ML21210A396

(Naps), Units 1 and 2 - Subsequent License Renewal Application (SLRA) Response to NRC Request for Additional Information Safety Review - Set 4 and Supplement 3

ML21210A396
Person / Time
Site:	North Anna
Issue date:	07/29/2021
From:	Mark D. Sartain Virginia Electric & Power Co (VEPCO)
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
21-213
Download: ML21210A396 (63)

Text

VIRGINIA ELECTRIC AND POWER COMPANY RICHMOND, VIRGINIA 23261 July 29, 2021 10 CFR 50 10 CFR 51 10 CFR 54 United States Nuclear Regulatory Commission Attention: Document Control Desk Washington, D.C. 20555-0001 Serial No.:

21-213 VIRGINIA ELECTRIC AND POWER COMPANY NRA/DEA:

RO Docket Nos.:

50-338/339 License Nos.: NPF-4/7 NORTH ANNA POWER STATION (NAPS) UNITS 1 AND 2 SUBSEQUENT LICENSE RENEWAL APPLICATION (SLRA)

RESPONSE TO NRC REQUEST FOR ADDITIONAL INFORMATION SAFETY REVIEW - SET 4 AND SUPPLEMENT 3 By letter dated August 24, 2020 (Agencywide Documents Access and Management System (ADAMS) Accession No. ML20246G697), Virginia Electric and Power Company (Dominion Energy Virginia or Dominion) submitted an application for the subsequent license renewal of Renewed Facility Operating License Nos. NPF-4 and NPF-7 for North Anna Power Station (NAPS) Units 1 and 2, respectively. The US Nuclear Regulatory Commission (NRG) has been reviewing the NAPS SLRA.

Public meetings were held between the NRG staff and Dominion on May 13, 2021 (ADAMS Accession No. ML21132A287), May 27, 2021 (ADAMS Accession No. ML21147A044), June 17, 2021 (ADAMS Accession No. ML21166A350) and June 24, 2021 (ADAMS Accession No. ML21174A310) to discuss select NRG RAls (Draft) associated with the safety review of the NAPS SLRA.

The NRG staff has identified an area where additional information is needed to complete their review. In an email from Lois M. James (NRG) to Daniel G. Stoddard (Dominion) dated July 7, 2021, the NRG staff transmitted a request for additional information (RAI) to support completion of the Safety Review. The RAI (draft) was discussed at the May 13, 2021 and June 17, 2021 public meetings. Enclosure 1 provides Dominion's response to NRG RAI B2.1.35-1a.

Dominion has decided to supplement the SLRA and previously submitted information to address NRG concerns discussed during the May and June public meetings. provides a description of the SLRA topics being supplemented and identifies the affected SLRA section and/or table. Enclosure 3 provides SLRA changes described in Enclosures 1 and 2. As a reviewer aid, all pages of the Appendix B aging management program section are provided, including unchanged pages, when there is a change on any of the pages in that section. Also, note that changes to three commitments (Items

1. 16, #27 and #49) are provided in Table A4.0-1.

Serial No.: 21-213 Docket Nos.: 50-338/339 Response to NAPS SLRA Safety Review RAI - Set 4 / Supplement 3 Page 2 of 6 In a letter dated April 1, 2021 (Serial No.21-074)(ADAMS Accession No. ML21091A187),

Dominion clarified the programs used for aging management of the fire protection system ductile iron valve bodies with internal linings exposed to raw water and provided associated SLRA mark-ups in the letter. It has recently been identified that the SLRA changes for the Fire Water System UFSAR Supplement (Section A 1.16) and Fire Water System Aging Management program (Section 82.1.16) were inadvertently not provided with the SLRA mark-ups. The mark-ups of SLRA Sections A 1.16 and 82.1.16 for the SLRA changes associated with the April 1, 2021 letter are included in Enclosure 3.

Additionally, Dominion is providing further details regarding the previous response to RAI B2.1.8-1 Request 3 (ML21091A000), associated with the performance of operational experience review personnel interviews and maintenance of the flow accelerated corrosion (FAC) operating experience (OE) database according to procedure ER-AA-FAC-1003.

Specifically, responsibilities in this procedure have been reviewed and reinforced with responsible FAC owners/analysts to assure the operational experience reviews with operations personnel and maintenance of the FAC OE database are consistently performed such that no further enhancements to the procedure are required.

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

s~-

Mark D. Sartain Vice President - Nuclear Engineering and Fleet Support COMMONWEAL TH OF VIRGINIA COUNTY OF HENRICO CRAIG D Notary P Commonwealth f:leg. #_75 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.J.J!!!... day of L li

, 2021.

My Commission Expires: _1-"'2.+---(2..... f....,/~"--'f.L.-__ _

Commitments made in this letter: None

Enclosures:

1. Response to NRC Request for Additional Information NAPS SLRA Safety Review Set4

2. Topics that Require a SLRA Supplement

3. SLRA Mark-ups - Response to RAI Safety Review Set 4 and Supplement 3

Serial No.: 21-213 Docket Nos.: 50-338/339 Response to NAPS SLRA Safety Review RAI - Set 4 / Supplement 3 Page 3 of 6 cc: U.S. Nuclear Regulatory Commission, Region II Marquis One Tower 245 Peachtree Center Avenue, NE Suite 1200 Atlanta, Georgia 30303-1257 Ms. Lois James NRG 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 NRG 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 NRG 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 NRG Senior Project Manager U.S. Nuclear Regulatory Commission One White Flint North Mail Stop 09 E-3 11555 Rockville Pike Rockville, Maryland 20852-2738 NRG Senior Resident Inspector North Anna Power Station Mr. Marcus Harris Old Dominion Electric Cooperative Innsbrook Corporate Center, Suite 300 4201 Dominion Boulevard Glen Allen, Virginia 23060

Serial No.: 21-213 Docket Nos.: 50-338/339 Response to NAPS SLRA Safety Review RAI - Set 4 / Supplement 3 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 Ms. Kathryn Perszyk Land Division Director Virginia Department of Environmental Quality 1111 East Main Street Suite 1400 Richmond, VA 23219 Mr. James Golden, Regional Director Virginia Department of Environmental Quality Piedmont Regional Office 4949-A Cox Road Glen Allen, VA 23060 Page 4 of 6

Serial No.: 21-213 Docket Nos.: 50-338/339 Response to NAPS SLRA Safety Review RAI - Set 4 / Supplement 3 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 Ms. Julie Henderson, Director Virginia Department of Health Office of Environmental Health Services 109 Governor St, 5th Floor Richmond, VA 23129 Ms. Julie Langan, Director Virginia Department of Historic Resources State Historic Preservation Office 2801 Kensington Avenue Richmond, VA 23221 Mr. Steven G. Bowman, Commissioner Virginia Marine Resources Commission 380 Fenwick Road Building 9 Ft. Monroe, VA 23651 Ms. Angel Deem, Director Virginia Department of Transportation Environmental Division 1401 East Broad Street Richmond, VA 23219 Mr. Stephen Moret, President Virginia Economic Development Partnership 901 East Byrd Street Richmond, VA 23219 Page 5 of 6

Serial No.: 21-213 Docket Nos.: 50-338/339 Response to NAPS SLRA Safety Review RAI - Set 4 / Supplement 3 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 Ms. Lauren Opett, Director Virginia Department of Emergency Management 9711 Farrar Ct North Chesterfield, VA 23226 Mr. Mark Stone, Chief Regional Coordinator Virginia Department of Emergency Management 13206 Lovers Lane Culpeper, VA 22701 Page 6 of 6

NAPS SLRA Serial No.: 21-213 RESPONSE TO NRC REQUEST FOR ADDITIONAL INFORMATION NAPS SLRA SAFETY REVIEW - SET 4 Virginia Electric and Power Company (Dominion Energy Virginia)

North Anna Power Station Units 1 and 2

NAPS SLRA Serial No.: 21-213 Docket Nos.: 50-338/339 Page 2 of 5 Response to NRC Request for Additional Information NAPS SLRA Safety Review - Set 4 North Anna Power Station, Units 1 and 2 Subsequent License Renewal Application By letters dated August 24, 2020, (Agencywide Documents Access and Management System Accession No. ML20246G703), Dominion Energy submitted an application for subsequent license renewal of Renewed Facility Operating License Nos. NPF-4 and NPF-7 for the North Anna Power Station, Unit Nos. 1 and 2 (North Anna) to the U.S.

Nuclear Regulatory Commission (NRC} pursuant to Section 103 of the Atomic Energy Act of 1954, as amended, and part 54 of title 10 of the Code of Federal Regulations, "Requirements for Renewal of Operating Licenses for Nuclear Power Plants."

The NRC is reviewing the subsequent license renewal application and has provided specific requests for additional information (RAls) to support completion of the Safety Review. Dominion Energy Virginia's response to the NRC RAls is provided below.

1.

RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants, AMP 82.1.35 Regulatory Basis:

Section 54.21(a)(3) of 10 CFR requires the applicant to demonstrate that the effects of aging for structures and components will be adequately managed so that the intended function will be maintained consistent with the current licensing basis (CLB) for the period of extended operation.

The staff uses the guidance in Appendix A of SRP-SLR to review operating experience to provide a basis to support its finding regarding the adequacy of the applicant's proposed aging management program (AMP) to manage the effects of aging in a manner that SC-intended functions will be maintained during the subsequent period of extended operation.

RAI 82.1.35-1 a

Background

SLRA Section 82.1.35, in item 8 of the Operating Experience Summary, states that (1) structures within the settlement monitoring program, including the Service Water

i Reservoir, the Service Water Pump House, and the Service Water Valve House, are monitored every 184 days, as specified in the" Technical Requirements Manual (TRM),

Section 3. 7. 7; (2) the initial baseline elevations for these structures and components are listed in UFSAR Table 3.8-15; (3) the appropriate action is taken in accordance with the

NAPS SLRA Serial No.: 21-213 Docket Nos.: 50-338/339 Page 3 of 5 Corrective Action Program if differences between observed values and baseline elevations exceed prescribed limits given in TRM Section B3. 7. 7; and (4) no settlement have been found to have exceeded the TRM limits.

During the staff's review, Dominion extended the settlement inspection interval from 184 days to 12 months. RA! B2. 1. 35-1 requested Dominion Energy to explain how the longer interval will continue to provide adequate aging management of settlement for structures within the scope of subsequent license renewal, especially structures which may be close to the settlement action limits identified in the TRM.

Dominion's response to RAJ B2.1.35-1, by letter dated April 29, 2021 (ADAMS Accession No. ML21119A287), indicates that settlement marker SM-28 for the Service Water Valve House has reached the 75 percent settlement limit specified in TRM Section B3. 7. 7.

Dominion Energy's response also indicates that an increase in allowable settlement could be accommodated by adjusting the expansion joint tie-rods as noted in the design change that implemented the 2009 modifications if future settlement exceeds the 75 percent threshold.

The NRG staff conducted an audit on recent operating experience related to settlement, and found that the projected settlement for the settlement marker SM-28 may exceed the current 100% settlement limit around 2036, but it is unclear what evaluation methodology will be used to implement the TRM required corrective actions.

Issue It is unclear what evaluation methodology will be used to implement the TRM requirements for the Inspection of Water-Control Structures Associated with Nuclear Power Plants program such that the settlement aging effect will be adequately to managed through the end of the SPEO if future settlement exceeds the settlement acceptance criteria specified in the TRM.

Based on the operating experience it is unclear whether other settlement markers are expected to exceed or will exceed the settlement acceptance criteria during the SPEO.

Therefore, program elements (e.g., acceptance criteria, corrective actions or evaluation methodology to change the acceptance criteria) related to settlement need to be described, modified or enhanced to demonstrate that the aging management program will be adequate to manage the aging effect during the SPEO.

NRC Request

1. Update the SLRA to include recent settlement related operating experience for the Service Water Valve House.

2. Provide updated settlement acceptance criteria with basis (or process for determining conditional acceptance criteria to. ensure intended function when the acceptance criteria is not met) against which the need for corrective actions are evaluated.

NAPS SLRA Dominion Response Serial No.: 21-213 Docket Nos.: 50-338/339 Page 4 of 5

1. OE #9 is added to SLRA Section B2.1.35, "Water-Control Structures Associated with Nuclear Power Plants program," to provide the following discussion of recent settlement related operating experience for the Service Water Valve House:

"In April of 2021, a condition report (CR) was submitted as required by Technical Requirement (TR) 3.7.7 in Section 3.7 of the Technical Requirements Manual (TRM), documenting 75% of the allowable total settlement indicated in TRM Table 3.7.7-1 had been exceeded for settlement marker SM-28, associated with the Service Water Valve House (SWVH).

