineering Representative PWR Internals (MRP-230, Revision 2, Supplement 1)" (ADAMS Accession No. ML17289A507). The failure modes, effects, and criticality analysis from EPRI Technical Report 3002013220, "Materials Reliability Program: Screening, Categorization, and Ranking of Reactor Internals Components for Westinghouse and Combustion Engineering PWR Designs (MRP-191, Revision 2)" (ADAMS Accession No. ML19081A057) provides the basis for grouping the reactor internals components into inspection categories by assessing aging effects and relevant time-dependent aging parameters.

For the 80-year operating period, aging management is based on the EPRI documents listed for the 60-year period, and a gap analysis that integrates the interim guidance from MRP 2018-022, "Transmittal of MRP-191 Screening, Ranking, and Categorization Results and Interim Guidance in Support of Subsequent License Renewal at U.S. PWR Plants," (ADAMS Accession No. ML19081A061) for additional inspections not listed in MRP-227, Revision 1-A.

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Serial No: 21-075 Enclosure 2 North Anna Power Station, Units 1 and 2 Page 31 of 56 Application for Subsequent License Renewal Supplement 2 Appendix B -Aging Management Programs The results from the gap analysis are shown below:

  • The following listing identifies the changes that are included in the PWR Vessel Internals program based on MRP 2018-022:
a. Clevis insert bolts {Alignment and Interfacing Components) were elevated from Existing Programs component to Primary component. The scope of this item was expanded to include the clevis insert dowels.
b. Thermal sleeves (Alignment and Interfacing Components) were added as a Primary component.
c. Radial support keys Stellite TM wear surface (Radial Support Keys) was added as a Primary component.
d. Clevis bearing Stellite' wear surface (Alignment and Interfacing Components) was added as a Primary component.
e. Fuel alignment pins (Malcomized) (Upper Internals Assembly) were added as an Existing Programs component.
f. Fuel alignment pins (Malcomized) (Lower Internals Assembly) were added as an Existing Programs component.
  • For the 80-year operating period, the gap analysis further integrates guidance for inspections of the following components:
a. Control rod guide tube (CRGT) assembly continuous section sheath and C-tube (CRGT Assembly) expansion component inspections in accordance with WCAP-17451-P, Revision 2, "Reactor Internals Guide Tube Wear - Westinghouse Domestic Fleet Operational Projections" (ADAMS Accession No. ML19262E593).
b. One-time inspections of the core barrel middle axial weld (MAW) and lower axial weld (LAW) (Core Barrel Assembly) primary component inspections in accordance with guidance provided in MRP 2019-009, "Transmittal of NEI 03-08 'Good Practice' Interim Guidance Regarding MRP-227-A and MRP-227, Revision 1 PWR Core Barrel and Core Support Barrel Inspection Requirements" (ADAMS Accession No. ML19249B102).

The selection of RVI components to be inspected is based on a four~step ranking process that includes the designations of "Primary", "Expansion", and "Existing Programs" (such as American Society of Mechanical Engineers Boiler and Pressure Vessel Code (ASME Code),Section XI, Examination Category B-N-3, examinations of core support structures), and "no additional measures". The program includes expanding examinations (i.e., "expansion" components) if the observed extent of degradation for the "primary" components exceeds acceptance criteria. The identified examinations for RVI components provide reasonable assurance that the effects of age-related degradation mechanisms will be managed during the subsequent period of extended operation.

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Serial No: 21-075 Enclosure 2 North Anna Power Station, Units 1 and 2 Page 32 of 56 Application for Subsequent License Renewal Supplement 2 Appendix B -Aging Management Programs The PWR Vessel Internals program is implemented as a Fleet program at Dominion. The Fleet program requirements and Fleet implementation procedures have been previously reviewed and evaluated by the NRC Staff and a determination was made that the effects of aging will be adequately managed so that the intended function(s) will be maintained consistent with the CLB for the subsequent period of extended operation, as required by 10 CFR 54 .21(a)(3) (ADAMS Accession No. ML19360A020).

NUREG-2191 Consistency The PWR Vessel Internals program is an existing program that, following enhancement, will be consistent, with NUREG - 2191, SectionXI.M16A, PWR Vessel Internals~

SLR-ISG-2021-01-PWRVI, Updated Aging Management Criteria for Reactor Vessel Internal Components for Pressurized-Water Reactors.

Exception Summary None Enhancements Prior to the subsequent period of extended operation , the following enhancement(s) will be implemented in the following program element(s):

Detection of Aging Effects (Element 4)

1. Procedures will be revised to provide guidance for inspections of the following reactor vessel internal components in accordance with the referenced report for each item:
a. Control rod guide tube (CRGT) lower flange weld (MRP-227, Revision 1-A, "Materials Reliability Program: Pressurized Water Reactor Internals Inspection and Evaluation Guidelines")
b. CRGT guide plates (cards) and the lower guide tube continuous section sheaths and C-tubes (WCAP - 17451-P, Revision 2, "Reactor Internals Guide Tube Wear -

Westinghouse Domestic Fleet Operational Projections") (Revised - Supplement 1)

c. i Core barrel upper flange weld (UFW) (MRP-227, Revision 1-A)
d. Core barrel lower girth weld (LGW) (MRP-227, Revision 1-A)
e. Core barrel middle axial weld (MAW) and lower axial weld (LAW) (MRP-227, Revision 1-A)
f. Core barrel upper axial weld (UAW) (MRP-227, Revision 1-A)
g. Core barrel upper girth weld (UGW) (MRP-227, Revision 1-A)

\ .

h. Core barrel lower flange weld (LFW) (MRP-227, Revision 1-A)
i. Baffle-edge bolts (M RP-227, Revision 1-A)

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Serial No: 21-075 Enclosure 2 North Anna Power Station, Units 1 and 2 Page 33 of 56 Application for Subsequent License Renewal Supplement 2 Appendix B -Aging Management Programs

j. Baffle plates (MRP-227, Revision 1-A)
k. Baffle-former bolts (MRP-227, Revision 1-A)

I. Barrel-former bolts (MRP-227, Revision 1-A)

m. Bottom-mounted instrumentation column bodies (MRP-227, Revision 1-A)
n. Lower support column bodies (MRP-227, Revision 1-A)
o. Lower support column bolts (MRP-227, Revision 1-A)
p. Clevis insert bolts (MRP 2018-022, "Transmittal of MRP-191 Screening, Ranking, and Categorization Results and Interim Guidance in Support of Subsequent License Renewal at U.S. PWR Plants")
q. Clevis insert dowels (MRP 2018-022)
r. Stel!ite ' wear surface on radial support keys (M RP 2018-022)
s. Stellite' wear surface on clevis inserts (MRP 2018-022)
t. Fuel alignment pins for lower core plate (MRP 2018-022)
u. Fuel alignment pins for upper core plate (MRP 2018-022)
2. (Deleted - Supplement 1)

Detection of Aging Effects (Element 4) and Acceptance Criteria (Element 6)

3. Procedures will be revised to provide acceptance criteria for inspection results for the following reactor vessel internal components in accordance with MRP-227, Revision 1-A:
a. Thermal shield flexures
b. Lower support forging
c. Upper core plate
4. Procedures will be revised to provide guidance for one-time inspections of the core barrel MAW and LAW in accordance with MRP 2019-009, "Transmittal of NEI 03-08 'Good Practice' Interim Guidance Regarding MRP-227-A and MRP-227, Revision 1, PWR Core Barrel and Core Support Barrel Inspection Requirements".

