ML21238A297

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Subsequent License Renewal Application Supplement 4
ML21238A297
Person / Time
Site: North Anna  Dominion icon.png
Issue date: 08/26/2021
From: Mark D. Sartain
Virginia Electric & Power Co (VEPCO)
To:
Document Control Desk, Office of Nuclear Reactor Regulation
References
21-280
Download: ML21238A297 (68)
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Text

VIRGINIA ELECTRIC AND POWER COMPANY RICHMOND, VIRGINIA 23261 August 26, 2021 10 CFR 50 10 CFR 51 10 CFR 54 United States Nuclear Regulatory Commission Serial No.: 21-280 Attention: Document Control Desk NRA/DEA: R1 Washington, D.C. 20555-0001 Docket Nos.: 50-338/339 License Nos.: NPF-4/7 VIRGINIA ELECTRIC AND POWER COMPANY NORTH ANNA POWER STATION (NAPS) UNITS 1 AND 2 SUBSEQUENT LICENSE RENEWAL APPLICATION (SLRA)

SUPPLEMENT 4

References:

1. Virginia Electric and Power Company (Dominion) letter to U. S.

Nuclear Regulatory Commission (NRG), "North Anna Power Station, Units 1 and 2 - Application for Subsequent Renewed Operating Licenses," (ADAMS Package Accession No. ML20246G703), dated August 24, 2020 (Serial No.20-115)

2. NRG Electronic mail to Dominion, "FINAL Request for Additional Information Set 2 - North Anna SLRA Safety Review (EPID No. L-2020-SLR-0000)," (ADAMS Accession Nos. ML21091A002 (email) and ML21091A003 (Enclosure 1)), dated April 1, 2021
3. NRG Electronic mail to Dominion, "FINAL Request for Additional Information Set 4 - North Anna SLRA Safety Review (EPID No. L-2020-SLR-0000)," (ADAMS Package Accession No. ML21188A160),

dated July 7, 2021

4. Virginia Electric and Power Company (Dominion) letter to U. S.

Nuclear Regulatory Commission (NRG), "North Anna Power Station (NAPS), Unit 1 and 2 - Subsequent License Renewal Application (SLRA) Response to NRG Request for Additional Information Safety Review - Set 2 and Flow Accelerated Corrosion Program Enhancement Completion," (ADAMS Accession No. ML21119A287),

dated April 29, 2021 (Serial No.21-134)

5. Virginia Electric and Power Company (Dominion) letter to U. S.

Nuclear Regulatory Commission (NRG), "North Anna Power Station (NAPS), Units 1 and 2 - Subsequent License Renewal Application (SLRA) Response to NRG Request for Additional Information Safety Review - Set 4 and Supplement 3," (ADAMS Accession Number ML21210A396), dated July 29, 2021 (Serial No.21-213)

Serial No.: 21-280 Docket Nos.: 50-338/339 NAPS SLRA Supplement 4 Page 2 of 6

6. Virginia Electric and Power Company (Dominion) letter to U. S.

Nuclear Regulatory Commission (NRC), "North Anna Power Station (NAPS), Units 1 and 2 - Update to Subsequent License Renewal Application (SLRA) - Supplement 1," (ADAMS Accession Number ML21035A303), dated February 4, 2021 (Serial No.20-416)

In Reference 1, Virginia Electric and Power Company (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 (NRC) has been reviewing the NAPS SLRA.

References 2 and 3 provided specific NRC requests for additional information (RAls).

References 4 and 5 provided Dominion's responses to the RAls received in References 2 and 3, respectively. Reference 6 provided Supplement 1 to update the SLRA.

This letter provides the NRC staff with additional information in support of the development of the safety evaluation report.

The SLRA and previously submitted information transmitted by References 4, 5, and 6 are supplemented herein. Enclosure 1 provides a description of the three topics being supplemented and identifies the affected SLRA section and/or table. Specifically, information related to inspection of caulking associated with the emergency condensate storage tank (ECST), aging management of buried gray cast iron piping and piping components in the fire protection system, and two previous omissions are provided in . The SLRA changes described in Enclosure 1 are provided in Enclosure 2.

Note that the Appendix B aging management program (AMP) section(s) being revised in also include unchanged pages, for ease of review. Also, note that changes to two commitments (Items #17 and #27) are provided in Table A4.0-1 in Enclosure 2.

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

Sincerely,

~al,-

Mark D. Sartain Vice President - Nuclear Engineering and Fleet Support COMMONWEALTH OF VIRGINIA COUNTY OF HENRICO 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 Compahy, and that the statements in the document are true to the best of his knowledge and belief.

Acknowledged before me this 2<.ot"ciay of Auius I ' 2021.

My Commission Expires: :ro.nU,o;<"I ~l 1'2. 2 Y ";f~ jJ _ IA'hR X

~ Notary ~ i c Kathryn Hill Barret Notary Public Commonwealth of Virginia Reg. No. 7905256 My Commission Expires January 31, 2024

Serial No.: 21-280 Docket Nos.: 50-338/339 NAPS SLRA Supplement 4 Page 3 of 6 Commitments made in this letter: None

Enclosures:

1. Topics that Require a SLRA Supplement
2. SLRA Mark-ups - Supplement 4 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 NRC Project Manager U.S. Nuclear Regulatory Commission One White Flint North Mail Stop O 11 F1 11555 Rockville Pike Rockville, Maryland 20852-2738 Mr. Tam Tran NRC Project Manager U. S. Nuclear Regulatory Commission One White Flint North Mail Stop O 11 F1 11555 Rockville Pike Rockville, Maryland 20852-2738 Mr. Vaughn Thomas NRC Project Manager U.S. Nuclear Regulatory Commission One White Flint North Mail Stop 04 F-12 11555 Rockville Pike Rockville, Maryland 20852-2738 Mr. G. Edward Miller NRC Senior Project Manager U. S. Nuclear Regulatory Commission One White Flint North Mail Stop 09 E-3 11555 Rockville Pike Rockville, Maryland 20852-2738 NRC Senior Resident Inspector North Anna Power Station

Serial No.: 21-280 Docket Nos.: 50-338/339 NAPS SLRA Supplement 4 Page 4 of 6 Mr. Marcus Harris Old Dominion Electric Cooperative Innsbrook Corporate Center, Suite 300 4201 Dominion Boulevard Glen Allen, Virginia 23060 State Health Commissioner Virginia Department of Health James Madison Building - 7th Floor 109 Governor Street Room 730 Richmond, Virginia 23219 Mr. David K. Paylor, Director Virginia Department of Environmental Quality P.O. Box 1105 Richmond, VA 23218 Ms. Melanie D. Davenport, Director Water Permitting Division Virginia Department of Environmental Quality P.O. Box 1105 Richmond, VA 23218 Ms. Bettina Rayfield, Manager Office of Environmental Impact Review Virginia Department of Environmental Quality P.O. Box 1105 Richmond, VA 23218 Mr. Michael Dowd, Director Air Division Virginia Department of Environmental Quality P.O. Box 1105 Richmond, VA 23218 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

Serial No.: 21-280 Docket Nos.: 50-338/339 NAPS SLRA Supplement 4 Page 5 of 6 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

Serial No.: 21-280 Docket Nos.: 50-338/339 NAPS SLRA Supplement 4 Page 6 of 6 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

NAPS SLRA Serial No.: 21-280 Page 1 of 9 Enclosure 1 TOPICS THAT REQUIRE A SLRA SUPPLEMENT Virginia Electric and Power Company (Dominion Energy Virginia)

North Anna Power Station Units 1 and 2

Serial No.: 21-280 Enclosure 1 Topics that require a SLRA Supplement NAPS SLRA Page 2 of 9 Topics that require a SLRA Supplement North Anna Power Station, Units 1 and 2 Subsequent License Renewal Application By letters dated August 24, 2020, (Agencywide Documents Access and Management System (ADAMS) Accession No. ML20246G703), Virginia Electric and Power Company (Dominion or 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 (NRG) 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 NRG is reviewing the subsequent license renewal application for development of the safety evaluation. Included below are the three topics that require the Subsequent License Renewal Application (SLRA) to be supplemented to support NRG staff needs in development of the safety evaluation.

1. Outdoor and Large Atmospheric Metallic Storage Tanks program (B2.1.17) - Updated By letters dated April 29, 2021 (ADAMS Accession No. ML21119A287) and July 29, 2021 (ADAMS Accession Number ML21210A396), Dominion provided the response to NRC RAI Set 2 and Supplement 3 to the NAPS SLRA, respectively. The SLRA is being modified to clarify RAI response Item 9 (Outdoor and Large Atmospheric Metallic Storage Tanks program (B2.1.17): Exception 2 Clarified) in the April 29, 2021 letter and Supplement 3 Item 5 (SLRA AMP B2.1.17, Atmospheric Metallic Tanks) in the July 29, 2021 letter.

An enhancement is added to require visual inspection of the caulking at the emergency condensate storage tank (ECST) vent and vacuum breaker penetration-concrete missile barrier interface on an 18-month frequency.

Based on the above, SLRA Sections 3.5.2.1.33, A1 .17 and B2.1.17, Table 3.5.1, Table 3.5.2-33, and Table A4.0-1 are supplemented as shown in Enclosure 2, to indicate the new inspection requirements.

Serial No.: 21-280 Enclosure 1 Topics that require a SLRA Supplement NAPS SLRA Page 3 of 9

2. Aging Management of Buried Gray Cast Iron Piping in the Fire Protection Clarified Dominion letter, "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," (ADAMS Accession Number ML21210A396), dated July 29, 2021 provided a revision to the aging management of fire protection system buried gray cast iron piping and piping components. As detailed in the July 29, 2021 letter, consistent with the requirements of NUREG-2191 Section XI.M41, Buried and Underground Piping and Tanks program, and NUREG-2191 Section XI.M33, Selective Leaching program, periodic and opportunistic inspections would be conducted for buried gray cast iron fire protection piping and piping components. As described, a minimum of six excavations would be conducted at each unit, and a one-foot length of fire protection piping from five of the excavations at each unit would be inspected for loss of material due to selective leaching. The letter indicated that, consistent with the requirements of NUREG-2191 Section XI.M41, Buried and Underground Piping and Tanks program, each piping sample of buried gray cast iron from the fire protection system piping would be a ten-foot pipe length.

SLRA Sections B2.1.27, "Buried Pipe and Underground Piping and Tanks program" and Table A4.0-1, Item 27 (Enhancement #5) are revised to clarify a one-foot length of fire protection system piping or a different component type from each discrete excavation location (six/unit) will be destructively examined to inspect for loss of material due to selective leaching. Five of the inspections will be conducted on a one-foot length of fire protection piping and the sixth inspection will be conducted on either a one-foot length of piping from the fire protection system or a different component type (e.g., hydrant) from fire protection system.

Cracking due to cyclic loading on gray cast iron fire protection piping will be managed by NUREG-2191 Section XI.M41, Buried and Underground Piping and Tanks program.

SLRA Sections B2.1.27 and Table A4.0-1 Item 27 are revised to also require inspections for detection and evaluation of cracking due to cyclic loading be conducted on gray cast iron fire protection piping. SLRA Section B2.1.21 is revised to remove management of cracking due to cyclic loading for gray cast iron fire protection piping. Consistent with the requirements of NUREG-2191 Section XI.M41, Buried and Underground Piping and Tanks program, ten-foot pipe lengths will be excavated, as noted above, for the gray cast iron fire protection piping samples inspected for cracking due to cyclic loading. A minimum of five pipe excavations for each unit will be conducted in the 10-year period prior to the subsequent period of extended operation (SPEO) and periodically in each 10-year period during the SPEO. The quantity of inspections was selected for consistency with the guidance of NUREG-2191,Section XI.M41, Buried Pipe and Underground Piping and Tanks Program, Element 4, and Table XI.M41-2 for Preventive Action Category F.

Over the course of the inspections conducted in the 10-year period prior to the SPEO and periodically during the SPEO, the total length of gray cast iron fire protection piping inspected for cracking due to cyclic loading will be a minimum of 300 feet. This sample

Serial No.: 21-280 Enclosure 1 Topics that require a SLRA Supplement NAPS SLRA Page 4 of 9 quantity, combined with application of the selection criteria detailed in Enhancement #5 (dated July 29, 2021) for determining inspection locations, provides assurance that a representative sample of gray cast iron fire protection piping will be selected for examination to detect cracking due to cyclic loading.

Visual (VT), magnetic particle (MT), and radiographic (RT) nondestructive examination (NOE) methods will be used on excavated gray cast iron fire protection piping samples to inspect for cracking due to cyclic loading. The NOE examination results will be evaluated by a Level II or Ill examiner qualified in accordance with American Society of Mechanical Engineers (ASME) Code,Section XI requirements to identify the presence of cracking. If there is no cracking identified using the NOE techniques described below, then a one-foot axial piece of the fire protection piping sample will still be destructively examined to inspect for the loss of material due to selective leaching as required by NUREG-2191 Section XI.M33, Selective Leaching program. If cracking is identified, then a bounding one-foot axial section of the fire protection piping sample will be selected based on the crack size and characterization determined by a qualified NOE Level II or Ill examiner and further destructive examination will be conducted to identify cracking due to cyclic loading.

A review of available operating experience identified occurrences of buried gray cast iron fire protection system piping failures between 1984 and 2003. The failures that originated from the inner diameter (ID) pipe surface were attributed to casting process defects. The failures that originated from the outer diameter (OD) pipe surfaces were attributed to defects, possibly introduced during installation of the pipe. There was no evidence of crack initiation at subsurface defects for these pipe failures. Following surface preparation to remove the cementitious lining (ID) and bitumastic coating (OD), defects like those observed in the previous failures would be readily detectable both visually and with MT techniques on the internal and external pipe surfaces.

The NOE techniques and methods that will be used to identify potential crack locations, the methodology that will be used for determining the bounding location, and the techniques that will be used during the destructive examination are provided below. If a crack is determined to be the result of a manufacturing flaw rather than the result of aging, the results will be documented in a metallurgical analysis report with no further actions required. If the crack is determined to be the result of cyclic loading, then a crack growth evaluation and flaw stability evaluation will be performed based on the predicted crack lengths at the end of the SPEO. If results of the evaluations indicate the depth or extent of cracking of the base metal is projected to cause loss of intended function prior to the end of the SPEO, Engineering will perform an evaluation to determine the extent of condition, extent of cause, and the need for further follow-on actions through the Corrective Action Program (e.g., additional inspections).

Serial No.: 21-280 Enclosure 1 Topics that require a SLRA Supplement NAPS SLRA Page 5 of 9 Nondestructive Examination Methods and Methodology The VT, MT, and RT NOE methods will be applied to assess the internal and external surface condition of the excavated gray cast iron fire protection piping. The NOE procedures and techniques applied for these examinations will be demonstrated and qualified in accordance with ASME Section 5, Article 2 for RT, Article 7 for MT, and Article 9 for VT. The NOE examination results will be evaluated by Level II or Ill examiners qualified in accordance with the requirements of ASME Code,Section XI.