Specifically, SM-28 was 75.6% of the allowable total settlement value in TRM Table 3.7.7-1.

The basis for TR 3.7.7 is to limit pipe stress of the adjacent SW piping. The allowable total settlement for SM-28, as well as other SWVH settlement markers (SM-25, SM-26, and SM-27), ensures pipe stress for the buried SW piping is maintained within Code allowable limits.

An engineering evaluation is being developed and work orders have been initiated to adjust SW expansion joints tie rods to accommodate for future potential settlement."

Based on the above, SLRA Section 82.1.35 is supplemented, as shown in Enclosure

3.

2. The requirements for Settlement of Class I structures is specified in Technical Requirement {TR) 3.7.7 of the Technical Requirements Manual (TRM). If a monitored location for any structure exceeds 75% of the allowable settlement value in TRM Table 3.7.7-1, a CR is required to be submitted immediately, and within 60 days engineering is required to review field conditions and evaluate the consequences of additional settlement. If 100% of the allowable settlement value is exceeded, the affected unit is required to shut down in accordance with the time limits provided in TR 3.7.7.

The allowable settlement value for the SWVH settlement markers in TR Table 3.7.7-1, including SM-28, was established in 2009. This value is based on a calculation and resultant design change which modified the SW piping configuration and rubber expansion joints with tie-rods to accommodate for future potential settlement.

In order to continue management of the settling (which is diminishing with time according to data recorded), a similar approach to the one taken in 2009 is being pursued. Prior to exceeding 100% allowable settlement, SW piping expansion joint tie-rods will be adjusted back to their original configuration; which then allows for additional settlement and restores margin. Following the tie-rods adjustments, the allowable settlement value ior the SWVH settlement markers will be the same as.the original allowable settlement value determined in 2009, or 0.041 feet.

The.final arrangement restores margin and will accommodate potential additional settling without consequence to the associated SSCs in the SWVH.

Serial No.: 21-213 Docket Nos.: 50-338/339 NAPS SLRA Page 5 of 5 TR Table 3.7.7-1 will be updated to reflect a new baseline date. After that time, the SWVH settlement markers data can be compared to baseline elevations associated with the new baseline date to determine if the new settlement is within the original allowable settlement value of 0.041 feet, as documented in the original design calculation.

Recent settlement data indicates the rate of SWVH settlement has significantly slowed and has reflected a trend towards leveling off. As such, after adjusting the expansion joint tie-rods and resetting the allowable settlement value, 75% of the SWVH allowable settlement value is not expected to be exceeded during the remaining life of the plant, including the subsequent period of extended operation (SPEO).

Settlement data was reviewed for the other Water-Control structures monitored per TR 3.7.7. There are no other settlement markers currently expected to challenge the 75% allowable TRM values in the near future.

Similar to the SWVH, review of settlement data indicates the settlement of the other Water-Control structures has slowed significantly over the years.

As a result, potential modifications to accommodate additional settlement for other Water-Control structures are currently not planned. With regards to settlement, other than previously discussed, no further actions or enhancements are considered necessary for SM-28.

TR 3. 7. 7 will continue to require settlement monitoring of Class I Structures during the SPEO, to provide settlement detection and corrective actions if future SWVH settlement is found to exceed the allowable settlement value.

Therefore, with regards to settlement, no further actions other than previously discussed or enhancements to the Water-Control Structures Associated with Nuclear Power Plants program are considered necessary to ensure the intended function of the service water piping or SSCs associated with Water-Control structures.

NAPS SLRA TOPICS THAT REQUIRE A SLRA SUPPLEMENT Virginia Electric and Power Company (Dominion Energy Virginia)

North Anna Power Station Units 1 and 2 Serial No.: 21-213

NAPS SLRA Serial No.: 21-213 Topics that require an SLRA Supplement Page 2 of 6 The following five topics require the SLRA to be supplemented:

1.

Fire Protection System: Diesel-driven fire pump engine coolant heat exchanger tube bundle replacement commitment revision

2.

Fire Protection System: Aging management of buried gray cast iron piping and piping components revised

3.

Fire Water program (B2.1.16): Program Description, Exception 1, and UFSAR Supplement Revised. Enhancement 9 Added. (Service Water and Circulating Water system revisions included)

4.

Reactor Vessel Internals: Table 1 and AMR Table Revised to Include Loss of Material due to Pitting and Crevice Corrosion as an Aging Effect Requiring Management

5.

Outdoor and Large Atmospheric Metallic Storage Tanks program (B2.1.17):

Exception 1 Clarified

NAPS SLRA Serial No.: 21-213 Topics that require an SLRA Supplement Page 3 of 6

1. Fire Protection System: Diesel-driven Fire Pump Engine Coolant Heat Exchanger Tube Bundle Replacement Commitment Revision SLRA Table A4.0-1, Item 49, hereinafter referred to as Commitment #49, was added in the response to RAI B2.1.15-1, dated April 1, 2021 (ADAMS Accession No. ML21091A187), is revised.

Commitment #49 was added to require replacement of the diesel-driven fire pump engine heat exchanger coolant tube bundle on a 20-year frequency and replacement of the heat exchanger tube bundle for the spare engine prior to being placed in-service with the diesel-driven fire pump. The diesel-driven fire pump has both an in-service and a spare engine. The 20-year replacement frequency is based on a failed tube bundle leakage event which occurred in an engine having 25 years of in-service history. Tube bundle replacement at a 20-year frequency is expected to preclude in-service age-related failures of the tube bundle.

On May 13, 2021, the NRC held a public meeting to discuss Dominion's response to select NRC staff RAls on the NAPS SLRA. During the discussion of RAI B2.1.15-1, Dominion indicated the fire pump engine had 29 years of run time at the time of the failed tube bundle leakage event. Subsequent to the May 13, 2021 meeting, additional research of maintenance history identified a change in the reported in-service history prior to tube bundle leakage from 29 years to 25 years based on information in corrective action report CA7616237.

Commitment #49 is revised because the current in-service engine has 18 years of service, and the spare engine has only 2 years of service since the last tube bundle replacement. The changes account for the age of the in-service tube bundle, permit time for procurement and scheduling, and maintain the tube bundle age less than the previous failed tube bundle leakage event.

Based on the above, the SLRA is supplemented, as shown in Enclosure 3, to revise SLRA Table A4.0-1, Item 49.

2. Fire Protection System: Aging Management of Buried Gray Cast Iron Piping and Piping Components Revised

'Consistent with the requirements of NUREG-2191 Section XI.M41, Buried and Underground Piping and Tanks program, and NUREG-2191 Section XI.M33, Selective l.!eaching program, periodic and opportunistic inspections will be conducted for buried gray cast iron fire protection piping and piping components. Periodic inspections will be conducted in the 10-year period prior to the subsequent period of extended operation and periodically in each 10-year period during the subsequent period of extended operation.

Opportunistic inspections are performed when buried components are exposed and may be credited if the inspection locations selection criteria are met.

Consistent with the requirements of NUREG-2191 Section XI.M41, Buried and Underground Piping and Tanks program, a ten-foot pipe length will be excavated for each buried gray cast iron fire protection piping inspection and the external surfaces inspected

NAPS SLRA Serial No.: 21-213 Topics that require an SLRA Supplement Page 4 of 6 for blistering, cracking, hardening or loss of strength, and loss of material. Periodic inspections will also be conducted consistent with the NUREG-2191 Section XI.M33 recommendations using the multiple unit criteria that requires eight visual and mechanical inspections and two destructive examinations to be conducted at each unit. The number of visual and mechanical inspections may be reduced by two for each component or one-foot piping length that is destructively examined beyond the minimum number of destructive examinations recommended for each sample population.

The SLRA is revised to require a minimum of six excavations be conducted at each unit and five of the inspections at each unit destructively examine the buried gray cast iron fire protection piping to inspect for the loss of material due to selective leaching. The SLRA is also revised to indicate reliance on jockey pump monitoring has been discontinued as an alternative to destructive examinations.

Consistent with NUREG-2191 Section XI.M33, each examination will be conducted on a representative sample of one-foot length (minimum) piping segments and/or piping components from each discrete excavation location (five/unit). Piping segment and piping component inspection locations, where possible, will focus on the bounding or lead piping segments/components most susceptible to aging based on time-in-service and severity of operating conditions for each population.

Based on operating experience, the selection of inspection locations for buried gray cast iron fire protection piping and piping components will consider the following:

Older piping segments (i.e. not previously replaced)

Piping and piping components found to be continuously wetted due to leaking piping/valves or in soil with high corrosivity ratings as determined by EPRI Report 3002005294, "Soil Sampling and Testing Methods to Evaluate the Corrosivity of the Environment for Buried Piping and Tanks at Nuclear Power Plants" Piping and piping components not cathodically protected Piping and piping components with significant coating degradation or unexpected backfill Consequence of failure (i.e. proximity to safety-related piping and piping components)

Locations with potentially high stress and/or cyclic loading conditions such as piping adjacent to locations that were replaced due to cracking/rupture, locations subject to settlement, or locations subject to heavy load traffic Metallography will be used to examine the microstructure of the samples cut from the selected cast iron components for signs of graphitic corrosion as described below:

In the laboratory, samples will be encapsulated in an epoxy, Bakelite, or acrylic compound to facilitate handling and provide good edge retention. Then the samples will be ground and polished to a 1-micron or 0.05-micron finish. The structure can be evaluated with a light microscope in the unetched or etched condition. If etching is needed to show the phase present in the matrix, a 3% solution of nitric acid in methanol will be used. Under

NAPS SLRA Serial No.: 21-213 Topics that require an SLRA Supplement Page 5 of 6 the microscope, at the far edges of the advancing corrosion line, graphitic corrosion will be identified by showing oxidation of the iron matrix surrounding the unaffected graphite flakes. Additional confirmation of the selective attack can be performed by examining the same prepared metallographic sample under the scanning electron microscope using energy dispersive spectroscopy. This method allows for mapping of the sample along the surface, so that the different areas can be identified based on their elemental compositions. Those areas that are corroded will show high levels of oxygen and lower levels of iron, while unaffected zones will contain higher levels of iron and no oxygen.

For the aforesaid reasons, implementation of the Buried and Underground Piping and Tanks program and the Selective Leaching program will provide reasonable assurance that the buried gray cast iron fire protection piping and piping components within the scope of these programs will continue to perform their intended functions consistent with the current licensing basis during the subsequent period of extended operation.

Based on the above, SLRA Sections A1.27, B2.1.16, B2.1.27, and Table A4.0-1 Items 27 I and 27 are supplemented, as shown in Enclosure 3.

3. Fire Water program (82.1.16): Program Description, Exception 1, and UFSAR Supplement Revised. Enhancement 9 Added. (Service Water and Circulating Water System Revisions Included)

The response to RAI B2.1.16-1, dated April 29, 2021 (ADAMS Accession No. ML21119A287), added plant-specific note 13 to the fire protection system strainer element (pump suction) line item in Table 3.3.2-42, "Auxiliary Systems - Fire Protection -

Aging Management Evaluation". Note 13 stated, "As noted in the Fire Water System (B2.1.16) program exception, the filtration intended function of the fire pump suction strainer element will be performed by the upstream service water or circulating water system travelling screens, which are active components and not subject to aging management review." The potential for loss of material for the traveling screen elements (the screens themselves) to affect the passive filtration function of the traveling screens and how loss of material for the fire pump suction strainer elements would be managed was not addressed.

Existing maintenance inspections are conducted every six months on the circulating water traveling screens, and every year on the service water traveling screens for loss of material to provide assurance that no large diameter debris will reach the fire pump suction.

Enhancement 9 is added to SLRA Section B2.1.16, Fire Water System program, and SLRA Table A4.0-1 to require inspection of the fire pump suction strainers for loss of material every 12 years. The 12-year frequency permits coordination with existing periodic maintenance inspections within the sub-systems which reduces out of service time and provides for the proper utilization of staff resources.

Plant-specific note 13 in SLRA Table 3.3.2-42 is revised to clarify how loss of material for the fire pump suction strainer elements is managed and flow blockage of the fire pump suction strainer element is precluded.

NAPS SLRA Serial No.: 21-213 Topics that require an SLRA Supplement Page 6 of 6 SLRA Sections 2.3.3.7, 2.3.3.9, and Tables 2.3.3-7, 2.3.3-9, 3.3.2-7, and 3.3.2-9 are revised to include the circulating water and service water traveling screen elements as components subject to aging management.

