ML20140A239

ASME Section XI Inservicee Inspection Program Proposed Inservice Inspection Alternative N1-15-NDE-002

ML20140A239
Person / Time
Site:	North Anna
Issue date:	05/18/2020
From:	Mark D. Sartain Virginia Electric & Power Co (VEPCO)
To:	Document Control Desk, Office of Nuclear Reactor Regulation
Shared Package
ML20140A238	List: ML20140A239
References
19-156, N1-15-NDE-002
Download: ML20140A239 (121)

Text

PROPRIETARY INFORMATION -WITHHOLD UNDER 10 CFR 2.390 VIRGINIA ELECTRIC AND POWER COMPANY RICHMOND, VIRGINIA 23261 May 18, 2020 U.S. Nuclear Regulatory Commission Serial No.: 19-156 Attention: Document Control Desk NRA/ENC: RO Washington, DC 20555 Docket No.: 50-338 License No.: NPF-4 VIRGINIA ELECTRIC AND POWER COMPANY (DOMINION ENERGY VIRGINIA)

NORTH ANNA POWER STATION UNIT 1 ASME SECTION XI INSERVICE INSPECTION PROGRAM PROPOSED INSERVICE INSPECTION ALTERNATIVE N1-15-NDE-002 Pursuant to 10 CFR 50.55a(z)(1 ), Virginia Electric and Power Company (Dominion Energy Virginia) proposes an alternative to the requirements of American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel (BPV) Code,Section XI.

Specifically, IWB-2420(b), Successive Inspections, requires VT-3 visual examination of the areas containing flaws identified in the fourth ISi interval, Third Period, B-N-1 examination, during the next three inspection periods. While B-N-1 examination is normally performed each period, only areas made accessible by removal of components are examined. Alternative N1-15-NDE-002, included in Attachment 1, requests relief from the frequency requirements for degraded cladding made accessible by the removal of the core barrel, which is normally removed once per ten-year inspection interval.

ETE-NA-2018-0013, "Engineering Evaluation of Unit 1 Reactor Vessel Cladding Indications," provided in Attachment 2, describes the technical basis for the requested alternative.

Supporting calculation C-4523-00-02-P, "North Anna Power Station Unit 1 RPV Corrosion Feature Evaluation/' provided in Attachment 3 contains information proprietary to Dominion Engineering. An affidavit signed by Dominion Engineering, the owner of the information, is included in Attachment 6 detailing the basis on which the information may be withheld from public disclosure by the Nuclear Regulatory Commission (NRC) and addresses with specificity the considerations listed in (b)(4) of 10 CFR 2.390.

Accordingly, it is respectfully requested that the information which is proprietary to Dominion Engineering be withheld from public disclosure in accordance with 10 CFR 2.390. A non-proprietary version of the calculation is provided in Attachment 4.

The calculation provided in Attachment 5, C-4523-00-01-NP, "Evaluation of Potential Low-Alloy Steel Corrosion at Cladding Defects of NAPS1 Reactor Vessel," also supports th is request. contains information that is being withheld from public disclosure under 10 CFR 2.390. Upon separation from Attachment 3, this letter is decontrolled.

Serial No.: 19-156 Docket No.: 50-338 Page 2 of 3 Pursuant to 10 CFR 50.55a(z), the proposed alternative requires NRC review and approval before implementation. Dominion Energy Virginia requests NRC approval of this request by March 1, 2021 to support the next scheduled NAPS1 refueling outage.

If you have any questions or require additional information, please contact Erica Combs at (804)-273-3386.

Sincerely, Mark D. Sartain Vice President - Nuclear Engineering and Fleet Support Attachments:

1. Relief Request N 1-15-NDE-002, Reactor Vessel Cladding Examination Extension

2. Engineering Evaluation ETE-NA-2018-0013, "Engineering Evaluation of Unit 1 Reactor Vessel Cladding Indications," Revision 1. Attachments 1-4. [Non-Proprietary]

3. Calculation C-4523-00-02-P, "North Anna Power Station Unit 1 RPV Corrosion Feature Evaluation," Revision 0. [Proprietary]

4. Calculation C-4523-00-02-NP, "North Anna Power Station Unit 1 RPV Corrosion Feature Evaluation," Revision 0. [Non-Proprietary]

5. Calculation C-4523-00-01-NP, "Evaluation of Potential Low-Alloy Steel Corrosion at Cladding Defects of NAPS1 Reactor Vessel," Revision 0. [Non-Proprietary]

6. Dominion Engineering Affidavit Pursuant to 10 CFR 2.390 Commitments made in this letter: None

Serial No.: 19-156 Docket No.: 50-338 Page 3 of 3 cc: Regional Administrator, Region II (w/o attachments)

U.S. Nuclear Regulatory Commission Marquis One Tower 245 Peachtree Center Ave., NE, Suite 1200 Atlanta, Georgia 30303-1257 Mr. G. Edward Miller NRC Senior Project Manager - North Anna Power Station U.S. Nuclear Regulatory Commission One White Flint North Mail Stop 09 E-3 11555 Rockville Pike Rockville, Maryland 20852-2738 Mr. Marcus Harris (w/o attachments)

Old Dominion Electric Cooperative Innsbrook Corporate Center 4201 Dominion Blvd.

Suite 300 Glen Allen, Virginia 23060 NRC Senior Resident Inspector (w/o attachments)

North Anna Power Station Mr. Vaughn Thomas NRC Project Manager - Surry Power Station U. S. Nuclear Regulatory Commission One White Flint North Mail Stop 04 F-12 11555 Rockville Pike Rockville, Maryland 20852-2738

Serial No.: 19-156 Attachment 1 Relief Request N1-15-NDE-002 Reactor Vessel Cladding Examination Extension Virginia Electric and Power Company (Dominion Energy Virginia)

North Anna Power Station Unit 1

Serial No.: 19-156 Docket No.: 50-338 RPV Internals Successive Examinations Page 1 of 9 North Anna Power Station Unit 1 10 CFR 50.55a Request Relief Request N1-15-NDE-002 Proposed Alternative in Accordance with 10 CFR 50.55a(z)(1)

--Alternative Provides Acceptable Level of Quality or Safety--

1. American Society of Mechanical Engineers (ASME} Code Components Affected The affected component is the North Anna Power Station Unit 1 (NAPS1) reactor pressure vessel (RPV) interior surface.

Vessel Interior B-N-1 813.10

2. Applicable Code Edition and Addenda

The applicable code for the NAPS1 fifth 10-year inservice inspection (ISi) interval and ISi Program is the ASME Boiler and Pressure Vessel Code (BPV)Section XI, 2013 Edition with no Addenda [Reference 1]. The NAPS1 fifth interval started May 1, 2019 and ends April 30, 2029.

3. Applicable Code Requirements

IWB-2411, Inspection Program, requires visual examination of accessible areas of the interior of the RPV made accessible for examination by removal of components during normal refueling outages (RFOs) as identified in Table IWB-2500-1. These examinations are to be performed each inspection period.

IWB-2420(b), states, in part, "If a component is accepted for continued service in accordance with IWB-3132.3 or IWB-3142.4, the areas containing flaws or relevant conditions shall be re-examined during the next three inspection periods listed in the schedule of the Inspection Program of IWB-2400."

Serial No.: 19-156 Docket No.: 50-338 RPV Internals Successive Examinations Page 2 of 9

4. Reason for Request

IWB-2420(b), Successive Inspections, requires a VT-3 visual examination of the areas containing flaws identified during the fourth ISi interval, Third Period, B-N-1 examination, during the next three inspection periods. While the B-N-1 examination is normally performed each period, only areas made accessible by removal of components are examined. An alternative is requested for B-N-1 examination of degraded cladding in areas only made accessible by the removal of the core barrel, an evolution normally taking place once per 10-year inspection interval.

Removal of the core barrel presents extensive radiological and industrial safety concerns, including:

(1) a significant heavy lift of a critical vessel internals component, (2) construction of a shield wall for the portion of the core barrel above the refueling pool water level when it is placed in the stand, (3) significantly higher dose rates for station personnel during the RFO, and (4) the potential for further cladding damage when the core barrel is moved.

Radiological Risk In the past, movement of the core barrel has required posting containment as a Very High Radiation Area (VHRA) due to dose rates of approximately 600 R/hr. Peak lifting height during transit to and from the storage stand exposes approximately 11 feet of the highly irradiated RPV lower internals.

This results in a general area dose rate of 335 R/hr measured at the top of the installed water shield tanks. Dose rates at the equipment hatch when the lower internals are at peak lift height are approximately 1 R/hr.

While resting in its storage stand, more than 4 ft of the core barrel remains exposed above the refueling pool's surface requiring the placement of multiple shield tanks to reduce the resulting elevated dose rates. Among the personnel receiving the most significant exposure during core barrel movement and storage in the stand are the crane operator and inspection personnel working over the cavity.

Serial No.: 19-156 Docket No.: 50-338 RPV Internals Successive Examinations Page 3 of 9 Industrial Risk Heavy lifts associated with removal of the RPV internals and placement of the shield tanks presents significant industrial risks to station personnel and equipment. Movement of the lower internals, weighing more than 115,000 lbs, poses a risk to critical components including the RPV flange and cavity seal ring as well as personnel and any other equipment in or near the load path.

The reason for this request is that the relevant indications were evaluated as acceptable for continued service through IWB-3142.4, Acceptance by Analytical Evaluation, there are no active degradation mechanisms which will reduce the capability of the RPV to perform its intended design function, and the maximum conservative estimates of corrosion are acceptable even after an 80-year life.

5. Proposed Alternatives and Basis for Use Dominion proposes to re-examine the areas with cladding damage found during the NAPS1 spring 2018 RFO (N1 R26) no later than the next scheduled core barrel removal at the end of the fifth ISi inspection interval, currently scheduled to occur in the fall 2028. The ASME XI, IWB-2420(b), requirement for Successive Examinations in the First Period and Second Period will be deferred. Pursuant to 10 CFR 50.55a(z)(1), the requested alternative will provide an acceptable level of quality and safety.

Characterization of Reactor Vessel Cladding Defects Two cladding deformations were found on the NAPS1 RPV internal surface during the spring 2018 RFO (N 1R26) [Reference 2]. Cladding indications were also discovered on the specimen slots during the 10-year ISi B-N-1 visual examination of the RPV interior surface [Reference 2]. These three indications are shown in Attachment 2 (RPV schematic plus 3 indications).

Indications 1 and 2 are most likely fabrication flaws. The sizes and shapes of these indications suggest that they were a consequence of poorly adhered cladding material which was produced by a lack of fusion of the deposited clad. Further investigation, which included VT-1 examination, revealed an area of cladding degradation which exposed the underlying low-alloy carbon steel. No indications of cracking were visible in the areas surrounding these indications.

Serial No.: 19-156 Docket No.: 50-338 RPV Internals Successive Examinations Page 4 of 9 The indications presented in Indication 3, in Attachment 2, are deformation of the cladding material mostly likely caused by the removal of the core barrel for the 10-year ISi B-N-1 vessel examination. There may have been slight misalignment of the core barrel such that when the core barrel was extracted the specimen features on the thermal shield made contact with the specimen slots. No indication of cracking was visible in the area surrounding each indication.

ASME Code Section XI Requirements The indications, as identified above, may not meet the acceptance requirements of IWB-3520.2 "Visual Examination, VT-3." IWB-3520.2 is presented as follows per ASME 2013E BPV Section XI:

IWB-3520.2 Visual Examination, VT -3. The following relevant conditions shall require corrective action in meeting the requirements of IWB-3122 prior to service or IWB-3142 prior to continued service:

(a) structural distortion or displacement of parts to the extent that component function may be impaired; (b) loose, missing, cracked, or fractured parts, bolting, or fasteners; (c) foreign materials or accumulation of corrosion products that could interfere with control rod motion or could result in blockage of coolant flow through fuel; (d) corrosion or erosion that reduces the nominal section thickness by more than 5%;

(e) wear of mating surfaces that may lead to loss of function; or (f) structural degradation of interior attachments such that the original cross - sectional area is reduced more than 5%.

IWB-3520.2 criteria (b) and (c) were not satisfied with the visual examinations. As shown in Reference 2 and Attachment 2, the discontinuities noticed in Indications 1 and 2 show the presence of loose, missing, or cracked parts. Based on shadows seen at various viewing angles both indications have some depth, but a known depth was not able to be determined with the tools available at the time of examination. Due to the uncertainty of their depths, the indications were determined to be relevant.

Serial No.: 19-156 Docket No.: 50-338 RPV Internals Successive Examinations Page 5 of 9 With a relevant indication, Dominion chose to accept the examination results by an analytical evaluation per IWB-3142.4. As determined by this evaluation, the component, the RPV, is acceptable for continued service [Reference 2].