VT examination of the internal cementitious lining will be performed to identify and record any areas of lining damage that may be an indicator of degradation to the internal surface of the pipe. MT examination of the inside diameter surface of the removed piping will be performed to detect indications of surface cracking. To perform the MT examination method, access to the inside surface must be available. This will be accomplished by cutting the removed section of fire protection pipe in half along the length. The removed pipe may be cut to lengths that can safely be handled during the examination process. The cementitious lining will be removed, and the surface prepped to an acceptable condition to perform the MT examination. The lining removal and surface preparation techniques will ensure no detrimental impact on the final surface condition for the NOE being performed. Particular attention will be applied to VT identified areas of lining damage during the MT examination. Linear surface indications representing potential cracking, identified with the MT method, will be validated using RT examination techniques.

Similarly, MT examination of the external surface of the removed piping will be performed to detect indications of surface cracking.

To perform the MT examination, access to the external surface must be available. The bitumastic coating will be removed, and the surface prepped to an acceptable condition to perform the MT examination. The coating removal and surface preparation techniques will ensure no detrimental impact on the final surface condition for the NOE being performed. Linear surface indications representing potential cracking, as identified using the MT method, will be validated using RT examination techniques.

The MT examination method will detect indications of cracks on the internal and external surfaces of the piping. The sensitivity is greatest for surface discontinuities and diminishes with increasing depth of discontinuities below the surface. However, as previously discussed, there has been no evidence of crack initiation at subsurface defects for past pipe failures. The particle patterns are used to characterize the type and orientation of discontinuity that is detected. The maximum sensitivity will be to linear discontinuities oriented perpendicular to the lines of flux. For optimum effectiveness in detecting both axial and circumferential oriented flaws, each area will be examined at least twice, with the lines of flux oriented approximately perpendicular during each of the two examinations. The MT method is sensitive to surface discontinuities as well as other surface imperfections that may not be associated with cracking indications. For this reason, RT will be applied to validate potential crack indications detected with MT. The

Serial No.: 21-280 Enclosure 1 Topics that require a SLRA Supplement NAPS SLRA Page 6 of 9 location, size and orientation of relevant linear indications detected will be recorded for further evaluation with RT.

The RT examination method will be applied to areas that have potential surface cracking identified using the MT method. A single wall technique, with the radiation passing through only one wall, will be able to be applied along with single wall viewing to maximize sensitivity. The RT examination technique provides a full volume examination of the pipe wall. Internal fabrication discontinuities may be detected during this examination, but the indication interpretation will focus on linear planar type flaws, which would eliminate manufacturing defects that have different characteristics. Image quality indicators (IOI) will be used to ensure proper image quality is provided for interpretation. Areas identified as containing potential surface cracking indications will be recorded, and the bounding crack location will be selected for further metallurgical analysis.

Metallurgical Analysis - Destructive Examination Confirmation of cracking in removed sections of gray cast iron fire protection piping can be performed using either metallography, fractography, or a combination of both. The process used will be dependent on the size of the crack detected by NOE results. The larger the crack, the more material that will be available for examination and there will be more flexibility in which method can be employed.

Metallography is used to examine the crystalline structure of metals. Samples prepared for metallography are cut and mounted in a manner that does not alter the material's condition, and then polished to a 1 micron or lesser finish. The prepared sample can then be examined under a light microscope as polished (unetched), or it can be etched in a particular reagent to expose the various constituents and phases of the metal.

Fractography involves the microscopic examination of fractured sections of materials. The microscopes are stereo light microscopes for low magnification work and a scanning electron microscope for higher magnification inspection. The fracture modes are documented as either transgranular, intergranular, overload (shear or tensile), or a combination of the three.

The bounding crack detected by NDE will be cut out in the materials laboratory in such a manner that the flaw is not disturbed and the microstructure of the material is not altered.

Once the section containing the crack is removed, the typical method of examination for a crack of sufficient length would be to cut off one end of the crack for metallography, and then section the pieces so that the remainder of the crack can be opened in the laboratory to expose the crack faces. Fractographic examination will then be performed on the open crack faces, while metallography will be carried out on the crack tip section. In most linear cracks, the center of the crack will represent the oldest portion, while the edges will account for the most recently formed part of the advancing crack front. The metallography performed on the crack edge will assess how the crack was advancing at the time of detection. Opening the remainder of the crack to allow for visual and microscopic inspection will provide confirmation as to the mode of crack advancement and may provide qualitative information on the age of the fracture based on the amount of oxidation along the surface of the opened crack.

Serial No.: 21-280 Enclosure 1 Topics that require a SLRA Supplement NAPS SLRA Page 7 of 9 Both the metallography and fractography testing will indicate if corrosion was involved in the crack initiation process. Previous laboratory work performed on cast iron fractures has also employed microanalytical testing in the form of energy dispersive spectroscopy.

This method allows deposits on the fracture surfaces of an opened crack to be analyzed for elemental composition. For internal surface fractures, if cementitious residues are detected along the portions of the fracture, this may indicate that the flaw in the pipe pre-dated application of the cement lining and was therefore a flaw associated with fabrication of the pipe, rather than the result of aging.

Cracking in gray cast iron will display some fractographic indications typically associated with that type of cracking in all metals but will also display features unique to cast iron based on its structure and properties. Typically, when cracking is due to high cycle fatigue, the oldest portion of the crack is worn from repetitive crack opening and closings and depending on the environment, may be oxidized. The latter is especially true for cast irons because of their propensity to corrode in moist environments. Some fatigue features, such as striations, will most likely not be identified on fractures of gray cast irons because of the diverse microstructure, and the low amount of ductility in the material that will not allow blunting of the advancing crack tip. Most of the fracture will consist of cleavage forming along the graphite flakes. Some ductility in the form of micro-voids may be visible in the ferrite and/or pearlite matrix if the material is subject to high stress conditions.

A crack due to cyclic loading captured in a metallographic cross section may exhibit a distinct pattern of crack advancement, because of the material's unique microstructure.

Gray cast irons have a crystalline structure that should consist of graphite flakes in a matrix of pearlite or ferrite. These graphite flakes are responsible for the material having a relatively low fracture toughness or "brittle-like" behavior. Cracks due to cyclic loading propagating through gray cast iron typically follow the path of least resistance and advance along a plane that will intersect many of the graphite flakes.

Cracks identified by NOE, as described above, will be further inspected by destructive examination to establish cause. If the cracking is determined to a be due to cyclic loading through the destructive examination evaluation, then a crack growth evaluation and flaw stability evaluation will be performed based on the predicted crack lengths at the end of the SPEO. If results of the evaluations indicate the depth or extent of cracking of the base metal is projected to cause loss of intended function prior to the end of the SPEO, Engineering will perform an evaluation to determine the extent of condition, extent of cause, and the need for further follow-on actions through the Corrective Action Program (e.g., additional inspections).

Dominion Energy is an active participant in industry working groups that are investigating new and improved NOE techniques. As NOE technology evolves, Dominion will continue to monitor any relevant improvements, particularly those related to examination of cast iron, for potential incorporation into Dominion Fleet procedures.

Serial No,: 21-280 Enclosure 1 Topics that require a SLRA Supplement NAPS SLRA Page 8 of 9 Based on the above, the SLRA is supplemented in Enclosure 2, to clarify aging management for buried gray cast iron piping in the fire protection system for the following:

SLRA Section SLRA Table A1,27 3.3.2-42 82.1.21 82.1.27 Table A4.0-1, Item 27

Serial No.: 21-280 Enclosure *1 Topics that require a SLRA Supplement NAPS SLRA Page 9 of 9

3. Previous Omissions - Updated SLRA Sections 3.3.2.1.7 and 3.3.2.1.9 are revised to add the Fire Water System program as an aging management program for components in the service water system and circulating water system. The addition of the Fire Water System program reflects aging management of the service water and circulating water traveling screens added in Dominion letter, "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," (ADAMS Accession Number ML21210A396), dated July 29, 2021 (Serial No.21-213).

SLRA Section 3.3.2.1.42, Section 4.3.3, Table 2.3.3-42, Table 3.3.2-42, and Table 4.3.3-1 are revised to reflect aging management of diesel fire pump engine exhaust components previously considered part of the active assembly.

Based on the above, the SLRA is supplemented as shown in Enclosure 2.

NAPS SLRA Serial No.: 1 Page 1 of Enclosure 2 SLRA MARK-UPS - SUPPLEMENT 4 Virginia Electric and Power Company (Dominion Energy Virginia)

North Anna Power Station Units 1 and 2

Serial No.: 21-280 Page 2 of 53 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Supplement 4 Mechanical System s Table 2.3.3-42 Fire Protection Component Type Intended Function(s)

Bolting Leakage Boundary (Spatial), Pressure Boundary Fire damper assembly Fire Barrier, Pressure Boundary Fire hydrant Pressure Boundary Flame arrestor Pressure Boundary Flexible hose Pressure Boundary Heat exchanger (carbon dioxide tank Pressure Boundary cooling coil)

Insulation (heat traced components) Thermal insulation Nozzle Spray Pattern Odorizer Pressure Boundary Orifice Pressure Boundary, Restricts Flow Piping, piping components Leakage Boundary (Spatial), Pressure Boundary Pump casing (diesel driven fire pump) Pressure Boundary Pump casing (motor driven fire pump) Pressure Boundary Pump casing (pressure maintenance) Pressure Boundary Rupture disc Pressure Boundary Sight glass Pressure Boundary Sight glass (body) Pressure Boundary Silencer Pressure Boundar:,£ Sprinkler head Spray Pattern See Table 2.1-1 for definitions of intended functions.

Page2-219

Serial No.: 21-280 Page 3 of 53 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Supplement 4 Aging Management Review 3.3.2.1.7 Service Water Materials The materials of construction for the service water system component types are:

  • Elastomer
  • Fiberglass
  • Nickel alloy
  • Non-metallic thermal insulation
  • Polymer
  • Stainless steel
  • Steel
  • Steel with internal coating
  • Zinc Environment The service water system component types are exposed to the following environments:
  • Air-dry
  • Air - indoor uncontrolled
  • Air outdoor
  • Air with borated water leakage
  • Concrete
  • Condensation
  • Petrolatum corrosion preventive casing filler
  • Rawwater
  • Soil
  • Treated water
  • Underground
  • Waste water Page3-200

Serial No.: 21-280 Page 4 of 53 North Anna Power Station, Units 1 and 2 Application for Subseq uent License Renewal Supplement 4 Agin g Management Review Aging Effects Requiring Management The following aging effects, associated with the service water system , require management:

  • Cracking
  • Cracking or blistering
  • Cracking, blistering, loss of material
  • Flow blockage
  • Hardening or loss of strength
  • Long-term loss of material
  • Loss of coating or lining integrity
  • Loss of material
  • Loss of preload
  • Reduced thermal insulation resistance
  • Bolting Integrity (B2 .1.9)
  • Buried and Underground Piping and Tanks (B2 .1.27)
  • Compressed Air Monitoring (B2 .1.14)
  • External Surfaces Monitoring of Mechanical Components (B2 .1.23)
  • Fire Water System (B2 .1.16)
  • Flow-Accelerated Corrosion (B2.1.8)
  • Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2 .1.25)
  • Internal Coatings/Linings For In-Scope Piping, Piping Components, Heat Exchangers, and Tanks (B2 .1.28)
  • One-Time Inspection (B2 .1.20)
  • Open-Cycle Cooling Water System (B2.1.11)
  • Selective Leaching (B2 .1.21)

Page3-201

Serial No.: 21-280 Page 5 of 53 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Supplement 4 Aging Management Review I 3.3.2.1.9 Circulating Water Materials The materials of construction for the circulating water system component types are:

  • Aluminum Copper alloy Elastomer
  • Fiberglass
  • Gray cast iron with internal lining
  • Non-metallic thermal insulation
  • Stainless steel
  • Steel
  • Steel with internal coating Environment The circulating water system component types are exposed to the following environments:
  • Air - indoor uncontrolled
  • Concrete

@ Raw water Aging Effects Requiring Management The following aging effects, associated with the circulating water system, require management:

  • Cracking
  • Cracking, blistering, loss of material
  • Flow blockage
  • Hardening or loss of strength
  • Long-term loss of material
  • Loss of coating or lining integrity
  • Loss of material
  • Loss of preload
  • Reduced thermal insulation resistance
  • Wall thinning Page3-204

Serial No.: 21 -280 Page 6 of 53 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Supplement 4 Aging Management Revi ew Aging Management Programs The following aging management programs manage the aging effects for the circulating water system component types:

  • Bolting Integrity (B2 .1.9)
  • External Surfaces Monitoring of Mechanical Components (B2 .1.23)
  • Fire Water System (B2 .1.16)
  • Flow-Accelerated Corrosion (B2 .1.8)
  • Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B2.1.25)
  • Internal Coatings/Linings For In-Scope Piping, Piping Components, Heat Exchangers, and Tanks (B2 .1.28)
  • One-Time Inspection (B2.1.20)
  • Selective Leaching (B2 .1.21)

Page3-205

Serial No.: 21-280 Page 7 of 53 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Supplement 4 Aging Management Revi ew 3.3.2.1.42 Fire Protection Materials The materials of construction for the fire protection system component types are:

  • Aluminum
  • Ductile iron with internal lining
  • Elastomer
  • Glass
  • Gray cast iron with internal lining
  • Non-metallic thermal insulation
  • Polymer
  • Stainless steel
  • Steel Environment The fire protection system component types are exposed to the following environments:
  • Air - indoor uncontrolled
  • Air - outdoor
  • Air with borated water leakage
  • Concrete
  • Condensation
  • Diesel exhaust
  • Fuel oil
  • Gas
  • Raw water
  • Soil Page3-255

Serial No.: 21-280 Enclosure 2 Page 8 of 53 Table 3.3.2-42 Auxiliary Systems - Fire Protection - Aging Management Evaluation Component Intended Aging Effect Requiring NUREG-2191 Table 1 Material Environment Aging Management Programs Notes Type Function(s) Management Item Item Piping, piping LB;PB Gray cast (E) Air - indoor Loss of material External Surfaces Monitoring of Mechanical Vll.1.A-77 3.3.1-078 A components iron uncontrolled Components (B2.1.23)

(I) Air - indoor Flow blockage Fire Water System (B2.1.16) VII.G.A-404 3.3.1-131 B, 7 uncontrolled Loss of material Fire Protection (B2.1 .15) VII.G.AP-150 3.3.1-058 A, 3 Fire Water System (B2.1.16) VII.G.A-412 3.3.1-136 D, 7 (E) Air - outdoor Loss of material External Surfaces Monitoring of Mechanical VII.I.A-77 3.3.1-078 A Components (B2.1.23)

(E) Air with borated Loss of material Boric Acid Corrosion (B2.1.4) VII.I.A-79 3.3.1-009 A water leakage (I) Raw water Long-term loss of material One-Time Inspection (B2.1 .20) VII.G.A-532 3.3.1-193 A, 9 Loss of material Selective Leaching (B2.1.21) VII.G.A-51 3.3.1-072 A, 9 Loss of material; flow Fire Water System (B2.1.16) VII.G.A-33 3.3.1-064 B, 2, 9 blockage Gray cast (I) Raw water Loss of coating or lining Internal Coatings/Linings For In-Scope Piping, VII.G.A-416 3.3. 1-138 B iron with integrity; loss of material or Piping Components, Heat Exchangers, and Tanks internal lining cracking (for cementitious (B2.1.28) coatings/linings)