Based on the above, the SLRA is supplemented, as shown in Enclosure 3.

4. Reactor Vessel Internals: Table 1 and AMR Table Revised to Include Loss of Material due to Pitting and Crevice Corrosion as an Aging Effect Requiring Management As a result of public meetings with the NRG staff on May 13, 2021 and May 27, 2021, Dominion has included the aging effect of loss of material due to pitting and crevice corrosion as an aging effect requiring management for reactor vessel internals (RVI) components in a reactor coolant environment.

The SLRA is revised to include aging management of RVI components for loss of material with the Water Chemistry program (B2.1.2).

Based on the above, the SLRA Section 3.1.2.2.9, Table 3.1.1 and Table 3.1.2-2 are supplemented, as shown in Enclosure 3.

5. Outdoor and Large Atmospheric Metallic Storage Tanks program (82.1.17):

Exception 1 Clarified NUREG-2191,Section XI. M29, Outdoor and Large Atmospheric Metallic Storage Tanks, states degradation of an exterior metallic surface can occur in the presence of moisture; therefore, periodic visual inspections conducted during each refueling outage confirm paint, coating, sealant, and caulking are intact.

Sealant or caulking applied at the interface between metallic tank external surfaces and concrete or earthen surfaces (e.g.,

foundation, tank interface joint in a partially encased tank), used to mitigate corrosion of the tank by minimizing the amount of water and moisture penetrating the interface, is also subject to these inspection requirements.

The emergency condensate storage tanks (ECSTs) are insulated from the outside atmosphere by two inches of expansion joint filler foam (Rodofoam II insulation) and surrounded by a two-foot-thick layer of reinforced concrete (i.e., missile barrier), thus making the external surfaces pf the ECSTs inaccessible. Vent and vacuum breaker penetrations are installed at the 'top of the concrete missile barrier. Caulking is located at each penetration-concrete missile barrier interface to prevent the ingress of moisture from affecting the metallic tank external surfaces.

Based on the configuration described above, periodic inspection of the ECST vent and vacuum breaker caulking on a five-year interval during ECST missile shield inspections under the Structures Monitoring program (82.1.34) is appropriate.

NAPS SLRA Serial No.: 21-213 SLRA MARK-UPS Response to RAI Safety Review Set 4 and Supplement 3 Virginia Electric and Power Company (Dominion Energy Virginia)

North Anna Power Station Units 1 and 2

Serial No.: 21-213 Supplement 3 Page 2 of 46 Components Subject to Aging Management Review North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Mechanical Systems The component types subject to aging management review are indicated in Table 2.3.3-6, Materials Handling.

The aging management review results for these component types are indicated in Table 3.3.2-6, Auxiliary Systems - Materials Handling - Aging Management Evaluation.

2.3.3.7 Service Water

System Description

The service water system transfers heat from plant systems and components to the ultimate heat sink provided by the Service Water Reservoir or the North Anna reservoir. The service water system removes heat from the component cooling water system, the recirculation spray system, the charging pump lubricating oil, the instrument air compressors, and the main control room air-conditioning chiller condensers. The normal source of service water is the man-made nine-acre Service Water Reservoir. Service water is pumped from the reservoir, treated with corrosion inhibitors and biocides, circulated through the serviced loads, and then returned to the reservoir through spray nozzles for evaporative cooling. The spray system has a bypass capability for cold weather operation, when evaporative cooling is not required. Water from the North Anna reservoir is an alternate source of service water and is the normal source of make-up supply to the Service Water Reservoir.

System Evaluation Boundary The evaluation boundary for the service water system components subject to aging management review includes the service water and auxiliary service water pumps with associated auxiliary equipment, including the Service Water Reservoir spray arrays; and piping and components that provide cooling water to and from the recirculation spray heat exchangers, the component cooling heat exchangers, the control and relay room chiller condensers, the instrument air cooling water heat exchangers, and the charging pump lubricating oil and gearbox coolers. The service water traveling screen elements (the screens themselves) are subject to aging management review for loss of material. but other portions of the traveling screens are active compbnents. The evaluation boundary also includes nonsafety-related components that provide support to directly-connected safety-related components, or that retain water in buildings containing safety-~elated components.

System Intended Functions The service water system performs the following safety-related functions: The system provides cooling water to safety-related components, provides non-EQ safety-related instrumentation, and provides containment isolation. Therefore, the service water system is within the scope of license renewal in accordtince with the criteria of 10 CFR 54.4(a)(1).

\\.

Page2-97

Serial No.: 21-213 Supplement 3 Page 3 of 46 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Mechanical Systems The service water system contains nonsafety-related components whose failure could prevent satisfactory accomplishment of a safety-related function. Therefore, the service water system is within the scope of license renewal in accordance with the criterion of 10 CFR 54.4(a)(2) for spatial interaction and structural integrity.

The service water system is relied upon for compliance with regulations for Fire Protection (10 CFR 50.48), Environmental Qualification (10 CFR 50.49), and Station Blackout (10 CFR 50.63). Therefore, the service water system is within the scope of license renewal in accordance with the criteria of 10 CFR 54.4(a)(3).

UFSAR References Additional details of the service water system can be found in the UFSAR, Section 9.2.1 and Table 9.2-4.

Subsequent License Renewal Boundary Drawings The subsequent license renewal boundary drawings for the service water system are listed below:

11715-SLRB-040D Sh. 1 11715-SLRB-040D Sh. 2 11715-SLRM-078A Sh. 1 11715-SLRM-078A Sh. 2 11715-SLRM-078A Sh. 3 11715-SLRM-078A Sh. 4 11715-SLRM-078A Sh. 5 11715-SLRM-0788 Sh. 1 11715-SLRM-0788 Sh. 3 11715-SLRM-078C Sh. 1 11715-SLRM-078C Sh. 2 11715-SLRM-078G Sh. 1 11715-SLRM-078G Sh. 2 11715-SLRM-078H Sh. 1 11715-SLRM-078J Sh. 1 11715-SLRM-078K Sh. 1 11715-SLRM-078L Sh. 1 11715-SLRM-078L Sh. 2 Page2-98

Serial No.: 21-213 Supplement 3 Page 4 of 46 Subsequent License Renewal Boundary Drawings North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Mechanical Systems The subsequent license renewal boundary drawings for the bearing cooling system are listed below:

11715-SLRB-040C Sh. 3 11715-SLRB-040D Sh. 1 11715-SLRB-040D Sh. 3 11715-SLRM-0B0A Sh. 1 11715-SLRM-0B0A Sh. 2 11715-SLRM-0808 Sh. 1 11715-SLRM-080C Sh. 1 11715-SLRM-081A Sh. 1 11715-SLRM-089F Sh. 2 12050-SLRM-0B0A Sh. 1 12050-SLRM-0B0A Sh. 2 12050-SLRM-0808 Sh. 1 12050-SLRM-081A Sh. 1 Components Subject to Aging Management Review The component types subject to aging management review are indicated in Table 2.3.3-8, Bearing Cooling.

The aging management review results for these component types are indicated in Table 3.3.2-8, Auxiliary Systems - Bearing Cooling - Aging Management Evaluation.

2.3.3.9 Circulating Water

System Description

The circulating water system is supplied from the North Anna reservoir and provides cooling water for the main condenser. Circulating water is taken from the North Anna reservoir on the north side of the station and, after passing through the condenser, is discharged into the Waste Heat Treatment Facility to dissipate a large portion of the heat before returning to the reservoir. The ci~culating water system also provides makeup from the Intake Structure to the Service Water Reservoir.

Page2-100

Serial No.: 21-213 Supplement 3 System Evaluation Boundary Page 5 of 46 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Mechanical Systems The evaluation boundary for the circulating water system components subject to aging management review includes the safety-related screen wash pumps and the piping and components in the discharge path to the Service Water Reservoir, and nonsafety-related components that provide support to directly-connected safety-related components, or that retain water in buildings containing safety-related components, including the condenser water boxes and the condenser tube cleaning subsystem. Other portions of the condenser (i.e., the hotwell) are evaluated in the condensate system. The circulating water traveling screen elements (the screens themselves) are subject to aging management review for loss of material. but other portions of the traveling screens are active components. The condenser tubes do not perform an intended function for subsequent license renewal and are, therefore, not in-scope.

Additionally, the circulating water intake tunnel does not perform an intended function for subsequent license renewal and is, therefore, not in-scope. The circulating water discharge tunnel is in-scope and is evaluated as a structural component.

System Intended Functions The circulating water system performs the following safety-related functions: The safety-related screen wash pump and discharge piping provide makeup to the Service Water Reservoir. The system also provides non-EQ safety-related instrumentation, including signals to trip the circulating water pumps and stop flow upon sensing Turbine Building flooding. Therefore, the circulating water system is within the scope of subsequent license renewal in accordance with the criteria of 10 CFR 54.4(a)(1).

The circulating water system contains nonsafety-related components whose failure could prevent satisfactory accomplishment of a safety-related function. Therefore, the circulating water system is within the scope of subsequent license renewal in accordance with the criterion of 10 CFR 54.4(a)(2) for spatial interaction and structural integrity.

The circulating water system is relied upon for compliance with regulations for Fire Protection (10 CFR 50.48). Therefore, the circulating water system is within the scope of license renewal in accordance with the criteria of 10 CFR 54.4(a)(3).

UFSAR References Additional details of the circulating water system can be found in the UFSAR, Section 10.4.2.

Page2-101

Serial No.: 21 -213 Supplement 3 Page 6 of 46 Subsequent License Renewal Boundary Drawings North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Mechanical Systems The subsequent license renewal boundary drawings for the circulating water system are listed below:

11715-SLRM-077A Sh. 1 11715-SLRM-077A Sh. 2 11715-SLRM-99A Sh. 1 12050-SLRM-077A Sh. 1 12050-SLRM-077A Sh. 2 12050-SLRM-99A Sh. 1 Components Subject to Aging Management Review The component types subject to aging management review are indicated in Table 2.3.3-9, Circulating Water.

The aging management review results for these component types are indicated in Table 3.3.2-9, Auxiliary Systems - Circulating Water -Aging Management Evaluation.

2.3.3.10 Vacuum Priming

System Description

The vacuum priming system removes non-condensable gases from various plant systems, including the condensate system (condenser waterboxes, discharge tunnel) and bearing cooling system (pump casings and suction lines).

System Evaluation Boundary The evaluation boundary for the vacuum priming system components subject to aging management review includes the safety-related containment isolation components, and nonsafety-related components that provide support to directly-connected safety-related components, or that retain water in buildings containing safety-related components.

System Intended Functions The vacuum priming system performs the following safety-related functions: The system provides containment isolation, and provides non-EQ safety-related instrumentation. Therefore, the vacuum priming system is within the scope of license renewal in accordance with the criteria of 10 CFR 54.4(a)(1).

The vacuum priming system contains nonsafety-related components whose failure could prevent satisfactory accomplishment of a safety-related function. Therefore, the vacuum priming system is within the scope of license renewal in accordance with the criterion of 10 CFR 54.4(a)(2) for spatial interaction and structural integrity.

Page2-102

Serial No.: 21-213 Supplement 3 Table 2.3.3-7 Service Water Component Type Tank (air receiver)

Tank (chemical mixing chamber)

Tank (desiccant dryer)

Tank (polymer storage)

Traveling screen element Valve body Page 7 of 46 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Mechanical Systems Intended Function(s)

Pressure Boundary Leakage Boundary (Spatial)

Structural Integrity (Attached)

Leakage Boundary (Spatial)

Filtration Leakage Boundary (Spatial), Pressure Boundary, Structural Integrity (Attached)

Valve body (not covered by NRC GL Leakage Boundary (Spatial) 89-13)

The aging management review results for these component types are indicated in Table 3.3.2-7, Auxiliary Systems - Service Water - Aging Management Evaluation.

See Table 2.1-1 for definitions of intended functions.

Page2-166

Serial No.: 21-213 Page 8 of 46 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Mechanical Systems Supplement 3 Table 2.3.3-9 Circulating Water Component Type Intended Function(s)

Bolting Leakage Boundary (Spatial), Pressure Boundary Expansion joint Leakage Boundary (Spatial), Pressure Boundary Heat exchanger (condenser waterbox)

Leakage Boundary (Spatial)

Insulation (safety-related heat traced Thermal insulation components)

Piping, piping components Leakage Boundary (Spatial), Pressure Boundary Pump casing (Amertap)

Leakage Boundary (Spatial)

Pump casing (screen wash)

Pressure Boundary Strainer body Leakage Boundary (Spatial)

Strainer body (cover)

Leakage Boundary (Spatial)

Tank (ball collector cover)

Leakage Boundary (Spatial)

Tank (ball collector)

Leakage Boundary (Spatial)

Traveling screen element Filtration Valve body Leakage Boundary (Spatial), Pressure Boundary The aging management review results for these component types are indicated in Table 3.3.2-9, Auxiliary Systems - Circulating Water -Aging Management Evaluation.