NOTE: The evaluation [Reference 2] performed in 2018 cites the 2004 Edition of the ASME Code. This request proposes an alternative to the requirements of the 2013 Edition [Reference 1] which became the applicable code at the beginning of the NAPS 1 fifth 10-year inservice inspection (ISi) interval that started May 1, 2019.

IWB-2420(b) stated, in part, "If a component is accepted for continued service in accordance with IWB-3132.3 or IWB-3142.4, the areas containing flaws or relevant conditions shall be reexamined during the next three inspection periods listed in the 11 schedule of the inspection program of IWB-2400.

The technical basis for the proposed alternative to the reexamination requirements of IWB-2420(b) is discussed in more detail below.

Operating Experience (OE)

An external OE search was conducted [References 2 and 5] for the potential for stress corrosion cracking (SSC) and . inservice induced fatigue crack growth degradation mechanisms to affect PWR RPV low-alloy steel material in the area of cladding defects. The results of the review and industry assessment concluded that these degradation mechanisms are not a significant concern for the case of cracked, damaged, missing, or removed cladding of the RPV.

Degradation Mechanisms Corrosion Evaluation & Conclusion Corrosion rate data documented in the Boric Acid Corrosion Guidebook

[Reference 4] for carbon and low-alloy steel were conservatively applied for each type of chemical environment within a PWR RPV. The highest corrosion rate reported for all immersion (general corrosion) applicable to each chemical environment was conservatively assumed. The unfavorable conditions that are known to have led to substantial amounts of low-alloy steel corrosion at cladding defects are not credible for the RPV interior.

As shown in Reference 2, the maximum conservative estimate of corrosion loss of 0.31 inches (40 yrs) and 0.62 inches (80 yrs) have been shown to be

Serial No.: 19-156 Docket No.: 50-338 RPV Internals Successive Examinations Page 6 of 9 structurally acceptable. The RPV has structural margin for the probable depth of the indications and the extreme, worst-case corrosion even after an 80-year life. Plant operating experience supports the above conclusions that the subject cladding defects are acceptable for long-term future operation. Several cases at other PWRs with areas of damaged, missing, or intentionally removed RPV cladding are described in WCAP-15338-A [Reference 3]. In all cases, the cladding defects were reported to be inconsequential.

Stress Corrosion Cracking (SCC) Evaluation and Conclusion As discussed in Reference 2, the typical PWR service and shutdown Reactor Coolant System (RCS) chemistry contains oxygen and chloride levels that are significantly below the threshold levels required to initiate either intergranular sec (IGSCC) or transgranular sec (TGSCC) in the cladding; even if the base metal were exposed. The degree of corrosive attack and wastage due to operation is insignificant as evidenced by operational histories and analyses based on corrosion tests. Therefore, SCC is not a feasible degradation mechanism even if the base metal were exposed. WCAP-15338-A [Reference 3] concluded that the underclad cracks in the RPV are of no concern to the structural integrity of the RV for continued plant operation, even through 60 years.

Structural Analysis Indications 1 and 2 are evaluated in the following structural analysis. Indication 3 is not structurally analyzed, as no indication of impact to the carbon steel vessel is apparent. The governing stresses experienced at these locations are less than the stresses at Indications 1 and 2.

Indication 1 A very conservative assumption of a 1.0-inch deep flaw was used to analyze its impact on the RPV flange and upper shell region. The upper shell is 10-inches thick; a 1.0-inch deep flaw is a 10% reduction in thickness. In the analysis of the closure flange region, a 100°F/hr heat-up transient from 100°F to operating temperature is used as a boundary transient analysis to evaluate the stresses in the vessel flange to shell transition. This transient typically leads to the highest overall stresses in the closure region because the closure flange heats

Serial No.: 19-156 Docket No.: 50-338 RPV Internals Successive Examinations Page 7 of 9 up faster than the closure studs, leading to additional load being carried by the closure studs.

The primary local membrane plus bending stress intensity for the intact RPV transition region was calculated to be 18.3 ksi, a factor of 2.2 below the 1.5 Sm limit of 40.05 ksi [Reference 2]. This is greater than the conservative estimate of 1.23 for increase in local stress due to corrosion.

The fatigue usage factor for the intact RPV transition region, reported in Reference 2 to be 0.0083, is well below the allowable value of 1.0.

Indication 2 As shown in Reference 2, the primary local membrane plus bending stress intensity is a factor of 1.58 below the allowable value. This is greater than the estimate of 1.25 for the increase in local stress due to corrosion conservatively based on the wall thickness of the bottom head. The primary plus secondary stress intensity range is a factor of 1.96 below the allowable value. This is greater than the estimate of 1.25 for the increase in local stress due to corrosion conservatively based on the wall thickness of the bottom head.

Furthermore, the thickness of the undisturbed region of the bottom head is more than 1.0-inch greater than the required 3.868-inch thickness [Reference 2] calculated on the basis of the primary membrane stress due to the design pressure.

In the analysis of fatigue effects on the lower shell, it is noted in the original RPV design documents that the fatigue usage factor for the [lower clevis]

keyway and adjacent pad is equal to 0.02182 [Reference 2]. This low value indicates that many of the design basis transients do not result in a stress exceeding the 12.5 ksi fatigue limit for carbon steel. In applying a 1.0-inch flaw to the fatigue analysis, a fatigue reduction factor of 4.0 can be used, which models the flaw as if it is the root of a thread of a bolt. Applying this factor increases the fatigue usage factor to 0.436, which is many times more than 0.02182, but still below the allowable limit of 1.0 and therefore acceptable.

Conclusions Plant OE indicates that the subject cladding defects are acceptable for long-term future operation. Cladding defects in several cases at PWRs with areas of damaged, missing, or intentionally removed RPV cladding were reported to be not

Serial No.: 19-156 Docket No.: 50-338 RPV Internals Successive Examinations Page 8 of 9 credible for the RPV interior. OE also indicates that cracking of the underlying low-alloy steel vessel material at cracked, damaged, missing, or intentionally removed cladding is not likely. In addition, sec is not a feasible degradation mechanism even if the base metal were exposed. WCAP-15338-A concluded that the underclad cracks in the RPV are of no concern to the structural integrity of the RPV.

Based on the structural analyses performed, local corrosion features up to 1.0-inch in depth at both locations continue to meet criteria in Section Ill of the Code.

Therefore, the subject cladding indications are concluded to be acceptable for operation until the end of an 80-year licensing period. Additional visual examinations of the cladding defects are considered appropriate when the core barrel is removed for a subsequent RPV ISi examination and the areas in which each cladding defect is located become accessible. A 10-year ISi examination is an opportunity to examine the cladding defects and confirm that any discernible low-alloy steel corrosion is bounded by the conservative predictions of this calculation, as well as measure the depth of the indications.

For the reasons stated above, it is requested that the re-examination be performed during the Third Period of the fifth 10-year ISi interval coincident with the currently scheduled RPV inspection in the fall of 2028.

6. Duration of Proposed Alternative

The proposed alternative will be used for the fifth 10-year inspection interval of the ISi Program for NAPS1, which is scheduled to end on April 30, 2029:

7. Precedents

Similar requests were granted to:

• Callaway, Unit 1: NRC Letter to Union Electric dated February 16, 2012, "Callaway Plant Unit 1 - Relief Request 13R-13 from ASME Code Requirements for Reactor Pressure Vessel Flange Insert Non-Destructive Examination during Third 10-Year lnservice Inspection Interval (TAC No.

ME7504)"

• Point Beach, Unit 1: NRC Letter to NextEra Energy Point Beach, LLC, dated December 10, 2014, "Point Beach Nuclear Plant, Unit 1 - Relief Request 1-RR-6, Proposed Alternative from the Requirements of the American Society of

Serial No.: 19-156 Docket No.: 50-338 RPV Internals Successive Examinations Page 9 of 9 Mechanical Engineers Boiler and Pressure Vessel Code for Re-examination of Reactor Pressure Vessel "A" Inlet Nozzle Weld (TAC No. MF3318)"

• Susquehanna Steam Electric Station, Unit 2: NRC Letter to PPL Susquehanna, LLC, dated February 23, 2013, "Susquehanna Steam Electric Station, Unit 2, RE: Relief Request No. 3RR-18, Regarding Relief from the Requirements of the ASME Code for Successive Inspection (TAC No ME7381 )"

8. References

1. ASME Boiler and Pressure Code, Section XI, 2013 Edition, ASME International.

2. ETE-NA-2018-0013, "Engineering Evaluation of Unit 1 Reactor Vessel Cladding Indications," Revision 0.

3. WCAP-15338-A, "A Review of Cracking Associated with Weld Deposited Cladding in Operating PWR Plants," October 2002.

4. Boric Acid Corrosion Guidebook, Revision 2: Managing Boric Acid Corrosion Issues at PWR Power Stations (MRP-058, Rev. 2), Palo Alto, CA.

5. EPRI Technical Report, 3002012966 "Evaluation of Basis for Periodic Visual Examination of Accessible Areas of Reactor Vessel Interior per Examination Category B-N-1 of ASME Section XI, Division 1."

Serial No.: 19-156 Attachment 2 Engineering Evaluation ETE-NA-2018-0013, "Engineering Evaluation of Unit 1 Reactor Vessel Cladding Indications"

[Non-Proprietary Version]

Revision 0 Attachments 1-4 Virginia Electric and Power Company (Dominion Energy Virginia)

North Anna Power Station Unit 1

ETE-NA-2018-0013 Rev.O

. Doc Type: . Sub Type: . Document Number: . Decomm?

TE 00 TE-NA-2018-0013 0Yes [8]No ngineering Evaluation of Unit 1 Reactor Vessel Cladding Indications

. ETE Level: o. Unit(s): 1. Quality Classification: 2. FSRC Approval: 3. Risk Assessment:

Low OMedium Unit 1 0Unit 2 0Unit 3 OISFSI SR 0NS 0NSQ Yes 0No High D N/A

4. Preparation, Review, and Approval Signatures (add or delete rows as needed)

Prepared by/Affiliation: (Print) ate:

.E. Allmond - Dominion Energy-North Anna/ System Engineering 91/ft 'mlf eviewed by/Affiliation: (Print) [8JIND OPEER

.M. Minton - Dominion Energy-Innsbrook I Engineering Mechanics eviewed by/Affiliation: (Print) DINO [8JPEER ate:

.J. Vasquez - Dominion Energy-Innsbrook/ Engineering Mechanics '1 l111Zol g Program/Other Reviewer/Affiliation: (Print) DINO t8l PEER 0SME

.K. Haluska-Dominion Energy-Innsbrook I Materials & Inspection upervisor Approval/Affiliation: (Print)

.S. Galbraith-Dominion Energy-North Anna I Materials & Inspection upervisor Approval/Affiliation: (Print) ate:

.W. Derreberry-Dominion Energy-Innsbrook/ Engineering Mechanics 1 J H 1'2cH8 ignature: II Reviewed/No Not Req.

pages Impact

5. Design Effects and Considerations (DNES-AA-GN-1003) D

6. Document Impact Summary (DRUL) {DNES-AA-GN-1002) Y..!,... .,

~ ll'

7. Considerations and Conditions for Document Updates (check [8JN/A if no document updates are noted on the DRUL)

All Document updates noted on the DRUL can be initiated immediately Document updates noted on DRUL are delayed until the following documents/actions are completed (e.g., WO, CR, etc.)

(See DRUL Remarks section) 10CFR50.59 Attachments Attachment # of pages Not Req.

8. 10CFR50.59/72.48 applicability review forms (CM AA-400)

9. 10CFR50.59/72.48 screen form {CM-AA-400) 9 4 D O. 1 OCFR50.59/72.48 evaluation form (CM-AA-400)

1. Additional Attachments Attachment of pages Description Attachment 1 4 Framatome Indication Notification Report INR-N1 R26-18-001 Attachment 2 4 Framatome Indication Notification Report INR-N1 R26-18-002 Attachment 3 4 Framatome Indication Notification Report INR-N1R26-18-004 Form No. 730801 (Ocl 2015)

CM-AA-ETE-101 ATTACHMENT 2 Page 2 of 15 ETE-NA-2018-0013 Rev.O Attachment 4 5 Supplemental Images of Cladding Indications M-4523-00-01_Rev.O Review of Low-Alloy Steel Cracking Mechanisms &

Attachment 5 4 Operating Experience Relevant to Cladding Defect in NAPS Unit 1 Reactor Vessel Attachment 6 21 C-4523-00-01_Rev.O_NAPS Unit 1 Corrosion Assessment Attachment 7 46 C-4523-00-02_Rev.O_NAPS Unit 1 RPV Corrosion Evaluation Dominion Engineering, Inc. Calculation C-4523-00-02 Applicability of Attachment 8 $2 Stress I Fatigue Analysis Results Primary Recipient(s): Mark Walker- System Engineering Manager- North Anna Power Station (Enter Name/Dept. or Location for EACH Primary Recipient in this block.)