PageB-53

Serial No: 21-075 Enclosure 2 North Anna Power Station, Units 1 and 2 Page 34 of 56 Application for Subsequent License Renewal Supplement 2 Appendix B - Aging Management Programs Operating Experience Summary The following examples of operating experience provide objective evidence that the PWR Vessel Internals prog ram has been, and will be effective in managing the aging effects for SSCs within the scope of the program so that the intended functions will be maintained consistent with the current licensing basis during the subsequent period of extended operation.

1. In April 2010, during the Unit 2 reactor vessel 10-year inservice inspection , slight damage was noted in the vessel core barrel keyways at 0° and 90 °. The keyways were bright and shiny indicating a recent rub when the core barrel was pulled. An Engineering evaluation was performed in accordance with ASME Code,Section XI requirements for visual examinations (VT-3) . Viewing the areas from varying angles and directions indicated that the areas were localized to the surface without any gouging or depth. These localized shiny areas were not considered recordable VT-3 indications.
2. In May 2016, an assessment was performed to determine the progress and substance of license commitment closure and readiness for the IP71003 NRC Phase I inspection to be conducted during the Fall 2016 Unit 1 refueling outage. The conclusion was reached that no performance deficiencies or learning opportunities were identified for the Reactor Vessel Internals Inspection AMA (UFSAR Section 18.2.15).
3. In September 2016, during the Unit 1 refueling outage, the core barrel baffle-to-former bolts were examined. Of the 1088 bolts, 1081 were examined, and three bolts determined to contain flaw indications. The remaining seven bolts could not be tested due to locking bars preventing proper contact with the bolt heads. The locking bars and welds were intact, and there was no indication of degradation. The recorded flaw conditions were determined to be acceptable in accordance with established criteria. The baffle-former assembly retained its structural integrity and continued to perform its intended function.
4. In September 2016, a tie-rod hole on Unit 1 control rod guide tube (CRGT) J-7, Card 7, was found to be oval instead of circular. This was a rejectable indication because the hole is shown as round on inspection documents. The suspected cause was a fabrication error that occurred when the pilot hole for the tie rod was drilled in the incorrect position. When a correction was made during fit-up, the tie-rod hole that should have been circular became oblong. There have been no other operational issues related to guide card wear, or control rod performance in rod drop and rod operability tests for this CRGT assembly. The CRGT J-7 continued to perform its intended function .
5. In December 2016, as part of the oversight review activities, a_review of procedures credited by initial license renewal AMAs was conducted to confirm the following:
  • Procedures were consistent with the licensing basis and bases documents PageB-54

Serial No: 21-075 Enclosure 2 North Anna Power Station, Units 1 and 2 Page 35 of 56 Application for Subsequent License Renewal Supplement 2 Appendix B -Aging Management Programs

  • Procedures contained a reference to conduct an aging management review prior to revising
  • Procedures credited for license renewal were identified by an appropriate program indicator and contained a reference to a license renewal document Procedure changes were completed as necessary to ensure the above items were satisfied.
6. In May 2017, an assessment was performed to determine the progress and substance of license commitment closure and readiness for the IP71003 NRC Phase II inspection to be conducted for Units 1 and 2 during November through December 2017. The conclusion was reached that no areas for improvement or enhancements were identified for the Reactor Vessel Internals Inspection AMA (UFSAR Section 18.2.15).
7. In March 2018, during the Unit 1 10-year inservice inspection visual examinations of the reactor vessel radial support clevis inserts, wear was identified on the mating surfaces at 0°,

90°, 180° and 270°. Further investigation identified wear on the corresponding surfaces of the radial support keys. Wear was only identified on one side of the clevis and corresponding key.

No wear was identified on the opposite side of the clevis insert or radial support key at any of these locations. The lower radial support components use an interference-fit between the clevis insert and the radial keys to provide structural support. The wear observed did not change the capability of the clevis inserts and radial support keys to perform their intended function.

8. In April 2019, an effectiveness review was performed on the Reactor Vessel Internals Inspection AMA (UFSAR Section 18.2.15). The AMA was evaluated against the performance criteria identified in NEI 14-12, "Aging Management Program Effectiveness". No gaps were identified by the effectiveness review.
9. MRP-227-A Compliance Inspections Page B-55

Serial No: 21-075 Enclosure 2 North Anna Power Station, Units 1 and 2 Page 36 of 56 Application for Subsequent License Renewal Supplement 2 Appendix B -Aging Management Programs Fall 2016 (Unit 1) and Spring 2019 (Unit 2) - During these dates, the initial phase of inspections were performed for MRP-227-A compliance, and included the following RVI components:

  • Core barrel assembly upper girth weld
  • Baffle-former assembly baffle-edge bolts
  • Baffle-former assembly baffle-former bolts
  • Baffle-former assembly baffle plates seams (examinations from the top and bottom of the formers for indications of void swelling or vertical displacement)
  • Alignment and interfacing components internals hold down spring Spring 2018 (Unit 1) - The Phase 2 inspections were completed for MRP-227-A compliance, and included the following RVI components:
  • Core barrel assembly lower girth weld
  • Baffle-former assembly high-fluence baffle plates and seams (examination for evidence of warping or misalignment)
  • Thermal shield assembly thermal shield flexures
  • Core barrel lower radial support clevis inserts and cap screws, and the radial keys (including the Stellite ' wear surfaces)
  • B-N-3 components
  • Upper support ring/upper support skirt
  • Lower core plate
  • Upper core plate alignment pins

[NOTE: Similar Phase 2 RV/ component inspections are scheduled to be performed for Unit 2]

The above examples of operating experience provide objective evidence that the PWR Vessel Internals program includes activities to perform visual and volumetric examinations to identify change in dimensions due to void swelling, cracking, loss of fracture toughness, loss of material, and loss of preload for the reactor vessel internals (RVI) within the scope of subsequent license renewal, and to initiate corrective actions. Occurrences identified under the PWR Vessel Internals program are evaluated to ensure there is no significant impact to the safe operation of the plant and PageB-56

Serial No: 21-075 Enclosure 2 North Anna Power Station, Units 1 and 2 Page 37 of 56 Application for Subsequent License Renewal Supplement 2 Appendix B -Aging Management Programs corrective actions will be taken to prevent recurrence. Guidance or corrective actions for additional inspections, re-evaluation, repairs, or replacements is provided for locations where aging effects are found. The program is informed and enhanced when necessary through the systematic and ongoing review of both plant-specific and industry operating experience. There is reasonable assurance that the continued implementation of the PWR Vessel Internals program, following enhancement, will effectively manage aging prior to a loss of intended function.

Conclusion The continued implementation of the PWR Vessel Internals program, following enhancement, provides reasonable assurance that aging effects will be managed such that the components within the scope of this program will continue to perform their intended functions consistent with the current licensing basis during the subsequent period of extended operation.