See Table 2.1-1 for definitions of intended functions.

Page2-168

Serial No.: 21-213 Supplement 3 Page 9 of 46 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal 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 justified in the SLRA. If the AMP is a plant-specific program, the NRC 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.

[3.1.1-053a] [3.1.1-053b] [3.1.1-053c] [3.1.1-055c] [3.1.1-059a] [3.1.1-059b] [3.1.1-059c]

[3.1.1-119] - Electric Power Research Institute (EPRI) Topical Report (TR)-3002017168,

"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 werefound acceptable by the NRC,as documented in a staff-issued safety evaluation dated 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, 2020.

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). To address an 80-year operating period, the guidelines have been supplemented with a gap analysis that identifies enhancements to the PWR Vessel Internals (B2.1.7) program. 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 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 PWR Vessel lmternals (B2.1.7) program manages the applicable aging effects for the reactor vessel internal components and the Water Chemistry (B2.1.2) program monitors and controls water environments 1consistent with industry guidelines to ensure that the reactor coolant water environment is favorable to mitigate sec and pitting and crevice corrosion in RVI components.

Page3-31

Serial No.: 21-213 Page 10 of 46 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 Component Number

t *... ii**

3.1.1-083 Steel steam generator shell assembly exposed to secondary feedwater or steam 3.1.1-084 Steel top head enclosure (without cladding): top head, top head nozzles (vent, top head spray, RCIC, spare) exposed to reactor coolant 3.1.1-085 Stainless steel, nickel alloy, and steel with nickel alloy or stainless steel cladding reactor vessel flanges, nozzles, penetrations, safe ends,vessel shells, heads and welds exposed to reactor coolant 3.1.1-086 Stainless steel steam generator primary side divider plate exposed to reactor coolant 3.1.1-087 Stainless steel, nickel all<:>y -

PWR reactor internal components exposed to reactor coolant, neutron flux North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Aging

-Effect/Mechanism Loss of material due to general, pitting, crevice corrosion Loss of material due to general, pitting, crevice corrosion Loss of material due to pitting, crevice corrosion Cracking due to SCC

-Coss-of material due to pitting, crevice corrosion Aging Management Further Evaluation Discussion Program Recommended AMP XI.M2, Water No Not applicable. Loss of material of the steel steam Chemistry, and AMP XI.M32, generator shell assembly exposed to secondary One-Time Inspection feedwater or steam is addressed by item 3.1.1-012. The associated NUREG-2191 aging items are not used.

AMP XI.M2, Water No Not applicable - BWR only.

Chemistry, and AMP XI.M32, One-Time Inspection AMP XI.M2, Water No Not applicable - BWR only.

Chemistry, and AMP XI.M32, One-Time Inspection AMP XI.M2, Water Chemistry No Not applicable. NAPS has no in-scope stainless steel steam generator primary side divider plate exposed to reactor coolant in the Reactor Vessel, Internals, and Reactor Coolant System. The associated NUREG-2191 aging items are not used.

AMP XI.M2, Water Chemistry No

~On§i~tent wi\\h NUREG-2191.~Isl a1313lisasle. bass ef A'laleFial a~e le 13illiA§ aAS SFe>,<ise 69FF9Si9A is RBI aA a§iA§ effesl Feet~iFiA§ A'laAa§eA'leAI feF FeaeleF >,<essel iAleFAal (l=!l,ll) S9A'lJ39A8AIS 8lEJ39S88 le FeasleF seelaAI aA8 Ae~IFBA fl~lE.WesliA§RS~se's 8lEJ3eFI 13aAel Fe1,*iew ef Plll=!Fl 1 Q1 l=!e*;isieA 2 feF ~IAFlS iASisales weaF is IRe BAI~

less ef A'laleFial A'l86RaAiSA'l feF iA see13e !=!VI 68A'lJ3BAeAls. bess ef A'laleFial a~e le weaF is aaaFessea 8~ FBWS d.U Q!i4, d.U Q!iQa, d.U QeQs, d.1.1 QeQs, aAa d.1.1 11Q. TRe assesialea ~IUl=!~G 21Q1 a§iA§ ileA'ls aFe Rel ~sea.

Page 3-69 Supplement 3

Serial No.: 21-213 Page 11 of 46 Table 3.1.2-2 Reactor Vessel, Internals, and Reactor Coolant System - Reactor Vessel Internals - Aging Management

-'I-

• Evaluation Subcomponent Intended Material Function(s)

Lower internals ss StelliteTM (radial support key wear surface)

Lower support ss Cast (column body) austenitic stainless steel Lower support ss Stainless (column bolt) steel Lower support ss Stainless (lower support steel forging)

No additional FD;SP;SS Cast measures austenitic components stainless steel

.. ~

1!*

Nickel alloy.

Stainless steel Stellite' ReiiH,tQr vessel

~ Stainless steel in1e.rrfil QQmQQnents NiQ~el <lllQ~

Thermal shield ss Stainless (flexure) steel North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Environment (E) Reactor coolant and neutron flux (E) Reactor coolant

>250°C (>482°F) and neutron flux (E) Reactor coolant and neutron flux (E) Reactor coolant and neutron flux (E) Reactor coolant

>250°C (>482°F) and neutron flux (E} -Reactor coolant and neutron flux (E) Reactor coolant and neutron flux (E) Reactor coolant and neutron flux (El ReslQ.!Qr coQl<lnl ang neutrQn fl!.!X (El ReslQtQr QQQl<l t and neutron flux (E) Reactor coolant and neutron flux Aging Effect Requiring Aging Management Programs NUREG-2191 Table 1 Notes Management Item Item Loss of material PWR Vessel Internals (B2.1.7)

IV.B2.RP-285 3.1.1-059c C, 5 Cracking PWR Vessel Internals (B2.1.7)

IV.B2.RP-291 3.1.1-053b A

Water Chemistry (B2.1.2)

IV.B2.RP-291 3.1.1-053b A

Loss of fracture toughness; PWR Vessel Internals (B2.1.7)

IV.B2.RP-290 3.1.1-059b A

changes in dimensions Cracking PWR Vessel Internals (B2.1.7)

IV.B2.RP-286 3.1.1-053b A

Water Chemistry (B2.1.2)

IV.B2.RP-286 3.1.1-053b A

Loss of fracture toughness; PWR Vessel Internals (B2.1.7)

IV.B2.RP-287 3.1.1-059b A

loss of preload; changes in dimensions; loss of material Cracking PWR Vessel Internals (B2.1.7)

IV.B2.RP-291 a 3.1.1 -053b A

None PWR Vessel Internals (B2.1.7)

IV.B2.RP-265 3.1.1-055c A, 1 None PWR Vessel Internals (B2.1.7)

IV.B2.RP-265 3.1.1-055c A, 1 None PWR Vessel Internals (B2.1.7)

IV.B2.RP-265 3.1.1-055c A, 1 None PWR Vessel Internals (B2.1. 7)

None None F, 1 Loss Qf mslleri<l I Wsller Chemistry (B2.1.2l IV.B2.RP-24

~.1.1-087 6

LQss Qf m;;iteri<ll Water Chemistry (B2 1.2l IV.B2.BP-24

~1.J-Q87 6

Cracking PWR Vessel Internals (B2.1.7)

IV.B2.RP-302 3.1.1-053a A

Water Chemistry (B2.1.2)

IV.B2.RP-302 3.1.1-053a A

Loss of material PWR Vessel Internals (B2.1.7)

IV.B2.RP-302a 3.1.1-059a A

Page 3-92 Supplement 3

Serial No.: 21-213 Page 12 of 46 Table 3.3.2-7 Auxiliary Systems - Service Water - Aging Management Evaluation Component Intended Material Type Function(s)

Tank (descant SI Steel dryer)

Tank (polymer LB storage)

Fiberglass Traveling screen FLT Com;ier alloy element North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Environment (E) Air - indoor uncontrolled (I) Condensation (E) Air - indoor uncontrolled (I) Treated water (El Raw WsiJer Aging Effect Requiring Aging Management Programs Management Loss of material External Surfaces Monitoring of Mechanical Components (B2.1.23)

Loss of material Inspection of Internal Surfaces in Miscellaneous Piping and Dueling Components (B2.1.25)

Loss of material External Surfaces Monitoring of Mechanical Components (B2.1.23)

Cracking, blistering, loss of External Surfaces Monitoring of Mechanical material Components (B2.1.23)

Cracking, blistering, loss of Inspection of Internal Surfaces in Miscellaneous material Piping and Ducting Components (B2.1.25)

LQSS of material Fire Water SysJem (B2.1.1 §)

Page 3-357 NUREG-2191 Table 1 Notes Item Item VII.I.A-77 3.3.1-078 A

VII.D.A-26 3.3.1-055 A

VII.I.A-719 3.3.1-082 A

VII.I.A-720 3.3.1 -150 A

VII.G.A-644 3.3.1-175 A

VII.G.AP-197

n.1-054 6

Supplement 3

Serial No.: 21-213 Page 13 of 46 Table 3.3.2-9 Auxiliary Systems - Circulating Water - Aging Management Evaluation Component Intended Material Type Function(s)

Pump casing PB Steel (screen wash)

Strainer body LB Steel Strainer body LB Gray cast (cover) iron Tank (ball LB Aluminum collector cover)

Tank (ball LB Steel collector)

Tr;;iv~ling §Qr~~n FLT St;;iinl~l2l2 element

~

North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Environment (E) Air - indoor uncontrolled (E) Raw water (I) Raw water (E) Air - indoor uncontrolled (I) Raw water (E) Air - indoor uncontrolled (I) Raw water (E) Air - indoor uncontrolled (I) Raw water (E) Air - indoor uncontrolled (I) Raw water (El R;;iw W;;it~r Aging Effect Requiring Aging Management Programs Management Loss of material External Surfaces Monitoring of Mechanical Components (B2.1.23)

Long-term loss of material One-Time Inspection (B2.1.20)

Loss of material External Surfaces Monitoring of Mechanical Components (B2.1.23)

Long-term loss of material One-Time Inspection (B2.1.20)

Loss of material Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.25)

Loss of material External Surfaces Monitoring of Mechanical Components (B2.1.23)

Long-term loss of material One-Time Inspection (B2.1.20)

Loss of material Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.25)

Loss of material External Surfaces Monitoring of Mechanical Components (B2.1.23)

Long-term loss of material One-Time Inspection (B2.1.20)

Loss of material Selective Leaching (B2.1.21)

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.25)

Cracking One-Time Inspection (B2.1.20)

Loss of material One-Time Inspection (B2.1.20)

Cracking One-Time Inspection (B2.1.20)

Loss of material One-Time Inspection (B2.1.20)

Loss of material External Surfaces Monitoring of Mechanical Components (B2.1.23)

Long-term loss of material One-Time Inspection (B2.1.20)

Loss of material Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.25)

Lo§s of material Fire Water Sllst~m (B2.1.1 (1)

Page 3-369 NUREG-2191 Table 1 Notes Item Item VII.I.A-77 3.3.1-078 A

VI I. C 1.A-532 3.3.1-193 A

VII.ES.A-410 3.3.1-135 A

VII.C1.A-532 3.3.1-193 A

VII.C1.A-727 3.3.1-134 A

VII.I.A-77 3.3.1-078 A

VII.C1.A-532 3.3.1-193 A

VII.C1.A-727 3.3.1-134 A

VII.I.A-77 3.3.1-078 A

VI I. C 1.A-532 3.3.1-193 A

VII.C1.A-51 3.3.1-072 A

VII.C1.A-727 3.3.1-134 A

VII.C1.A-451a 3.3.1-189 A

VII.C1.A-763a 3.3.1 -234 A

VII.C1.A-451 a 3.3.1-189 A

VII.C1.A-776b 3.3.1-247 A

VII.I.A-77 3.3.1-078 A

VI I. C 1.A-532 3.3.1-193 A

VII.C1.A-727 3.3.1-134 A

Vll.~.A-55 J~ 1-066 6

Supplement 3

Serial No.: 21-213 Page 14 of 46 Table 3.3.2-42 Auxiliary Systems - Fire Protection - Aging Management Evaluation Component Intended Material Environment Aging Effect Requiring Aging Management Programs Type Function(s)

Management Valve body LB;PB Stainless (E) Air - indoor Cracking One-Time Inspection (B2.1.20)

Steel uncontrolled Loss of material One-Time Inspection (B2.1.20)

(I) Air - indoor Cracking One-Time Inspection (B2.1.20) uncontrolled Loss of material One-Time Inspection (B2.1.20)

Steel (E) Air - indoor Loss of material External Surfaces Monitoring of Mechanical uncontrolled Components (B2.1.23)

(I) Air - indoor Flow blockage Fire Water System (B2.1.16) uncontrolled Loss of material Fire Protection (B2.1.15)

Fire Water System (B2.1.16)

(E) Air - outdoor Loss of material External Surfaces Monitoring of Mechanical

• cc:--

Components (B2.1.23)

(E) Air with borated Loss of material Boric Acid Corrosion (B2.1.4) water leakage (I) Gas None None (I) Raw water Long-term loss of material One-Time Inspection (B2.1.20)

Loss of material Fire Water System (B2.1.16)

Loss of material; flow Fire Water System (B2.1.16) blockage Table 3.3.2-42 Plant-Specific Notes:

NUREG-2191 Item VII.G.AP-209a VII.G.AP-221 a VII.G.AP-209a VII.G.AP-221a VII.I.A-77 VII.G.A-404 VII.G.AP-150 VII.G.A-412 VII.I.A-77 VII.I.A-79 VII.J.AP-6 VII.G.A-532 VII.G.A-400 VII.G.A-33

1.