Copy To? Other Recipient/Department or Location Copy To? Other Recipient/Department Location f8l Preparer - C. Allmond f8l System Engineer - A. Connor f8l Reviewer- C. Minton ID. J. Vasquez/ B. Haluska D Nuclear Document Management f8l Supervisor - R. Galbraith f8l Supervisor - R. Simpson f8l Site DCE - K. Gill f8l Supervisor - B. Derreberry D Affected Organization f8l GA Gardner D Program Owners D Form No. 730801 (Oct 2015)

CM-AA-ETE-101 ATTACHMENT 2 Page 3 of 15 ETE-NA-2018-0013 Rev.O Source Document CR1092975- Relevant indication found on RV interior Surface CR1092857 - Relevant indication was identified on RV interior Surface CR1093165- Deformation found on RPV Interior on Internals Support Ledge Record of Revision Revision O- Original Revision Purpose This ETE evaluates the two cladding deformation indications found on the Unit 1 Reactor Vessel (1-RC-R-1-VESSEL) as identified in CR1092857 and CR1092975. These two cladding indications were discovered during the 10-year ISi visual examination of the reactor vessel interior surface.

This ETE also evaluates the three cladding indications found on the specimen slots as identified in CR1093165.

This ETE will determine the following:

1. Is there a "relevant condition requiring corrective action discovered in performing the B-N-1 exam to the standards of IWB-3520.2?

2. Is there an active degradation mechanism impacting future RPV safety?

3. Does the vessel meet ASME code requirements for structural integrity in the areas of indications?

This Engineering Evaluation is a Level 2 ETE per CM-AA-ETE-101, Section 2.4 (a) Document technical basis supporting resolution of Condition Reports (CR) in cases where more rigorous documentation is required to support the disposition.

The risk of this ETE has been determined to be HIGH risk due to being performed on a compressed schedule and the safety significance of the component under evaluation, 1-RC-R-1-VESSEL Design Inputs and Assumptions Design inputs describing the basis for the evaluations are as follows:

1. Extent of cladding deformation 1.1. As described in CR1092857 [1] and Attachment 1 Form No. 730801 (Oct 2015)

CM-AA-ETE-101 ATTACHMENT 2 Page 4 of 15 ETE-NA-2018-0013 Rev. 0 1.2. As described in CR1092975 [2] and Attachment 2 1.3. As described in CR1093165 [3] and Attachment 3 1.4. Supplemental images provided in Attachment 4

2. Minimum clad thickness 2.1. 1/8 inch (3.2 mm) per Reactor Vessel VTM [4] and Rotterdam Drawing 30660-1101 Sheet 1 of 2 [5]

3. Minimum Reactor Vessel Thickness at Vessel Flange Area for CR1092857 and CR1093165 3.1. 10 inches (250 mm) as determined from the Reactor Vessel VTM [4] and Rotterdam Drawing 30660-1152 Sheet 2 of 2 [7L Section A_A and Detail D.

4. Minimum Reactor Vessel Lower Shell Course Thickness for CR1092975 4.1. 4. 7 inches (119.4 mm) as determined from Reactor Vessel VTM [4] and Rotterdam Drawing 30660-1101 Sheet 1 of 2 [5] Detail Ill 4.2. 5.0 inches (128 mm) is the Nominal Thickness as determined from Reactor Vessel VTM [4]

and Rotterdam Drawing 30660-1101 Sheet 1 of 2 [5] Detail Ill

5. Reactor Vessel Data 5.1. Reactor Vessel Weight: 551,250 lb [41 5.2. Reactor Vessel Material - Upper Shell Course: ASME SA-508, Class 2 [4]

5.3. Reactor Vessel Material - Lower Shell Course: ASME SA-508, Class 2 [4]

5.4. Reactor Vessel Material - Lower Head Ring: ASME SA-533, Class 1 Grade B [4, 6]

6. Engineering Basis for Design 6.1. ASME Boiler and Pressure Vessel Code, Section 11 I, 1968 Ed through Winter 1968 Addenda

[9]

6.2. Reactor Vessel Design Report [4]

6.3. Reactor Vessel Stress Report [6]

7. Repair/Replacement Requirements 7.1. ASME BPV Section XI, 2004 Ed. [10]

8. Licensing Basis 8.1. North Anna UFSAR [11]

Form No. 730801 (Oct 2015}

CM-AA-ETE-101 ATTACHMENT 2 Page 5 of 15 ETE-NA-2018-0013 Rev.O 8.1.1. UFSAR Chapter 5.2.3.1.1, 5.2.3.1.9, 5.2.3.3.2, 5.2.5.1 8.1.2. UFSAR Chapter 18.3.2.2

9. North Anna Unit 1 is a Westinghouse-designed Nuclear Steam Supply System with a Pressurized Water Reactor (PWR) vessel fabricated from low alloy carbon steel internally clad with stainless steel cladding [11].

Assumptions 1

1. This evaluation assumes that the cladding and service conditions of North Anna s Unit 1 reactor vessel is similar to those of other Westinghouse, Combustion Engineering, and Babcock and Wilcox designed reactor vessels, and that operating experience from those vessels is applicable to North Anna Unit 1 [12 - 14].

Methodology During the B-N-1 examination of the vessel, discontinuities of the vessel interior surface were noticed.

Those indications may not meet the acceptance requirements of IWB-3520.2. The most applicable requirements being: "loose, missing, cracked or fractured parts, bolting or fasteners" and "corrosion or erosion that reduces the nominal section thickness by more than 5%JJ. This ETE explores degradation mechanisms, operating experience, and other input to provide a technical evaluation of the indications in relation to the acceptance criteria oflWB-3520.2. In addition, this ETE will provide an evaluation of the reactor vessel's ability to meet structural requirements for a pressure vessel now and at the end of an 80-year life.

In the sections that follow, the following topics are addressed:

1. Description of Indications

2. Potential Causes of Indications

3. Operating Experience

4. Degradation Mechanism

a. General and Localized Corrosion & Flow Accelerated Corrosion

b. Stress Corrosion Cracking

5. Structural Analyses

a. Original conditions Form No. 730801 {Oct 2015)

CM-AA-ETE-101 ATTACHMENT 2 Page 6 of 15 ETE-NA-2018-0013 Rev.O

b. Original requirements

c. Analysis

6. ASME Section XI Code requirements Discussion

1. Description of Indications

a. Indication 1 - This indication was identified as an area of interest during a review of the 2009 B-N-1 RPV inspection video. This indication was located below the 55° irradiation specimen slot, and visual examination revealed an area of cladding degradation which exposed the underlying low alloy steel. This area of clad loss, its location and dimensions are presented in Attachment 1. No indications of cracking were visible in the area surrounding this indication [1].

b. Indication 2- During the RPV interior examination, this indication was identified adjacent to the 270° Radial (Clevis) Support Keyway as seen in Attachment 2 and Figure 4-8 in Attachment 4. Further investigation which included an EVT-1 examination revealed an area of cladding degradation which exposed the underlying low alloy carbon steel. No indication of cracking was visible in the area surrounding this indication [2].

C. Indication 3 - During the examination of the Lower Internals Support Ledge, there were areas identified with materials deformation at the base of each of the following Irradiation Specimen Slots: 45°, 55°, and 65°. This was a total of three areas of deformation: one area per Specimen Slot. No indication of cracking was visible in the area surrounding each indication [3]. See Attachment 3.

2. Potential Causes of Indications Indication 1 and Indication 2 are most likely fabrication flaws. The size and shape of Indication 1 suggests that it is a consequence of poorly adhered cladding material which was produced by lack of fusion of the deposited clad. Indication 2 also has the physical characteristics of a consequence of poorly adhered cladding material which was produced by lack of fusion of the deposited clad.

There is evidence of grinding in the area of this indication as seen in Figure 4-8 of Attachment 4; therefore, this indication may have been an undersurface indication opened during the grinding activities. The grinding activities were done to remove cladding in the areas where the Radial Form No. 730801 (Oct 2015)

CM-AA-ETE-101 ATTACHMENT 2 Page 7 of 15 ETE-NA-2018-0013 Rev.O (Clevis) Support Keyways were installed. The Radial (Clevis) Support Keyways were installed on-site as presented in Reactor Vessel VTM [4] and Rotterdam Drawing 30660-1101 Sheet 1 of 2 [7]

Detail Ill.

The indications presented in Indication 3 are deformation of the cladding material most likely caused by the removal of the reactor vessel core barrel for 10-Yr ISi B-N-1 vessel examinations. There may have been slight misalignment of the core barrel (e.g. a fraction of a degree) such that when the core barrel was extracted the Specimen features on the thermal shield actually made contact with the Specimen Slots. Since each indication area is on the same face of each Specimen Slot, there is validity in this assumption. Because there is more structural material at these locations, the evaluation of the two other flaws (Indication 1 and Indication 2) will bound these three indications; the governing stresses experienced at these locations are less than stresses at Indication 1 and Indication 2.

3. Operating Experience An external OE search as presented in Attachment 5 was based on intentionally removed cladding from four vessels and no problems were subsequently observed associated with the removed cladding areas [12].

Recent external OE on a cladding indication came from Palo Verde Unit 1 [13]. During 1R20, the Palo Verde In-service Inspection group discovered an anomaly along an Alloy 82/182 (lnconel) clad area of the reactor vessel bottom head. The anomaly was measured 0. 7 inches wide, 0.8 inches long, and 0.2 inches deep. The cladding anomaly was evaluated by engineering arid accepted as-is. This particular OE is relevant to the indication observed in the vicinity of the 270° clevis insert.

Diabfo Canyon Unit 1 had an area in the reactor vessel interior that had missing cladding; an area of 1.025 inches x 0.53 inches was found at the bottom of loop 3 reactor vessel inlet nozzle. No evidence of cracking, pitting, or wastage was identified in this distressed cladding location. The NSSS vendor provided an assessment of the distressed cladding area, and the conclusion was as follows: the size, shape, and close proximity of the missing cladding area suggests the missing cladding is the consequence of poorly adhered cladding material in a limited area which was produced by lack of fusion of the deposited cladding in the area during original fabrication. It was concluded, based on the fact that cladding is nonstructural in design, and that no cracking, pitting, or wastage of the base material was identified during the visual examination, that the area of Form No. 730801 (Oct 2015)

CM-AA-ETE-101 ATTACHMENT 2 Page 8 of 15 ETE-NA-2018-0013 Rev.O distressed cladding material in the loop three inlet nozzle is no threat to the continued structural integrity of the reactor vessel [14].

Within the Dominion Energy fleet experience, a cladding deformation that the Millstone Unit 3 vessel closure head incurred during the Fall 2017 refueling outage required field rework. The following conclusions in regards to cladding deformation are presented from ETE-M P-2017-1159

• ~

[15]: (1) there was no impact on the structural integrity of the vessel head, (2) there is no concern for cladding integrity or future stress corrosion cracking, and* (3) there is no impact on ASME Code compliance or the ASME Design Report. This cladding deformation did not breach the cladding exposing the low alloy steel; therefore, there was no concern with the structural integrity or corrosion. This OE from Millstone is applicable to the three areas noted in indication 3.

Although not a reactor vessel, the Surry Power Station Unit 1, 'A' Steam Generator has a loss of cladding defect on its tubesheet, noticed in 2006. The tubesheet is constructed in a similar manner to the reactor vessel, with low-alloy carbon steel cladded by another alloy {82/182 in this case). As evaluated in ET-MAT-06-0002 [16], the defect was noted to have no impact on the structural requirements of the tubesheet and continued monitoring has shown no appreciable growth due to corrosion.

4. Degradation Mechanism

a. Corrosion Evaluation (General/Localized/FAG)

The stainless cladding protects the underlying low alloy steel from corrosion. In areas of cladding loss, corrosion of the low alloy steel may occur. As presented in Dominion Engineering calculation C-4523-00-01 (Attachment 6), corrosion rate data documented in the EPRI BAC Guidebook [17] for carbon and low-alloy steel were conservatively applied for each type of chemical environment within a PWR reactor vessel. The highest corrosion rate reported for alt immersion tests (i.e., general corrosion) applicable to each chemical environment was conservatively assumed. The total amount of future corrosion was projected with conservative assumptions regarding the portion of future operation when more aggressive conditions exist due to reduced pH and aeration. The unfavorable conditions that are known to have led to substantial amounts of low-alloy steel corrosion at cladding defects (ongoing air in-leakage during normal operation and highly concentrated boric acid associated with pressure boundary leakage or evaporation of a limited volume of liquid) are not credible for the reactor vessel interior.

Furthermore, as discussed in Attachment 6, localized and flow-accelerated corrosion are not Form No. 730801 {Oct 2015)

CM-AA-ETE-101 ATTACHMENT 2 Page 9 of 15 ETE-NA-2018-0013 Rev.O considered to be of significant concern for areas of reactor vessel low-alloy steel material exposed to primary coolant.