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Serial No: 21-075 Enclosure 2 North Anna Power Station, Units 1 and 2 Page 38 of 56 Application for Subsequent License Renewal Supplement 2 Appendix B -Aging Management Programs 82.1.15 Fire Protection Program Description The Fire Protection program is an existing condition and performance monitoring program that requires periodic visual inspections of fire barrier components and functional testing of fire doors and halon and 1011, pressure carbon dioxide fire suppression systems. The program manages:

  • Loss of material for fire-rated doors, fire damper assemblies, the halon systems, steel seismic gap covers and the low pressure carbon dioxide systems
  • Loss of material or cracking for concrete structures, including fire barrier walls, ceilings, and floors
  • Loss of material... aR&-cracking/delamination , change in material properties, and separation for non-elastomer fire barrier penetration seals, fire stops, containment radiant energy shields, fire wraps, and coatings The Fire Protection program requires visual inspections of not less than 20% of the penetration seals every twelve months, such that 100% of the seals are inspected every five years. The program specifies visual inspections of the fire barrier walls, ceilings and floors in structures within the scope of subsequent license renewal every five years. The visual inspections of fire barriers include determining the condition of fire wraps every eighteen months. The eighteen-month frequency also is applicable for visual inspections of fire doors and damper assemblies. Periodic functional checks are performed on the fire doors.

The program also provides for aging management of external surfaces of the halon systems and low pressure carbon dioxide fire systems components that are within the scope of license renewal through periodic visual inspections for corrosion that may lead to loss of material. The program includes functional testing of the halon systems and low pressure carbon dioxide fire suppression

  • systems components in accordance with the Technical Requirements Manual.

Personnel performing inspections are qualified and trained to perform the inspection activities.

Unacceptable conditions are entered into the Corrective Action Program for disposition.

NUREG-2191 Consistency The Fire Protection program is an existing program that, following enhancement, will be consistent, with NUREG-2191, Section XI.M26, Fire Protection as modified by SLR-ISG-2021 MECHANICAL. Updated Aging Management Criteria for Mechanical Portions of Subsequent License Renewal Guidance.

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Serial No: 21-075 Enclosure 2 North Anna Power Station, Units 1 and 2 Page 39 of 56 Application for Subsequent License Renewal Supplement 2 Appendix B -Aging Management Programs Exception Summary None Enhancements Prior to the subsequent period of extended operation, the following enhancement(s) will be implemented in the following program element(s):

Monitoring and Trending (Element 5)

1. Procedures for fire barrier penetration seals, fire barriers, fire damper assemblies, and fire doors will be revised to require, where practical, identified degradation to be projected until the next scheduled inspection. For sampling-based inspections, results are evaluated against acceptance criteria to confirm that the sampling bases (e.g., selection, size, frequency) will maintain the components' intended functions throughout the subsequent period of extended operation based on the projected rate and extent of degradation.

Corrective Actions (Element 7)

2. Procedures will be revised to require that if degradation is detected within the inspection sample of penetration seals, the scope of the inspection is expanded to include additional seals in accordance with the Corrective Action Program. Additional inspections would be 20%

of each applicable inspection sample; however, additional inspections would not exceed five. If any projected inspection results will not meet acceptance criteria prior to the next scheduled inspection, inspection frequencies are adjusted as determined by the Corrective Action Program.

Operating Experience Summary The following examples of operating experience provide objective evidence that the Fire Protection program has been, and will be effective in managing the aging effects for SSCs within the scope of the program so that the intended functions will be maintained consistent with the current licensing basis during the subsequent period of extended operation.

1. In October 2011, a h.air-line crack was observed in a Marinite fire-stop board attached to the bottom of a cable tray. This crack was approximately 1O inches long at one corner of the board. The fire stop board provides separation from equipment of the opposite train. The Engineering Appendix R Coordinator determined that the crack did not alter the ability of the Marinite board to meet the separation requirements between trays in this location. The damaged Marinite board was subsequently replaced.
2. In May 2016, an assessment was performed to determine the progress and substance of license commitment closure and readiness for the IP 71003 NRG Phase I inspection to be conducted during the Fall 2016 Unit 1 refueling outage. The conclusion was reached that no Page 8-104

Serial No: 21-075 Enclosure 2 North Anna Power Station, Units 1 and 2 Page 40 of 56 Application for Subsequent License Renewal Supplement 2 Appendix B -Aging Management Programs performance deficiencies or learning opportunities were identified for the Fire Protection Program AMA (UFSAR Section 18.2.7).

3. In December 2016, as part of oversight review activities, a review of procedures credited by initial license renewal AMAs was conducted to confirm the following:
  • Procedures were consistent with the licensing basis and bases documents
  • Procedures contained a reference to conduct an aging management review prior to revising
  • Procedures credited for license renewal were identified by an appropriate program indicator and contained a reference to a license renewal document Procedure changes were completed as necessary to ensure the above items were satisfied.
4. In May 2017, an assessment was performed to determine the progress and substance of license commitment closure and readiness for the IP 71003 NRC Phase II inspection to be conducted for Units 1 and 2 from November through December of 2017. The conclusion was reached that no areas for improvement or enhancements were identified for the Fire Protection Program AMA (UFSAR Section 18.2.7).
5. In April 2019, an effectiveness review was performed on the Fire Protection Program AMA (UFSAR Section 18.2.7). The AMA was evaluated against the performance criteria identified in NEI 14-12, "Aging Management Program Effectiveness." No gaps were identified by the effectiveness review.
6. In August 2019, a search for plant-specific OE related to fire barriers and fire suppression systems from November 2008 to January 2019 was performed. Although cases of degraded firewall caulking, torn fire door seals, and damaged counter weights for a CO 2 damper louver were identified, there were no conclusive examples of applicable aging effects (i.e., loss of material, cracking, hardening, loss of strength, or shrinkage) due to the aging mechanisms of corrosion, stress corrosion cracking, elastomer degradation, or wear.

The above examples of operating experience provide objective evidence that the Fire Protection program includes activities to perform visual inspections to identify cracking, loss of material, hardening, shrinkage and loss of strength for structures and components inc!uding fire-rated doors, fire damper assemblies, halon systems, seismic gap covers, lov,' pressure carbon dioxide systems, fire barriers, penetration seals, fire stops, fire wraps, and coatings within the scope of subsequent license renewal and to initiate corrective actions. Occurrences identified under the Fire Protection program are evaluated to ensure there is no significant impact to the safe operation of the plant and corrective actions will be taken to prevent recurrence. Guidance or corrective actions for additional inspections, re-evaluation, repairs, or replacements is provided for locations where aging effects are found. The program is informed and enhanced when necessary through the systematic and ongoing review of both plant-specific and industry operating experience. There is reasonable PageB-105

Serial No: 21-075 Enclosure 2 North Anna Power Station, Units 1 and 2 Page 41 of 56 Application for Subsequent License Renewal Supplement 2 Appendix B -Aging Management Programs assurance that the continued implementation of the Fire Protection program, following enhancement, will effectively manage aging prior to a loss of intended function.

Conclusion The continued implementation of the Fire Protection program, following enhancement, provides reasonable assurance that aging effects will be managed such that the components within the scope of this program will continue to perform their intended functions consistent with the current licensing basis during the subsequent period of extended operation.