Internal and external environments are such that the external surface condition is representative of the internal surface condition.

Table 1 Item 3.3.1-004 3.3.1-006 3.3.1-004 3.3.1-006 3.3.1 -078 3.3.1-131 3.3.1-058 3.3.1 -136 3.3.1-078 3.3.1-009 3.3.1-121 3.3.1-193 3.3.1-127 3.3.1-064

2.

Flow blockage is addressed by the cited NUREG-2191 item, but is not an applicable aging effect requiring management for nonsafety-related components that do not support a function of delivering downstream flow.

Notes A

A A

A A

B A, 3 D

A A

A A

B B

3.

The Fire Protection (B2.1.15) program will manage loss of material for the steel Halon and carbon dioxide fire suppression piping, tanks, and valves exposed internally to air.

4.

Cracking of copper alloy (>15% Zn) in air and condensation environments requires the presence of ammonia-based compounds. In indoor air, such compounds could be conveyed to external surfaces of components via leakage through the insulation from bolted connections. However, internal surfaces of components are not exposed to contamination from external leakage sources. Therefore, internal cracking of these components is not expected.

5.

Cracking, hardening, loss of strength, and shrinkage are not aging effects requiring management for steel fire damper assemblies exposed to air.

North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Page 3-537 Supplement 3

Serial No.: 21-213 Page 15 of 46

6.

The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.25) program will manage cracking of copper alloy (>15%

Zn) components exposed to raw water.

7.

This row includes piping and fittings downstream from hose rack isolation valves.

8.

Not used.

9.

This row includes piping and fittings associated with standpipe risers.

10. Flow blockage is an aging effect requiring management only for copper alloy valve bodies in the water suppression portion of the fire protection system.

It is not an aging effect requiring management in the carbon dioxide or Halon portions.

11. Cracking of buried gray cast iron piping due to cyclic loading is managed by the Buried and Underground Piping and Tanks (B2.1.27) program. CLB fatigue analysis does not exist.

12. Aging effects for lined ductile iron valves (01-FP-85 and 01-FP-90) are managed as follows: Loss of coating or lining integrity; loss of material due to general, pitting, crevice corrosion, and MIC; and flow blockage due to fouling are managed with the Fire Water System (B2.1.16) program. Full flow test\\ng and flushing is performed annually, at design pressure and flow rate, on downstream hydrants to detect flow blockage due to fouling as result of corrosion products or coating debris. Valves are flushed fully open for greater than one minute until all foreign material has cleared. Loss of material due to selective leaching is managed by the Selective Leaching (B2.1.21) program, and long-term loss of material is managed by the One-Time Inspection (B2.1.20) program.

13. /\\s noted in H=ie Fire 'Nater ~ystem (82.1.16) program mcoeption, the filtration intended funotion Of the fire pump suotion strainer element will be performed by the upstream servioe water or oiroulating water system tra¥eling screens, whioh are aotiYe components and not subjeot to aging management review.As noted in the Fire Water System /B2.1.16) program exception. flow blockage of the fire pump suction strainer element is precluded by operation of the upstream service water or circulating water system traveling screens. Loss of material of the fire pump suction strainer element will be managed by the Fire Water System (82.1.16) program.

North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Page 3-538 Supplement 3

Serial No.: 21-213 Page 16 of 46 Supplement 3 A1.16 FIRE WATER SYSTEM North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Appendix A - UFSAR Supplement The Fire Water System program is an existing condition monitoring program that manages cracking, flow blockage, loss of coating or lining integrity and, loss of material for in-scope water-based fire protection systems. This program manages cracking, flow blockage, and, loss of material by conducting periodic visual inspections, flow testing, and flushes performed in accordance with the NFPA 25, 2011 Edition. Testing or replacement of sprinklers that have been in place for 50 years is performed in accordance with NFPA 25, 2011 Edition.

With exception of two locations that will be reconfigured to allow drainage, portions of the water-based fire protection system that have been wetted but are normally dry have been confirmed to drain and are not subjected to augmented testing and inspections.

The water-based fire protection system is normally maintained at required operating pressure and is monitored such that loss of system pressure is immediately detected and corrective actions initiated. 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 follow site procedures that include inspection parameters for items such as lighting, distance offset, presence of protective coatings, and cleaning processes that ensure an adequate examination.

A1.17 OUTDOOR AND LARGE ATMOSPHERIC METALLIC STORAGE TANKS The Outdoor and Large Atmospheric Metallic Storage Tanks program is an existing condition monitoring program that manages the effects of cracking and loss of material on the outside and inside surfaces of aboveground metallic tanks constructed on concrete or soil. This program is a condition monitoring program that manages aging effects associated with outdoor tanks with internal pressures approximating atmospheric pressure including the refueling water storage tanks (RWSTs), refueling water chemical addition tanks (CATs), casing cooling tanks (CCTs), and emergency condensate storage tanks (ECSTs). The program includes preventive measures to mitigate corrosion by protecting the external surfaces of steel components con~istent with standard industry practices. The RWSTs and CCTs are insulated and rest on a concrete foundation covered with an oil sand cushion. Caulking is used at the concrete-component interfac~ of the RWSTs and CCTs. The CATs are skirt supported and insulated. The ECSTs are internally coated and protected by concrete missile barriers.

The program manages loss of material on tank internal bare metal surfaces by conducting visual inspections. Inspections of RWST and CCT caulking/sealants are supplemented with physical manipulation. Surface exams of external tank surfaces are conducted to detect cracking on the stainless-steel tanks*.1,Thickness measurements of the tank's bottoms are conducted to ensure that significant degradati6n is not occurring. The external surfaces of insulated tariks are periodically PageA-12

Serial No.: 21-213 Page 17 of 46 Supplement 3 A1.26 LUBRICATING OIL ANALYSIS North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Appendix A - UFSAR Supplement The Lubricating Oil Analysis program is an existing preventive program that ensures that loss of material and reduction of heat transfer is not occurring by maintaining the quality of the lubricating oil or hydraulic oil. The program ensures that contaminants (primarily water and particulates) are within acceptable limits. Testing activities include sampling and analysis of lubricating oil for detrimental contaminants. Oil testing that indicates the presence of water or particulates results in the initiation of corrective action that may include evaluating for inleakage.

A1.27 BURIED AND UNDERGROUND PIPING AND TANKS The Buried and Underground Piping and Tanks program is an existing condition monitoring program that manages blistering, cracking, and loss of material on external surfaces of components in soil, concrete, or underground environments within the scope of subsequent license renewal through preventive and mitigative actions. The program addresses piping and tanks composed of stainless steel, carbon steel, cast iron, ductile iron, copper alloy, and fiberglass.

Depending on the material, preventive and mitigative techniques include external coatings, cathodic protection (CP), and the quality of backfill. Direct visual inspection quantities for buried components are planned using procedural categorization criteria. Transitioning to a higher number of inspections than originally planned is based on the effectiveness of the preventive and mitigative actions. Also, depending on the material, inspection activities include annual surveys of CP, nondestructive evaluation of pipe or tank wall thicknesses, and visual inspections of the pipe from the exterior. For steel components, where the acceptance criteria for the effectiveness of the cathodic protection is other than -850 mV instant off, loss of material rates are measured.

Soil sampling and testing is performed during each excavation and a station-wide soil survey based on initial baseline data is also performed once in each 10-year period to confirm the soil corrosivity level near components within the scope of subsequent license renewal for the installed material types.

Inspections are conducted by qualified individuals. Where the coatings, backfill or the condition of exposed piping does not meet acceptance criteria such that the depth or extent of degradation of the base n;ietal could have resulted in a loss of pressure bounda~y function when the loss of material rate\\ is extrapolated to the end of the subsequent period of ext~nded operation an increase in the sample size is conducted.

/\\s an alternative to performing 1risual inspections of the buried fire proteotion system components, monitoring the aotivity of the jockey pump is performed by the Fire v1/2itor System program (A1.16).

PageA-20

Serial No.: 21-213 Page 18 of 46 Table A4.0-1 Subsequent License Renewal Commitments Program 15 Fire Protection program 16 Fire Water System program Commitment The Fire Protection program is an existing condition monitoring program that will be enhanced as follows:

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.

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.

The Fire Water System program is an existing condition monitoring and performance monitoring program that will be enhanced as follows:

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 te-sts 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.

North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Appendix A - UFSAR Supplement PageA-67 AMP Implementation Program enhancements for SLR will be implemented B2.1.15 6 months prior to the subsequent period of extended operation.

Program will be implemented and inspections or tests begin 5 years before the subsequent period of extended operation.

Inspections or tests that are to be completed prior to the B2.1.16 subsequent period of extended operation are 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.

Supplement 3

Serial No.: 21-213 Page 19 of 46 Table A4.0-1 Subsequent License Renewal Commitments Program Commitment

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 0.5, 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.

16 Fire Water System program

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.

4. Procedures will be revised to address recurring internal corrosion with the use of Low Frequency Electromagn*etic 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 addition 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 joclrny 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 ~IURE:G 2191,Section XI. M 41.

(Relocated from original Commitment l Supplement 2)!Deleted - Supplement 3)

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 Application for Subsequent License Renewal Appendix A - UFSAR Supplement PageA-68 AMP Implementation Program will be implemented and inspections or tests begin 5 years before the subsequent period of extended operation.

Inspections or tests that are to be completed prior to the B2.1.16 subsequent period of extended operation are 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.

Supplement 3

Serial Nb.: 21-213 Page 20 of 46 Table A4.0-1 Subsequent License Renewal Commitments 16 Program Commitment

7. +Re aeti,,ity ef tRe jeeliey 131::1FA13 (i.e., an ineFease in tRe n1::1FA0eF ef 131::1FA13 staFts eF F1::1n tiFAe ef tRe 131::1FA13) will se FAeniteFeel eensistent witR tRe "eletestien ef a§in§ effeets" j3FS§FaFA eleFAent ef ~l6JR~G ~191, Seetien XI.M41.

(Reloc2!~d !o new CQmmitment 5 - Sugglement 2)

8. l=lFeeeel1::1Fes will se Fe.,.iseel feF wet 51i51e s51Finl~leF S!tsteFAs a ene tiFAe test ef s51Finl~leFs tRal Ra,1e seen eH51eseel le,YaleF insl1::1elin§ !Re saFA51le sice saFA51le selestien sFileFia anel FAiniFAl::IFA liFAe in seFYise sf testeel s51Finl~leFs *Nill se 51eFfsFFAeel. Al easR 1::1nit, a saFA13le sf g%, eF a FAa,EiFA1::1FA sf ten,Yet 13i13e s13Finl~leFs wilR ns FASFe !Ran fo1::1F s13Finl~leFs 13eF slF1::1611::1Fe sRall se testeel. =+estin§ is easeel en a FAiniFA1::1FA tiFAe in sep,,iee ef fi#y yeaFS anel se*,eFily ef e13erntin§ seneliliens foF easR 13e131::1lalien. (Re.,.iseel S1::1@leFAenl 1 )(Comgleted -

Fire Water System Sugglement 2) program

9. Procedures will be revised to gerform a visual insgection of the fire grotection gumg suction strainer§ for loss of ma!~rial on a 12-l,(ear freguencl,(. (Added - ~ugglement 3)

North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Appendix A - UFSAR Supplement PageA-69 AMP Implementation Program will be implemented and inspections or tests begin 5 years before the subsequent period of extended operation.