Loss of material Internal Coatings/Linings For In-Scope Piping, VII.G .A-414 3.3.1-139 B I Piping Components, Heat Exchangers, and Tanks VII.G.A-415 3.3.1-140 B (B2.1.28) I

~ 6uried sind Und~rgrQ!JnQ Piping and Tsioki, NQne ~ H 11 (E) Soil Cracking (B2.1 .27)

Buried and Underground Piping and Tanks None None H, 11 I

Loss of material (B2.1 .27)

Selective Leaching (B2.1.21) VII.G.A-02 3.3.1 -072 A I

Buried and Underground Piping and Tanks Vll.1.AP-198 3.3.1 -109 A (B2.1 .27)

North Anna Power Station, Units 1 and 2 Page 3-530 Supplement 4 Application for Subsequent License Renewal

Serial No.: 21-280 Enclosure 2 Page 9 of 53 Table 3.3.2-42 Auxiliary Systems - Fire Protection - Aging Management Evaluation Component Intended Aging Effect Requiring NUREG-2191 Table 1 Material Environment Aging Management Programs Notes Type Function(s) Management Item Item Piping, piping LB;PB Steel (E) Air - indoor Loss of material External Surfaces Monitoring of Mechanical VII.I.A-77 3.3.1-078 A components uncontrolled Components (B2.1.23)

(I) Air - indoor Flow blockage Fire Water System (B2.1.16) VII.G.A-404 3.3.1-131 B, 7 uncontrolled Loss of material Fire Protection (B2.1.15) VII.G.AP-150 3.3.1-058 A, 3 Fire Water System (B2.1 .16) VII.G.A-412 3.3.1-136 D, 7 (E) Air - outdoor Loss of material External Surfaces Monitoring of Mechanical VII.I.A-77 3.3.1-078 A Components (B2.1.23)

(I) Air - outdoor Loss of material External Surfaces Monitoring of Mechanical Vll.1.A-77 3.3.1-078 A, 1 Components (B2.1.23)

(E) Air with borated Loss of material Boric Acid Corrosion (B2.1.4) Vll.1.A-79 3.3.1-009 A water leakage (E) Concrete Loss of material Buried and Underground Piping and Tanks VII.I.AP-198 3.3.1-109 A (B2.1.27)

(I) Gas None None VII.J.AP-6 3.3.1-121 A (E) Raw water Long-term loss of material One-Time Inspection (B2.1.20) VII.G.A-532 3.3.1-193 A Loss of material Fire Water System (B2.1.16) VII.G.A-33 3.3.1-064 B (I) Raw water Long-term loss of material One-Time Inspection (B2.1.20) VII.G .A-532 3.3.1-193 A, 9 Loss of material Fire Water System (B2.1.16) VI I.G.A-400 3.3.1-127 B, 9 Loss of material ; flow Fire Water System (B2.1.16) VII.G.A-33 3.3.1-064 B, 2, 9 blockage (I) Qie~eI e~bs;1u~l LQ~~ Qf ms;1lerial ln~J;lei;liQ Qf lntern2l ~!.lrfa~~ in Mi~1,ells;1neQ!.!~ Y'.11 .H,:! AP-104 ~-l 1-Q!l!l I:,

Pi[ling and Ducjing Com12onents (B2.1.2~}

~umul 2jiv~ fajig!,,I~ gam 2ge TLAA VII.E1.A-;M ~-~-1-Q02 8 Pump casing PB Gray cast (E) Raw water Long-term loss of material One-Time Inspection (B2.1.20) VII.G.A-532 3.3.1-193 A (diesel driven fire iron Loss of material Fire Water System (B2.1.16) VII.G .A-33 3.3.1-064 B pump)

Selective Leaching (B2.1.21) VII.G.A-5 1 3.3.1-072 A (I) Raw water Long-term loss of material One-Time Inspection (B2.1.20) VII. G.A-532 3.3.1-193 A Loss of material Selective Leaching (B2.1 .21) VII.G.A-51 3.3.1-072 A Loss of material; flow Fire Water System (B2.1.16) VII.G .A-33 3.3.1-064 B blockage North Anna Power Station , Un its 1 and 2 Page 3-531 Supplement 4 Application for Subsequent License Renewal

Serial No.: 21-280 Enclosure 2 Page 10 of 53 Table 3.3.2-42 Auxiliary Systems - Fire Protection - Aging Management Evaluation Component Intended Aging Effect Requiring NUREG-2191 Table 1 Material Environment Aging Management Programs Notes Type Function(s) Management Item Item Pump casing PB Gray cast (E) Raw water Long-term loss of material One-Time Inspection (B2.1.20) V II.G.A-532 3.3.1-193 A (motor driven fire iron Loss of material Fire Water System (B2.1 .16) V II.G.A-33 3.3.1-064 B pump)

Selective Leaching (B2.1.21) VII.G .A-5 1 3.3.1-072 A (I) Raw water Long-term loss of material One-Time Inspection (B2.1.20) VII.G.A-532 3.3.1-193 A Loss of material Selective Leaching (B2.1.21) VII.G.A-51 3.3.1-072 A Loss of material; flow Fire Water System (B2.1.16) VI I.G.A-33 3.3.1-064 B blockage Pump casing PB Stainless (E) Raw water Loss of material Fire Water System (B2.1.16) VII.G .A-55 3.3.1-066 B (pressure steel (I) Raw water Loss of material; flow Fire Water System (B2.1.16) VII.G .A-55 3.3.1-066 B maintenance) blockage Ruptu re disc PB Copper alloy (E) Air - indoor Cracking External Surfaces Monitoring of Mechanical VII. I.A-405a 3.3.1-132 A

(>15% Zn) uncontrolled Components (B2.1.23)

(I) Air - indoor None None VII.J.AP- 144 3.3 .1-114 A, 4 uncontrolled (E) Air - outdoor Cracki ng External Surfaces Monitoring of Mechanical V II.I.A-405a 3.3.1- 132 A Components (B2.1 .23)

Sight glass PB Glass (E) Air - indoor None None VII.J .AP-48 3.3.1 - 117 A uncontrolled (I) Raw w ater None None V II.J .AP-50 3.3 .1-117 A Sight glass PB Copper alloy (E) Air - indoor None None VI I.J .AP-144 3.3.1-114 A (body) uncontrolled (I) Raw water Loss of material; flow Fire Water System (B2.1.16) VII. G.AP- 197 3.3.1-064 B blockage Copper alloy (E) Air - indoor Cracking External Surfaces Monitoring of Mechanical VII.I.A-405a 3.3.1-132 A

(>1 5% Zn) uncontrolled Components (B2.1 .23)

(I) Air - indoor None None VII.J.AP-144 3.3.1-114 A, 4 uncontrolled (I) Raw w ater Cracking Inspection of Internal Surfaces in Miscellaneous VII .C1 .A-473b 3.3.1 -160 E, 6 Piping and Ducting Components (B2.1.25)

Loss of material Selective Leaching (B2.1.21) VII.G.A-47 3.3.1-072 A Loss of material; flow Fire Water System (B2.1.16) VII. G.AP- 197 3.3.1-064 B blockage North Anna Power Station, Units 1 and 2 Page 3-532 Supplement 4 Application for Subsequent License Renewal

Serial No.: 21-280 Enclosure 2 Page 11 of 53 Table 3.3.2-42 Auxiliary Systems - Fire Protection -Aging Management Evaluation Component Intended Aging Effect Requiring NUREG-2191 Table 1 Material Environment Aging Management Programs Notes Type Function(s) Management Item Item Silencer PB Steel (El Air - indoor Loss of material External Surfaces Monitoring of Mechanical VII.I.A-77 3.3.1-078 6 yn@nJrQll~Q (;;QmQQn~nt~ (!;!2.1.2~)

(I) Diesel exhaysl Loss of milterial lnsi;iecjion of lnt~roal Surfi;!Q~s in Mis~llaneQu~ VII.H2.AP-104 H 1-Q~8 6 Piging ang Ducting (;;omgQnents (B2.1.25)

Sprinkler head SP Copper alloy (E) Air - indoor None None VII.J.AP-144 3.3.1-114 A uncontrolled (E) Air - outdoor None None VII.J.AP-144 3.3.1-114 A (I) Air - indoor Loss of material ; flow Fire Water System (B2.1.16) VII.G.A-403 3.3.1-130 B uncontrolled blockage (I) Raw water Loss of material; flow Fire Water System (B2.1.16) VI I.G.A-403 3.3.1-130 B blockage Strainer body PB Copper alloy (E) Air - indoor None None VII.J.AP-144 3.3.1-114 A uncontrolled (I) Raw water Loss of material; flow Fire Water System (B2.1.16) VII.G.AP-197 3.3.1-064 B blockage Steel (E) Air - indoor Loss of material External Surfaces Monitoring of Mechanical VI I.I.A-77 3.3.1 -078 A uncontrolled Components (B2.1.23)

(I) Raw water Long-term loss of material One-Time Inspection (B2.1.20) VII.G.A-532 3.3.1-193 A Loss of material; flow Fire Water System (B2.1.16) VII.G.A-33 3.3.1-064 B blockage Strainer element FLT Copper alloy (E) Raw water Loss of material; flow Fire Water System (B2.1.16) VII.G.AP-197 3.3.1-064 B (deluge/alarm blockage check valve)

Strainer element FLT Copper alloy (E) Raw water Loss of material; flow Fire Water System (B2.1.16) VII.G.AP-197 3.3.1-064 B, 13 (pump suction) blockage Strainer element FLT Copper alloy (E) Raw water Loss of material; flow Fire Water System (B2.1.16) VII.G.AP-197 3.3.1-064 B (turbine building blockage supply header)

Tank (1 7-ton PB Steel (E) Air - outdoor Loss of material External Surfaces Monitoring of Mechanical Vll.1.A-77 3.3.1-078 A ca rbon dioxide Components (B2.1.23) storage) (I) Gas None None VII.J.AP-6 3.3.1-121 A North Anna Power Station, Units 1 and 2 Page 3-533 Supplement 4 Application for Subsequent License Renewal

Serial No.: 21-280 Page 12 of 53 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Supplement 4 Aging Management Review

.33 Tank Foundations and Missile Barriers Materials The materials of construction for the tank foundations and missile barriers structural members are:

Concrete

  • Elastomer, rubber and other similar materials
  • Steel Environment The tank foundations and missile barriers structural members are exposed to the following environments:
  • Air
  • Air indoor uncontrolled
  • Air- outdoor
  • Groundwater
  • Soil Water - flowing Page 3-737

Serial No.: 21 -280 Enclosu re 2 Page 13 of 53 North Anna Power Station, Units 1 and 2 Application for Subsequent License Ren ewal Supplement 4 Aging Management Review Aging Effects Requiring Management The fo llowing aging effects , associated with the tank foundation s and missile barriers stru ctural members, require management:

  • Cracking
  • Cracking and distortion
  • Increase in porosity and permeability
  • Loss of bond
  • Loss of material
  • Loss of material (spalling, scaling)
  • Loss of material (spalling, scaling) and cracking
  • Loss of preload
  • Loss of sealing
  • Loss of strength
  • Reduction in concrete anchor capacity Aging Management Programs The fo llowing aging management programs manage the aging effects for the tank foundation s and missile barriers structural members:
  • Outdoor and Large Atmospheric Metallic Storage Tanks (82.1.17}
  • Structures Monitoring (82 .1.34)

Page 3-738

Serial No.: 2 1-280 Enclosure 2 Page 14 of 53 Table 3.5.1 Summary of Aging Management Programs for Containments, Structures and Component Supports Evaluated in Chapters II and III of the GALL-SLR Report Item Aging Aging Management Further Evaluation Component Discussion Number Effect/Mechanism Program Recommended 3.5.1-071 Masonry walls: all Loss of material AMP X I.S5, Masonry Walls No Consistent with NUREG-2 191.

(spalling , scaling) and cracking due to freeze-thaw 3.5.1-072 Seals; gasket; moisture Loss of sealing due to AMP XI.S6, Structures No GeAsisleAI will:l ~Jl:lREG ~HH. CQnsis!en! with barriers (caulking, flashing, wear, damage, Monitoring NUREG-2191 with si different 1:1rogram assigned for and other sealants) erosion, tear, surface  !&Ulking sing §esilsints associsi!ed with the EC~T vent cracks , other defects sing vsiQuum bresiker 1:1enetra!iQn-QQncrete mi§§il~ !;isirrier in!erfaQe in Tsink Fo!,!ndsiliQns and Mis§ile Barriers. Los§ Qf §esiling Qf Qsi!.llking sing §esilsin!§ si! !he EC~T ~ ! ll g vacuum bresiker 1:1enetration-conQrete mis§ile b 2 rrier interfslce in Tsink FQunga\iQn§ <1nd Mi§§il~ Bsirriers will be msinsiged by !he Q!.!ldoQr sing Large Atmos1:1heriQ Melsillic Storage Tanks (82.1 .17) RrQgram .