The conservatively predicted cumulative amount of corrosion is shown in Table 1 of Attachment 6 for cases of interest. The additional corrosion in one 18-month cycle (with a 30-day refueling outage) was calculated to be 0.012 inch. This corresponds to 0.077 inch in 10 years, 0.153 inch in 20 years, and 0.307 inch in 40 years. The conservative estimate of a depth which bounds any corrosion of the underlying low-allow steel at either cladding indication, as examined in March 2018, is 0.25 inch (per Assumption 8 of Attachment 6). Thus, the total depth of either indication is conservatively estimated to be less than 0.262 inch in 18 months, less than 0.327 inch in 10 years, less than 0.403 inch in 20 years (until the 60-year license expiration date), and less than 0.557 inch in 40 years (until an 80-year license expiration date). The current (i.e., first) renewed license for North Anna Unit 1 expires on April 1, 2038

[18]. The total amount of corrosion evaluated over the full 80-year operating life is calculated to be 0.619 inch.

Given the OE presented, a total amount of corrosion of 0.619 inches is very conservative. No utility with a cladding indication has reported a depth that reflects the above calculated corrosion rates. As presented in WCAP-15338-A and the more recent OE, the typical PWR service and shut down RCS chemistry contains oxygen and chlorine levels that are significantly below the threshold levels required to initiate either intergranular stress corrosion cracking (IGSCC) or transgranular stress corrosion cracking (TGSCC); even if the base metal were exposed, the degree of corrosive attack and wastage due to operation is insignificant as evidenced by operational histories and analyses based on corrosion tests [11].

b. Stress Corrosion Cracking Testing indicates that stress corrosion cracking (SCC) does not occur of pressure vessel steels (e.g. low alloy steels) under normal reactor coolant system (RCS) conditions - under conditions with normal PWR RCS chemistry characterized by fully deoxygenated conditions [20]. But, sec can occur in the cladding. As presented in WCAP-15338-A, two sequential steps envelope the entire process: (1) cracking and separation of a portion of the clad weld metal yielding base metal exposure to RCS water, and (2) Corrosive attack and wastage of the carbon steel base metal because of its exposure to RCS water [11]. lntergranular stress corrosion cracking (IGSCC) of the clad metal can occur if the weld is sensitized (chromium depleted grain boundaries), and this sensitized area is exposed to oxygenated water [11]. TGSCC can occur in cladding only in the presence of a chloride environment [11]. As stated previously, the typical PWR service and shut Form No. 730801 (Oct 2015)

CM-AA-ETE-101 ATTACHMENT 2 Page 10 of 15 ETE-NA-2018-0013 Rev.O down RCS chemistry contains oxygen and chlorine levels that are significantly below the threshold levels required to initiate either IGSCC or transgranular stress corrosion cracking {TGSCC) in the cladding; even if the base metal were exposed, the degree of corrosive attack and wastage due to operation is insignificant as evidenced by operational histories and analyses based on corrosion tests

[11 ]. Therefore, sec is not a feasible degradation mechanism even if the base metal were exposed.

WCAP-15338-A concluded that underclad cracks in reactor pressure vessels (RPVs) are of no concern to the structural integrity of the vessel for continued plant operation, even through 60 years.

From the OE presented in the industry, stress corrosion cracking of reactor coolant wetted steels is generally unlikely in PWRs as long as the RCS environment is deoxygenated and the low alloy steel is very low in manganese sulfide inclusions [20].

5. Structural Analysis Indications 1 and 2 are evaluated in the following structural analysis. Indication 3 is not structurally analyzed, as no indication of impact to the carbon steel vessel is apparent.

a. Original Conditions The following stress values for the radial support keyway and adjacent shell are taken from North Anna design basis report summary [6]:

i. Primary Local Membrane Plus Bending stress intensity~ 25.35 ksi vs 40.05 ksi allowable ii. Primary Plus Secondary stress intensity range= 40.90 ksi vs 80.10 ksi allowable iii. Fatigue Usage= 0.02182 vs 1.0 allowable

b. Original Requirements The following ASME Code Section Ill [9] stress limits are applicable for this evaluation:

i. Primary Local Membrane Plus Bending stress intensity is limited to 1.5Sm.

ii. Primary Plus Secondary Stress Intensity Range is limited to 3Sm.

iii. Peak stress intensity is limited by fatigue, with a calculated fatigue usage of less than 1.0.

iv. For both SA-508 Class 2 and SA-533 Grade B Class 1 materials, the value of Sm is invariant with temperature, and is equal to 26. 7 ksi.

c. Analysis

i. Indication 1 (Upper indication)

Fonn No. 730801 (Oct 2015}

CM-AA-ETE-101 ATTACHMENT 2 Page 11 of 15 ETE-NA-2018-0013 Rev.O In order to provide a bounding analysis of Indication 1, both now and for the remainder of the 80-year plant life, a very conservative assumption of a 1.0-inch deep flaw was used to analyze its impact on the reactor vessel flange and upper shell region. The upper shell is 10 inches thick, a 1.0-inch deep flaw is a 10% reduction in thickness.

In the analysis of the closure flange region, a 100°F I hour heat-up transient from 100°F to operating temperature is used as a bounding transient analysis to evaluate stresses in the vessel flange to shell transition. This transient typically leads to the highest overall stresses in the closure region because the closure flange heats up faster than the closure studs, leading to additional load carried by the closure studs. The temperature difference between the flange and the studs is on the order of 200°F due to the rate and duration of this design basis transient. The 100°F I hour design basis heat-up transient is defined as follows, consistent with typical design basis transient values:

COJ?fidential Information in this Table can be found Commercial lnfommtion in the attached Proprietary ca [culation.

An estimate of the additional stress resulting from a one-inch deep local corrosion feature can be made by assuming the stresses are primarily bending in nature and will increase by the square of the ratios of the new thickness to the old. In this case the increase in going from a 10-inch thickness to 9-inch is a factor of 1.23.

The primary local membrane plus bending stress intensity for the intact vessel transition region is 18.3 ksi, a factor of 2.2 below the 1.5Sm limit of 40.05 ksi. This is greater than the conservative estimate of 1.23 for increase in local stress due to corrosion.

The fatigue usage for the intact vessel transition region, reported in Reference [19] to be 0.0083, is well below the allowable* of 1.0. Increasing the stress ranges using a fatigue strength reduction factor of 4.0

{a similar reduction as the root of threads) still results in an estimated fatigue usage well below the allowable of 1.0.

ii. Indication 2 (Lower indication)

Form No. 730801 (Oct 2015)

CM-AA-ETE-101 ATTACHMENT 2 Page 12 of 15 ETE-NA-2018-0013 Rev. 0 In the analysis of the lower corrosion feature, it is assumed that stresses are primarily a result of internal pressure, and therefore increase linearly with reduced thickness. The primary local membrane plus bending stress intensity is a factor of 1.58 below the allowable value. This is greater than the estimate of 1.25 for increase in local stress due to corrosion conservatively based on the wall thickness of the bottom head. The primary plus secondary stress intensity range is a factor of 1.96 below the allowable value. This is greater than the estimate of 1.25 for increase in local stress due to corrosion conservatively based on the wall thickness of the bottom head. Furthermore, per reference 5, the thickness of the undisturbed region of the bottom head is more than 1.0 inch greater than the required thickness (3.868 from Attachment 7) calculated on the basis of the primary membrane stress due to design pressure.

In the analysis of fatigue effects on the lower shell, it is noted in original vessel design documents that the fatigue usage factor for the [lower clevis] keyway and adjacent pad is equal to 0.02182. This low value indicates that many of the design basis transients do not result in a stress exceeding the fatique limit for carbon steel (12.5 ksi). In applying a 1.0-inch flaw to the fatigue analysis, a fatigue reduction factor of 4.0 can be used, which models the flaw as if it is the root of a thread of a bolt. Applying this factor increases the fatigue usage factor to 0.436, which is many times more than 0.02182, but still below the allowable limit of 1.0 and therefore acceptable.

Dominion Energy's structural engineers have performed a detailed analysis and acceptance of Dominion Engineering, Inc's analysis. This more detailed discussion is included in Attachment 8. The overall result is that stress / fatigue results near the indications under evaluation are not appreciably affected by the Plant Loading and Unloading Transient and the results used by DEi are valid. The difference in usage factor results will not affect the conclusions of the DEi analysis, which employs a conservative approach to assess continued acceptability for a 1" deep corrosion feature against ASME code allowable limits on stresses and fatigue.

In conclusion, even with the assumption of a 1.0-inch flaw, the reactor vessel still meets ASME Section Ill requirements (as if it were a new vessel) for thermally induced, flange (bending), pressure (hoop) and fatigue stresses.

6. ASME Section XI Code requirements IWB-3520.2 is presented as follows per ASME 2004 BPV Section XI:

Form No. 730801 (Oct 2015)

CM-AA-ETE-101 ATTACHMENT 2 Page 13 of 15 ETE-NA-2018-0013 Rev.O IWB-3520.2 Visual Examination, VT-3. The following relevant conditions shall require corrective action in meeting the requirements of IWB-3122 prior to service or IWB-3142 prior to continued service:

(a) structural distortion or displacement of parts to the extent that component function may be impaired; (b) loose, missing, cracked, or fractured parts, bolting, or fasteners; (c) foreign materials or accumulation of corrosion products that could interfere with control rod motion or could result in blockage of coolant flow through fuel; (d) corrosion or erosion that reduces the nominal section thickness by more than 5%;

(e) wear of mating surfaces that may lead to loss of function; or (j) structural degradation of interior attachments such that the original cross-sectional area is reduced more than 5%.

IWB-3520.2 criteria (b) and (d) were not satisfied with the visual examinations. As seen in the indication reports, the discontinuities noticed in indications 1 and 2 show the presence of loose, missing or cracked parts. In addition, both indications do have some depth (based on shadows seen at various viewing angles), but a known depth was not able to be determined for these indications with the tools available at the time of examination. Therefore, due to the uncertainty of their depth, the indications are determined to be relevant.

With a relevant indication, Dominion Energy has chosen to accept the examination results by an analytical evaluation (this ETE) Per IWB-3142.4. As determined by this evaluation, the component, the reactor vessel, is acceptable for continued service. The Unit 1 Reactor Pressure Vessel (RPV) is fully functional, and it is capable of performing its intended design functions under normal operations and upset conditions as defined in the UFSAR [11].

Conclusions This ETE determined the following:

1. The vessel, as inspected in the B-N-1 exam, has two "relevant conditions that require corrective action" in comparison to the criteria of IWB-3520.2. The upper and lower indications are relevant indications. This ETE evaluates these two indications as acceptable for continued service through IWB-3142.4, Acceptance by Analytical Evaluation. The three indications found on the irradiation sample slots are not "relevant conditions" because the indication features did not display a breach in the cladding.

2. There is no active degradation mechanism which will reduce the capability of the vessel to perform its intended design function or will require monitoring more frequently than as needed per IWB-2500.

3. Since the maximum conservative estimate of corrosion loss 0.31 inches (40-yr) and 0.62 inches (80-yr) have been shown to be structurally acceptable, the vessel has structural Form No. 730801 (Oct 2015}

CM-AA-ETE-101 ATTACHMENT 2 Page 14 of 15 ETE-NA-2018-0013 Rev.O margin for the probable depth of the indications and the extreme, worst-case corrosion even after an 80 year life.

Based on the analyses performed, a local corrosion feature up to 1.0 inches in depth at both locations continues to meet ASME Boiler and Pressure Vessel Code Section Ill criteria. Therefore, the subject cladding indications are concluded to be acceptable for operation until the end of an 80-year licensing period. Additional visual examinations of the cladding indications are considered appropriate when the core barrel is removed for a subsequent reactor vessel ISi examination and the areas in which each cladding indication is located become accessible.

Required Actions

1. Schedule the collection of depth measurements on the two indications presented in CR1092975 and CR1092857. (CA3181694)

2. Schedule successive inspections in accordance with IWB-2420(b) and (c). (CA3181697)

References

1. CR1092857 - Relevant Indication was identified on RV interior Surface, March 22, 2018.

2. CR1092975 - Relevant indication found on RV interior Surface, March 24, 2018.

3. CR1093165- Deformation found on RPV Interior on Internals Support Ledge, March 26, 2018.

4. Instruction Manual- 157 /nch I.D. Reactor Pressure Vessei-_Project VRA-RCPCRV- Virginia Electric and Power Company- North Anna Power Station, The Rotterdam Dockyard Company, for ROM Order 30661/30662, Revision 2, including Addenda 1 to 4 (also Virginia Power Control No. 59-W893-00125), ROM, 1971.

5. Rotterdam Report 30600-1130, Final Stress Report (Part 1)- P.W.R. Vessels North Anna I & II, Rev. 1, ROM, May 1976.

6. Rotterdam Dockyards Report No. 30660-1130, Rev. 1, Final Stress Report (Part 1) - PWR Vessels North Anna I & II, May 1976.