PageB-106

Serial No: 21-075 Enclosure 2 North Anna Power Station, Units 1 and 2 Page 42 of 56 Application for Subsequent License Renewal Supplement 2 Appendix B -Aging Management Programs B2.1.16 Fire Water System Program Description The Fire Water System program is an existing condition monitoring program that manages cracking, flow blockage, and loss of material, for in-scope water-based fire protection systems. This program manages aging by conducting periodic visual inspections, flow testing, and flushes performed in accordance with the 2011 Edition of National Fire Protection Association (NFPA) 25, "Standard for The Inspection, Testing and Maintenance of Water-Based Fire Protection Systems,".Testing and inspections are conducted on a refueling outage interval as allowed by NUREG-2191,Section XI.M27, Table XI.M27-1, "Fire Water System Inspection and Testing Recommendations." There are no nozzle strainers, glass bulb sprinklers, fire water storage tanks, or foam water sprinkler systems within the scope of subsequent license renewal.

The Fire Water System program will include testing a representative sample of the sprinklers prior to fifty years in service with additional representative samples tested at 10-year intervals. Sprinkler testing will be performed consistent with the 2011 Edition of NFPA 25, Section 5.3.1. Fire protection sprinkler system in-service dates vary, and require sprinkler testing or replacement to be completed beginning by 2023 (50 years of service).

Portions of water-based fire protection system components that have been wetted, but are normally dry, such as dry-pipe or pre-action sprinkler system piping and valves, were designed and installed with a configuration and pitch to allow draining. With the exception of two locations, Engineering walkdowns confirmed the as-built configuration that allows draining and does not allow water to collect. Corrective actions have been initiated for the two locations to verify a flow blockage condition does not exist and to restore the locations to the original configuration requirements that allow draining and do not allow water to collect. After corrective actions for the locations are completed, portions of the water-based fire protection system that were wetted, but are normally dry, will not be subjected to augmented testing and inspections beyond those required by NUREG-2191, AMP XI.M27, Table XI.M27-1.

The water-based fire protection system is normally maintained at required operating pressure and is monitored such that loss of system pressure is detected and corrective actions initiated. A low-pressure condition is alarmed in the main control room by the auto start of the electric motor-driven fire pump, followed by the start of the diesel-driven fire pump if the low-pressure condition continues to degrade. The status of the fire pumps is indicated in the main control room and at the fire pump control panels in the Intake Structure Fire Pump House (electric motor-driven fire pump) and the Service Water Pump House (diesel-driven fire pump). Both fire pumps may be manually started from the main control room.

Page B-107

Serial No: 21-075 Enclosure 2 North Anna Power Station, Units 1 and 2 Page 43 of 56 Application for Subsequent License Renewal Supplement 2 Appendix B -Aging Management Programs Piping wall thickness measurements are conducted when visual inspections detect surface irregularities indicative of unexpected levels of degradation. When the presence of organic or inorganic material sufficient to obstruct piping or sprinklers is detected, the material is removed, and the source is detected and corrected.

Inspections and tests are performed by personnel qualified in accordance with procedures and programs to perform the specified task. Non-code inspections and tests follow procedures that include inspection parameters for items such as lighting, distance, offset, presence of protective coatings, and cleaning processes that ensure an adequate examination.

If a flow test (i.e., NFPA25, 2011 Edition, Section 6.3.1) or a main drain test (i.e., NFPA25, 2011 Edition, Section 13.2.5) does not meet the acceptance criteria due to current or projected degradation, additional tests are or will be conducted . The number of increased tests is determined in accordance with the Corrective Action Program; however, there are no fewer than two additional tests for each test that did not meet the acceptance criteria. The additional inspections are completed within the interval (i.e., five years or annual/refueling) in which the original test was conducted. If subsequent tests do not meet the acceptance criteria, an extent of condition and extent of cause analysis is conducted to determine the further extent of tests required. The additional tests will include at least one test at the other unit on site with the same material, environment, and aging effect combination.

In addition to piping replacement, actions will be taken to address instances of recurring corrosion due to microbiologically influenced corrosion (MIC) or pitting on the internal surfaces of fire protection system steel piping. Low Frequency Electromagnetic Technique (LFET) or similar scanning technique will be used for screening 100 feet of accessible piping during each refueling cycle to detect changes in the wall thickness of the pipe. Thinned areas found during the LFET scan are followed up with pipe wall thickness examinations to ensure aging effects are managed and that wall thickness is within acceptable limits. In addition to the pipe wall thickness examination, opportunistic visual inspections of the fire protection system will be performed whenever the fire water system is opened for maintenance. The piping age, time in service, and susceptibility to corrosion will be considered in determining sample location's.

Aging of the external surfaces of buried and underground fir~ main piping is managed by the Buried and Underground Piping and Tanks program (B2.1.27) . Loss of material and cracking of the internal surfaces of cementitious lined buried and underground fire main piping are managed by the Internal Coatings/Linings For In-Scope Piping, Piping Components, Heat Exchangers, and Tanks program (B2.1.28) .

NUREG-2191 Consistency The Fire Water System program is an existing program that, following enhancement, will be consistent, with exception, to NUREG-2191,Section XI M27, Fire Water System.

Page 8-108

Serial No: 21-075 Enclosure 2 North Anna Power Station, Units 1 and 2 Page 44 of 56 Application for Subsequent License Renewal Supplement 2 Appendix B Aging Management Programs Exception Summary The following program element is affected:

Detection of Aging Effects {Element 4)

1. NUREG-2191, Table XI.M27-1, Note 10 directs inspections/testing of the fire pump suction screen, which recommends the pump suction screens be inspected for signs of degradation on a refueling outage interval based on operating experience. The circulating water and service water traveling screens will be monitored for a change in differential pressure since the water flow to the fire protection pumps travels through the respective circulating or service water traveling screens prior to the fire pump suction strainers.

Justification for Exception:

NUREG-2191,Section XI.M27, Table XI.M27-1 for fire pump suction screen inspection, uses guidance in NFPA-25, 2011 Edition, Section 8.3.3.7 that requires inspection and clearing of any debris or obstructions after the water flow portions of the annual test or fire protection system activations. The circulating water and service water traveling screens will be monitored for a change in differential pressure {dp) since the water flow to the fire protection pumps travels through the respective circulating water or service water traveling screens prior to the fire pump suction strainers. The dp across the circulating water and service water traveling screens are monitored once per shift by Operations personnel and the dp is recorded in the logs and trended for a change

{10.0 inches and 3.5 inches maximum, respectively) as an indication of potential flow blockage. The circulating water and service water screen wash operation are automatically initiated on increasing differential pressure. A main control room alarm indicates high differential pressure and requires operator corrective actions.

Both the diesel and motor driven fire pumps are equipped with suction strainers that meet the requirements of NFPA 20, Section 7.3.4.3, with a screen opening size of 0.5 inches. The wet pit suction screening (circulating water and service water traveling screens) requirement of NFPA 20, Section 4.16.8.6, requires a maximum opening size of 0.5 inches. The circulating water and service water traveling screens have a 3/8-inch opening size, which is expected to ensure debris will not enter the fire pump suction strainer. A historical review of work orders since 1993 revealed no indication of any flow blockage of either fire pumps' suction.

Monitoring and trending of the circulating water and service water traveling screens dp will ensure clearing of any debris or obstructions from the fire protection suction is performed as a result of pump activations.