3.5.1-073 Service Level I coatings Loss of coati ng or A MP X I.SB, Protective No Cons istent with NUREG-2 191 .

lining integrity due to Coating Monitoring and blistering, cracking , Maintenance flaking , peeling ,

delamination, rusting, or physical damage

3. 5. 1-074 Sliding support bearings; Loss of mechani cal AMP XI. S6, Structures No Consistent with NUREG-2191 .

sliding support surfaces function due to Monitoring corrosion, distortion, dirt or debris accumul ation, overload, wear 3.5.1 -075 Sliding surfaces Loss of mechanical AMP XI.S3, ASME Section No Consistent with NU REG-2191.

function due to XI, Subsection IWF corrosion, distortion, dirt or deb ris accumulation, overl oad, wear North Anna Power Station, Units 1 and 2 Page 3-796 Supplement 4 Application for Subsequent License Renewal

Serial No.: 21-280 Enclosure 2 Page 15 of 53 Table 3.5.2-33 Structures and Component Supports - Tank Foundations and Missile Barriers - Aging Management Evaluation Structural Intended Aging Effect Requiring NUREG-2191 Table 1 Material Environment Aging Management Programs Notes Member Function(s) Management Item Item Bolting ss Steel (E) Air - outdoor Loss of material Structures Monitoring (B2.1.34) III.A3.TP-248 3.5.1-080 A Loss of preload Structures Monitoring (B2.1.34) III.A3.TP-261 3.5.1-088 A Caulking and EN Elastomer, (E) Air - outdoor Loss of sealing Structures Monitoring (B2.1.34) II1.A6.TP-7 3.5.1-072 A sealants rubber and II1.A6.TP-7 Outdoor and Large Atmo~Qheric Metallic S!orag~ 3 5 1-Q72 Ll other similar Tanks /B2.1.17\

materials Compressible EN Elastomer, (E) Air - indoor Loss of sealing Structures Monitoring (B2.1.34) III.A6.TP-7 3.5.1-072 A seal rubber and uncontrolled other similar materials Concrete MB;SS Concrete (E) Air - indoor Cracking Structures Monitoring (B2.1.34) III.A3.TP-204 3.5.1-043 A, 1 elements uncontrolled III.A3.TP-25 3.5.1-054 A, 1 Cracking; loss of bond; and Structures Monitoring (82.1.34) III.A3.TP-26 3.5.1-066 A, 1 loss of material (spalling, scaling)

Increase in porosity and Structures Monitoring (82.1.34) III.A3.TP-28 3.5.1-067 A, 1 permeability; cracking ; loss of material (spalling , scaling)

(E) Air - outdoor Cracking Structures Monitoring (82.1.34) 111.A3.TP-204 3.5.1-043 A, 1 III.A3.TP-25 3.5.1-054 A, 1 Cracking; loss of bond; and Structures Monitoring (B2.1.34) III.A3.TP-26 3.5.1-066 A, 1 loss of material (spalling, scaling)

Increase in porosity and Structures Monitoring (B2.1.34) 111.A3.TP-28 3.5.1-067 A, 1 permeability; cracking; loss of material (spalling, scaling)

Loss of material (spa lling, Structures Monitoring (B2.1.34) III.A3.TP-23 3.5.1-064 A, 1 scaling) and cracking North Anna Power Station, Units 1 and 2 Page 3-879 Supplement 4 Application for Subsequent License Renewal

Serial No.: 21-280 Enclosure 2 Page 16 of 53 Table 3.5.2-33 Structures and Component Supports - Tank Foundations and Missile Barriers - Aging Management Evaluation Structural Intended Aging Effect Requiring NUREG-2191 Table 1 Material Environment Aging Management Programs Notes Member Function(s) Management Item Item Concrete MB;SS Concrete (E) Groundwater Cracking; loss of bond; and Structures Monitoring (B2.1.34) III.A3.TP-212 3.5.1-065 A, 1 elements loss of material (spalling , III.A3.TP-27 3.5.1-065 A, 1 scaling)

Increase in porosity and Structures Monitoring (B2.1.34) III.A3.TP-29 3.5.1-067 A, 1 permeability; cracking; loss of material (spalling, scaling)

(E) Soil Cracking Structures Monitoring (B2.1 .34) III.A3.TP-204 3.5.1-043 A, 1 Cracking and distortion Structures Monitoring (B2.1 .34) III.A3.TP-30 3.5.1-044 A, 1 Cracking; loss of bond ; and Structures Monitoring (B2.1 .34) III.A3.TP-212 3.5.1-065 A, 1 loss of material (spalling , III.A3.TP-27 3.5.1 -065 A, 1 scaling)

Increase in porosity and Structures Monitoring (B2.1.34) II1.A3.TP-29 3.5.1-067 A, 1 permeability; cracking; loss of material (spalling , scaling)

(E) Water - flowing Increase in porosity and Structures Monitoring (B2.1.34) III.A3.TP-24 3.5.1-063 A, 1 permeability; loss of strength Grout ss Grout (E) Air - indoor Reduction in concrete Structures Monitoring (B2.1 .34) III.B4.TP-42 3.5.1-055 A uncontrolled anchor capacity (E) Air - outdoor Reduction in concrete Structures Monitoring (B2.1.34) III.B4.TP-42 3.5.1-055 A anchor capacity Stainless steel MB Stainless (E)Air Loss of material; cracking Structures Monitoring (B2.1.34) 111.B5.T-37b 3.5.1-100 C, 2 elements steel (E) Soil Loss of material Structures Monitoring (B2.1.34) None None H, 2 Steel elements MB Steel (E) Air - indoor Loss of material Structures Monitoring (B2.1.34) III.A3.TP-302 3.5.1-077 A, 3 uncontrolled (E) Air - outdoor Loss of material Structures Monitoring (B2 .1.34) II I.A3.TP-302 3.5.1-077 A, 3 Table 3.5.2-33 Plant-Specific Notes :

1. Concrete elements include foundation, hatches, and missile barriers.
2. Stainless steel elements include missile barriers.
3. Steel elements include baseplates, missile barriers, and embedded steel.
4. The Outdoor and Large Atmospheric Metallic Storage Tanks (B2 .1.17) program will be used instead of the Structures Monitoring program to manage this aging effect for caulking at the ECST vent and vacuum breaker penetration-concrete missile barrier interface. Visual inspections will be conducted on a 18-month frequency to confirm the caulking is intact.

North Anna Power Station, Units 1 and 2 Page 3-880 Supplement 4 Application for Subsequent License Renewal

Serial No. : 21 -280 Enclosure 2 Page 17 of 53 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Supplement 4 Time-Lim ited Aging Analyses As shown in Table 4.3.1- 1, the 40-year design cycles (CLB cycl es) are postu lated to bou nd 80 years of plant operations. Therefore, the fatigu e waivers for Class 1 components remain valid for the subsequent period of extended operation as described in WCAP-18503-NP. In order to ensure the design cycles remain bounding in th e ASME Code, Section Ill , Class 1 component fatigue wa ivers, the Fatigue Monitoring program (B3 .1) will track cycles fo r sign ifica nt transients and ensure corrective action is taken prior to potentially exceeding fatigue design limits.

TLAA Dis position: 10 CFR 54. 21(c)( 1)(iii)

The ASME Code, Section Ill, Class 1 compon ent fatigue waivers will be managed by th e Fatigue Monitoring program (B3 .1) through the subsequent period of extended operation. The Fatigue Monitoring program (B3.1) will monitor the transient cycles and severities which are the in puts to the fatigue waiver analyses and requi re action prior to exceedi ng design limits that would invalidate their conclusions.

4.3 .3 USAS (ANSI) 831.1 ALLOWABLE STRESS ANALYSES TLAA

Description:

Nuclear piping is constructed in accordance with the USAS (ANSI) B31.7, "Nuclear Power Piping" Code, 1969 Edition with 1970 and 1971 Addenda. USAS (ANSI) B31. 7-69, Class I pi ping is designed to consider the cumulative effect of stress cycles by use of a cumulative usage factor (CUF). Fatigue for Class I piping is addressed as a TLAA in Section 4.3.2.7.

As identified in USAS (ANSI) B31.7-69 paragraphs 2-702 and 3-702, Class II and Class Ill piping meets the design criteria of USAS (ANSI) B3 1.1.0-1967, Divi sion 102. Non-nuclea r (Balance of Plant) piping is constructed to "The Power Piping Code" USAS (ANSI) B31. 1, 1967 Edition with 1969 Addenda.

For piping systems designed in accordanc e with USA S (ANSI) B3 1. 1, exp li cit analyses of cumu lative fatigue usage are not required. Instead, cyclic load ing is con sidered in a simplified ma nn er in th e design process. Allowable th ermal stresses are red uced using a stress range reduction factor based on the number of anticipated thermal cycles expected during th e component ope ratin g lifetime. Stress range reduct ion factors are spec ified in USAS (AN SI) B31.1, Table 102.3.2(c). No reduction of allowable stresses is required for piping that is subjected to less than 7,000 equivalent full temperature cycles during plant service. The stress range reduction factor for hi gher numbers of fatigue cycles is less than 1.0 and is grad ually reduced until a rang e of 100, 000 cycles is reached. For piping anticipated to experience 100,000 or more equiva lent fu ll temperature cycles , the allowable stress range would be redu ced to half of the maximum nominal allowable stress. The evaluations for required stress reduction factors are implicit fatigue analyses because they are based on the number of fatigue cycles anticipated for the life of the component.

Therefore , they are TLAAs requiring evaluation for the subsequent period of extended operation.

Page4-81

Serial No.: 21-280 Page 18 of 53 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Supplem ent 4 Time-Limited Aging Analyses TLAA Evaluation:

USAS (ANSI) B31.1 systems are generally subject to continuou s steady state operation and operating temperatures vary only during plant heatup and cooldown, during plant transients, or during periodic testing. Portions of piping systems designed in acco rdan ce with USAS (ANS I)

B31.1 requirements that are attached to the reactor coolant system or other power cycl e rel ated systems are subject to a similar number or fewer cycles as the reactor coolant system . These include condensate, containment vacuum, extraction steam, feedwater, primary and secondary gas supply, main steam, reactor coolant, steam drains, and vacuum priming systems. Portions of some of these systems are normally isolated from the normal power cycle and would experience fewer cycles tha n those portions at the system boundary. The expected number of transients for these system s is much less than 7,000 cycles, therefore, the stress range reduction factors applied to the piping remain applicable and the implicit TLAAs remain valid for the subsequent period of extended operation .

Portions of the following systems, designed in accordance with USAS (ANSI) B31 .1 requirements, are affected by thermal and pressure transients that are different than th e reactor coolant and power cycles discussed above: alternate AC, auxiliary boilers, auxiliary steam, blowdown, chilled water, ch emical and volume control, emergency diesel generator, fire protection , high radi ation sampling, heating and ventilation, residual heat, security, and sampling system. The basis for cycle projections have been reviewed for these systems to validate th at the projected cycles for 80 years rema in less than 7,000 cycles. Table 4.3.3-1 and Section 4.4.2 of WCA P- 18503-P provide the basis for concluding that the number of cycles for each of these piping systems is projected to be less than 7,000. Therefore, the USAS (ANSI) B31.1 allowable stress analyses remain valid for the subsequent period of extended operation.

Initial license renewal validated that the USAS (ANSI) B31.1 piping would receive less than 7,000 cycles . For SLR, it is confirmed that the USAS (ANSI) B31.1 pi ping is projected to receive less than 7,000 cycles.

In addition, no component in the systems identified by Table 4.3.3-1 were designed in accord ance with ASME Code,Section VIII, Division 2.

TLAA Dis position: 10 CFR 54.21(c)(1)(i)

The USAS (ANSI) B31 .1 allowable stress analyses remain valid for the subsequent period of extended operation.

Page4-82

Seri al N o.: 21-280 E nclosure 2 Page 19 of 53 North Anna Power Station , Units 1 and 2 Application for Subsequent License Renewal Supplement 4 Time-Limited Aging An alyses Table 4.3.3-1 80 Year Transient Cycle Proj ections for USAS (ANS I) 831.1 Piping Projected Cyc les for Description Conservative Basis for Cycle Projection 80 years 10 starts per year, since installation of the AAC

~lternate AC (AAC) diesel diesels in 1992 to 2060 (10 cycles/year x 68 years engine exhaust piping

= Less th an 1000 cycles 680 cycles) .

Cycles for the AB System piping are bounded by the Less than 2000 cycles Auxili ary Boilers (AB) number of AS System thermal cycles .

Au xiliary Steam (AS) 20 cycles per year - 1600 cycles . Less than 2000 cycl es Slowdown (BD) 10 cycles per year - 800 cycles . Less th an 1000 cycles Cycles for the CD system piping are bounded by the Less th an 2000 cycles Chilled Water (CD) number of AS System thermal cycles .

Chemical and Volume Transients relative to power cycle operation Less th an 7000 cycles Control (CH) consistent with RCS transients from Table 4.3.1-1 .

Transients relative to power cycle operation Less than 7000 cycl es Condensate (CN) consistent with RCS transients from Table 4.3.1-1 .

Transients relative to power cycle operation Less th an 7000 cycles Containment Vacuum (CV) consistent with RCS transients from Table 4.3.1-1 .

Twice per month to account for monthly (hi storic)

Emergency Diesel surveillance testing (currently conducted quarterly) Less than 2000 cycles Generator (EG) and post maintenance testing (2 cycles/month x 12

=

month/year x 80 years 1920).

Transients relative to power cycle operation Less th an 7000 cycles Extraction Steam (ES) consistent with RCS transients from Table 4.3.1-1.

Transients relative to power cycle operation Less than 7000 cycl es Feedwater (FW) consistent with RCS transients from Table 4.3.1-1 .

Twice i;1er month to account for monthlll testing and Fire Prot~ction (FP) i;1ost maintenance testing (2 Cl£cles/montb x 12 Less than 2000 Cl£cles

=

month s/)lear x 80 l£ears 1920).

Primary and Secondary Transients relative to power cycle operation Less than 7000 cycl es Gas Supply (GN) consistent with RCS transients from Table 4.3.1-1 .

Simultaneous sampling by the HRS system an d the High Radiation Sampling PSS is prevented by interlocks. Projected 80-year Less than 1000 cycles (HRS) thermal cycles is well below 1000 Cycles based on seasonal heating. Conservatively Heating and Ventilation (HV) assume 85 cycles per year (80 years x 85/year = Less than 7000 cycles 6800 cycles) .

Transients relative to power cycle operation Less than 7000 cycles Main Steam (MS) consistent with RCS transients from Table 4.3.1-1 Reactor Coolant (RC) RCS transients from Table 4.3.1-1 . Less than 7000 cycles System piping heated during shutdowns and sta rtups . Less th an 1000 cycles Residual Heat (RH) 2 per heatup and cooldown each refueling cycle.

Transients relative to power cycle operation Less than 7000 cycles Steam Drains (SD) consistent with RCS transients from Table 4.3.1-1.

Twice per month to account for monthly testing and Security (SEC) post maintenance testing (2 cycles/month x 12 Less th an 2000 cycles

=

months/year x 80 years 1920).

Page4-83

Serial No.: 21-280 Enclosure 2 Page 20 of 53 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Supplement 4 Appendix A - UFSAR Supplement A1.16 FIRE WATER SYSTEM 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 water-based fire protection system that have been wetted but are normally dry have 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 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 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 consistent 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 interface 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 meta! 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. Thickness measurements of the tank's bottoms are conducted to ensure that significant degradation is not occurring. The external surfaces of insulated tanks are periodically PageA-12

Serial No.: 21 -280 Page 21 of 53 North Anna Power Station , Units 1 and 2 Application for Subsequent License Renewal Suppl ement 4 Appendix A- UFSAR Supplement sampling-based inspected. Inspections not conducted in accordance with ASME Code,Section XI requirements are conducted in accordance with plant-specific procedures th at include inspection parameters such as lighting, distance, offset, and surface condition s.

One-tim e thickness measurements will be performed on the Unit 1 ECST interior wall and tank bottom prior to the subsequent period of extended operation to identify and assess potentia l degradation between the concrete missile shield and the metallic tank. Periodic wall thickness measurements of the tank bottom and a minimum of five Unit 2 ECST interior vertical wall locations with th e lowest wall thickness readings will be performed on a ten-year in spection freq uen cy to evalu ate degradation. The Unit 2 ECST vertical wall degrad ation projection s to the end of the subseq uent period of extended operation that exceed less th an 0.1 inch wall thickn ess will be repaired prior to entering the subsequent period of extended operation and no longer require wall thickness measurements. The gasket on the ECST upper access concrete plug is repl aced whenever it is removed to allow access for internal tank wall thickn ess measurements. The E:CST vent and 1,aouum breaker caulking is periodioally inspected during E:CST ooncrete missile shield inspeotions.The caulking at the ECST vent and vacuum breaker penetration-concrete missile barrier interface is inspected on a 18-month frequency.

Consistent with the recommendations of the Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks program (A 1.28), loss of co ating integrity for the emergency condensate tanks is managed by this program. Intern al surfaces of the RWSTs, CATs, and CCTs will be managed by the One-Time Inspection program (A 1.20). Tank reinforced concrete found ations and the reinforced concrete missile barrier of the ECSTs will be manag ed by the Structures Monitoring program (A 1.34) .