Inspections or tests that are to be completed prior to the B2.1.16 subsequent period of extended operation are 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.

Supplement 3

Serial No.: 21-213 Page 21 of 46 Table A4.0-1 Subsequent License Renewal Commitments 26 27 Program Commitment Lubricating Oil The Lubricating Oil Analysis program is an existing preventive program that is credited.

Analysis program The Buried and Underground Piping and Tanks program is an existing condition monitoring program that will be enhanced as follows:

1. Procedures will be revised to obtain pipe-to-soil potential measurements for piping in the scope of SLR during the next soil survey within 1 O years prior to entering the subsequent period of operation.

2. The following service water CP subsystems will be refurbished and reconnected before the last five years of the inspection period prior to entering the subsequent period of extended operation:

a. The service water 'D' CP subsystem

b. The service water 'C' CP subsystem associated with the buried carbon steel piping of the fuel oil system for the emergency electrical power system

3. The following buried giging materials will be reglaced before the last five ~ears of the insgection geriod grior to entering the §YQSeguent geriod of extended ogeration. (Added - Sugglement 1)

a. The buried cogger giging between the fire grotection jocke~ gumg and the h~drogneumatic tank will be Buried and reglaced with carbon steel.

Underground Piping

b. The buried carbon steel fill line giging for the security diesel fuel oil tank will be reglaced with corrosion and Tanks program resistant material that does not reguire insgection (e.g., titanium allo~. suger austenitic or nickel allo~

materials).

4. Procedures will be revised to specify that cathodic protection surveys use the -850 mV polarized potential, instant off criterion specified in NACE SP0169-2007 for steel piping acceptance criteria unless a suitable alternative polarization criteria can be demonstrated. Alternatives will include the -100 mV polarization criteria,

-750 mV criterion (soil resistivity is greater than 10,000 ohm-cm to less than 100,000 ohm-cm}, -650 mV criterion (soil resistivity is greater than 100,000 ohm-cm), or verification of less than 1 mpy loss of material rate.

a. The external loss of material rate is verified:

• Every year when verifying the effectiveness of the cathodic protection system by measuring the loss of material rate.

• Every 2 years when using the 100 mV minimum polarization.

• Every 5 years when using the -750 or -650 mV criteria associated with higher resistivity soils. The soil resistivity is verified every 5 years.

North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Appendix A - UFSAR Supplement PageA-78 AMP Implementation B2.1.26 Ongoing Program will be implemented and inspections begin 10 years before the subsequent period of extended operation. Inspections that are to be completed prior to B2.1.27 the subsequent period of extended operation are 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.

Supplement 3

Serial No.: 21-213 Page 22 of 46 Table A4.0-1 Subsequent License Renewal Commitments 27 Program Commitment

b. As an alternative to verifying the effectiveness of the cathodic protection system every five years, soil resistivity testing is conducted annually during a period of time when the soil resistivity would be expected to be at its lowest value (e.g., maximum rainfall periods). Upon completion of ten annual consecutive soil samples, soil resistivity testing can be extended to every five years if the results of the soil sample tests consistently have verified that the resistivity did not fall outside of the range being credited (e.g., for the

-750 mV relative to a CSE, instant off criterion, measured soil resistivity values were greater than 10,000 ohm-cm).

c. When using the electrical resistance corrosion rate probes:

• The individual determining the installation of the probes and method of use will be qualified to NACE Cl?4, "Cathodic Protection Specialist" or similar

• The*impact of significant site features and local soil conditions will be factored into placement of the probes and use of the data

5. Procedures will be revised to reguire a minimum of six excavations be conducted at each unit and five of the Buried and insgections at each unit destructively examine the buried gray cast iron fire grotection QiQing. A ten-foot gige Underground Piping length will be excavated for each Q!Jried gr2y cast irQn fire grotection giging s2mgle and the external surfaces and Tanks program insgected for blis1ering cracking, hardening or loss of strength, and loss of material. NUREQ-2191 Section XI.M33 Selective Leaching grogram examinations will be conducted on a one-foot length /minimum) giging section from each discrete excavation location (five/unit) to insgect for loss of material due to selective leaching. The selection of insgection locations for buried gray cast iron fire grotection giging and giging comgonents will consider the following criteria: /Added - Sugglement 3)

• Older giging segments /i.e. not greviously reglaced)

• Piging and giging comgonents found to be continuously wetted due to leaking giging/valves or in soil with high corrosivity ratings as determined by EPRI Regort 3002005294, Soil Samgling and Testing Methods to Evaluate the Corrosivity of the Environment for Buried Piging and Tanks a1 Nuclear Power Plants

• Piging and QiQing comgonents not cathodically grotected

• Piging and giging comgonents with significant coating degradation or unexgected backfill

• Conseguence of failure /i.e. groximity to safety-related giging and giging comgonents)

• Locations with gotentially high stress and/or cyclic loading conditions such as QiQing adjacent to locations that were reg laced due to cracking/rugture locations subject to settlement or locations subject to heavy load traffic North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Appendix A - UFSAR Supplement PageA-79 AMP Implementation Program will be implemented and inspections begin 10 years before the subsequent period of extended operation. Inspections that are to be completed prior to B2.1.27 the subsequent period of extended operation are 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.

Supplement 3

Serial No.: 21-213 Page 23 of 46 Table A4.0-1 Subsequent License Renewal Commitments 49 Program Commitment Procedures will be develoged to reglace the diesel-driven fire gumg engine heat exchanger tube bundle on a N/A 20-~ear freguenc~aRe FeEjYiFe tAe Aeat elESAaR§eF tc1se sc1Rale feF tl'le s13aFe eR§iRe ts se Fe13lasee 13FisF ts seiR§ 13lasee iR seF¥ise,,,,iitl'I tl'le eiesel eFi>;eR fiFe 13c1m19. (Added North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Appendix A-UFSAR Supplement RAI Set 1) (Revised - Sugglement 3)

PageA-89 AMP Implementation Procedures to reglace the diesel-driven fire gumg heat exchanger tube bundle will be in glace § yeaFs 13FisF ts t!:ie Aeat eiesAaR§eF tc1se BYRele asAie>,1iR§ ~g yeaFs sf asti~*e seF¥ise..J2y_

N/A 12/31 /2021. Initial reglacement of the tube bundle for engine

1. 10277066 or reglacement of that engine with the sgare engine will be comgleted b~

12/31 /2025.(Added RAI Set

1) (Revised - Sugglement 3)

Supplement 3

Serial No.: 21-213 RAI 4 / Supplement 3 82.1.16 Fire Water System Program Description Page 24 of 46 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Appendix 8 -Aging Management Programs The Fire Water System program is an existing condition monitoring program that manages cracking, flow blockage, loss of coating or lining integrity, 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 req*uired operating pressure and is monitored such that loss of system pressure is detected and corrective actions initiated. A low-pressur.e 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.

PageB-106

Serial No.: 21-213 RAI 4 / Supplement 3 Page 25 of 46 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal 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., NFPA 25, 2011 Edition, Section 6.3.1) or a main drain test (i.e., NFPA 25, 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 locations.

Aging of the external surfaces of buried and underground fire :main piping is managed by the Buried and1 Underground Piping and Tanks program (B2.1.27). Loss of material and cracking of the internal surfaces of cementitious lined buried and underground fire mai~ 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 Th*e 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.

PageB-107

Serial No.: 21-213 RAI 4 / Supplement 3 Exception Summary Page 26 of 46 The following program element is affected:

Detection of Aging Effects (Element 4)

North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Appendix B -Aging Management Programs

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 r~view of work orders since 1993 revealed no I

indication of any flow blockage of either fire pumps' s~ction.

Monitoring and trending of the circulating water and s~rvice 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.

Inspection of the circulation water traveling water screens every six months. and inspection of the service water traveling screens every year for loss of material provides assurance that no large diameter debris will reach the fire pump suction.

_.',r PageB-108

.

• r

.. r Serial No.: 21-213 RAI 4 / Supplement 3 Page 27 of 46 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Appendix B -Aging Management Programs Inspection of the fire pump suction strainers will be conducted for loss of material every 12 years.

The 12 year frequency permits coordination with existing periodic maintenance inspections within the sub-systems which reduces out of service time and provides for the proper utilization of staff resources.

2.

NUREG-2191, TableXI.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.

Justification for Exception As indicated by NUREG-2191,Section XI.M27, Table XI.M27-1, 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/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 nece,ssary corrective action.

c. If a flow test or a main drain test does not meet acceptance criteria due to current or projected degradation additional te*sts 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 d~ not meet acceptance criteria, an extent of condition and extent of cause analysis is cq~ducted to determine the further extent of tests. The PageB-109

Serial No.: 21-213 RAI 4 / Supplement 3 Page 28 of 46 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Appendix B Aging Management Programs 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, 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 T~chnique (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 PageB-110

Serial No.: 21-213 RAI 4 / Supplement 3 Page 29 of 46 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Appendix B -Aging Management Programs examinations to ensure aging effects are managed and wall thickness is within acceptable limits. In addition 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 aging effeots" program element of NUREG 2191,Section XI.M11. (Relocated from original Commitment 6 Supplement 2)

(Deleted - Supplement 3)

Detection of Aging Effects (Element 4)

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.

(Relocated to new Commitment 5 - Supplement 2)

8.

(Completed - Supplement 2)

Parameters Monitored/Inspected (Element 3): Detection of Aging Effects (Element 4)

9.

Procedures will be revised to perform a visual inspection of the fire protection pump suction strainers for loss of material on a 12-year frequency. (Added - Supplement 3)

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, ~n inspection of the fire water system piping identified d,ebris on the internal surfaces. Thi;) external condition of the pipe was observed to be t~_inning 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-1manufacturing flaws or a flaw that was initiated during the installation process. There were nd1 1reported instances due to age related degradation. The ~'etallurgical Page B-111

Serial No.: 21-213 RA! 4 / Supplement 3 Page 30 of 46 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Appendix B -Aging Management Programs failure reports for these pipe failures did not attribute any of the failures to the cementitious liner. Several of the materials analysis 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 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 refueling 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 ~prinkler 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 *it1ot 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.

PageB-112

Serial No.: 21-213 RAI 4 / Supplement 3 Page 31 of 46 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Appendix B -Aging Management Programs

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:

• Procedures credited for license renewal were identified

• 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 the 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.

I

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 dete.?mined to not provide any additic:i-~al debris removal. Engineering determined the existing'flushing methodology and Page B-113

Serial No.: 21-213 RAI 4 / Supplement 3 Page 32 of 46 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Appendix B - Aging Management Programs 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)

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 inspecttons are scheduled for Unit 1 and 2.

1 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 1 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 1 :*':1thickness is within acceptable limits. In addition tot~~ pipe wall thickness examination, PageB-114

Serial No.: 21-213 RAI 4 / Supplement 3 Page 33 of 46 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Appendix 8 Aging Management Programs 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 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-115

Serial No.: 21-213 RAI 4 / Supplement 3 Page 34 of 46 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Appendix B -Aging Management Programs B2.1.27 Buried and Underground Piping and Tanks Program Description The Buried and Underground Piping and Tanks program is an existing condition monitoring program that manages blistering, cracking, hardening or loss of strength, and loss of material on external surfaces of piping and tanks in soil, concrete, or underground environments within the scope of subsequent license renewal through preventive and mitigative actions. The program addresses stainless steel, carbon steel, cast iron, ductile iron, copper alloy, and fiberglass piping and tanks.

The program will also manage cracking due to cyclic loading in buried gray cast iron fire protection piping that is lined with a cementitious coating.

Depending on the material, preventive and mitigative techniques include external coatings, cathodic protection (CP), and the quality of backfill. Direct visual inspection quantities for buried components are planned using procedural categorization criteria. Transitioning to a higher number of inspections than originally planned is based on the effectiveness of the preventive and mitigative actions. Also, depending on the material, inspection activities include annual surveys of CP, non-destructive evaluation of pipe or tank wall thicknesses, and visual inspections of the pipe from the exterior.