2. NUREG-2191, Table XI.M27-1, Note 10, recommends main drain tests at each water-based system riser to determine if there is a change in the condition of the water piping and control valves on an annual or refueling outage interval. Main drain tests will be performed on 20% of the standpipes and risers every refueling cycle.

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Serial No: 21-075 Enclosure 2 North Anna Power Station, Units 1 and 2 Page 45 of 56 Application for Subsequent License Renewal Supplement 2 Appendix B Aging Management Programs Justification for Exception As indicated by NUREG-2191,Section XI.M27, Table XLM27-1, Note 10, access for some inspections is feasible only during refueling outages which are scheduled every 18 months. Main drain tests on 20% of the standpipes and risers every 18 months (refueling outage interval) provides adequate information to determine the fire water piping is being maintained consistent with the design basis.

Enhancements Prior to the subsequent period of extended operation, the following enhancement(s) will be implemented in the following program element(s):

Parameters Monitored or Inspected (Element 3); Detection of Aging Effects (Element 4); Monitoring and Trending (Element 5); Acceptance Criteria (Element 6); and Corrective Actions (Element 7)

1. Procedures will be developed or revised to specify:
a. Standpipe and system flow tests for hose stations at the hydraulically most limiting locations for each zone of the system on a five-year interval to demonstrate the capability to provide the design pressure at required flow
b. Wet pipe main drain testing will be performed on 20% of the standpipes and risers every 18 months on a refueling cycle basis. Acceptance criteria will be based upon monitoring flowing pressures from test to test to determine if there is a 10% reduction in full flow pressure when compared to previously performed tests. The Corrective Action Program will determine the cause and necessary corrective action.
c. If a flow test or a main drain test does not meet acceptance criteria due to current or projected degradation additional tests are conducted. The number of increased tests is determined in accordance with the corrective action process; however, there are no fewer than two additional tests for each test that did not meet acceptance criteria. The additional inspections are completed within the interval in which the original test was conducted. If subsequent tests do not meet acceptance criteria, an extent of condition and extent of cause analysis is conducted to determine the further extent of tests. The additional tests include at least one test at the other unit with the same material, environment, and aging effect combination.
d. Main drains for the standpipes associated with hose stations within the scope of subsequent license renewal will also be added to main drain testing procedures.
2. Procedures will be revised to perform internal visual inspections of sprinkler and deluge system piping to identify internal corrosion, foreign material, and obstructions to flow.

Follow-up volumetric examinations will be performed if internal visual inspections detect an unexpected level of degradation due to corrosion product deposition. If organic or foreign material, or internal flow blockage that could result in failure of system function is identified, PageB-110

Serial No: 21-075 Enclosure 2 North Anna Power Station, Units 1 and 2 Page 46 of 56 Application for Subsequent License Renewal Supplement 2 Appendix B -Aging Management Programs then an obstruction investigation will be performed within the Corrective Action Program that includes removal of the material, an extent of condition determination , review for increased inspections, extent of follow-up examinations, and a flush in accordance with NFPA 25, 2011 Edition, Annex D.5, Flushing Procedures. The internal visual inspections will consist of the following:

a. Wet pipe sprinkler systems - 50% of the wet pipe sprinkler systems in scope for subsequent license renewal will have visual internal inspections of piping by removing a hydraulically remote sprinkler, performed every five years, consistent with NFPA 25, 2011 Edition, Section 14.2. During the next five-year inspection period , the alternate systems previously not inspected shall be inspected.
b. Pre-action sprinkler systems - pre-action sprinkler systems in scope for subsequent license renewal will have visual internal inspections of piping by removing a hydraulically remote nozzle, performed every five years, consistent with NFPA 25 , 2011 Edition, Section 14.2.
c. Deluge systems - deluge systems in scope for subsequent license renewal will have visual internal inspections of piping by removing a hydraulically remote nozzle, performed every five years, consistent with NFPA 25, 2011 Edition, Section 14.2.
3. Procedures will be revised to perform system flow testing at five-year intervals with flows representative of those expected during a fire. A flow resistance factor (C-factor) will be calculated to compare and trend the friction loss characteristics to the results from previous flow tests.

Detection of Aging Effects (Element 4) , and Monitoring and Trending (Element 5) , and Acceptance Criteria (Element 6)

4. Procedures will be revised to address recurring internal corrosion with the use of Low Frequency Electromagnetic Technique (LFET) or a similar technique on 100 feet of piping during each refueling cycle to detect changes in the pipe wall thickness. The procedure will specify thinned areas found during the LFET screening be followed up with pipe wall thickness examinations to ensure aging effects are managed and wall thickness is within acceptable limits. In add ition to the pipe wall thickness examination , the performance of opportunistic visual inspections of the fire protection system will be required whenever the fire water system is opened for maintenance. The piping age, time in service, and susceptibility to corrosion should be considered in determining sample location priorities.
5. The activity of the jockey pump (i.e., an increase in the number of pump starts or run time of the pump) will be monitored consistent with the "detection of ag ing effects" program element of NUREG-2191,Section XI.M41 . (Relocated from original Commitment 6- Supplement 2)

Detection of Aging Effects (Element 4)

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Serial No: 21 -075 Enclosure 2 North Anna Power Station, Units 1 and 2 Page 47 of 56 Application for Subsequent License Renewal Supplement 2 Appendix B -Aging Management Programs

6. The Unit 2 lube oil purification piping will have the piping pitch adjusted to improve drainage. A drain valve will be installed on the Unit 2 hydrogen seal oil fire protection piping to drain the line after system testing or initiation. As part of the drainage reconfiguration, visual inspections and wall thickness measurements will be performed to identify unexpected degradation . Piping with unexpected degradation will be replaced . (Revised - Supplement 1)(Renumbered -

Supplement 2)

7. The activity of the jockey pump (i.e., an increase in the number of pump starts or run time of the pump) 1.vill be monitored consistent 1,*.iith the "deteotion of aging effects" program element of NUReG 2191,Section XI.M41.(Relocated to new Commitment 5 - Supplement 2)
8. Procedures 'Nill be revised for 'Net pipe sprinkler systems, a one time test of sprinl<lers that hm,re been mcposed to water inoluding the sample size, sample seleotion criteria, and minimum time in servioe of tested sprinl<lers 1,vill be performed . At cash unit, a sample of 3% or a maximum of ten sprinklers with no more than four sprinl<lers per structure shall be tested .

Testing is based on a minimum time in servioe of fifty years and se 1.ierity of operating conditions for each population. (Revised Supplement 1)(Completed - Supplement 2)

Operating Experience Summary The following examples of operating experience provide objective evidence that the Fire Water System program has been, and will be effective in managing the aging effects for SSCs within the scope of the program so that the intended functions will be maintained consistent with the current licensing basis during the subsequent period of extended operation.