A1 .18 FUEL OIL CHEMISTRY The Fuel Oil Chemistry program is an existing mitigative and condition monitoring and preventive program that manages cracking or blistering, flow blockage, hardening or loss of strength, loss of materi al, and reduction of heat transfer from tanks, piping, and compon e nts in a fu el oil environment. The program includes activities which provide assurance th at contami nants are maintained at acceptable levels in fuel oil for systems and components within th e scope of subsequent license renewal.

This program relies on a combination of surveillance and maintenance procedures. Fuel oil quality is maintained by monitoring and controlling fuel oil contamin ation in accordance with Techn ical Specifi cations, the Technical Requirements Manual, and ASTM standards such as ASTM D 0975, D 1796, D 2276, D 2709, D 6217, and D 4057.

Exposure to fuel oil contaminants, such as water and microbiological organisms, is minimized by periodic cleaning/draining of tanks and by verifying the quality of new oil before its introduction into the storage tanks . Where internal cleaning and inspection are not physica lly possibl e, bottom PageA-13

Serial No.: 21-280 Enclosure 2 Page 22 of 53 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Suppl ement 4 Appendix A - UFSAR Supplement A1. 26 LUBRICATING OIL ANALYSIS The Lubricating Oil Analysis program is an existing preventive program th at ensures th at loss of material and reduction of heat transfer is not occurring by maintaining th e quality of the lubricating oil or hydraulic oil. The program ensures that contaminants (primarily water and particu lates) are within acceptable limits. Testing activities include sampling and analysi s 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 compon ents in soil, concrete, or underground environments within the scope of subsequent license ren ewa l through preventive and mitigative actions. The program addresses piping and ta nks composed of stainless steel, carbon steel, cast iron, ductile iron, copper alloy, and fibergl ass.

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 techniqu es includ e external coatin gs, cathodic protection (CP), and the quality of backfill. Direct vi sual inspection quantities for bu ried 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 action s. Also, depending on the material, inspection activities include annual surveys of CP, nondestructive evaluation of pipe or tank wall thicknesses, and visu al inspections of th e pipe from the exterior. For steel components, where the acceptance criteri a for th e 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 nea r components within the scope of subsequent license ren ewal 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 metal could have resulted in a loss of pressure bound ary function wh en th e loss of materi al rate is extrapolated to the end of the subsequent period of extended operation an increase in the sample size is conducted.

PageA-20

Serial No.: 21-280 Enclosure 2 Page 23 of 53 Table A4.0-1 Subsequent License Renewal Commitments

  1. Program Commitment AMP Implementation The Outdoor and Large Atmospheric Metallic Storage Tanks program is an existing condition monitoring program that will be enhanced as follows:
1. Procedures will be revised to require periodic visual inspections of the RWSTs and CCTs be performed at each refueling outage to confirm that the mastic sealant at the RWSTs and CCTs insulation and concrete foundation interface is intact. The visual inspections of the sealant will be supplemented with physical manipulation to detect any degradation. If there are any identified flaws, the mastic sealant will be repaired or replaced, and follow-up examination of the tank's surfaces will be conducted if deemed appropri ate. An inspection of the caulk at the tank and concrete foundation interface will be included in the sample when the RWSTs and CCTs external insulation is removed and the caulk will be sampled for external surface visual examinations ten years before the subsequent period of extended operation . Results wi ll be forwarded to Engineering fo r evaluati on and the need for add itional inspections will be determined based on projected Program will be corrosion rates. implemented and
2. Procedures will be revised to require the caulking at the ECST vent and vacuum breaker penetration-concrete inspections or tests begin missile barrier interface be inspected on a 18-month frequency to confirm that the caulking is intact. The 1O years before the visual inspections will be supplemented with physical manipulation to detect any degradation. If there are any subsequent period of identified flaws. the caulking will be repaired or replaced . (Added - Supplement 4} extended operation.
3. Procedures will be revised to require visual and su rface examination of the exterior surfaces of the RWSTs , Inspections or tests that are Outdoor and Large CATs, and CCTs be performed to identify any loss of material or cracking. A minimum of either 25 one-square to be completed prior to the Atmospheric Metallic 17 B2.1.17 subseq uent period of Storage Tanks foot section s or 20% of the su rface area of insulation will be required to be removed to permit inspection of the exterior surface of each tank. The procedure will specify that sample inspection points be distributed in such a extended operation are program way that inspections occur near the bottoms, at points where structural supports, pipe, or instrument nozzles completed 6 months prior to penetrate the insulation, and where water could collect such as on top of stiffening rings. If no unacceptable the subsequent period of loss of material or cracking is observed, subsequent external su rface examinations of insu lated tanks will extended operation or no inspect for indications of damage to the jacketing , evidence of water intrusion through the insulation, or later than the last refueling evidence of damage to the moisture barrier of tightly adhering insulation . (Renumbered - Supplement 4} outage prior to the subsequent period of
4. Unit 1 ECST: Procedures will be revised to require one-time thickness measurements of a sample of the Unit extended operation .

1 aRd UR it 2 ECSTs interior wall and tank bottom prior to the subsequent period of extended operation to assess potential degradation due to leakage identified from the missile shield into the pipe penetration area in the Auxiliary Feedwater Pump House. The samples will examine the ECSTs interior vertical steel shell region from the bottom of the tank along the pipe penetrati on area, extending six feet vertically up from the tank, as thi s is a region potentia lly most susceptible to external surface degradation. Tank bottom thickness measurements will also be performed . The inspection results will be projected to the end of the subsequent period of extended operation to confirm the Unit 1 ECSTs intended fun cti ons will be mai ntained throughout the subsequent period of extended operation based on the projected rate of degradation. Any degradation not meeting acceptance criteria will require periodic 10-year thickne ss measurements and a sample expansion along the leakage path consistent with the observed degradation. The l:l J') J') OF maRway aRd lower maRway

.* :11 --- ...I , .. ; _ _ ** --- *- . *- '. - -

North Anna Power Station, Units 1 and 2 PageA-70 Supplement 4 Application for Subsequent License Renewal Appendix A - UFSAR Supplement

Serial No.: 21-280 Enclosure 2 Page 24 of 53 Table A4.0-1 Subsequent License Renewal Commitments

  1. Program Comm itment AMP Implementation Unit 2 ECST: The Unit 2 ECST external vertical wall degradation grojections to the end of the S!,!bseguent Qe[iod of extended ogeration that exceed less than 0.1 inch wall thickn§ss will be regaired Q Qr to entering the subseguent geriod of extended ogeration. Periodic insgections of a minimum of five locations with the lowest wall thickness readings will be gerformed on a ten-year insgection freguency. lnsgection results grojected to the end of the subseguent geriod of extended ogeration that do not meet accegtance criteria will reguire an extent of condition and ex!ent of c;;iuse to get§rmine the f!,!rther extent of insgec!ion and corrective actions .

Tank bottom thickness measurements will also be gerformed . (Revised - Sugglement 1) (Renumbered -

Su@lement 4)

5. Procedures will be revised to require volumetric examination thickness measurements of the bottom of the RWSTs and CCTs be performed each 10-year period during the subsequent period of extended operation Program will be starting ten years before the subsequent period of extended operation. Results will be forwarded to implemented and Engineering for evaluation and the need for additional inspections will be determined based on projected inspections or tests begin corrosion rates. (Renumbered - Sugglement 4) 10 years before the
6. A new procedure will be developed to specify that additional inspections be performed consistent with subsequent period of NUREG-2191. (Renumbered - Sugglement 4) extended operation.

If any inspections do not meet the acceptance criteria, additional inspections are conducted if one of the Inspections or tests that are Outdoor and Large inspections does not meet acceptance criteria due to current or projected degradation (i .e., trending). to be completed prior to the Atmospheric Metallic 17 a. For inspections where only one tank of a material, environment, and aging effect was inspected, all tanks B2.1.17 subsequent period of Storage Tanks in that grouping are inspected. extended operation are program

b. For other sampling based inspections there will be no fewer than five additional inspections for each completed 6 months prior to inspection that did not meet acceptance criteria, or 20% of each applicable material, environment, and the subsequent period of aging effect combination inspected, whichever is less. If any subsequent inspections do not meet extended operation or no acceptance criteria, an extent of condition and extent of cause analysis will be conducted to determine the later th an the last refueling further extent of inspections required. Additional samples will be inspected for any recurring degradation to outage prior to the ensure corrective actions appropriately address the associated causes. The additional inspections will subsequent period of include inspection s of components with the same material, environment, and aging effect combination at extended operation.

the other unit.

The additional inspections will be completed within the interval (i.e., 10-year inspection interval) in which the original inspection was conducted or, if identified in the latter half of the current inspection interval, within the first half of the next inspection interval. These additional inspections conducted in the next inspection interval cannot also be credited towards the number of inspections in the latter interval.

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. However, for one-time inspections that do not meet acceptance criteria, inspections are subsequently conducted at least at 10-year inspection intervals.

North Anna Power Station, Units 1 and 2 PageA-7 1 Supplement 4 Application for Subsequent License Renewal Appendix A - UFSAR Supplement

Serial No.: 21-280 Enclosure 2 Page 25 of 53 Table A4.0-1 Subsequent License Renewal Commitments

  1. Program Commitment AMP Implementation Lubricating Oil 26 The Lubricating Oil Analysis program is an existing preventive program that is credited. 82.1.26 Ongoing 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 10 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 Program will be
b. The service water 'C' CP subsystem associated with the buried carbon steel piping of the fuel oil system implemented and for the emergency electrical power system inspections begin 10 years
3. The following buried QiQing materials will be reglaced before the last five years of the insgection geriod grior to before the subsequent entering the subseguent g~riod of extended ogeration . (Added - Sugglement 1) period of extended
a. The buried cogger giging between the fire grotection jockey gumg and the hydrogneumatic tank will be operation. Inspections that reglaced with carbon steel. are to be completed prior to Buried and
b. The buried carbon steel fill line giging for !he security gjesel fuel oil tank will be reglaced with corrosion the subsequent period of 27 Underground Piping 82.1.27 resistant material that does not reguire insgection (e.g., titanium alloy. suger austenitic, or nickel alloy extended operation are and Tanks program materials). completed 6 months prior to
4. Procedures will be revised to specify that cathodic protection surveys use the -850 mV polarized potential, the subsequent period of instant off criterion specified in NACE SP0169-2007 for steel piping acceptance criteria unless a suitable extended operation or no alternative polarization criteria can be demonstrated. Alternatives will include the -100 mV polarization criteria, later than the last refueling

-750 mV criterion (soil resistivity is greater than 10,000 ohm-cm to less than 100,000 ohm-cm), -650 mV outage prior to the criterion (soil resistivity is greater than 100,000 ohm-cm), or verification of less than 1 mpy loss of material subsequent period of rate. extended operation .

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 PageA-78 Supplement 4 Application for Subsequent License Renewal Appendix A - UFSAR Supplement

Serial No.: 21-280 Enclosure 2 Page 26 of 53 Table A4.0-1 Subsequent License Renewal Commitments

  1. Program Commitment AMP Implementation
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 tim e when the soil resistivity would be expected to be at its lowest value (e.g., maximum rainfall periods). Upon completion of ten annual consecutive soi l 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 featu res and local soil conditions will be factored into placement of the Program will be probes and use of the data implemented and
5. Procedures will be revised to reguire a minimum of six excavations be conducted at each unit to insQect for inspections beg in 10 years loss of material due to selective leaching in and fi>,ce of the inspeotions at eaoh unit destruoti¥ely mmmine the before the subsequent buried gra;t cast iron fire Qrotection QiQing and QiQing comQonents. The insQections will be conducted in the period of extended 10-;tear Qeriod Qrior to the subseguent Qeriod of extended oQeration and in each 10-;tear 12eriod during the operation. Inspections that subseguent Qeriod of extended OQeration. A ten-foot QiQe length will be excavated for each buried gra;t cast are to be completed prior to Buried and iron fire grotection QiQing samQle and the external surfaces insgected for blistering, cracking hardening or loss the subsequent period of 27 Underground Piping of strength and loss of material. Additionall;t NUREG-2191 Section XI.M33 Selective Leaching 12rogram B2.1.27 extended operation are and Tanks program destructive examinations will be conducted on a one-foot length of fire Qrotection s;tstem QiQing or a different completed 6 months prior to comgonent !J'.Qe from each discrete insQection location (six/unit) on a one foot len§th (minimum) pipin§ seotion the subsequent period of from eaoh disorete e:>Eoa*,cation looation (fi,,cetunit) to insQect for loss of material due to selective leaching. Five extended operation or no of the insgections will be conducted on a one-foot length of fire grotection Qiging and the sixth insQection will later than the last refueling be conducted on either a one-foot length of giging from the fire grotection s;tstem or a different comQonent outage prior to the

!J'.Qe (e.g., h;tdrant) from the fire grotection s;tstem . The selection of insQection locations for buried gra;t cast subsequent period of iron fire grotection giging and QiQing comgonents will consider the following criteria: (Added - Sugglement extended operati on.

3)(Revised Sugglement 4)

  • Older QiQing segments (i.e. not greviousl;t reglaced)
  • Piging and QiQing comgonents found to be continuousl;t wetted due to leaking QiQing/valves or in soil with high corrosivit;t ratings as determined b;t EPRI ReQort 3002005294, Soil SamQling and Testing Methods to Evaluate the Corrosivi!J'. of the Environment for Buried PiQing and Tanks at Nuclear Power Plants
  • PiQing and QiQing comgonents not cathodicall;t Qrotected
  • Piging and QiQing comQonents with significant coating degradation or unexgected backfill
  • Conseguence of failure (i.e. groximi!J'. to safe!J'.-related QiQing and QiQing comQonents)
  • Locations with Qotentiall;t high stress and/or c;tclic loading conditions such as QiQing adjacent to locations that were reQlaced due to cracking/ruQture locations subject to settlement or locations subject to hea)!Y load traffic North Anna Power Station, Units 1 and 2 Page A-79 Supplement 4 Application for Subsequent License Renewal Appendix A - UFSAR Supplement

Serial No.: 21-280 Enclosure 2 Page 27 of 53 Table A4.0-1 Subsequent License Renewal Commitments

  1. Program Commitment AMP Implementation
6. Procedures will be revised to reguire fiv~ excavsited giging samgl~s at each unit be insgected (internally'. and externally'.) fQr cracking due to Cl£clic loading. Tbe iosgections will b~ QQngug~d in the 10-y'.ear geriod grior to the subseguent geriod of extended ogeration (SPEO) and in each 10-y'.ear geriod during the SPEO as follows:

(Added - Sugglement 4)

a. A ~n-foo! i;iige length of b!,lrieg gral£ Qs!§! irQn fir~ grotection giging will be exQavated for each insi;iection.
b. Visual (VT) and magnetic garticle (MT) examinations will be conducted on the 10-foot buried grall cast iron Program will be fire grotection giging samgles. The radiograghic (RT) nondestructive examination (NOE) method will be imi;ilemented and ai;iglied to areas that have gotential surface cracking identified using the MT method. insgections begin 10 l£ears C. Examination results will be evaluated bl£ a Level II or Ill examiner gualified to ASME Code,Section XI and before the subseguent the following gerformed, as agglicable: geriod of extended
  • If there is no cracking identified using the NOE technigues, then a one-foot axial giece of the fire ogeration . lnsgections that grotection giging samgle will still be removed and destructively'. examined to insgect for the loss of are to be comgleted grior to Buried and material due to selective leaching as reguired bl£ NUREG-2191 Section XI.M33 Selective Leaching the subseguent geriod of 27 Underground Piping 82.1.27 grogram (see Enhancement 5). extended ogeration are and Tanks grogram
  • If cracking is identified then a bounding one-foot axial section of the fire grotection giging samgle will b~ comgleted 6 months grior to selected based on the crack size and characterization determined bl£ a gualified NOE Level II or Ill the subseguent geriod of examiner and further destructive examination conducted to identify'. cracking due to Cl£clic loading. The extended ogeration or oo destructive examination of the one-foot axial section will also be insgected for the loss of material due to later than the last refueling selective leaching (see Enhancement 5) . outage grior to the
d. If results of the destructive examination insgections determine the cracking is due to Cl£clic loading, then subseguent geriod of Engineering will gerform a crack growth evaluation and a flaw stabilitl£ evaluation based on the gredicted extended ogeration.

crack lengths at the end of the SPEO.

e. If results of the evaluations indicate the deg!h or ~~ent of ccackiog Qf !he bas~ m~tsil i§ i;irojeQ!ed !Q Qause loss of intended function i;irior to the end of the SPEO Engineering will gerform an evaluation to determine the extent of condition . extent of cause and the need for further follow-on actions through the Corrective Action Program (e.g .. additional insgections).