7. Rotterdam Drawing 30660-1101, Sheet 1 of 2, 157" P. W.R. Vessel Westinghouse - Assembly of the Lowershe/1 (sic), ROM, May 1971.

8. Rotterdam Drawing 30660-1152, Sheet 2 of 2, Upper Shell Assembly- Vessel Flange, ROM, June 1971.

9. ASME Boiler and Pressure Vessel Code, Section Ill, 1968 Ed with Addenda through Winter 1968.

10. ASME Boiler and Pressure Vessel Code,Section XI, 2004 Ed.

Fonn No_ 730801 (Oct 2015)

ETE-NA-2018*0013 Rev. 0

11. North Anna Power Station Updated Final Safety Analysis Report, Revision 53.03- Revised January 15, 2018.

12. WCAP - 15338 - A A Review of Cracking Associated with Weld Deposited Cladding in 1

Operating PWR Plants, October 2002 [NRC ADAMS Number: ML11306A084].

13. Evaluation Report No. 17-1085, Bottom Head/Flow Skirt Attachment Weld at 180 degrees, Palo Verde Generating Station, Arizona Public Service, October 2017.

14. Notification 50611088, U1 RPV Cladding Indication, Diablo Canyon Unit 1, PG&E Corporation, February 2014.

15. ETE-MP-2017-1159, Evaluation and Rework of Cladding Deformation, ref. CR1081407, on M33RCS*REV2, MPS3 Reactor Vessel Closure Head, Millstone Power Station, November 2017.

16. ET-MAT-06-0002 Steam Generator Channel Head/Tube Sheet Corrosion, Surry Power Station, 1

November 2006.

17. Boric Acid Corrosion Guidebook, Revision 2: Managing Boric Acid Corrosion Issues at PWR Power Stations (MRP-058, Rev 2), EPRI, Palo Alto, CA: 2012. 1025145.

18. NRC: North Anna Power Station, Unit 1, Accessed March 16, 2018. IBY~0!!:l.'i:!L.llm:.9.Q~!IQ.:

19. Dominion Engineering, Inc. Report R-4509-00-1, Rev. Of Reactor Vessel Bolting Evaluations -

North Anna Power Station. Section Ill, August 1998.

20. Carbon and Low Alloy Steels for Pressure Vessels,Section I, Chapter 1 in Materials Handbook for Nuclear Plant Pressure Boundary Applications (2018). EPRI, Palo Alto* CA: 2018.

3002012420.

Form No. 730801 (Oci 2015}

Attachment 1 - ETE-NA-2018-0013. Rev. 0 (p. 1 of 4)

North Anna N1R26 Remote Visual Examination Indication Notification Report Date: 22 March 2018 INR -N1R26 001 Time: 16:30 Component: Video File:

RPV Interior Vid_0134.mkv Description of Condition:

An EVT-1 examination of an area of interest, identified from the 2009 examination video, located below the 55" Irradiation Specimen Slot revealed an area of cladding degradation which exposes the underlying low alloy steel.

This area of clad loss, its location and dimensions are depicted in the following images. No indication of cracking is visible in the area surrounding this indication.

Page 1 of 4

- ETE-NA-2018-0013, Rev. 0 (p. 2 of 4) framatome Indication Location

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Indication Location Page 2 of 4

- ETE-NA-2018-0013. Rev. 0 (p. 3 of 4) rra,m~tto~me Indication Measurement Page 3 of 4

- ETE-NA-2018-0013, Rev. 0 (p. 4 of 4) framatome (Return Copy ta Framatome Page 4 of 4

Attachment 2 - ETE-NA-2018-0013, Rev. 0 {P. 1 of 4)

North Anna N1R26 Remote Visual Examination Indication Notification Report Date: 23 March 2018 INR-N1R26 002 Time: 17:30 Component: Video File:

RPV Interior Vid_0142.mkv & Vid_0184.mkv Description of Condition:

During the RPV Interior examination, an area of interest was identified adjacent to the 270° Radial Support Keyway. Further investigation, including an EVT-1 examination, revealed an area of cladding degradation which exposes the underlying low alloy steel. This area of clad loss, its location and dimensions are depicted in the following images. No indication of cracking is visible in the area surrounding this indication.

Page 1 of 4

- ETE-NA-2018-0013, Rev. 0 (p. 2 of 4)

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- ETE-NA-2018-0013. Rev. 0 (p. 3 of 4) fram e Indication Measurement Page 3 of 4

- ETE-NA-2018-0013, Rev. 0 (p. 4 of 4)

Page4of4

Attachment 3 - ETE-NA-2018-0013, Rev. 0 (p. 1 of 4)

North Anna N1 R26 Remote Visual Examination Indication Notification Report Date: 26 March 2018 INR-N1R26 -18~004 Time: 15:30 Component: Video File:

RPV Interior, Internals Support Ledge Vid_0194.mkv Description of Condition:

The examination of the Lower Internals Support Ledge, identified material deformation at the base of the 45°, 55° and 65° Irradiation Specimen Slots. Photos of these indications are depicted in the following images. A review of prior examination data was inconclusive.

Indication Locations Alignment Keyway(4X)

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- ETE-NA-2018-0013, Rev. 0 (p. 3 of 4) framatome

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- ETE-NA-2018-0013, Rev. 0 (p. 4 of 4) framatome Date: J rJg.tJJJ> I~

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Page 4 of 4

- ETE-NA-2018-0013. Rev. 0 (p. 1 of 5) - Supplemental Images (p. 1 of 5) - ETE-NA-2018-0013, Rev. 0 2!,}

CONTROL MECHANISM:**--*-*

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(MK 29° AND 29 b}

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(MK 17, 18 At'1D 38}

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INSTRUMENTATION-NOZZ LES IMK 19 AND 20) BOTTOM HEAD CAP F fGUR£ H REACTOR VESSEL Figure 4 NAPS Unit 1 Reactor Pressure Vessel as presented in the Rotterdam VTM [4]

- ETE-NA-2018-0013, Rev. 0 (p. 2 of 5) -Supplemental Images (p. 2 of 5)- ETE-NA-2018-0013, Rev. 0 LONGITUQINAl SECTION l'.r.,:mi,,ic,,w,_(lll,.-!..-_1,,:,!,11:_J*u*)

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Figure 4 NAPS Unit 1- Bottom Head of Reactor Pressure Vessel as presented in the Rotterdam VTM [4]

- ETE-NA-2018-0013, Rev. 0 (p. 3 of 5) - Supplemental Images (p. 3 of 5) - ETE-NA-2018-0013, Rev. 0 A...,._J

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Figure 4-4 NAPS Unit 1- Clevis and Weld Detail for Bottom Head (Detail I & II) during fabrication of the Reactor Pressure Vessel as presented in the Rotterdam VTM [4]

DETAIL m Figure 4-5 NAPS Unit 1-Clevis and Weld Detail for Bottom Head (Detail Ill & IV) during fabrication of the Reactor Pressure Vessel as presented in the Rotterdam VTM [4]

- ETE-NA-2018-0013, Rev. 0 (p. 4 of 5) - Supplemental Images (p. 4 of S) - ETE-NA-2018-0013, Rev. 0 DETAtl A C1:n1d Figure 4-6 NAPS Unit 1- Specimen Slot Detail used during fabrication of the Reactor Pressure Vessel as presented in the Rotterdam VTM [4]

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• II~ 3066(L1152. ~1 Figure 4 NAPS Unit 1- Upper Flange and Refueling Seal Ledge used during fabrication of the Reactor Pressure Vessel as presented in the Rotterdam VTM [4]

- ETE-NA-2018-0013. Rev. 0 {p: 5 of 5) - Supplemental Images (p. 5 of 5} - ETE-NA-2018-0013, Rev. O Figure 4 NAPS Unit 1- Indication near 270° Clevis: RED encircles the indication; encircles the area with evident grinding Figure 4 NAPS Unit 1- Indication near 270° Clevis

Serial No.: 19-156 Attachment 4 Calculation C-4523-00-02-NP, "North Anna Power Station Unit 1 RPV Corrosion Feature Evaluation"

[Non-Proprietary Version]

Revision 0 Virginia Electric and Power Company (Dominion Energy Virginia)

North Anna Power Station Unit 1

NON-PROPRIETARY VERSION CALCULATION

Title:

North Anna Power Station Unit 1 RPV Corrosion Feature Evaluation CalculationNo.: C-4523-00-02-NP RevisionNo.: 0 Page_...;;.__of 46 RECORD OF REVISIONS Prepared by Checked by Reviewed by Approved by Rev. Descri tion Date Date Date Date 0 Original Issue J.E. Broussard Princi al En ineer

-M. Burkardt En ineer G.A. White Princi al En ineer The last revision number to reflect any changes for each section of the calculation is shown in the G.A. White inci al En ineer Table of Contents. The last revision numbers to reflect any changes for tables and figures are shown in the List of Tables and the List of Figures. Changes made in the latest revision, except for Rev. 0 and revisions which change the calculation in its entirety, are indicated by a double line in the right hand margin as shown here.

NON-PROPRIETARY VERSION

Dominion fnvineeriny, Inc. NON-PROPRIETARY VERSION

Title:

North Anna Power Station Unit 1 RPV Corrosion Feature Evaluation CalculationNo.: C-4523-00-02-NP RevisionNo.: 0 Page 2 of_4....:....;6:.__~

TABLE OF CONTENTS Last Mod.

Section Page Rev.

PURPOSE ....................................................................................................................................................... 5 0 2

SUMMARY

OF RESULTS *************************************************************************************************************************************** 5 0 3 INPUT REQUIREMENTS***************************************************************************************************************************************** 6 0 4 ASSUMPTIONS********************************************************************************************************************************************* 7 0 5 ANALYSIS***************************************************************************************************************************************************************** 9 0 5.1 UpperCorrosionFeatureEvaluation ................................................................... 9 0 5.1.1 Evaluation Methodology ........................................................................ 9 0 5.1.2 Reactor Vessel ClosureFlange Model ................................................... 9 0 5.1.2.1 Model Geometry .................................................................. 9 0 5 .1.2.2 Thermal Model Boundary Conditions and Analysis ........... 10 0 5 .1.2.3 Structural Model Boundary Conditions and Analysis ......... 10 0 5 .1.3 Analysis Results ................................................................................... 11 0 5 .1.3 .1 Results Discussion ............................................................. 11 0 5.1.4 ANSYS Input Listings and Output Files ................................................... 12 0 5.2 Lower Corrosion Feature Evaluation ................................................................. 12 0 5 .3 Quality Assurance Software Controls ............................................................... 13 0 5 .4 Software Usage QA Records ............................................................................. 14 0 6 REFERENCES ............................................................................................................................................. 14 0 A FINITE ELEMENT ANALYSIS INPUT LISTINGS ............................................................................................ 22 0

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A. I File: PWR- NAPS- RPV.txt. ........................................................................................... 22 0

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LIST OF TABLES Last Mod.

Table No. Rev.

Table 1. FEA Model Inputs 0 Table 2. Material Properties Data 0 Table 3. North Anna RPV Closure Flange Analysis Results 0 Table 4. Contents of DEi Data Disk D-4523-00-01 [13] 0 LIST OF FIGURES Last Mod.

Figure No. Rev.

Figure 1. North Anna RPV Closure Analysis Model 0 Figure 2. Model Detail Showing Vessel Path Locations 0

Dominion fn~ineeri~, I NON-PROPRIETARY VERSION

Title:

North Anna Power Station Unit I RPV Corrosion Feature Evaluation CalculationNo.: C-4523-00-02-NP RevisionNo.: 0 Page 5 46 1 PURPOSE The purpose of this calculation is to document analyses that have been performed to evaluate two conservatively bounded corrosion features in the reactor pressure vessel (RPV) at North Anna Unit 1.

One feature is located at the transition of the vessel flange to the upper shell, and the second feature is located at the bottom of the vessel shell, adjacent to one of the four radial support keyways.

2

SUMMARY

OF RESULTS Based on the analyses performed, a local corrosion feature up to 1.0 inches in depth at both locations continues to meet ASME Boiler and Pressure Vessel Code Section III criteria, as follows.

For the upper corrosion feature:

o The primary local membrane plus bending stress intensity for the intact vessel transition region is 18.3 ksi, a factor of 2.2 below the l .5Sm limit of 40.05 ksi. This is greater than the conservative estimate of 1.23 for increase in local stress due to corrosion.

o The primary plus secondary stress intensity range, considering the heat-up transient only, forthe intact vessel transition region is 26.5 ksi, a factor of 3.0 below the 3Sm limit of 80.1 ksi. This is much greater than the conservative estimate of 1.23 for increase in local stress due to corrosion.

o The fatigue usage for the intact vessel transition region, reported in Reference [4, p 8-6] to beno more than 0.00830, is well below the allowable of 1.0. Increasing the stress ranges using a fatigue strength reduction factor of 4.0 results in an estimated fatigue usage below the allowable of 1.0.