1. In September 2012, an inspection of the fire water system piping identified debris on the internal surfaces. The external condition of the pipe was observed to be thinning with excessive rust. The piping section was subsequently replaced.
2. In May 2013, sections of cementitious lined cast iron piping were replaced with a higher pressure rated cementitious lined ductile iron piping. Additional isolation valves were also installed to improve system sectional isolation capability . These modifications were implemented due to six below ground fire protection pipe failures that occurred from 1984 to 2003 because of either manufacturing flaws or a flaw that was initiated during the ins~allation process. There were no reported instances due to age related degradation. The metallurgical failure reports for these pipe failures did not attribute any of the failures to the cementitious

' I liner. Several of the materials an'alysis reports stated the cementitious liner was tightly adhered to the pipe or in good contact with the existing pipe. All the internal pipe failures were attributed to preexisting conditions and not due to the failure of the lining.

3. In November 2014, a small through wall leak was identified in the bottom of a 90-degree elbow on the Unit 2 turbine lube oil purification fire protection deluge system . Engineering evaluated the system as capable of supplying the required water flow and pressure to meet the design PageB-112

Serial No: 21-075 Enclosure 2 North Anna Power Station , Units 1 and 2 Page 48 of 56 Application for Subsequent License Renewal Supplement 2 Appendix B -Aging Management Programs requirement . The cause of the through wall leak was attributed to residual water left in the system following testing . Actions were taken to ensure the affected piping was drained following deluge testing . There has not been any further identified through wall leaks since this action was implemented. Permanent repair of this section of pipe is being developed.

4. In March 2014, a level decrease in the fire protection hydro-pneumatic tank resulted in the system maintenance pump cycling on and off at an increased rate. The pump discharge check valve was replaced due to suspected leak-by, pitting on the seating surface and disc. During the check valve replacement, a portion of the pipe was replaced due to partial blockage and a temporary pipe repair was performed to stop the leak. In December 2014, evidence of a buried fire protection pipe leak was observed during a fire protection system walkdown at the intake structure. The leak appeared to be associated with small diameter carbon steel piping between the system pressure maintenance pump and the hydro-pneumatic tank where the fire protection piping enters the rip-rap lined embankment adjacent to the intake structure. The affected carbon steel piping was replaced and restored to service. A follow-on Engineering walkdown observed the tank level and pressure remained steady.
5. In January 2015, a work order was initiated to perform an internal inspection of the motor-driven fire pump discharge piping (on the system side of the discharge check valve).

The inspection addressed the extent of condition for the Unit 2 Turbine Building 12-inch fire protection above ground supply piping developed a leak and was replaced coming out of the 2014 Unit 2 refuel ing outage. Visual inspection of the piping identified it was in very good condition with only minimal signs of corrosion.

6. In October 2015, an inspection for the SBO fire protection pre-action sprinkler system was unsatisfactory due to some minor sediment in the piping. The inspection was performed on a small section of piping that had not been completely drained following past testing . To facilitate the inspection, the drain valve and associated spool piece were removed. The inspection found minor sediment but no indication of loss of material or formation of tubercles in the piping . The sediment collected due to the stagnant water conditions at the rim of fitting transitions. The remaining portions of the system were maintained dry. The sediment observed was not significant and would not block flow to the battery room sprinkler. The test procedure was revised to ensure this section of piping is adequately drained.
7. In May 2016, an assessment was performed to determine the progress and substance of license commitment closure and readiness for the IP 71003 NRC Phase I inspection to be conducted during the Fall 2016 Unit 1 refueling outage. The conclusion was reached that no performance deficiencies or learning opportunities were identified for the Fire Protection Program AMA (UFSAR Section 18.2.7).
8. In December 2016, as part of oversight review activities, a review of procedures credited by initial license renewal AMAs was conducted to confirm the following :

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Serial No: 21-075 Enclosure 2 North Anna Power Station, Units 1 and 2 Page 49 of 56 Application for Subsequent License Renewal Supplement 2 Appendix B -Aging Management Programs

  • Procedures were consistent with the licensing basis and bases documents
  • Procedures contained a reference to conduct an aging management review prior to revising
  • Procedures credited for license renewal were identified by an appropriate program indicator and contained a reference to a license renewal document Procedure changes were completed as necessary to ensure the above items were satisfied.
9. In June 2016, a through wall pipe leak was discovered on a Unit 2 fire protection supply line elbow located in the overhead of tt,e Turbine Building. The elbow was located at the bottom of a short vertical run of piping which filled with stagnate water. The system was only drained and refilled when maintenance was required (such as replacing damage sprinklers, system valves, or removal of piping to facilitate outage activities). A metallurgical analysis was performed on the removed section of piping. The metallurgical analysis confirmed the leak originated internally to the elbow. The internal surface of the piping that was removed was visually consistent with other sections of the Turbine Building sprinkler systems previously inspected (black magnetite layer with some very small nodules). The examined pipe segment was found to have some small nodules but minimal wall loss. The material loss at the leak location was not consistent with the overall condition of the remainder of the pipe segment. Based on the visual condition of the removed piping, metallurgical analysis, prior internal inspections of stagnant wet fire protection lines, and planned supplemental inspections, Engineering determined no additional inspections or actions were required. The leaking elbow and pipe segment were replaced.
10. In May 2017, two fire protection valves were disassembled due to excessive leak-by. Build-up of debris with corrosion products was found inside the valve bodies. The deposit was a combination of corrosion products and sediment that had been compacted down over the years and required extensive scrubbing to remove. Engineering determined the valves were original plant equipment that were continuously exposed to water and the amount of material deposited on the valve body was not excessive and unlikely to be removed by flushing.

Engineering performed an evaluation to determine what actions could be made to prevent debris build-up. Increasing the flushing frequency was determined to not provide any additional debris removal. Engineering determined the existing flushing *methodology and frequency was the best available option for debris removal and mechanical cleaning would be performed, if required.

11 . In May 2017, an assessment was performed to determine the progress and substance of license commitment closure and readiness for the IP 71003 NRC Phase II inspection to be conducted for Units 1 and 2 from November through December of 2017. The conclusion was reached that no areas for improvement or enhancements were identified for the Fire Protection Program AMA (UFSAR Section 18.2.7)

PageB-114

Serial No: 21-075 Enclosure 2 North Anna Power Station, Units 1 and 2 Page 50 of 56 Application for Subsequent License Renewal Supplement 2 Appendix B -Aging Management Programs

12. In April 2019, an effectiveness review was performed on the Fire Protection Program AMA (UFSAR Section 18.2.7) that includes inspection for corrosion loss of material, cracking , and flow blockage among its inspection activities. The AMA was evaluated against the performance criteria identified in NEI 14-12, "Aging Management Program Effectiveness."

Gaps were identified by the effectiveness review related to addressing corrosion in the fire water system. Procedures were identified to lack specific criteria related to aging inspections.

Several system test and operating procedures were determined to not use existing valves to drain the section of pipe after a test or actuation. Open work orders to replace piping, obtain piping ultrasonic testing (UT) examination data, perform internal inspections and adjust piping pitch for drainage were identified as not being completed. Both the Unit 1 and Unit 2 Turbine Building fire protection 10-inch and 12-inch deluge supply piping have been replaced or are scheduled to be replaced . Procedure updates have been completed to use existing valves to drain the system piping . Work orders to perform UT examinations on the Unit 2 hydrogen seal oil deluge system and other internal pipe inspections and work orders for pipe replacement are being scheduled.