North Anna Power Station, Units 1 and 2 PageA-80 Supplement 4 Application for Subsequent License Renewal Appendix A - UFSAR Supplement

Seri al No.: 21 -280 Enclosure 2 Page 28 of 53 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Supplement 4 Appendix B - Aging Management Programs 82.1.1 7 Outdoor and La rge Atmospheric Metallic Storage Tanks Program Description Th e Outdoor and Large Atmospheric Metallic Storage Tanks program is an existing conditi on monitoring program that manages the effects of loss of material and cracking on the outside and inside surfaces of aboveground metallic tanks constructed on concrete or soil. Thi s program man ages aging effects associated with outdoor tanks with internal press ures approximat ing atmospheric pressure including the refueling water storag e tanks (RWSTs), refu eling water chemical addition tanks (CATs), casing cooling tanks (CCTs), and emergency conden sate storage tanks (ECSTs).

The program includes preventive measures to mitigate corrosion by protecting th e extern al surfaces of steel components consistent with standard industry practices . The RWSTs and CCTs are insulated and rest on a concrete mat/foundation covered with an oil sand cushion. Caulking is used at the concrete-component interface of the RWST s . Caulking is u se d at th e concrete-component interface of the CCTs, where there are no grout pads.

The CATs are insulated, and skirt supported. The insulation jacketing on th e RWSTs, CATs, and CCTs is corrugated aluminum (with a factory applied moisture barri er) with overlapped sea ms. The ECSTs are internally coated and protected by concrete missile barriers . Cau lking is used at the ECST vent and vacuum breaker penetration-concrete missile barrier interface.

The program manages loss of material on tank internal bare metal surfaces by conducting vi sua l inspections. Surface exams of external tank surfaces are conducted to detect cracki ng on the stainl ess steel tanks. Inspections of RWST and CCT caulking/sealants are supplemented by physical manipulation. UT examinations of the tanks' bottoms are conducted to ensure that design thickness and corrosion allowance criteria are met. A periodic sampling-based inspection is used on th e external surfaces of insulated tanks. Inspections not conducted in accordance with ASM E Code ,Section XI requirements are conducted in accordance with plant-specific proced ures that include inspection parameters such as lighting, distance, offset, and surface condition s. Additional inspections are conducted if one of the inspections does not meet acceptance criteria due to current or projected degradation (i.e., trending); however:

  • For inspections where only one tank of a material, environment, and aging effect was inspected, all tanks in that grouping are inspected.
  • For other sampling-based inspections there will be no fewer than five additiona l inspections for each inspection that did not meet acceptance criteria, or 20% of each applicable material, environment, and aging effect combination in spected, which ever is less. If any subsequent inspections do not meet acceptance criteria, an extent of condition and extent of cause analysis will be conducted to determine the furth e r exten t of inspections required. Additional samples will be inspected for any recurring degradation to ensure corrective actions address the associated causes. The additional inspections will PageB-116

Serial No.: 21-280 Enclosure 2 Page 29 of 53 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Supplem ent 4 Appendi x B - Agin g Management Programs include inspections of components with the same material, environment, and ag ing effect combination at the other unit.

The additional inspections will be completed within the interval (i.e. , 10-year inspection interval) in whi ch the original inspection was conducted or, if identified in the latter half of the current inspection interval, within the first half of the next inspection interval. These additional inspections conducted in th e next inspection interval cannot also be credited toward s th e number of inspections in the latter interval.

If any projected inspection results will not meet acceptance criteria prior to the next scheduled inspection, inspection frequencies are adjusted as determin ed by the Corrective Action Program.

However, for one-time inspections that do not meet acce pt ance cri teria, in spect ion s are subsequently conducted at least at 10-year inspection interval s.

Consistent with the recommendation s of th e Internal Coatings/Linings for In-Scope Piping, Piping Com ponents, Heat Exchangers, and Tanks program (B2.1.28), loss of coating integrity fo r the emergency condensate tanks is managed by thi s program. Internal surfaces of the RWSTs, CATs, and CCTs are managed by the One- Time Inspection program (B2 .1.20). Tank reinforced concrete foun dations and the reinforced concrete missile barri er of t he ECSTs are manag ed by t he Structures Monitoring program (B2.1.34).

NUREG-2191 Consistency The Outdoor and Large Atmospheric Metallic Storage Tanks program is an existing prog ram th at, followi ng enhancement, will be con sistent, with exception, to NUREG-2 191, Secti on XI.M 29, Outdoor and Large Atmospheric Metallic Storage Tanks.

Exception Summary The following program element(s) are affected:

Preventive Actions (Element 2); Pa rameters Monitored/Inspected (Element 3); Detection of Aging Effects (Element 4); Acceptance Criteria (Element 6); and Corrective Action s (Element 7)

1. NUREG-2191 specifies for outdoor tanks, that sealant or caulking is applied at the interface between the tank external surfa ce and concrete or earth en surface to mitigate corrosion of the ta nk by minimizing the amount of water and moisture penetrating the interface. The ECSTs do not use caulking or sealant at the concrete-component interface and therefore, do not require inspection of the caulking or sealant. The RWSTs and CCTs have mastic sealant installed on th e tank shell between th e insulation and th e tank con crete fo undation t o e nsure water-tightness and to prevent water from getting to the tank.

Page B-117

Serial No.: 21-280 Enclosure 2 Page 30 of 53 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Supplement 4 Appendix B - Aging Management Programs Justification for Exception:

The ECSTs are insulated from the outside atmosphere by two inches of expansion joint filler foam and surrounded by a two-foot-thick layer of reinforced concrete that provides missile protection.

The concrete missile shield and expansion joint filler foam configuration mitigates corrosion of the tank by minimizing water and moisture from penetrating inaccessible exterior tank surfaces.

The roofs and sides of the RWSTs, CA Ts, and CCTs are insulated and jacketed to mitigate corrosion of the tank by minimizing the amount of water and moisture on the exterior surfaces.

an additional preventive measure, the RWSTs and CCTs have mastic sealant installed on the tank shell between the insulation and the tank concrete foundation to ensure water-tightness and to prevent water from getting to the tank. The RWSTs, CA Ts, and CCTs have insulation jacketing installed with overlapping seams to provide a protective outer layer and to prevent water intrusion.

The mastic sealant installed on the tank shell between the insulation and the tank concrete foundation provides a boundary to mitigate corrosion of the tank bottom surface and the concrete foundation. In addition, the RWSTs and CCTs bottom surface is protected by an oil sand cushion and caulk at the interface between the tank external surface and the concrete surface. Periodic inspections normally performed on the caulk at the tank and concrete foundation will be performed on the mastic sealant installed on the tank shell between the insulation and the tank concrete foundation. An inspection of the caulk at the tank and concrete foundation interface will be included in the sample when the RWSTs and CCTs external insulation is removed and sampled for external surface visual examinations.

Detection of Aging Effects (Element 4)

2. NUREG-2191 recommends both visual and volumetric inspection techniques to identify degradation on carbon steel tank external surfaces, located outdoors on soil or concrete. The external surface of the ECSTs are encased in a two-foot-thick reinforced concrete missile shield with expansion joint filler foam between the external tank wall and the concrete missile shield. The concrete missile shield prevents visual and volumetric examinations of the external surface of the tank.

Justification for Exception:

The concrete missile shield and the expansion joint filler foam act as multiple barriers protecting the external tank surfaces. Initial License Renewal inspections of the Unit 1 and Unit 2 ECSTs external surfaces indicated differing inspection results and will be managed as follows during the subsequent period of extended operation.

Initial License Renewal inspections of the Unit 1 ECST external surfaces met the established acceptance criteria through-out the various inspection locations. One-time thickness measurements of a sample of the Unit 1 ECST interior wall will be performed prior to the subsequent period of extended operation. The samples will examine the Unit 1 ECST interior PageB-118

Serial No.: 21-280 Enclosu re 2 Page 31 of 53 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Supplement 4 Appendix B - Aging Management Programs vertical steel shell region from the bottom of the tank along the pipe penetration area, extend in g six feet vertically up from the tank, as this is a region potentially most susceptible to degradation .

The in spection results will be projected to the end of the subsequent period of exten ded operation to confirm the Unit 1 ECST intended functions will be mainta ined throu gho ut the subseque nt period of extended operation based on the projected rate of degradation. Aging degradation not meeting acceptance criteria will require periodic 10-year thi ckness measurements and a sample expansion along the leakage path consistent with the observed degradation.

Initial License Renewal inspections of the Unit 2 ECST external surfaces indicated varyin g aging resu lts. During September 2020, follow-up inspections of degraded areas identified pitting with wall thickn ess measurements of less than 0.1 inch in specific locations. Projected wall thi ckne ss measurements with less than 0.1 inch will be repaired prior to entering the subsequent period of extended operation. Periodic in spect ions of a minimum of five location s with the lowest wall thickn ess readings will be performed on a ten -year inspection frequen cy. Inspection re sults projected to the end of the subsequent period of extended operation that do not meet acceptance criteri a will require an extent of condition and extent of cause to determine the further extent of inspection and corrective actions.

The program also inspects the external bottom surfaces of the Unit 1 and 2 ECSTs that are exposed to a soil or concrete environment by performing volumetric exa mination thickn ess measurements. The gasket on th e ECST upper access concrete plug is replaced when ever it is removed to allow access for internal tank wall thickness measurements. The EGST vent and

  • .iaouum breaker oaulking is periodioally inspeoted during EGST missile shield inspeotionsThe cau lking at the ECST vent and vacuum breaker penetration-concrete missile barrier interface will be inspected on a 18-month frequency to confirm that the caulking is intact. The visual inspections will be supplemented with phys ical manipulation to detect any degradation . If there are any identified flaws, the caulking will be repaired or rep laced.

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

Preventive Actions (Element 2); Parameters Monitored/Inspected (Element 3); Detection of Aging Effects (Element 4); Acceptance Criteria (Element 6); and Corrective Action s (Element 7)

1. Procedures will be revised to require periodic visual inspections of th e RWSTs and CCTs be performed at each refueling outage to confirm that the mastic sealant at the RWSTs and CCTs insu lation and concrete found ation interface is intact. The visu al inspections of the sealant will be supplemented with physical manipulation to detect any degrad ation. If there are any identified flaws, the mastic sealant will be repaired or replaced, and follow-up examination of the tank's surfaces will be conducted if deemed appropriate. An inspection of the caulk at the Page B-119

Serial No.: 21-280 Page 32 of 53 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Supplement 4 Appendix B - Aging Management Programs tank and concrete foundation interface will be included in the sample when the RWSTs and CCTs external insulation is removed and the caulk will be sampled for external surface visual examinations ten years before the subsequent period of extended operation. Results will be forwarded to Engineering for evaluation and the need for addition al inspections will be determined based on projected corrosion rates.

2. Procedures will be revised to require the caulking at the ECST vent and vacuum breaker penetration-concrete missile barrier interface be inspected on a 18-month frequency to confirm that the caulking is intact. The visual inspections will be supplemented with physical manipulation to detect any degradation. If there are any identified flaws, the caulking will be repaired or replaced. (Added - Supplement 4)

Detection of Aging Effects (Element 4)

3. Procedures will be revised to require visual and surface examination of the exterior surfaces of the RWSTs, CATs, and CCTs be performed to identify any loss of material or crackin g. A minimum of either 25 one-square foot sections or 20% of the surface area of insulation will be required to be removed to permit inspection of the exterior surface of each tank. Th e procedure will specify that sample inspection points be distributed in such a way th at inspections occur near the bottoms, at points where structural supports, pipe, or instrument nozzles penetrate the insulation, and where water could collect such as on top of stiffening rings. If no unacceptable loss of material or cracking is observed, subseq uent external surface examinations of insulated tanks will inspect for indications of dam age to the jac keting, evidence of water intrusion through the insulation, or evidence of damage to the moisture barrier of tightly adhering insulation. (Renumbered - Supplement 4)
4. Unit 1 ECST: Procedures will be revised to require one-time thickness measurements of a sam ple of the Unit 1 ECST interior wall and tank bottom prior to the subsequent period of extended operation to assess potential degradation due to leakage identified from the missile shield into the pipe penetration area in the Auxiliary Feedwater Pump House. The samples will examine the ECSTs interior vertical steel shell region from th e bottom of the tank along th e pipe penetration area, extending six feet vertically up from the tank, as this is a region potentially most susceptible to external surface degradation . Tank bottom thickn es s measurements will also be performed. The inspection results will be projected to the end of th e subsequent period of extended operation to confirm the Unit 1 ECST intended function will be maintained throughout the subsequent period of extended operation based on the projected rate of degradation. Any degradation not meeting acceptance criteri a will require periodic 10-year thickness measurements and a sample expansion along the leakage path consistent with the observed degradation . (Renumbered - Supplement 4)

Unit 2 ECST: The Unit 2 ECST external vertical wall degradation projections to the end of th e subsequent period of extended operation that exceed less than 0.1 inch wall thickn ess will be PageB-120

Serial No.: 21 -280 Page 33 of 53 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Supplement 4 Appendix B - Aging Management Programs repaired prior to entering the subsequent period of extended operation . Periodic inspections of a minimum of five locations with the lowest wall thickness re adings will be performed on a ten-year inspection frequency. Inspection results projected to the end of the subsequent period of extended operation that do not meet acceptance criteria will require an extent of condition and extent of cause to determine the further extent of inspection and corrective actions. Tank bottom thickness measurements will also be performed. (Revised - Supplement 1)

5. Procedures will be revised to require volumetric examination thickness measurements of th e bottom of the RWSTs and CCTs be performed each 10-year period during the subsequent period of extended operation starting ten years before the subsequent period of extended operation. Results will be forwarded to Engineering for evaluation and the need for add itional in spections will be determined based on projected corr os ion rates. <Renumbered -

Supplement 4)

Corrective Action (Element 7)

6. A new procedure will be developed to specify that additional inspections be performed consistent with NUREG-2191. (Renumbered - Supplement 4)

If any inspections do not meet the acceptance criteria, additional inspections are conducted if on e of the inspections does not meet acceptance criteri a due to current or projecte d degradation (i.e., trending) .

a. For inspections where only one tank of a material, environment, and aging effect was inspected, all tanks in th at grouping are inspected.
b. For other sampling based inspections there will be no fewer than five additional inspections for each inspection that did not meet acceptance criteria, or 20% of each applicable material, environment, and aging effect combination inspected, whichever is less . If any subsequent inspections do not meet acceptance criteria, an exten t of condition and extent of cause analysis will be conducted to determine the further extent of inspections required . Additional samples will be inspected for any recurring degradation to ensure corrective actions appropriately address the associated causes. The additional inspections will include inspections of components with the same material, environment, and aging effect combination at the other unit.