For the lower corrosion feature:

o The primary local membrane plus bending stress intensity for the radial support keyway and shell is a factor of 1.58 below the allowable value. This is greater than the estimate of 1.25 for increase in local stress due to corrosion conservatively based on the wall thickness of the bottom head.

o The primary plus secondary stress intensity range for the radial support keyway and shell is a factor of 1.96 below the allowable value. This is greater than the estimate of 1.25 for increase in local stress due to corrosion conservatively based on the wall thickness of the bottom head.

o The fatigue usage for the radial support keyway and shell is 0.02182, well below the allowable of 1.0. Increasing the stress ranges using a fatigue strength reduction factor of 4.0 results in an estimated fatigue usage below the allowable of 1.0.

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3 INPUT REQUIREMENTS The following inputs are required for this calculation.

1. The location of the upper corrosion feature is defined in Reference [7] as being 24 to 32 inches below the vessel flange. This elevation is close to the transition from the thicker vessel flange cylinder (the section containing the core barrel groove) to the thinner cylindrical region above the inlet and outlet nozzles. Furthermore, an included figure in Reference [8] identifies the corrosion feature as being located at the flange to shell transition region.

2. The location of the lower corrosion feature is defined in Reference [9] as being adjacent to the radial support keyway, at the lower portion of the RPV cylindrical shell near the junction with the bottom head. The vessel wall thickness in this area transitions down from the thickness of the cylindrical shell down to the thickness of the bottom head.

3. 'Reactor vessel head and closure flange dimensions. The geometry of the model developed for the analysis of the upper corrosion feature is consistent with the one used in the Reference [1],as supplemented by inputs in Reference [2]. The model parameters used in this FEA model are detailed in Table 1. It is specifically noted that the shell thickness at the upper transition region is 9.843 inches [3, p. 5.1-1]. ,r---Confidentia!Commerciallnfonnation--~

4. The lower cylindrical shell of the RPV is ( )inches thick, and the bottom head is ( )inches thick [3, p. 5.1-1 ]. The calculated required wall thickness based on the primary membrane stress due to design pressure is 3.868 inches for the undisturbed region of the bottom head [3, p.5.1-1].

5. Thermo-physical and structural material properties are input as a function of temperature. The values are taken from Reference [6]. The values input for the analysis are reported in Table 2.

6. The following ASME Code Section III [5] stress limits are applicable for this evaluation:

a. Primary Local Membrane Plus Bending stress intensity is limited to 1.5Sm.

b. Primary Plus Secondary Stress Intensity Range is limited to 3Sm.

c. Peak stress intensity is limited by fatigue, with a calculated fatigue usage of less than 1.0.

d. For both SA-508 Class 2 and SA-533 Grade B Class 1 materials, the value of Sm is invariant with temperature, and is equal to 26. 7 ksi.

7. The fatigue usage at various locations on the closure flange is summarized in the closure flange design basis report [4, p 8-6]. The fatigue usage in the closure head flange to shell junction is reported as 0.02865 and the fatigue usage in the vessel flange to shell junction is reported as 0.00830. Additional detail for these calculations is provided in [4, Section C.3.1].

8. The following stress values for the radial support keyway and adjacent shell in the region where the wall thickness transitions to the thickness of the bottom head are taken from North Anna design basis report summary [3, p. 5.5-3]:

a. Primary Local Membrane Plus Bending stress intensity= 25.35 ksi vs 40.05 ksi allowable

b. Primary Plus Secondary stress intensity range = 40.90 ksi vs 80.10 ksi allowable

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c. Fatigue Usage= 0.02182 vs 1.0 allowable 4 ASSUMPTIONS The following assumptions are used in this calculation.

1. A corrosion feature size of 1.0 inches in depth is assumed for this evaluation. It is assumed that the feature is localized; i.e., not a uniform reduction of wall thickness over the entire vessel inside surface. This is demonstrated to be appropriate based on pictures of the two corrosion regions provided in References [7] and [9].

2. In the analysis of the closure flange region, the value for the convective heat transfer coefficient within the RPV is assumed to be ( )

• for the vessel and head wetted surfaces based on other similar evaluations. This value is consistent with the 500 BTU/hr/ft2/°F heat transfer coefficient used in the Rotterdam design basis calculation [4, pp. A.2-1 to A.2-3]. *Confidential Commercial Information

3. In the analysis of the closure flange region, all contact surfaces in the thermal model are treated as bonded contact. A large thermal conductance coefficient of lxl 04 BTU/s/in2/°F is applied at each bonded contact surface to minimize the thermal resistance through the interface.

4. In the analysis of the closure flange region, the results reported are for the intact vessel case that does not consider the upper corrosion feature. An estimate of the additional stress resulting from a one-inch deep local corrosion feature can be made by conservatively assuming the stresses are primarily from bending due to stud pre load. The increase in stress of the reduced section can be estimated by assuming the section acts as a beam in bending. The thickness of the section is equivalent to the height of the beam cross-section in calculating the beam*bending stress, as follows [14].

In this example, the bending stress is inversely proportional to the square of the beam height; likewise, the section stress is assumed to change by the square of the change in thickness for the cross section. The local corrosion feature depth is about 10% of the intact wall; therefore, stresses are estimated to increase according to a factor of (1/0.9) 2 = 1.23. This approach is conservative as a wall thickness reduction has only a linear effect on the stress component due to internal pressure.

5. In the analysis of the lower corrosion feature, it is assumed that stresses are primarily a result of internal pressure, and therefore increase linearly with reduced thickness. A comparison of the Primary Local Membrane Plus Bending stress intensity (Input 8.a) with the nominal hoopstress in a cylindrical vessel due to internal pressure shows that the primary stress at this location is in

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fact dominated by internal pressure. A I-inch reduction in thickness for the lower shell at the transition to the bottom head is about a 20% reduction conservatively based on the thickness of the adjoining bottom head (5.039 inches; Input 4); therefore, stresses are estimated to increase according to a factor of (1/0.80) = 1.25.

6. In the analysis of the lower corrosion feature, only the resulting fatigue usage of 0.02182 at the keyway and adjacent shell is known (Input 8.c). This low value shows that many of the design basis transient stress amplitude values do not exceed the fatigue limit of 12.5 ksi for carbonsteel materials [5]. For the purpose of quantitatively assessing the effect on this low fatigue usage factor, the following reasonable assumptions are made based in part on information in

[4, p. 7-10] and [15]:

a. The unconcentrated stress amplitude is 12 ksi.

b. The fatigue strength reduction factor is 1.67.

These values result in a 20 ksi peak stress amplitude with 100,000 allowable cycles [5] and2,182 applied cycles to reach to usage of 0.02182. It is also noted that the fatigue usage calculated at the keyway and adjacent shell is similar to the fatigue usage calculated at the closure flange region (Input 7), where more details are available on the fatigue calculation methodology. The more detailed results are generally consistent with these assumed values.

7. The effect of the corrosion feature on fatigue is considered by assuming a fatigue strength reduction factor of 4.0. A value of 4.0 is used for locations such as the root of threads [5, Paragraph N-416.2(b)(4)], and is considered a conservative estimate.

8. In the analysis of the closure flange region, a 100°F / hour heat-up transient from 100°F to operating temperature is used as a bounding transient analysis to evaluate stresses in the vessel flange to shell transition. This transient typically leads to the highest overall stresses in the closure region because the closure flange heats up faster than the closure studs, leading to additional load carried by the closure studs. The temperature difference between the flange and the studs is on the order of 200°F due to the rate and duration of this design basis transient. The I 00°F / hour design basis heat-up transient is defined as follows, consistent with typical design basis transient values:

Time [Hours] Temperature [°F] Pressure [psi]

"' Confidential Commercial Information

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5 ANALYSIS The upper and lower corrosion features are evaluated based on the stress conditions present at each respective feature location. The upper corrosion feature is at the vessel flange to shell transition, where bending stresses due to the closure flange bolting combine with other thermal and pressure stresses.

Therefore, the upper corrosion feature is evaluated using stresses obtained from a finite element analysis model of the closure flange region. In contrast, the shell region is primarily loaded with pressure stresses. Therefore, the lower corrosion feature is evaluated using stress information from the reactor vessel design basis report [3] for the lower shell in the region of each radial support keyway.

5.1 Upper Corrosion Feature Evaluation 5 .1.1 Evaluation Methodology The stresses at the corrosion feature location were analyzed using a three-dimensional model of the closure flange region, shown in Figure 1. As shown in Figure 1, the circumferential extent ofthemodel represents one stud pitch, with the stud and stud hole centered in the model. The corrosion feature is not explicitly modeled in the analysis. Instead, the stresses at the corrosion feature location are evaluated in the context of the corroded region.

Four loading conditions are considered for the model: (1) stud preload only, (2)stud preload plus design pressure, (3) stud preload plus operating pressure at operating temperature, and (4) 100°F / hour design basis heat-up transient.

5.1.2 Reactor Vessel Closure Flange Model 5.1.2.1 Model Geometry The meshed model geometry shown in Figure 1 was used to generate both thermal and structural finite element models. The solid portions of the model were generated using SOLID90 20-node thermal brick elements and SOLID95 20-node structural brick elements. In both the thermal and structural models, contact surfaces were overlaid on the brick elements using CONTAl 74 and TARGEI 70 8-node surface elements, which can be either thermal or structural elements depending on their setup parameters.

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North Anna Power Station Unit 1 RPV Corrosion Feature Evaluation CalculationNo.: C-4523-00-02-NP RevisionNo.: 0 Page- 10- -of 46 5.1.2.2 Thermal Model Boundary Conditions and Analysis The circumferential edges of the thermal model are not constrained; therefore, they are treated as adiabatic surfaces. This is appropriate given the model's symmetry assumptions. The outer surfaces of the head, vessel, and stud were treated as adiabatic, and all thermal loads were applied as convective heat transfer surfaces on the wetted (interior) portions of the model.

Conductance between mating parts of the model (:flange mating surface, nut to head :flange, stud to nut, and stud to vessel flange) is simulated using contact surfaces. In the thermal model, all contact surfaces are treated as bonded contact, with a high (lxl 04 BTU/s/in2/°F) thermal conductance coefficient (i.e.,

no temperature discontinuity across the contact surface).

A heat-up transient with a heat-up rate of 100°F / hour was simulated using a transient thermal analysis per Assumption 8.

5.1.2.3 Structural Model Boundary Conditions and Analysis In the structural model, symmetry boundary conditions are applied by restraining the circumferential displacements at the edges of the model. The remaining structural boundary conditions are enforced by contact surfaces at the mating parts of the model (:flange mating surface, nut to head :flange, stud to nut, and stud to vessel :flange). The nut to head :flange and stud to nut surfaces are held in bonded contact, and the :flange mating surface is in standard (compression-only) rough contact. Since the flange mating surface is in standard contact, the rotation of the head due to mechanical and thermal loads is allowed to cause separation as applicable at the :flange mating surface.

The bottom of the stud at the vessel :flange threaded hole is held by two different contact types. The OD surface of the stud is in standard contact with the ID of the "threaded" region hole, providing shear resistance during bending loads. Axial restraint is provided by the bonded contact between the bottom of the stud and the bottom of the vessel flange hole. If bonded contact were enforced at the OD surface of the stud, it would unrealistically limit radial shrinkage of the stud under axial loads due to the Poisson effect, leading to unrealistic tensile radial stresses. The contact arrangement used in the model best represents the stress state at the top of the vessel :flange, where bending due to :flange rotation is combined with the axial stress of pre load. Stresses at the bonded surface at the bottom of the stud are due to the necessary but artificial constraints, and may be ignored.

Dominion yineeri°", Inc. NON-PROPRIETARY VERSION

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North Anna Power Station Unit 1 RPV Corrosion Feature Evaluation CalculationNo.: C-4523-00-02-NP Revision No.: 0 Page'"'"""lc....;.;l__of 46 The first analysis step in the structural model is to preload the stud, simulating the loaded configuration of the vessel flange joint. Pre loading the model is accomplished by using the PSMESH command, which separates the stud component into two pieces. At the first load step, the two pieces are pulled together to generate the design basis preload force. At every other subsequent step, this force is

~'locked" in as a displacement load, which allows the model to simulate the combined effects of thermal displacement and mechanical loads, even in the presence of the non-linear contact surfaces.

In order to simulate the structural response to the thermal transient, the finite element model is designed to automatically read in the results of the thermal model as body force temperature loads, and then apply the appropriate pressure at the same time step (see Assumption 8). The structural analysis of each transient proceeds as a series of static load steps.