The buried carbon steel piping of the service water system and the flood protection dike drain is protected by an active CP system. Periodic inspections confirm CP system availability and reliability. Annual CP surveys are conducted to assess the effectiveness of the CP system. The program uses the -850 mV relative to CSE (copper/copper sulfate reference electrode), instant off criterion specified in NACE SP0169 for acceptance criteria for steel piping and tanks and determination of cathodic protection system effectiveness in performing cathodic protection surveys. The program includes an upper limit of -1200 mV on cathodic protection pipe-to-soil potential measurements of coated pipes to preclude potential damage to coatings. For steel components, where the acceptance criteria for the effectiveness of the cathodic protection is other than -850 mV instant off, loss of material rates are measured. The buried carbon steel piping of the fuel oil system for the emergency electrical power system will be refurbished and reconnected to the service water CP system described above.

Soil sampling and testing is performed during each excavation and a station-wide soil survey based on initial baseline data is also performed once in each 10-year period to confirm the soil corrosivity level near components within the scope of license renewal for the installed material types. Soil sampling and testing is consistent with EPRI Report 3002005294, "Soil Sampling and Testing Methods to Evaluate the Corrosivity of the Environment for Buried Piping and Tanks at Nuclear Power Plants." Soil survey baselines were performed in 2011.

PageB-188

Serial No.: 21 -213 RAI 4 I Supplement 3 Page 35 of 46 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Appendix B - Aging Management Programs External inspections of buried components within the scope of subsequent license renewal will occur opportunistically when they are excavated for any reason.

Inspections are conducted by qualified individuals. Where the coatings, backfill or the condition of exposed piping does not meet acceptance criteria such that the depth or extent of degradation of the base metal could have resulted in a loss of pressure boundary function when the loss of material rate is extrapolated to the end of the subsequent period of extended operation an increase in the sample size is conducted.

/\\s an alternati1.<<e to performing visual inspeotions of the buried fire proteotion system oomponents, monitoring the aotivity of the jookey pump is performed by the Fire ~"later System program (B2.1.16). The water based fire protection system is normally maintained at required operating pressure and is monitored such that a loss of system pressure is detected and oorreetive action initiated.

The Selective Leacf:Jing program (B2.1.21) is applied in addition to this program to manage seleetii.*e leashing for applicable materials in soil en1.<<ironments.

The Buried and Underground Piping and Tanks program conducts periodic and opportunistic visual inspections of the buried fire protection system piping and components that will facilitate examinations performed by the Selective Leaching program (82.1.21) to manage loss of material due to selective leaching for applicable materials in soil environments. A minimum of six excavations will be required to be conducted at each unit and five of the inspections at each unit will destructively examine the buried gray cast iron fire protection piping. Consistent with NUREG-2191 Section XI.M41. Buried and Underground Piping and Tanks program. a ten-foot pipe length will be excavated for each buried gray cast iron fire protection piping sample to inspect for blistering.

cracking. hardening or loss of strength. and loss of material on external surfaces of piping.

NUREG-2191 Section XI.M33. Selective Leaching program. examinations will also be conducted on a one-foot length (minimum) piping section from each discrete excavation location (five/unit) to inspect for the loss of material due to selective leaching. Sections of buried gray cast iron fire protection piping and piping components that are removed for destructive examination will be replaced with ductile iron piping and _piping components.

I The Buried and Underground Piping and Tanks program is implemented as a Fleet progran:i 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).

PageB-189

Serial No.: 21-213 RAI 4 / Supplement 3 NUREG-2191 Consistency Page 36 of 46 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Appendix B Aging Management Programs The Buried and Underground Piping and Tanks program is an existing program that, following enhancement, will be consistent, with NUREG-2191,Section XI.M41, Buried and Underground Piping and Tanks.

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

Preventive Actions (Element 2)

1.

Procedures will be revised to obtain pipe-to-soil potential measurements for piping in the scope of SLR during the next soil survey within 10 years prior to entering the subsequent period of operation.

Detection of Aging Effects (Element 4) and Corrective Actions (Element 7)

2.

The following service water CP subsystems will be refurbished and reconnected before the last five years of the inspection period prior to entering the subsequent period of extended operation.

a. The service water 'D' CP subsystem

b. The service water 'C' CP subsystem associated with the buried carbon steel piping of the fuel oil system for the emergency electrical power system Scope of Program (Element 1), Preventive Actions (Element 2) and Detection of Aging Effects (Element 4)

3.

The following buried piping materials will be replaced before the last five years of the inspection period prior to entering the subsequent period of extended operation. (Added Supplement 1)

a. The buried copper piping between the fire protection jockey pump and the hydropneumatic tank will be replaced with carbon steel.

b. The buried carbon steel fill line piping for the security diesel fuel oil tank will be replaced with corrosion resistant material that does not require inspection (e.g., titanium alloy, super austenitic, or nickel alloy materials).

Acceptance Criteria (Element 6)

4.

Procedures will be revised to specify that cathodic protection surveys use the -850 mV polarized potential, instant off criterion specified in NACE SP0169-2007 for steel piping acceptance criteria unless a suitable alternative polarization criteria can be demonstrated.

PageB-190

Serial No.: 21-213 RAI 4 / Supplement 3 Page 37 of 46 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Appendix B - Aging Management Programs Alternatives will include the -100 mV polarization criteria, -750 mV criterion (soil resistivity is greater than 10,000 ohm-cm to less than 100,000 ohm-cm), -650 mV criterion (soil resistivity is greater than 100,000 ohm-cm), or verification of less than 1 mpy loss of material rate.

a. The external loss of material rate is verified:

Every year when verifying the effectiveness of the cathodic protection system by measuring the loss of material rate.

Every 2 years when using the 100 mV minimum polarization.

Every 5 years when using the -750 or -650 mV criteria associated with higher resistivity soils. The soil resistivity is verified every 5 years.

b. As an alternative to verifying the effectiveness of the cathodic protection system every five years, soil resistivity testing is conducted annually during a period of time when the soil resistivity would be expected to be at its lowest value (e.g., maximum rainfall periods). Upon completion of ten annual consecutive soil samples, soil resistivity testing can be extended to every five years if the results of the soil sample tests consistently have verified that the resistivity did not fall outside of the range being credited (e.g., for the -750 mV relative to a CSE, instant off criterion, measured soil resistivity values were greater than 10,000 ohm-cm).

c. When using the electrical resistance corrosion rate probes:

The individual determining the installation of the probes and method of use will be qualified to NACE CP4, "Cathodic Protection Specialist" or similar The impact of significant site features and local soil conditions will be factored into placement of the probes and use of the data Detection of Aging Effects (Element 4)

5.

Procedures will be revised to require a minimum of six excavations be conducted at each unit and five of the inspections at each unit destructively examine the buried gray cast iron fire protection piping. A ten-foot pipe length will be excavated for each buried gray cast iron fire protection pi~ing sample and the external surfaces inspected for ~listering, cracking, hardening or loss of strength, and loss of material. NUREG-2191 Section XI.M33 Selective Leaching program examinations will be conducted on a one-foot length: (minimum) piping I

section from each discrete excavation location (five/unit) to inspect for loss of material due to selective leaching. The selection of inspection locations for buried gray cast iron fire protection piping and piping components will consider the following criteria: (Added -,Supplement 3)

• Older piping segments (i.e. not previously replaced)

• Piping and piping components found to be continuously wetteb due to leaking piping/valves or in soil with high corrosivity ratings as determined by EPRI Report PageB-191

Serial No.: 21-213 RAI 4 I Supplement 3 Page 38 of 46 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Appendix B -Aging Management Programs 3002005294, Soil Sampling and Testing Methods to Evaluate the Corrosivity of the Environment for Buried Piping and Tanks at Nuclear Power Plants

• Piping and piping components not cathodically protected

• Piping and piping components with significant coating degradation or unexpected backfill

• Consequence of failure (i.e. proximity to safety-related piping and piping components)

• Locations with potentially high stress and/or cyclic loading conditions such as piping adjacent to locations that were replaced due to cracking/rupture, locations subject to settlement, or locations subject to heavy load traffic Operating Experience Summary The following examples of operating experience provide objective evidence that the Buried and Underground Piping and Tanks 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 November 2005, a through-wall leak was discovered in a weld in Unit 1 underground stainless steel safety injection system piping. A portion of the piping was replaced and weld repair was also performed. The Root Cause Evaluation determined the cause to be stress corrosion cracking due to inadequate original construction welding procedures that did not specify the maximum heat input. The high heat input applied during welding to this type of material resulted in sensitizing the weld. The adverse environmental condition attributed to the inside diameter cracking was possible high chloride content in the fluid. Groundwater dripping on the piping was the source for the adverse environmental condition for the outside diameter cracking.

2.

In May 2010, stainless steel chemical and volume control, quench spray, residual heat removal, and safety injection buried piping associated with the Unit 1 refueling water storage tank was excavated and inspected. A portion of the external coating was degraded and brittle.

No adverse condition or corrosion was found and the coating was restored and the pipes were reburied.

I

3.

In June 2010, stainless steel and carbon steel piping associated with the Unit 1 chemical

\\

additioni_tank was excavated and inspected. The stainless steel p_iping had no indications of pitting o:r corrosion. The carbon steel piping had degraded coating with general surface corrosion.

4.

In Janupry 2012, stainless steel quench spray piping associated with the Unit 1 refueling water storage tank was excavated and inspected. Both pipes had disbanded coating, but there were no signs of corrosion or degradation. Ultrasonic test results were reviewed by Engineering and found tb;be acceptable minimum wall thickness. The disbanded cohting was repaired.

PageB-192

Serial No.: 21-213 RA! 4 / Supplement 3 Page 39 of 46 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Appendix B -Aging Management Programs

5.

In September 2012, opportunistic inspection of stainless steel Unit 2 Casing Cooling Pump House floor drain piping was excavated and inspected. Coating was found to be disbanded and removed after excavation. There were no indications of pitting or corrosion. Ultrasonic testing indicated greater than minimum wall thickness.The disbanded coating was repaired.

6.

In May 2013, following replacement of cast iron with (and installation of new) ductile iron fire main piping, the scope of cast iron fire protection piping replacement with ductile iron was reduced to the portion identified as high priority due to the postulated pipe rupture in this area potentially challenging adjacent safety-related piping. The buried fire protection piping on the west side of the station that serves as the backup water supply to the Unit 2 auxiliary feedwater system was replaced. Also, the buried cast iron fire protection piping at the northwest and southwest tie-in connection points was replaced with ductile iron pipe. New ductile iron pipe was installed at the Southeast Security Building. The basis for scope reduction also included the good condition of existing fire piping found in at least five buried fire main locations. The internal cementitious lining was determined to be in good condition, fully intact, and protecting the pipe in these cases.

7.

In November 2014, evaluation was completed of a baseline soil survey conducted during 2011 that involved 25 samples (24 sample locations are within the scope of subsequent license renewal). Soil samples were extracted from various plant locations where safety related piping or piping that contained nuclear/environmentally hazardous material was buried. Ratings for soil resistivity, water content, pH, sulfide content, groundwater level, redox potential, and chloride concentration parameters were compiled to determine a corrosivity index. Using a corrosivity index consistent with American Water Works Association C105, "Polyethylene Encasement for Ductile-Iron Pipe Systems," the 24 samples within the scope of subsequent license renewal were determined to be non-corrosive.

8.

In July 2015, service water CP system test results indicate that the majority of the piping associated with CP subsystems 'A,' 'B,' and 'C' are receiving adequate cathodic protection as defined in NACE SP 0169-2013 for both the -0.850 volt and 100-millivolt criteria. Test results indicate a lack of protection on the extreme ends of the system where the pipes enter the concrete vaults or buildings. The 'D' subsystem was shut off because test results indicated

\\ that the service water piping was not receiving a level 'of protection consistent with the 'D' subsystem's rectifier output. The service water piping protected by the 'D' subsystem was volumetrically inspected. There are no issues with the service water piping and no issues will be induced from shutting off the 'D' subsystem; the service water piping remains fully capable

• of performing its intended functions. CP 'D' subsystem will be refurbished and reconnected before the last five years of the inspection period prior to entering the subsequent period of

-extended operation.

PageB-193

Serial No.: 21-213 RAI 4 / Supplement 3 Page 40 of 46 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Appendix B -Aging Management Programs

9.

In August 2015, during an Underground Piping and Tanks program inspection of cast iron fire protection and carbon steel bearing cooling piping associated with the bearing cooling tower found the pipe to be in good condition. In particular, the bearing cooling piping excavated did not show evidence of material degradation, pitting, gross corrosion, or other abnormalities.