Recurring Internal Corrosion (RIC)

Recurring internal corrosion, including through-wall failures as a result of loss of material due to pitting or MIC has occurred on several occasions. Periodic fire protection system piping flushes, flow testing and piping thickness measurements will be performed to identify pipe degradation prior to loss of system intended function. The Unit 1, 12-inch Turbine Building Fire Protection piping header has been replaced . Replacement of the Unit 2, 10 and 12-inch piping headers are scheduled . Internal 10-inch pipe inspections are scheduled for Unit 1 and 2.

Follow-up ultrasonic testing of pipes with trapped water sections has been completed with no indication of increased corrosion rates or pipe wall thinning . In addition to recent piping replacements and inspections in the Turbine Building and the Auxiliary Building to address instances of RIC due to pitting or MIC, Low Frequency Electromagnetic Technique (LFET) or a similar technique on 100 feet of piping will be performed during each refueling cycle to detect changes in the pipe wall thickness. Thinned areas found during the LFET scan are followed-up with pipe wall thickness examinations to ensure aging effects are managed and that wall thickness is' within acceptable limits . In addition to the pipe wall thickness examination, opportunistic visual inspections of the fire protection system will be performed whenever the fire water system is opened for maintenance.

The above examples of operating experience provides objective evidence that the Fire Water System program includes activities to perform periodic fire main and hydrant inspections and flushing, sprinkler inspections, functional test, and flow tests to identify cracking , flow blockage, and loss of material for in-scope water-based fire protection systems within the scope of subsequent license renewal, and to initiate corrective actions. Occurrences identified under the Fire Water System program are evaluated to ensure there is no significant impact to the safe operation of the PageB-115

Serial No: 21-075 Enclosure 2 North Anna Power Station, Units 1 and 2 Page 51 of 56 Application for Subsequent License Renewal Supplement 2 Appendix B Aging Management Programs plant and corrective actions will be taken to prevent recurrence. Guidance or corrective actions for additional inspections, re-evaluation, repairs, or replacements is provided for locations where aging effects are found. The program is informed and enhanced when necessary through the systematic and ongoing review of both plant-specific and industry operating experience. There is reasonable assurance that the continued implementation of the Fire Water System program, following enhancement, will effectively identify aging, and initiate corrective actions, prior to a loss of intended function.

Conclusion The continued implementation of the Fire Water System program, following enhancement, provides reasonable assurance that aging effects will be managed such that the components within the scope of this program will continue to perform their intended functions consistent with the current licensing basis during the subsequent period of extended operation.

PageB-116

Serial No: 21-075 Enclosure 2 North Anna Power Station , Units 1 and 2 Page 52 of 56 Application for Subsequent License Renewal Supplement 2 Appendix B -Aging Management Programs 82.1.45 High-Voltage Insulators Program Description The High-Voltage Insulators program is a new condition monitoring program that will manage loss of material and reduced electrical insulation resistance for insulators that are credited for recovery of offsite power. Insulators in the scope of this program operate at 34.5 kV and 4, 160V and include porcelain, toughened glass, and polymer materials.

Insulator surfaces of porcelain, toughened glass, and polymer insulators will be visually inspected to detect reduced electrical insulation resistance aging effects including cracks, missing sheds, foreign debris, excessive salt, dust, fog , cooling tower plume, and industrial effluent contamination, and loss of material from impaet of wind dri*,mn partieles. Additionally, polymer insulator surfaces will be visually inspected to detect signs of polymer degradation, swelling, discoloration, chalking, crazing, mechanical failure of components , and swelling or peeling of silicone rubber sleeves.

Metallic parts of the insulator will be visually inspected to detect loss of material due to mechanical wear and corrosion .

Insulators within the scope of the High-Voltage Insulators program will be visually inspected at least once every two years initially with the frequency adjusted based on plant specific operating experience with the specific type of insulator. For insulators that are coated, the visual inspection will be performed at least once every five years.

The first inspections for the subsequent period of extended operation will be completed prior to the subsequent period of extended operation.

NUREG-2191 Consistency The High-Voltage Insulators program is a new program that, when implemented, will be consistent, with NUREG - 2191,Section XI . E7, High-Voltage Insulators as modified by SLR 18G Eleetrieal 2020 XXSLR-ISG-2021-04-ELECTRICAL , Updated Aging Management Criteria for Electrical Portions of t-Ae--Subsequent License Renewal Guidance.

Exception Summary None Enhancements None PageB-277

Serial No: 21-075 Enclosure 2 North Anna Power Station, Units 1 and 2 Page 53 of 56 Application for Subsequent License Renewal Supplement 2 Appendix A - UFSAR Supplement degradation of bridge, rail, and trolley structural components and bolted connections. This program relies on the guidance in NUREG-0612, "Control of Heavy Loads at Nuclear Power Plants," ASME 830.2, "Overhead and Gantry Cranes (Top Running Bridge, Single or Multiple Girder, Top Running Trolley Hoist)," and other appropriate standards in the ASME/ANSI 830 series to manage aging.

A1.14 COMPRESSED AIR MONITORING The Compressed Air Monitoring program is an existing preventive and condition monitoring program that manages loss of material. The Compressed Air Monitoring program includes monitoring of air moisture content and contaminants such that specified limits are maintained, and performance of opportunistic inspections of components for indications of loss of material.

This program is consistent with the North Anna response to NRC GL 88-14, "Instrument Air Supply Problems;" and INPO SOER 88-01, "Instrument Air System Failures," The program relies on guidance and standards provided in EPRI TR 108147, "Compressor and Instrument Air System Maintenance Guide: Revision to NP-7079," and ANSI/ISA-S7.3-1975, "Quality Standard for Instrument Air," for testing and monitoring air quality and moisture. The Compressed Air Monitoring program activities implement the moisture content and contaminant criteria of ANSI/ISA-S7.3-1975 (incorporated into ISA-S7.0.01-1996).

Program activities include air quality checks at various locations to ensure that dew point, particulates, and hydrocarbons are maintained within the specified limits. Opportunistic inspections of the internal surfaces of select compressed air system components for loss of material are performed.

A1.15 FIRE PROTECTION The Fire Protection program is an existing condition and performance monitoring program that requires periodic visual inspections of fire barrier components and functional testing of fire doors and halon and lo*,e,* pressure carbon dioxide fire suppression systems. The program manages:

  • Loss of material for fire-rated doors, fire damper assemblies, the halon systems, steel seismic gap covers and the lo*.v pressure carbon dioxide systems
  • Loss of material or cracking for concrete structures, including fire barrier walls, ceilings, and floors
  • Loss of material... ooa-cracking/delamination , change in material properties, and separation for non-elastomer fire barrier penetration seals, fire stops, containment radiant energy shields, fire wraps, and coatings.