5 .1.3 Analysis Results Stress component data for a cylindrical coordinate system centered on the vessel are obtained for two path lines at the vessel flange to shell transition region; radial, hoop, and axial stress components are recorded. The path line locations are shown in Figure 2. When the model is post-processed, the stress data are linearized consistent with ASME Code methodology, and the membrane plus bending stress values for the three component directions are recorded. The differences between these principal directions are then used to calculate the three different stress intensity values. The results data and the calculated stress intensities are reported in Table 3 for all four loading conditions; stresses for all structural time steps considered in the analysis are reported for the heat-up transient. The stress intensity range over the heat-up transient is also reported for each stress combination.

5.1.3.1 Results Discussion As noted in Assumption 4, the results reported are for the intact vessel case that does not consider the corrosion feature. A conservative estimate of the additional stress resulting from a one-inch deep local corrosion feature is a factor of 1.23 per Assumption 4.

The preload plus design pressure load case is a suitable representation of the stress state for comparison with the Section III requirement for the primary local membrane plus bending stress limits.

The resulting maximum stress intensity at either path line is 18.3 ksi, which is a factor of 2.2 below the

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North Anna Power Station Unit 1 RPV Corrosion Feature Evaluation CalculationNo.: C-4523-00-02-NP RevisionNo.: 0 Page__;;lc.=2'---_of 46 1.5Sm limit of 40.05 ksi. This is greater than the conservative estimate of 1.23 for increase in local stress due to corrosion.

The maximum stress intensity range due to the heat-up transient is calculated to be 26.6 ksi. This value is a factor of 3.0 below the 3Sm limit of 80.1 ksi. This is greater than the conservative estimate of 1.23 for increase in local stress due to corrosion.

In evaluating fatigue, it is noted that the fatigue usage for the vessel flange is 0.00830 (Input 7).

Additional detail on the calculation methodology [4, pp. C.3.1-41 to C.3.1-42] shows this low value results from many of the design basis transient stress amplitude values not exceeding the fatigue limit of 12.5 ksi for carbon steel materials [5]. The results shown in Table 3 are consistent with this observation; the heat-up transient unconcentrated stress amplitude is half the stress intensity range calculated above, or 13.3 ksi. Further review of the fatigue calculations show stress combinations with a total of 255 applied cycles contribute to the fatigue usage. Applying a fatigue strength reduction factor of 4 (Assumption 7) to the heat-up transient stress amplitude of 13.3 ksi, then applying a modulus correction factor of 30/26.2 (the ratio of the nominal modulus value associated with the fatigue curve to the modulus value at 400°F for the flange material in Table 2), a new stress amplitude of 60.9 ksi is calculated, which has 2,300 allowable cycles [5]. Using the same 255 applied cycles, the revised fatigue usage would be 0.111, which is still well below the ASME Code allowable of 1.0.

5.1.4 ANSYS Input Listings and Output Files The thermal and structural analysis described in Section 5, as well as the post-processing of the analysis results, is performed using the ANSYS input listing file "PWR_NAPS_RPV.txt." This input listing is provided in Appendix A.

5.2 Lower Corrosion Feature Evaluation As noted in Assumption 5, the estimate of the additional stress resulting from a one-inch deep local corrosion feature for the lower shell region is a factor of 1.25. The following Code stress comparisons can be performed using the design basis stress values in Input 8:

o The primary local membrane plus bending stress intensity is a factor of 1.58 below the allowable value. This is greater than the estimate of 1.25 for increase in local stress due to corrosion conservatively based on the wall thickness of the bottom head.

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North Anna Power Station Unit 1 RPV Corrosion Feature Evaluation CalculationNo.: C-4523-00-02-NP RevisionNo.: 0 Page 13 of 46 o The primary plus secondary stress intensity range is a factor of 1.96 below the allowable value.

This is greater than the estimate of 1.25 for increase in local stress due to corrosion conservatively based on the wall thickness of the bottom head.

Furthermore, per Input 4, the thickness of the undisturbed region of the bottom head is more than 1.0 inch greater than the required thickness calculated on the basis of the primary membrane stress due to design pressure. The penetrations in the bottom head are remote from the location of the lower corrosion feature at the bottom of the cylindrical shell.

In evaluating fatigue, it is noted that the fatigue usage for the keyway and adjacent pad is equal to 0.02182, as reported in Input 8.c. Similar to the closure flange (see Section 5.1.3.1), this low value indicates many of the design basis transient stress amplitude values do not exceed the fatigue limit of 12.5 ksi for carbon steel materials [5]. Assuming an unconcentrated stress amplitude of 12 ksi and a fatigue strength reduction factor of 1.67 (Assumption 6) results in a 20 ksi peak stress amplitude with 100,000 allowable cycles [5], or 2,182 applied cycles to reach to usage of 0.02182. This is a conservatively high number of cycles relative to the actual values for the closure flange identified in Section 5.1.3.1. If a fatigue strength reduction factor of 4.0 is assumed (see Assumption 7), the revised stress amplitude is 48 ksi, which has 5,000 allowable cycles [5]. Using the same 2,182 applied cycles, the revised fatigue usage would be 0.436. This is a notable increase, but still below the allowable of 1.0.

5.3 Quality Assurance Software Controls The analyses reported in this calculation were performed on the "ANSYS-A" Dell Precision R7910 workstation, using Windows Server 2012 R2 64-bit operating system and ANSYS Version 15.0 provided by ANSYS, Inc. which was verified on February 8, 2018, as documented in Reference [10].

This software is maintained in accordance with the provisions for control of software described in Dominion Engineering, Inc.'s (DEI's) quality assurance (QA) program for safety-related nuclear work

[11 ]. 1 In addition to QA controls associated with the procurement and use of the AN SYS software (e.g., maintenance of ANSYS Inc. as an approved supplier of the software based on formal auditing 1

DEI's quality assurance program for safety-related work (DEI-002) commits to applicable requirements of 10 CFR 21, Appendix B of 10 CFR 50, and ASME/ANSI NQA-1. This QA program is independently audited periodically by both NUPIC (the Nuclear Procurement Issues Committee) and NIAC (the Nuclear Industry Assessment Committee).

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North Anna Power Station Unit 1 RPV Corrosion Feature Evaluation CalculationNo.: C-4523-00-02-NP RevisionNo.: 0 Page_l_4__of 46 and surveillance; formal periodic verification of ANSYS software installation), QA controls associated with all ANSYS batch input listings are also carried out by DEL These include independent checks of a batch input listing each time it is used; review of all ANSYS Class 3 error reports and QA notices to assess their potential impact on a batch input listing; and independent confirmatory analyses2 to ensure that the project-specific application of the analysis is appropriate. The review of ANSYS error reports and QA notices as well as the project-specific check calculations are documented formally in a QA memo to the project file [12].

5.4 Software Usage QA Records This calculation includes results that were generated using ANSYS finite element analysis (FEA) software, which is pre-verified software under the QA program. No other pre-verified software (i.e.

software which would require software usage QA records to be archived and traceable to work products) was utilized to support the calculation. The traceability of software usage QA records was accomplished via records which are identified in this calculation and archived in the task project file on Data Disk D-4523-00-01 [13]. The complete set ofrequired ANSYS software usage QA records associated with this calculation are listed in Table 4. No other files were needed to re-create the runs, and no additional files were requested by the customer. One time use spreadsheets were not used during generation of this calculation.

6 REFERENCES

1. DEi Report R-4509-00-1, Rev. 0, "Reactor Vessel Bolting Evaluations -North AnnaPower Station," August 1998,Section III.

2. Rotterdam Dockyards Drawing No. 30661-1808 RO, "Dimensions of Flanges, Stud, Nutand Washers - 157" PWR Vessel North Annal," Figure F3-l ofNorth Anna Design Report.

3. Rotterdam Dockyards Report No. 30660-1130, Rev. 1, "Final Stress Report (Part 1)-PWR Vessels North Anna I & II," May 1976.

4. Rotterdam Dockyards Report No. 30660-1103, Rev. 2, "Analysis of the Main Closure - PWR Vessels North Anna I & II," August 1975.

5. ASME Boiler and Pressure Vessel Code,Section III, 1968 Edition with Addenda through Winter 1968.

2 Confirmatory analyses for a given project may include comparison of model-computed stresses to theoretical closed-form solutions.

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North Anna Power Station Unit 1 RPV Corrosion Feature Evaluation CalculationNo.: C-4523-00-02-NP RevisionNo.: 0 Page 15 of 46

6. ASME Boiler and Pressure Vessel Code, Section II-D, 2004Edition.

7. Incoming Correspondence IC-4523-00-01, Email from Roger Galbraith, Dominion Energyto Glenn White, DEi, dated February 7, 2018.

8. Incoming Correspondence IC-4523-00-02, Email from Roger Galbraith, Dominion Energyto Glenn White, DEi, dated March 2, 2018.

9. "North Anna N1R26 Remote Visual Examination Indication Notification Report,"Framatome INR-N1R26-18-002, dated March 23, 2018.

10. Dominion Engineering, Inc. Software Test Report No. STR-9898-00-21, Revision 0, "ANSYS 15.0 Re-Verification on ANSYS-A.DOMENG.COM Software Test Report." February 2018.

11. Dominion Engineering, Inc. Quality Assurance Manual for Safety-Related Nuclear Work, DEI-002. Revision 18, November 2010.

12. Dominion Engineering, Inc. Memorandum M-4523-00-02, "ANSYS Confirmatory Analysis and Review of Error Notices for C-4523-00-02." Revision 0, March 2018.

13. Dominion Engineering, Inc. Data Disk D-4523-00-01. Revision 0, March 2018.

14. Young, Warren C., Roark's Formulas for Stress and Strain, Sixth Edition, McGraw-Hill, Inc.,

1989.

15. Peterson, R. E., Stress Concentration Factors, John Wiley & Sons, Inc. 1974.

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North Anna Power Station Unit 1 RPV Corrosion Feature Evaluation CalculationNo.: C-4523-00-02-NP Revision No.: 0 Page 16 of 46 Table 1. FEA Model Inputs NAPS Model Data

,. Parameter I Units: Value Ill Confidential Commercial Information

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North Anna Power Station Unit 1 RPV Corrosion Feature Evaluation CalculationNo.: C-4523-00-02-NP Revision No.: 0 Page 17 of 46 Table 2. Material Properties Data Closure Flange, Vessel Flange Property !units I Values Confidential Commercial Information I

- Closure Head Shell and Vessel Shell

,II Property Iunits I Values

. Confidential Commercial Information Bolt, Nut, and Washer Property !units I Values

. Confidential Commercial Information

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North Anna Power Station Unit I RPV Corrosion Feature Evaluation CalculationNo.: C-4523-00-02-NP RevisionNo.:- - Page_l_8_ _of 46 Table 3. North Anna RPV Closure Flange Analysis Results Vessel Path 1 - Inside Surface Stress Intensi si)

Load Step Sr-t St-x Sx-r Confidential Commercial Information Range Vessel Path 2 - Inside Surface Stress Intensi si)

Sx (axial) Sr-t St-x Sx-r Confidential Commercial Information Range

Do

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North Anna Power Station Unit 1 RPV Corrosion Feature Evaluation CalculationNo.: C-4523-00-02-NP RevisionNo.: 0 Page -of 46 Table 4. Contents ofDEI Data Disk D-4523-00-01 (13]

File Name Description PWR- NAPS- RPV.txt Input file that defines the geometry, runs the analysis, and post-processes the results.

results.out Formatted output file that reports the stresses in the studs and selected stress path information for the closure head and vessel flange PWR- NAPS- RPV.out Full output file generated automatically that includes every ANSYS operation performed throughout the analysis.

PWR- NAPS- RPV.err Automatically generated error file that includes all warnings generated during the analysis.

transplots.grph Output plot data file used to generate report figures.

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North Anna Power Station Unit I RPV Corrosion Feature Evaluation CalculationNo.: C-4523-00-02-NP RevisionNo.: 0 Page -of 46 Figure 1. North Anna RPV Closure AnalysisModel

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North Anna Power Station Unit I RPV Corrosion Feature Evaluation CalculationNo.: C-4523-00-02-NP RevisionNo.: 0 Page -of 46 Vessel PATH I Vessel PATH 2 Figure 2. Model Detail Showing Vessel PathLocations 12100

• Rtston, VA 20191

• PH

• FX 703.65U301

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North Anna Power Station Unit 1 RPV Corrosion Feature Evaluation Calculation No.: C-4523-00-02-NP RevisionNo.: 0 Page-==;.__- 46 A FINITE ELEMENT ANALYSIS INPUT LISTINGS A. I File: PWR NAPS RPV.txt Confidential Commercial Information

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Serial No.: 19-156 Attachment 5 Calculation C-4523-00-01-NP, "Evaluation of Potential Low-Alloy Steel Corrosion at Cladding Defects of NAPS1 Reactor Vessel"

[Non-Proprietary Version]

Revision 0 Virginia Electric and Power Company (Dominion Energy Virginia)

North Anna Power Station Unit 1

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Evaluation of Potential Low-Alloy Steel Corrosion at Cladding Defects of NAPS 1 Reactor Vessel Calculation No.: C-4523-00-01-NP Revision No.:- - 0- Page 1 of 21 RECORD OF REVISIONS Rev. Description 0 Original Issue M. Burkardt A.J. Simon G. A. White G. A. White Engineer Associate Engineer rincipal Engineer P ncipal Engineer The last revision number to reflect any changes for each section of the calculation is shown in the Table of Contents. The last revision numbers to reflect any changes for tables and figures are shown in the List of Tables and the List of Figures. Changes made in the latest revision, except for Rev. 0 and revisions which change the calculation in its entirety, are indicated by a double line in the right hand margin as shown here.