The additional inspections will be completed within the interval (i. e. , 10-year inspection interval) in which the original inspection was conducted or, if identified in the latter half of the current inspection interval, within the first half of the next inspection interval. These additional inspections conducted in the next inspection interval cannot also be credited towards the number of inspections in the latter interval.

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Serial No.: 21-280 Page 34 of 53 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Supplement 4 Appendix B - Aging Management Programs 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. However, for one-time inspections that do not meet acceptance criteria, inspections are subsequently conducted at least at 10-year inspection intervals.

Operating Experience Summary The following examples of operating experience provide objective evidence that the Outdoor and Large Atmospheric Metallic Storage 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 April 2010, an internal inspection of the Unit 2 RWST was performed using Low Frequency Electromagnetic Technique (LFET) to scan the perimeter of the bottom plates of the RWST, including the weir, allowing adequate assessment of degradation due to pitting. In addition, a scan was performed along the welds in the inspection area. Ultrasonic testing (UT) examinations were performed on the tank bottom. Two indications were identified with the LFET. Both indications were visible topside dents, with UT readings being greater than the nominal design thickness. The inspection concluded that there was no indication of age-related degradation on the Unit 2 RWST bottom.
2. In September 2010, UT examinations were performed on bottom of the Unit 1 CAT in the filled condition, in a two-inch wide ring around the drain pipe. The thickness measurements of the tank bottom exceeded the acceptance criteria. There was no indication of material loss.
3. In September 2013, during the Unit 1 Fall 2013 refueling outage an internal inspection of the Unit 1 RWST was performed in the filled condition. UT examinations of the tank bottom resulted in thicknesses above the nominal design thickness. Internal structures (e.g., piping) were in good condition and no visible pitting of the internal stainless-steel surfaces was observed. Floor plate, internal shell plate and nozzle welds were identified to be in good condition. Visual inspection of the tank did not indicate any adverse conditions or areas of concern. Based on the data collected from this inspection, no measurable corrosion was noted and the readings were at or above the design nominal thickness. As such, no meaningful corrosion rate can be established at this time. Based on no corrosion being found, API Standard 653, "Tank Inspection, Repair, Alteration, and Reconstruction," calculations show a 20-year inspection interval for this tank.
4. In May 2015, a work order was initiated to locate and resolve rain water leakage between the missile shield and outer tank wall at the Unit 1 ECST. Rain water leakage between the concrete missile shield and the outer surface of Unit 1 and Unit 2 ECSTs has been a chronic condition. The rain water collects between the two surfaces and leaks out of the piping PageB-122

Serial No.: 21-280 Page 35 of 53 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Supplement 4 Appendix B - Aging Management Programs penetrations and onto the floor of the Motor-driven Auxiliary Feedwater (MDAFW) Pum p House. Fresh caulk was applied to three conduit penetrations, vent base plates, and the perimeter of vents with missile shields, but did not resolve th e leakag e issue. Another wo rk order was initiated to identify the source of rain water leakage at th e tank and repair the leakage. Piping penetration cover plates were removed to allow in spection of the area between the missile shield and outer tank wall. A small amount of water was found leakin g from the penetration area. New sealanUgasket was applied, and the penetration cover plates were reinstalled. There have been no issues of water leakage at the Unit 1 ECST penetration area since the repair was performed.

5. 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 conclu sion reached wa s that performance deficiencies or learning opportunities were identified fo r the Tank Inspection Activities AMA (UFSAR Section 18.1.3). Engineering was tasked with an assi gnment to consider obtaining more wall/roof shell data on the Unit 1 ECST. An internal inspection was performed consisting of a visual inspection of the interior coating, UT examinations were performed on the tank bottom, wall and roof, and LFET on the bottom and wall. The inspection identified 23 minor coating indications. Coating degradation and minor corrosion were also observed on the angle iron forming the roof/wall joint. Degraded areas identified were cleaned and recoated. UT examination was performed on the tank bottom and on a quarter section of the roof at the roof/wall joint. LFET was performed on the tank bottom and the tank walls . Data obtained on the bottom, wall, and roof was satisfactory showing no indications of significant corrosion or degradation .
6. In July 2016, a small puddle of dark colored water was observed on the bottom of the Unit 2 MDAFW Pump House directly under the MDAFW pump suction isolation valves. The leakage appeared to be coming from the caulked seal where th e AFW suction pipes penetrate the missile shield, indicating water intrusion between the tank and the missile shield . The leakage wa s not active; but staining on the wall indicated the leakage was coming from th e pipe penetrations under the MDAFW pump suction isolation valves. During the Spring 2016 Unit 2 refueling outage, the upper manway was inspected for water intrusion and found no damage or leaks. The manway was removed and replaced with a new gasket.

Engineering developed and implemented an investigation plan to identify any water intrusion paths contributing to the leakage that included:

a. Replacement of the roof over the Unit 2 MDAFW Pump House, and
b. while the roof was removed, a walkdown was performed to inspect the 2-inch rattle space between the Unit 2 ECST and missile shield as well as any other potential areas corresponding to the leak, and PageB-123

Serial No.: 21-280 Page 36 of 53 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Supplem ent 4 Appendix B - Agin g Management Programs

c. after the new roof was installed, Security or Operations personnel checked (on normal rounds) to see if there was still a leak.

Sin ce the plan was implemented, there has been no evidence of leakage into th e Un it 2 MDAFW Pump House.

7. In November 2016, external inspection and insulation repl acement was performed on th e Unit 1 RWST. Up until that time, in order to determine if any aging degradation was occurring on the exterior of insulated stainless steel tanks, insulation in selected areas was removed and the exterior was visually inspected for loss of material or cracking . Also, in March 2009, the insulation at the top of the Unit 1 RWST was observed to be degrading and falling off. A subsequent design change was developed to define th e tank inspection activities, remove insulation from the Unit 1 RWST to perform external tank inspections, replace the insul ation with like for like materials, and apply a new layer of weatherproofing protection. Grey aluminum corrugated flashing with a factory applied interior polyfilm moisture barrier covers the insulation. The grey aluminum corrugated flashing vertical seam overlaps are four inches and horizontal seam overlaps are three inches and are held in place with stainless steel bands. Longitudinal overlaps are secured with stainless steel sheet metal screw s. The inspections concluded that there were no adverse conditions identified.
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 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 th e above items were sati sfied .
9. 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 conclu sion re ached was that an area for improvement or enhancement was identified for th e Tank Inspection Activities AMA (UFSAR Section 18.1.3). Results of the assessment indicated that inspections performed for some tanks under the Tank Inspection Activities AMA were not performed in accordance with the UFSAR description. The UFSAR states, "visual inspections of the internal and external surfaces will be performed . Volumetric examination s will be performed on tanks founded on soil or buried." However, in accordance with the Tank Inspection Activities AMA, volumetric examinations were performed on some tanks in lieu of PageB-124

Serial No.: 21-280 Enclosure 2 Page 37 of 53 North Anna Power Station , Units 1 and 2 Application for Subsequent License Renewal Supplement 4 Appendix B - Aging Management Programs internal inspections due to accessibility. In May 2017, Engineering was tasked to evaluate th e deficiency and initiate any document changes or additional inspections that may be req uired.

Subsequently, UFSAR Section 18 .1.3, Tank Inspection Activities AMA, was updated to address the use of UT examinations in lieu of visual examinations for some tanks .

10. In April 2019, an effectiveness review was performed on the Tank Inspection Activities AMA (U FSAR Section 18 .1.3) th at includes the RWSTS, CATs, CCTs, and ECSTs am ong its inspection activities. The AMA was evaluated against the performance criteria identified in NEI 14- 12, "Aging Management Program Effectiveness ." No gaps were identifi ed by t he effectiveness review.

The above examples of operating experience provides objective evidence that the Outdoor and Large Atmospheric Metallic Storage Tanks program includes activities to perform visual inspections of tank internal bare metal surfaces, surface examination of external tank surfaces, and UT examinations of tank bottoms to identify cracking or loss of material for aboveground metallic tanks within the scope of subsequent license renewal, and to initiate corrective actions. Occu rrences identified under the Outdoor and Large Atmospheric Metallic Storage Tanks program are evalu ated 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 action s for additional ins pe ction s, re-evaluation, repairs, or replacem ents 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 pl ant-specific and industry operating experience. There is reasonable assurance that the continued implementation of the Outdoor and Large Atmospheric Metallic Storage Tanks program ,

following enhancement, will effectively manage aging prior to a loss of intended function .

Conclusion The continued implementation of the Outdoor and Large Atmospheric Metallic Storage 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 basi s during the subsequent period of extend ed operation.

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Serial No.: 21-280 Enclosure 2 Page 38 of 53 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Supplem ent 4 Appendix B -Aging Management Programs 82.1. 21 Selective Leach ing Program Description The Selective Leaching program is a new condition monitoring program that will manage loss of material of the susceptible materials located in a potentially aggressive environment. The materials of con struction for these components may include gray cast iron, ductile iron, and cop per alloys (greater than 15% zinc).

The SoJoo#ve Loaohing prograR'l \*.<<ill also R'lanage oraoking due to eyeli o loading of oeR'lentitious lined gray east iron piping in a soil en*.iironR'lent. Periodie inspeetions of oeR'lentitious lined gray east iron piping in a soil environR'lent will be perforR'led as a separate saR'lple population and inolude inspeetions to deteot seleetive leashing of oeR'lentitious lined gray east iron piping .

A one-time inspection of components exposed to closed-cycle cooling water or treated water environments will be conducted when plant-specific operating experience has not revealed selective leaching in these environments. Opportunistic and periodic inspections will be conducted for raw water, waste water, soil, and groundwater environments, and for closed-cycle cooling water or treated water environments when plant specific operating experience has revealed selective leaching in these environments. A sample of 3% of the population or a maximum of ten components per population at each unit will be visually and mechanically (gray cast iron and du ctil e iron components) inspected. If the inspection conducted for ductile iron in the 10-year period prior to a subsequent period of extended operation (i.e., the initial inspection) meets acceptance crite ria, periodic inspections do not need to be conducted during th e subsequent period of exten ded operation for ductile iron.

Periodic destructive examinations of components for physical properties (i.e., degree of dealloying, through-wall thickness, and chemical composition) will be conducted for components exposed to raw water, waste water, soil, and groundwater environments or for closed-cycle cooling water or treated water environments when plant specific operating experience has revealed se lective leachin g in these environments. For sample populations with greater than 35 su sceptibl e compon ents at each unit, two destructive examinations will be performed for that population. In addition , for sample populations with less than 35 susceptible compon ents at each unit, on e destructive examination will be performed for that population. For opportunistic an d periodi c inspections, the number of visual and mechanical inspections may be reduced by two for each compon ent that is destructively examined beyond the minimum number of destructive exa minations recomm ended for each sample population. For one-time inspections, the number of vi sual and mechanical inspections may be reduced by two for each component that is destructively examined for each sample population.

For two-unit sites the periodic visu al and mechanical inspections can be reduced from ten to eight because the operating conditions and history at each unit are sufficiently similar (e.g., flowrate, Page 8 -151

Serial No.: 21-280 Enclosure 2 Page 39 of 53 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Supplement 4 Appendix B

  • Aging Management Programs chemistry, temperature, excursions) such that aging effects are not occurring differently between the units. Past power up-rates were implemented for both units at approximately the same time.

Historically, water chemistry conditions between the two units have been very similar. The raw water source for both units is Lake Anna. Emergency diesel generator runs are managed to equalize total run times among the diesels, so as to equalize wear and aging. The soil corrosivity analysis performed on soil samples was consistent between the two units. The soil analysis demonstrated that the soil environment was not evaluated as severely corrosive or corrosive.

Operating experience for each unit demonstrates no significant difference in aging effects of systems in the scope of this program between the two units.

Inspections will be performed by personnel qualified in accordance with procedures and programs to perform the specified task. Inspections within the scope of the ASME Code will follow procedures consistent with the ASME Code. Non-ASME Code inspection procedures will include requirements for items such as lighting, distance, offset, and surface conditions.

Inspection results will be 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.

The acceptance criteria are:

(a) for copper-based alloys, no noticeable change in color from the normal yellow color to the reddish copper color or green copper oxide; (b) for gray cast iron and ductile iron, the absence of a surface layer that can be easily removed by chipping or scraping or identified in the destructive examinations, (c) the presence of no more than a superficial layer of dealloying, as determined by removal of the dealloyed material by mechanical removal, and (d) the components meet system design requirements such as minimum wall thickness, when extended to the end of the subsequent period of extended operation.

When the acceptance criteria are not met such that it is determined that the affected component should be replaced prior to the end of the subsequent period of extended operation, additional inspections will be performed. If subsequent inspections do not meet acceptance criteria, an extent of condition and extent of cause analysis will be conducted to determine the further extent of inspections. Extent of condition and extent of cause analysis will include evaluation of difficult-to-access surfaces if unacceptable inspection findings occur within the same material environment population. The timing of the additional inspections is based on the severity of the degradation identified and is commensurate with the potential for loss of intended function.

NUREG-2191 Consistency The Selective Leaching program is a new program that, when implemented, will be consistent, with NUREG-2191,Section XI.M33, Selective Leaching.

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Serial No.: 21-280 Page 40 of 53 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Supplement 4 Appendix B - Aging Management Programs Exception Summary None Enhancements None Operating Experience Summary The following examples of operating experience provide objective evidence that the Selective Leaching program 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 December 2015, a buried fire protection supply isolation valve was leaking by its closed seat. The valve had a metallurgical analysis performed which identified some isolated locations of graphitic corrosion on the interior and exterior of the valve body. The corrosion had minimal impact on the valve body thickness. In March of 2016, the six-inch cast-iron valve was replaced with a new valve fabricated from ductile iron body, which has improved corrosion resistance.
2. In June 2020, a review of 2001 through 2020 operational experience for buried and underground piping susceptible to selective leaching within the scope of subsequent license renewal was performed and did not identify any loss of intended function due to selective leaching. Inspection reports did not identify internal coating failures. In addition, isolated areas of external surface degradation with no pitting or gross corrosion were observed. Metallurgical analysis performed on removed piping indicated the internal cementitious coating was intact, showing only a fine, craze surface cracking in some areas. Opportunistic or scheduled inspections noted below indicated the piping was in good condition.
  • In October 2001 a rupture of fire protection main loop piping occurred. A metallurgical analysis determined that the failure most likely occurred as a result of a low cycle fatigue process that originated at a pre-existing manufacturing flaw in the pipe. The ruptured piping was replaced.
  • In August 2011 opportunistic inspections were performed on the southside section of the fire protection main yard loop piping during system modifications. There were no signs of degradation.
  • In September 2011 opportunistic inspection of NANIC fire protection piping during modifications for North Anna 3 site separation activities was performed. The cast iron piping was in satisfactory condition, no repairs required.