PageA-11

Serial No: 21-075 Enclosure 2 Page 54 of 56 Table A4.0-1 Subsequent License Renewal Commitments

  1. Program Comm itment AMP Implementation
2. Procedures will be revised to perform internal visual inspections of sprinkler and deluge system piping to identify internal corrosion , foreign material, and obstructions to flow. Follow-up volumetric examinations will be performed if internal visual inspections detect an unexpected level of degradation due to corrosion product deposition. If organic or foreign material, or internal flow blockage that could result in failure of system function is identified , then an obstruction investigation will be performed within the Corrective Action Program that includes removal of the material, an extent of condition determination, review for increased inspections, extent of follow-up examinations, and a flush in accordance with NFPA 25, 2011 Edition, Annex D.5, Flushing Procedures. The internal visual inspections will consist of the following :
a. Wet pipe sprinkler systems - 50% of the wet pipe sprinkler systems in scope for subsequent license renewal will have visual internal inspections of piping by removing a hydraulically remote sprinkler, performed every five years, consistent with NFPA 25, 2011 Edition, Section 14.2. During the next five-year Program will be inspection period, the alternate systems previously not inspected shall be inspected . implemented and
b. Pre-action sprinkler systems - pre-action sprinkler systems in scope for subsequent license renewal will inspections or tests begin have visual internal inspections of piping by removing a hydraulically remote nozzle, performed every five 5 years before the years, consistent with NFPA 25, 2011 Edition , Section 14.2. subsequent period of
c. Deluge systems - deluge systems in scope for subsequent license renewal will have visual internal extended operation.

inspections of piping by removing a hydraulically remote nozzle , performed every five years, consistent Inspections or tests that are with NFPA25, 2011 Edition, Section 14.2. to be completed prior to the Fire Water System 16 3. Procedures will be revised to perform system flow testing at five-year intervals with flows representative of B2.1.16 subsequent period of program those expected during a fire . A flow resistance factor (C-factor) will be calculated to compare and trend the extended operation are friction loss characteristics to the results from previous flow tests. completed 6 months prior to

4. Procedures *will be revised to address recurring internal corrosion with the use of Low Frequency the subsequent period of Electromagnetic Technique (LFET) or a similar technique on 100 feet of piping during each refueling cycle to extended operation or no detect changes in the pipe wall thickness. The procedure will specify thinned areas found during the LFET later than the last refueling screening be followed up with pipe wall thickness examinations to ensure aging effects are managed and wall outage prior to the thickness is within acceptable limits. In addition to the pipe wall thickness examination, the performance of subsequent period of opportunistic visual inspections of the fire protection system will be required whenever the fire water system is extended operation.

opened for maintenance. The piping age, time in service, and susceptibility to corrosion should be considered in determining sample location priorities.

5. The activity of the jockey pump (i .e., an increase in the number of pump starts or run time of the pump) will be monitored consistent with the "detection of aging effects" program element of NUREG-2191,Section XI.M41 .

(Relocated from original Commitment 6 - Supplement 2)

6. The Unit 2 lube oil purification and hydrogen seal oil piping will have the piping pitch adjusted to improve drainage. A drain valve will be installed on the Unit 2 hydrogen seal oil fire protection piping to drain the line after system testing or initiation. As part of the drainage reconfiguration , visual inspections and wall thickness measurements will be performed to identify unexpected degradation. Piping with unexpected degradation will be replaced. (Revised - Supplement 1) (Renumbered - Supplement 2)

North Anna Power Station , Units 1 and 2 PageA-68 Supplement 2 Application for Subsequent License Renewal Appendix A- UFSAR Supplement

Serial No: 21-075 Enclosure 2 Page 55 of 56 Table A4.0-1 Subsequent License Renewal Commitments

  1. Program Commitment AMP Implementation Program will be
7. +l=le aeti¥ity ef tl=le jeekey 131::1m13 Ei .e., aA iAeFease iA tl=le A1::1meeF ef 131::1m13 staFls eF Fl::IA time ef tl=le 131::1m13) will ee implemented and meAiternd eeAsistent ,,.,*itl=I tl=le "deteetien ef aging effects" 13rngrnm element ef ~JU REG 2191, 8eetien XI.M41 .

inspections or tests begin (Relocated to new Commitment 5 - Sum:ilement 2}

5 years before the

8. Prneed1::1Fes will ee Fe'o'ised feF wet !li!le S!lFinkleF s*tstems, a ene time test ef S!!FinkleFS tl=lat f:ia,,.e seen elE!lesed te ,,.,.ateF inel1::1din~ tl=le sam!lle siii!:e, sam!lle seleetien eFiteFia, and minim1::1m time in seP.1iee ef tested subsequent period of S!lFinl~leFs will ee !leFfeFmed . At eael=I 1::1Ait, a sam13le ef d% eF a malEim1::1m ef ten ,..,.et 13i13e s13FiAkleFs witl=I ne extended operation.

meFe tl=lan fe1::1F s13Finl~leFs 13eF stF1::1et1::1Fe sl=lall ee tested . :resting is eased en a minim1::1m time in sePa<iee ef fifty Inspections or tests that are yeaFS and se,..eFity ef e13eFating eenditiens feF eael=I 13e131::1latien. (Re'o'ised 81::!!l!llement 1l(Comi:ileted - to be completed prior to the Fire Water System Sui:ii:ilement 2) subsequent period of 16 B2.1.16 extended operation are program completed 6 months prior to the subsequent period of extended operation or no later than the last refueling outage prior to the subsequent period of extended operation.

North Anna Power Station, Units 1 and 2 PageA-69 Supplement 2 Application for Subsequent License Renewal Appendix A- UFSAR Supplement

Serial No: 21-075 Enclosure 2 Page 56 of 56 Table A4.0-1 Subsequent License Renewal Commitments

  1. Program Commitment AMP Implementation Program will be implemented and The One-Time Inspection program is a new condition monitoring program consisting of a one-time inspection of inspections begin 10 years selected components to verify: (a) the system-wide effectiveness of an AMP that is designed to prevent or before the subsequent minimize aging to the extent that it will not cause the loss of intended function during the subsequent period of period of extended extended operation ; (b) the insignificance of an aging effect; and (c) that long-term loss of material will not cause a operation . Inspections that loss of intended function for steel components exposed to environments that do not include corrosion inhibitors as are to be completed prior to One-Time Inspection a preventive action. the subsequent period of 20 82 .1.20 program The One-Time lnsgection grogram will gerform a magnetic garticle test insgection of the continuous extended operation are circumferential transition cone closure weld and the accessible gortions of the ugger shell-to-transition cone girth completed 6 months prior to weld on each steam generator (essentialll'. 100% examination coverage of each weld) grior to the subseguent the subsequent period of geriod of extended ogeration. (Ugdated - Sugglement 2) extended operation or no Industry and plant-specific operating experience will be evaluated in the development and implementation of this later than the last refueling program . outage prior to the subsequent period of extended operation.

Program will be implemented and inspections begin 1O years before the subsequent The Selective Leaching program is a new condition monitoring program that will monitor components constructed period of extended of materials which are susceptible to selective leaching. The selective leaching program includes a one-time operation . Inspections that inspection for susceptible components exposed to closed cycle cooling water and treated water environment since are to be completed prior to Selective Leaching plant-specific operating experience has not revealed selective leaching in these environments, as well as the subsequent period of 21 opportunistic and periodic inspections for susceptible components exposed to raw water, waste water, and soil 82.1 .21 program extended operation are (which may include groundwater) environments. completed 6 months prior to Industry and plant-specific operating experience will be evaluated in the development and implementation of this the subsequent period of program . extended operation or no later than the last refueling outage prior to the subsequent period of extended operation .

North Anna Power Station, Units 1 and 2 PageA-73 Supplement 2 Application for Subsequent License Renewal Appendix A- UFSAR Supplement

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