New coatings were applied to the bearing cooling piping prior to backfill.

10. 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 reached was that performance deficiencies or learning opportunities were identified for the Buried Piping and Valve Inspection AMA (UFSAR Section 18.1.1 ). From a review of inspection documentation, no discussion of tape wrap removal to inspect epoxy coating was discovered. A follow-on action was initiated ensure evaluation of this omission as part of summarizing buried piping activities for license renewal. The required inspections of in-scope stainless steel piping were conducted. In cases where stainless steel piping was found without coating or with significantly disbanded coating, no evidence of pitting or corrosion existed. It was concluded that there is no benefit to the removal of any tape wrap to inspect the coating underneath.

11. In September 2016, unsatisfactory output voltage and current were measured while performing bimonthly inspection of service water CP subsystem 'C.' Although the output voltage and the output current have not been within the procedural band (-850 mV relative to a CSE, instant off, and 100 mV minimum polarization), the "On" potentials and the "Instant Off' potentials have been consistent and within the acceptable band since May 2013. Engineering will continue to monitor this CP Subsystem on the bimonthly schedule.

12. In October 2016, leakage was observed outside the Unit 1 Auxiliary Feedwater Pump House.

A leak of 1-2 gallons per minute was observed from the joint between the concrete walkway and the foundation. After excavation, the leak location was identified in an elbow of a direct buried service water pipe. The failure mechanism was determined to be external corrosion caused by the lack of an external protective coating. The service water elbow was replaced and protective coating was applied to the external surfaces. The accessible adjacent service water piping was also tape-wrapped. The service water line was returned to service.

13. In December 2016, suspected leakage in buried carbon steel piping from the Fuel Oil Pump House to the '2H' diesel room was identified. The leakage was due to localized corrosion on I

the outside diameter of the pipe due to coating /'tape wrap degradation (direct cause). The failure of the coating permitted localized corrosion on the pipe due to chemical attack from the buildup of contaminants on the surface of the pipe.

The extent of condition included pressurized fuel oil supply lines buried between the Fuel Oil Pump House and each EOG room, along with tt1e SBO EOG room. The buried fuel oil lines in that scope have been replaced with stainless steel and placed in service.

PageB-194

Serial No.: 21-213 RAI 4 / Supplement 3 Page 41 of 46 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Appendix B -Aging Management Programs

14. 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 credited for license renewal were identified

• 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.

15. 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 Buried Piping and Valve Inspection Activities AMA (UFSAR Section 18.1.1 ).

16. In April 2019, an effectiveness review was performed on the Buried Piping and Valve Inspection Activities AMA (UFSAR Section 18.1.1 ) 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.

The above examples of operating experience provide objective evidence that the Buried and Underground Piping and Tanks program includes activities to perform volumetric and visual inspections to identify blistering, cracking, hardening or loss of strength, and loss of material for buried and underground piping and tanks within the scope of subsequent license renewal, and to initiate corrective actions. Occurrences identified under the Buried and Underground Piping and Tanks 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 assurance that the continued implementatio'n of the Buried and Underground Piping and Tanks program, following enhancement, will effectively manage aging prior to a loss of intended function.

Conclusion The continued implementation of the Buried and Underground Piping and Tanks 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 du i1ing the subsequent period of extended operation.

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Serial No.: 21-213 RAI 4 / Supplement 3 Page 42 of 46 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Appendix B -Aging Management Programs 82.1.35 Inspection of Water-Control Structures Associated with Nuclear Power Plants Program Description The Inspection of Water-Control Structures Associated with Nuclear Power Plants program is an existing condition monitoring program, which is implemented as part of the Structures Monitoring program (82.1.34), and manages the following aging effects:

Cracking Cracking; loss of bond; loss of material (spalling, scaling)

Increase in porosity and permeability; loss of strength Loss of material Loss of material (spalling, scaling) and cracking Loss of material; loss of form The program consists of inspection and surveillance of raw-water control structures associated with emergency cooling systems or flood protection, which are the Discharge Tunnel, the Flood Protection Dike (flood wall west of Turbine Building), the Intake Structure, the Service Water Pump House, the Service Water Reservoir, the Service Water Valve House, the Circulating Water Intake Tunnel Header, and the Discharge Tunnel Seal Pit. Inspection and surveillance of the dam and water impoundments is in accordance with Regulatory Guide 1.127, "Inspection of Water-Control Structures Associated with Nuclear Power Plants." The Inspection of Water-Control Structures Associated with Nuclear Power Plants program relies on periodic visual inspections conducted by qualified personnel at a frequency not to exceed five years to monitor and maintain the condition of water-control structures within the scope of subsequent license renewal. The program also includes structural steel and structural bolting associated with water-control structures.

Qualifications for personnel performing concrete inspections and evaluations are consistent with ACI 349.3R, "Evaluation of Existing Nuclear Safety-Related Concrete Structures." Inspections are performed and inspection results evaluated consistent with applicable industry documents to ensure that a loss of intended function does not occur. Quantitative measurements are recorded for findings that exceed the acceptance criteria for applicable parameters monitored or inspected.

Conditions found to impact the intended function of the water-control structure are documented and entered into the Corrective Action Program for evaluation, which will result in analysis, repair or replacement. Evaluation of the inspection results determines whether the discovered deficiency is minor and will not threaten the structure's ability to perform its intended function until the next scheduled inspection. A significant deficiency requires corrective action and/or more frequent monitoring to ensure that the struct!lJre will remain functional until the next regularly schedl!_led inspection.

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Serial No.: 21-213 RAI 4 / Supplement 3 Page 43 of 46 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Appendix B -Aging Management Programs In order to evaluate the potential of groundwater to cause degradation of concrete, samples of groundwater are taken at intervals not to exceed five years. The water chemistry is evaluated, and should the results of water testing indicate potentially harmful levels of substances, such as chlorides > 500 ppm, sulfates > 1,500 ppm, or a pH < 5.5, areas exposed to groundwater are assessed for potential aging.

The program includes monitoring Service Water Reservoir horizontal drains flow rate as a preventive measure to avoid or minimize additional settlement of the Service Water Pump House.

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 such inaccessible areas. Whenever inaccessible areas are excavated, exposed, or modified an opportunistic examination is performed.

Procedures include preventive actions to ensure bolting integrity for replacement and maintenance activities by specifying proper selection of bolting material and lubricants, and appropriate installation torque or tension to prevent or minimize loss of bolting preload and cracking of high-strength bolting. For structural bolting consisting of ASTM A325 and ASTM A490 bolts, the preventive actions for storage, lubricant selection, and bolting and coating material selection are consistent with Section 2 of the Research Council for Structural Connections publication, "Specification for Structural Joints Using High-Strength Bolts." Twist-off type ASTM F1852 and ASTM F2280 bolts are not specified or stocked for use.

Concrete inspectors are trained to identify changes that could be indicative of Alkali-Silica Reaction (ASR). If indications of ASR development are identified, the evaluation considers the potential for ASR development in concrete that is within the scope of the ASME Section XI, Subsection IWL program (B2.1.30), the Structures Monitoring program (B2.1.34), or the Inspection of Water-Control Structures Associated with Nuclear Power Plants program (B2.1.35).

NUREG-2191 Consistency The Inspection of Water-Control Structures Associated with Nuclear Power Plants program is an existing program that, following enhancement, will be consistent, with NUREG-2191, S~ction XI.S7, Inspection of Water-Control Structures Associated with Nuclear Power Plants.

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):

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Serial No.: 21-213 RAI 4 / Supplement 3 Scope of Program (Element 1)

Page 44 of 46 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Appendix B -Aging Management Programs

1.

Procedures will be revised to include the Circulating Water Intake Tunnel Header and the Discharge Tunnel Seal Pit within the scope of the program.

Detection of Aging Effects (Element 4)

2.

Procedures will be revised to specify underwater inspections or dewatering to permit visual inspections for submerged structures, on a frequency not to exceed five years.

Operating Experience Summary The following examples of operating experience provide objective evidence that the Inspection of Water-Control Structures Associated with Nuclear Power Plants 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 March 2012, vegetation was observed on slopes at the Service Water Reservoir. During the biennial NRC inspection of the Service Water Reservoir, the Inspectors identified various locations of vegetative growth on the slopes of the Service Water Reservoir in the rip-rap. The growth was evaluated to be normal and did not pose a threat to the structural integrity of the Service Water Reservoir. The vegetation was removed.

2.

In March 2013, concrete spalling and cracking was found at the Service Water Pump House.

During efforts to remove loose concrete, additional concrete degradation was discovered.

During the initial visual investigation, reinforcing steel was not visible. Upon further investigation and removal of additional loose concrete, it was determined that approximately eight linear feet of reinforcing steel was degraded and required repair. The average degradation of the rebar was 30% but did not prevent the Service Water Pump House from performing its design function. Repairs to the rebar and concrete were completed.

3.

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 performance deficiencies or learning opportunities were identified for t~e Civil Engineering Structural Inspection AMA (UFSAR Section 18.2.6). Plant procedures did not include dewatering and installation of shielding as activities to consider that could potentially result in a normally inaccessible structural component becoming accessible for inspection. Plant procedures were revised to include dewatering and installation of shielding as activities to consider that could potentially result in a normally inaccessible structural component becoming accessible for inspection.

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Serial No.: 21-213 RAI 4 / Supplement 3 Page 45 of 46 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Appendix B -Aging Management Programs

4.

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 credited for license renewal were identified

• 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.

5.

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 Civil Engineering Structural Inspection AMA (UFSAR Section 18.2.6) related to the Inspection of Water-Control Structures Associated with Nuclear Power Plants program.

6.

In April 2019, an effectiveness review was performed on the Civil Engineering Structural Inspection AMA (UFSAR Section 18.2.6), that includes periodic inspections for aging management to ensure the continuing capability of civil engineering structures to meet their intended functions consistent with the current licensing basis. 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 related to the Inspection of Water-Control Structures Associated with Nuclear Power Plants program.

7.

From December 2006 to May 2019, samples of groundwater were analyzed quarterly. This monitoring showed the site groundwater to be non-aggressive (pH > 5.5, chlorides< 500 ppm, and sulfates < 1,500 ppm).

8.

From April 2001 to September 2019, settlement of structures has been monitored every 184 days, as specified in the Technical Requirements Manual (TRM), Section 3.7.7. UFSAR Section 3.8.4.5.3 describes the Settlement Monitoring Program. The elevations of points located on structures and components at the Service Water Reservoir and at the main plant were md_nitored for settlement, beginning in 1975. Structures for which minimal movement had occurred are no longer monitored. The in-scope water-control structures currently being monitored for settlement are the Service Water Reservoir, the Service Water Pump House, and the Service Water Valve House. The initial baseline elevations for these structures and components are listed in UFSAR Table 3.8-15. If differences between observed values and baseline elevations exceed prescribed limits given in TRM Section B 3.7.7, appropriate action is taken'1n accordance with the Corrective Action Program. No set9ements have been found to have exceeded the TRM limits.

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Serial No.: 21-213 RAI 4 / Supplement 3 Page 46 of 46 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Appendix B -Aging Management Programs

9.

In April of 2021, a condition report (CR) was submitted as required by Technical Requirement (TR) 3.7.7 in Section 3.7 of the Technical Requirement Manual (TRM). documenting 75% of the allowable total settlement indicated in TRM Table 3.7.7-1 had been exceeded for settlement marker SM-28. associated with the Service Water Valve House (SWVH).

Specifically, SM-28 was 75.6% of the allowable total settlement value in TRM Table 3.7.7-1.

The basis for TR 3.7.7 is to limit pipe stress of the adjacent SW piping. The allowable total settlement for SM-28. as well as other SWVH settlement markers (SM-25. SM-26. and SM-27), ensures pipe stress for the buried SW piping is maintained within Code allowable limits.

An engineering evaluation is being developed and work orders have been initiated to adjust SW expansion joints tie rods to accommodate for future potential settlement.

The above examples of operating experience provide objective evidence that the Inspection of Water-Control Structures Associated with Nuclear Power Plants program includes activities to perform visual inspections to identify aging effects for water-control structures within the scope of subsequent license renewal. and to initiate corrective actions. Occurrences identified under the Inspection of Water-Control Structures Associated with Nuclear Power Plants 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 assurance that the continued implementation of the Inspection of Water-Control Structures Associated with Nuclear Power Plants program, following enhancement, will effectively manage aging prior to a loss of intended function.

Conclusion The continued implementation of the Inspection of Water-Control Structures Associated with Nuclear Power Plants 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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