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Serial No.: 21-280 Enclosure 2 Page 41 of 53 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Supplement 4 Appendix B -Aging Management Programs

  • In December 2011 opportunistic inspection of fire protection piping outside the southeast corner of the protected area during modifications for North Anna 3 site separation activities was performed. The cast iron piping was in satisfactory condition, no repairs required.
  • In September 2012 opportunistic inspection of fire protection piping during modification for the Unit 3 tie-in to main fire loop was performed. The external coating was found to be covering the pipe and not degraded by the condition. There was no bare metal observed and no signs of corrosion or pitting. The internal lining was found to be fully intact.
  • In November 2012 opportunistic inspection of the fire protection pipe replacement design change, opportunistic inspection of the cast iron fire protection main loop to the auxiliary building room was performed. There were small areas of external coating degradation, no pitting was observed, and the internal mortar lining was found to be fully intact.

Opportunistic inspection was also performed on a southside section of the cast iron fire protection main yard loop piping. The external coating was in good condition with no damage. The cast iron piping external surfaces did not show evidence of pitting or corrosion. The internal mortar lining was found to be fully intact and protecting the pipe.

  • In May 2013, following replacement of cast iron fire main piping segments with ductile iron fire main piping, the scope of the replacement project was reduced to areas 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 external coating was in good condition. There was no corrosion identified on the external surface. The internal cementitious lining was determined to be in good condition, fully intact, and protecting the pipe in these cases.
  • In August 2015, cast iron North Yard fire protection piping from the main fire loop to the Unit 2 Turbine Building was excavated for a buried pipe inspection. The cast iron fire protection piping is internally lined with a cementitious coating and externally coated with a coal tar epoxy. Inspection required removal of a portion of the exterior coating on each pipe for visual and wall thickness examinations. Coatings were in good condition. Visual and wall thickness examinations indicated minor corrosion and pitting in a few places.

There was no significant loss of material or minimum wall thickness identified. The piping was recoated prior to backfill.

The above examples of operating experience provide objective evidence that the Selective Leaching program will include activities to perform visual and mechanical inspections or destructive examinations to identify loss of material for piping, valve bodies and bonnets, pump casings, and heat exchanger components within the scope of subsequent license renewal, and to initiate corrective actions. Occurrences identified under the Selective Leaching program will be evaluated to ensure there is no significant impact to the safe operation of the plant and corrective actions will PageB-154

Serial No.: 21-280 Page 42 of 53 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Supplement 4 Appendix B - Aging Management Programs be taken to prevent recurrence. Guidance or corrective actions for additional inspections, re-evaluation, repairs, or replacements will be provided for locations where aging effects are found.

The program will be 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 implementation of the Selective Leaching program will effectively manage aging prior to a loss of intended function. Industry and plant specific operating experience will be evaluated in the development and implementation of this program.

Conclusion The implementation of the Selective Leaching program will provide reasonable assurance that aging effects will be managed such that the components within the scope of this program will continue to perform their intended functions consistent with the current licensing basis during the subsequent period of extended operation.

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Serial No.: 21-280 Enclosure 2 Page 43 of 53 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Supplement 4 Appendix B -Aging Management Programs 82.1 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 SP0 169 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.: 21-280 Enclosure 2 Page 44 of 53 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Supplement 4 Appendix B - Aging Management Program s 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 th e lo ss of material rate is extrapolated to the end of the subsequent period of extended operation an increase in the sample size is conducted.

The Buried and Underground Piping and Tanks program conducts periodic and opportunistic visu al inspections of the buried fire protection system piping and compon ents that will fa cilitate examinations performed by the Selective Leaching program (B2.1 .2 1) to manage loss of material due to se lective leaching for applicable materials in soil environments. A minim um of si x excavations will be required to be conducted at each unit in the 10-year period prior to the subsequent period of extended operation (SPEO) and periodically in each 10-year period during the SPEOand fii.1e of the inspestions at eash unit will destrustii,ely e>mmine the buried gray east iron fire protestion piping . Consistent with NUREG-2191 Section XI.M41, Buried and Undergroun d 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. Add iti ona ll y, NUREG -2191 Section XI.M33 ,

Selective Leaching program, destructive examinations will al-se be conducted on a one-foot length of fire protection system piping or a different compo nent type fro m each discrete excavati on location (six/unit) a one foot length (minimum) piping sestion from eash dissrete e*sa*,ation losation (fivetunit) to inspect for tRe loss of material due to selective leaching. Five of the inspections will be conducted on one-foot lengths of fire protection piping and the sixth inspection will be conducted on either a one-foot length of piping from the fire protection system or a different component type (e.g.,

hydrant) from the fire protection system, whi chever was removed during the sixth excavation.

Sections of buried gray cast iron fire protection piping and piping components that are removed for destructive examination will be replaced with a material better suited for the service conditions and environmentsdustile iron piping and piping somponents. The Buried and Underground Piping and Tanks program is implemented as a Fleet program at Dominion. The Fleet program req uirements 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 e xtend e d operation, as required by 10 CFR 54.21(a)(3) (ADAMS Acces s ion No .

ML19360A020).(Revised - Supplement 4)

Inspections for detection and evaluation of cracking due to cycli c load ing on gray cast iron fire protection piping will also be conducted by the Buried and Underground Piping and Tanks program.

Consistent with the requ irements of NUREG-2191 Section XI. M41, Buried and Underground Piping PageB-189

Serial No.: 21-280 Enclosure 2 Page 45 of 53 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Supplement 4 Appendix B - Aging Management Programs and Tanks program, ten-foot pipe lengths will be excavated, as noted above, for the gray cast iron fire protection piping samples inspected for cracking due to cyclic load ing . A minimum of five pipe excavations for each unit will be conducted in the 10-year period prior to the subsequent period of extended operation (SPEO) and periodically in each 10-year period during the SPEO. The quantity of inspections was selected for consistency with the guidance of NUREG-2191,Section XI.M41, Buried Pipe and Underground Piping and Tanks Program, Element 4, and Table XI.M41-2 for Preventive Action Category F.

Visual (VT), magnetic particle (MT), and radiographic (RT) nondestructive examination (NOE) methods will be used on the excavated gray cast iron fire protection piping to inspect for cracking due to cyclic loading . The NOE examination results will be evaluated by a Level II or Ill examiner qualified in accordance with ASME Code,Section XI requirements to identify the presence of cracking . If cracking is not identified using the NOE techniques, then a one-foot axial piece of the fire protection piping will still be destructively examined for the loss of material due to selective leaching as required by NUREG-2191 Section XI.M33, Selective Leaching program . If cracking is identified, then a one-foot axial piece of the fire protection piping sample will be selected for further examination for cracking due to cyclic load ing and the loss of material due to selective leaching using destructive examination methods. The one-foot axial piece of fire protection piping will be selected from a bounding location based on the crack size and characterization as determined by a NOE Level II or Il l examiner.

VT examination of the internal cementitious lining will be performed to identify and record any areas of lining damage that may be an indicator of degradation to the internal surface of the pipe. MT examination of the inside diameter surface of the removed piping wi ll be performed to detect indications of surface cracking . The cementitious lining will be removed, and the surface prepped to an acceptable condition to perform the MT examination. The lining removal and surface preparation techniques will ensure no detrimental impact on the final surface cond ition for the NOE being performed. Particular attention will be applied to VT identified areas of lining damage during the MT examination . Linear surface indications representing potentia l cracking, identified with the MT method, will be validated using RT examination techniques.

Similarly, MT examination of the external surface of the removed piping will be performed to detect indications of surface cracking . The bitumastic coating will be removed, and the surface prepped to an acceptable condition to perform the MT examination. The coating removal and surface preparation techniques will ensure no detrimental impact on the fina l surface condition for the NOE being performed . Linear surface indications representing potential cracking, identified with the MT method, will be validated using RT examination techniques.

The MT method is sensitive to surface discontinuities as well as other surface imperfections that may not be associated with cracking indications. The RT examination technique provides a full volume examination of the pipe wall . For th is reason, RT will be applied to validate potential crack Page B-190

Serial No.: 21 -280 Enclosure 2 Page 46 of 53 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Supplement 4 Appendix B -Aging Management Programs indications detected with MT. Areas identified by RT examination as containing potential surface cracking indications wjll be recorded, and the bounding crack location selected for further metallurgical analysis.

The one-foot axial piece of fire protection piping selected from the bounding location based on the crack size and characterization as determined by a NOE Level II or Ill examiner will be further inspected by destructive examination to establish cause . If a crack is determined to be the result of a manufacturing flaw, and not the result of aging, then the results will be documented in a metallurgical analysis report with no further actions required . If the cracking is determined to a be due to cyclic loading through the destructive examination evaluation, then a crack growth evaluation and flaw stability evaluation will be performed based on the predicted crack lengths at the end of the SPEO . If results of the evaluations indicate the depth or extent of cracking of the base metal is projected to cause loss of intended function prior to the end of the SPEO, Engineering will perform an evaluation to determine the extent of condition, extent of cause, and the need for further follow-on actions through the Corrective Action Program (e.g., additional inspections} .

Dominion Energy is an active participant in industry working groups that are investigating new and improved NOE techniques . As NOE technology evolves, Dominion will continue to monitor any relevant improvements, particularly those related to examination of cast iron, for potential incorporation into Dominion Fleet procedures. (Added - Supplement 4}

NUREG-2191 Consistency 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 Underg roun d 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 th e scope of SLR during the next soil survey within 1O years prior to entering the subsequent period of operation.

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Serial No.: 21-280 Page 47 of 53 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Supplement 4 Appendix B -Aging Management Programs 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 SP0 169-2007 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 toss 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 PageB-192

Serial No.: 21-280 Page 48 of 53 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Supplem ent 4 Appendix B -Aging Management Programs have verified that the resistivity did not fall outside of the range being credited (e. g., fo r 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 to inspect for loss of material due to selective leaching in and fi¥e of the inspeotions at eaoh unit de struoti*.iely examine tho buried gray cast iron fire protection piping and piping components . The inspections will be conducted in the 10-year period prior to the subsequent period of extended operation and in each 10-year period during the subsequent period of extended operation. A ten-foot pipe length will be excavated for each buried gray ca st iron fire protection piping sample and the external surfaces inspected for blistering, cracking ,

hardening or loss of strength, and loss of material. Additionally. NUREG-2191 Section XI.M33 Selective Leaching program destructive examinations will ~ be conducted on a one-foot length of fire protection system piping or a different component type from each discrete excavation location (six/unit)a one foot length (minimum) piping seotion from eaoh disorete exoa¥ation looation (fi¥e~unit) to inspect for loss of material due to selective leaching. Five of the inspections will be conducted on a one-foot length of fire protection piping and the sixth inspection will be conducted on either a one-foot length of piping from the fire protection system or a different component type (e .g., hydrant) from the fire protection system . The sel ection of inspection locations for buried gray cast iron fire protection piping and piping components will consider the following criteria: (Added - Supplement 3) (Revised -

Supplement 4)

  • 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 PageB-193

Serial No.: 21-280 Page 49 of 53 North Anna Power Station, Units 1 and 2 Application for Subsequent License Re newal Supplement 4 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 compon ents)
  • 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
6. Procedures will be revised to require five excavated piping samples at each unit be inspected (internally and externally) for cracking due to cyclic loading. The inspections will be conducted in the 10-year period prior to the subsequent period of extended operation (SPEO) and in each 10-year period during the SPEO as follows : (Added - Supplement 4)
a. A ten-foot pipe length of buried gray cast iron fire protection piping will be excavated for each inspection.
b. Visual (VT) and magnetic particle (MT) examinations will be conducted on the 10-foot buried gray cast iron fire protection piping samples. The radiographic (RT) nondestructive examination (NOE) method will be applied to areas that have potential surface cracking identified using the MT method.
c. Examination results will be evaluated by a Level II or Ill examiner qualified to ASME Code,Section XI and the following performed. as applicable:
  • If there is no cracking identified using the NOE techniques, then a one-foot axial piece of the fire protection piping sample will still be removed and destructively examined to inspect for the loss of material due to selective leaching as required by NUREG-2191 Section XI.M33, Selective Leaching program (see Enhancement 5).
  • If cracking is identified, then a bounding one-foot axial section of the fire protection piping sample will be selected based on the crack size and characterizat ion determined by a qualified NOE Level II or Ill examiner and further destructive examination conducted to identify cracking due to cyclic loading . The destructive examination of the one-foot axial section will also be inspected for the loss of material due to selective leaching (see Enhancement 5).
d. If results of the destructive examination inspections determine the cracking is due to cyclic loading, then Engineering will perform a crack growth evaluation and a flaw stability evaluation based on the predicted crack lengths at the end of the SPEO.
e. If results of the evaluations indicate the depth or extent of cracking of the base metal is projected to cause loss of intended function prior to the end of the SPEO, Engineering will PageB-194

Serial No.: 21-280 Enclosu re 2 Page 50 of 53 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Supplement 4 Appendix B - Aging Management Programs perform an evaluation to determine the extent of condition, extent of cause, and the need for further fo ll ow-on actions through the Corrective Action Program (e .g., additiona l inspections}.

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 ag ing 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 th at did not specify the maximum heat input. The high heat input applied during welding to thi s 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 th e 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.

3. In June 2010, stainless steel and carbon steel piping associated with the Unit 1 chemical addition tank was excavated and inspected. The stainless steel piping had no indications of pitting or corrosion. The carbon steel piping had deg raded coating with general surface corrosion.
4. In January 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 th ere were no signs of corrosion or degradation. Ultrasonic test results were reviewed by Engineering and found to be acceptable minimum wall thickness. The disbanded coating was repaired.
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 repa ired.
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 replacem ent with ductile iron wa s PageB-195

Serial No.: 21-280 Page 51 of 53 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Supplement 4 Appendix 8 - Aging Management Programs 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.
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 PageB-196

Serial No.: 21-280 Page 52 of 53 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Supplement 4 Appendix B - Aging Management Programs 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 pi ping 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 "I nstant 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 cau sed 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 the outside diameter of the pipe due to coating I 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 the SBO EOG room. The buried fuel oil lines in that scope have been replaced with stainless steel and placed in service.

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 were consistent with the licensing basis and bases documents
  • Procedures contained a reference to conduct an aging management review prior to revising PageB-197

Serial No.: 21-280 Enclosure 2 Page 53 of 53 North Anna Power Station, Units 1 and 2 Application for Subsequent License Renewal Supplement 4 Appendix B - Aging Management Programs

  • 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 concl usion 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 visu al inspections to identify blistering, cracking, hardening or loss of strength, and loss of material fo r 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 fo r additional inspections, re-evaluation, repairs, or replacements is provided for locations where ag ing 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 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 , fo llowing 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 fu nction s consistent with the current licensing basis during the subsequent period of extended operation.

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