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Evaluation of Potential Low-Alloy Steel Corrosion at Cladding Defects of NAPS 1 Reactor Vessel Calculation No.: C-4523-00-01-NP Revision No.: 0 Page 2 of 21 TABLE OF CONTENTS Last Mod.

Section Page Rev.

1 PURPOSE ..................................................................................................................................... 4 0 2

SUMMARY

.................................................................................................................................... 5 0 2.1 Summary of Results ....................................................................................................... 5 0 2.2 Conclusion ...................................................................................................................... 6 0 3 INPUT REQUIREMENTS .................................................................................................................. 6 0 4 ASSUMPTIONS .............................................................................................................................. 7 0 5 ANALYSIS ..................................................................................................................................... 9 0 5.1 Applicable Chemical Environments and Associated Duty Times .................................... 9 0 5.1.1 General Corrosion ............................................................................................ 9 0 5.1.2 Localized Corrosion ....................................................................................... 11 0.

5.1.3 Flow-Accelerated Corrosion (FAC) ................................................................ 11 0 5.2 Corrosion Rate Laboratory Data ................................................................................... 12 0 5.3 Cumulative Corrosion ................................................................................................... 12 0 6 REFERENCES ......... ;...................................................................................... :............................ 15 0

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LIST OF TABLES Last Mod.

Table No. Rev.

Table 1. Summary of Conservatively Calculated Corrosion Depth 0 Table 2. Summary of Conservatively Assumed PWR Operating Conditions for BAC 0 Assessment Table 3. Summary of Relevant Corrosion Rates for Conservatively Assumed Operating 0 Conditions LIST OF FIGURES Last Mod.

Figure No. Rev.

Figure 1. Photo of Cladding Defect in the Shell Flange Section of the Reactor Vessel from 0 2009 Examination with Indication Measurement [1 a]

Figure 2. Photo of Cladding Defect in the Shell Flange Section of the Reactor Vessel from 0 March 2018 Examination with Indication Measurement [2]

Figure 3. Close-Up Photo of Cladding Defect in the Shell Flange Section of the Reactor 0 Vessel from March 2018 Examination [2]

Figure 4. Photo of Cladding Defect near a Radial Support Keyway from March 2018 0 Examination with Indication Measurement [3]

Figure 5. Diagram Depicting Conservatively Assumed Operating Conditions for Refueling, 0 Cold Shutdown, Startup/Shutdown, and Normal Operation

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1 PURPOSE In 2009, a cladding defect was observed in the shell flange section of the reactor vessel at North Anna Power Station (NAPS) Unit 1. This narrow defect was observed to be located midway between adjacent primary nozzles, near the elevation of the transition in wall thickness, with a maximum extent along the cladding surface of about 1.8 inches [la] (see Figure 1). DEI understands that the defect was suspected of being formed during core barrel removal during the 2009 refueling outage.

In March 2018, NAPS conducted a IO-year reactor vessel inservice examination for Unit 1. During the 2018 EVT-1 enhanced visual examination, NAPS visually examined the cladding defect area and checked the extent of the cladding defect exposing the underlying low-alloy steel (see Figure 2 and Figure 3) [2]. The examination also identified a second cladding defect near a radial support keyway, in the area of the cylindrical shell-to-bottom head transition (see Figure 4) [3]. The examination vendor reported that no indication of cracking was visible in the area surrounding either indication ([2], [3]).

In both cases, the examination photos do not show any discernible corrosion of the underlying low-alloy steel material, and no rust bleed-out or discoloration is visible in the area surrounding either indication.

As discussed in the EPRI Boric Acid Corrosion (BAC) Guidebook [4], only small amounts of corrosion are expected to affect areas of missing or damaged reactor vessel cladding. During full-power operation, the applicable corrosion rate is extremely low due to the deaerated, near-neutral pH conditions. During refueling, startups, and shutdowns, higher corrosion rates are applicable, but the exposure times are limited. In addition, stresses in the shell flange region away from the primary nozzles are expected to be relatively small.

This calculation conservatively assesses the increase in corrosion depth over future operation of the underlying low-alloy steel material. This result is applied in combination with a conservatively estimated bound on the low-alloy steel corrosion depth based on the examination results from the March 2018 refueling outage to assess the acceptability for future operation of the exposed areas of low-alloy steel associated with the two cladding defects. A separate DEI calculation is referenced as the basis for the acceptable corrosion feature depth for which the ASME design Code stress limits will be satisfied.

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2

SUMMARY

2.1 Summary of Results Corrosion rate data documented in the BAC Guidebook [4] for carbon and low-alloy steel were conservatively applied for each type of chemical environment within a PWR reactor vessel. The highest corrosion rate reported for all immersion tests (i.e., general corrosion) applicable to each chemical environment was conservatively assumed. The total amount of future corrosion was projected with conservative assumptions regarding the portion of future operation when more aggressive conditions exist due to reduced pH and aeration. The unfavorable conditions that are known to have led to substantial amounts of low-alloy steel corrosion at cladding defects (ongoing air in-leakage during normal operation and highly concentrated boric acid associated with pressure boundary leakage or evaporation of a limited volume of liquid) are not credible for the reactor vessel interior.

Furthermore, as discussed in Sections 5.1.2 and 5.1.3, localized and flow-accelerated corrosion are not considered to be of significant concern for areas of reactor vessel low-alloy steel material exposed to primary coolant.

The conservatively predicted cumulative amount of corrosion is shown in Table 1 for cases of interest.

The additional corrosion in one 18-month cycle (with a 30-day refueling outage) was calculated to be 0.012 inch. This corresponds to 0.077 inch in 10 years, 0.153 inch in 20 years, and 0.307 inch in 40 years. The conservative estimate of a depth which bounds any corrosion of the underlying low-alloy steel at either cladding defect, as examined in March 2018, is 0.25 inch (per Assumption 8). Thus, the total depth of either defect is conservatively estimated to be less than 0.262 inch in 18 months, less than 0.327 inch in 10 years, less than 0.403 inch in 20 years (until the 60-year license expiration date),

and less than 0.557 inch in 40 years (until an 80-year license expiration date). (The current (i.e., first) renewed license for North Anna Unit 1 expires on April 1, 2038 [5].) The total amount of corrosion evaluated over the full 80-year operating life is calculated to be 0.619 inch.

The conservatively predicted future corrosion for operation until the 80-year license expiration date (expected to be April 1, 2058, i.e., for an additional 40 years) is within the acceptable corrosion feature depth for which the ASME design Code stress limits will be satisfied. As demonstrated for the North Anna Unit 1 reactor vessel in C-4523-00-02 [6], a corrosion feature at the location of both subject cladding defects with a depth of at least 1.0 inch would result in stresses satisfying the ASME Section III design limits.

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2.2 Conclusion On this basis, the subject cladding defects are concluded to be acceptable for operation until the end of an 80-year licensing period. Additional visual examinations of the cladding defects are considered appropriate when the core barrel is removed for a subsequent reactor vessel ISI examination and the areas in which each cladding defect is located become accessible. Reactor vessel ISI examinations (which are required on a nominal interval of 10 years, or 20 years with NRC approval of a 20-year alternative) are opportunities to examine the cladding defects and confirm that any discernible low-alloy steel corrosion is bounded by the conservative predictions of this calculation.

Note that the conclusion regarding the acceptability of the cladding defects for future operation is not dependent on when the defects were formed. The corrosion depth projected for the full 80 years of operation for either defect is within the acceptance limit, and the March 2018 visual examination results place a constraint on the credible defect depths at that time.

Plant experience supports the conclusion of this calculation that the subject cladding defects are acceptable for long-term future operation. Several cases at other PWRs with areas of damaged, missing, or intentionally removed reactor vessel cladding are described in WCAP-15338-A [7]. In all these cases, the cladding defects were reported to be inconsequential. Severe corrosion rates of exposed low-alloy steel in PWRs can be caused by highly concentrated boric acid associated with pressure boundary leakage or evaporation of a limited volume of liquid (such has been reported for a steam generator channel head ([18], [19])). Such unfavorable environmental conditions are not credible for the interior of PWR reactor vessels.

3 INPUT REQUIREMENTS The following inputs were used in support of this calculation:

1. As-found length of the reactor vessel cladding defect in the shell flange section of the reactor vessel in 2009 [la]: 1.793 inch. (reproduced in Figure 1)

2. As-found dimensions of the reactor vessel cladding defect in the shell flange section of the reactor vessel in March 2018 [2] (reproduced in Figure 2 and Figure 3)

a. Maximum horizontal (circumferential) extent along the surface: 2.02 inches

b. Maximum vertical (axial) extent along the surface: 0.274 inch

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3. As-found dimensions of the reactor vessel cladding defect near a radial support keyway in March 2018 [3] (reproduced in Figure 4)

a. Maximum horizontal (circumferential) extent along the surface: 0.688 inch

b. Maximum vertical (axial) extent along the surface: 0.136 inch

4. 60-year license expiration date: April 1, 2038 [5]

5. NAPS Unit 1 operates on a 18-month refueling cycle [l]

6. Allowable corrosion feature depth demonstrated in C-4523-00-02 [6] for both defect locations: at least 1.0 inch

7. The shell flange section of the NAPS Unit 1 reactor vessel was fabricated using an SA-508 Class 2 (now referred to as SA-508 Grade 2 Class 1) low-alloy steel forging [8].

8. The cylindrical shell of the NAPS Unit 1 reactor vessel was fabricated using SA-508 Class 2 (now referred to as SA-508 Grade 2 Class 1) low-alloy steel forgings, while the adjoining bottom head section was fabricated using SA-533 Grade B Class 1 low-alloy steel plate material [8].

4 ASSUMPTIONS

1. Plant operating conditions are considered to be constant during each of the explicitly considered operating periods (refueling water, cold shutdown, startup/shutdown, and normal operating conditions). Operating conditions captured in Assumptions 2 through 5 are developed to provide a conservative representation of the operating conditions at NAPS Unit 1 on the basis of the requirements specified in the EPRI Primary Water Chemistry guidelines [9].

2. The constant operating conditions for refueling water are assumed to be:

a. Temperature: typically less than 49°C (120°F)

b. Oxygen condition: aerated [9, Section 3 and 4]

c. Boron: 2200 ppm (typical concentration [9])

d. Lithium: 0 ppm [9]

e. Minimum pHT: 4.64 (evaluated at 25°C (77°F) [10, Table A-10])

f. Duration: 45 days for first 20 years of operation, 30 days for 20-80 years of operation [l]

3. The constant operating conditions for cold shutdown are assumed to be:

a. Temperature:< 121 °C (< 250°F) [IO, Section 3]

b. Oxygen condition: aerated [9, Section 4]

c. Boron: 2200 ppm [9]

d. Lithium: 0 ppm [9]

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e. Minimum pHT: 4.69 (Calculated using the EPRI ChemWorks pH Calculator [11 ], at 2200 ppm B and Oppm Li at I00°C.)

f. Duration: 7 days (typically, cold shutdown lasts at most a few (e.g., 1-3) days)

4. The constant operating conditions for startup/shutdown are assumed to be:

a. Temperature: 121-300°C (250-572°F) [10, Section 3]

b. Oxygen condition: deaerated [9, Section 4]

c. Boron: 2200 ppm [9]

d. Lithium: 0 ppm [9]

e. Minimum pHT: 4.7 (Calculated using the EPRI ChemWorks pH Calculator [11], at 2200 ppm Band Oppm Li at 121 °C. The pHT for the same Band Li levels at 300°C was calculated to be 5.11.)

f. Duration: 7 days (typically, startup or shutdown each lasts at most a few (e.g., 1-3) days)

5. The constant operating conditions for normal operation are assumed to be:

a. Temperature: 300°C (572°F) (typical reference value for average RCS temperature)

b. Oxygen condition: deaerated [10, Section 3]

c. Minimum pHT: 6.9 (pHT ranges from 6.9 to 7.4 per [10, Section3])

d. Duration: Remainder of 1.5 years, per Input 5 (503.9 days when assuming 30-day refueling outages, 488.9 days when assuming 45-day refueling outages)

6. The BAC Guidebook [4, Section 4 and Appendix A] documents extensive sets of laboratory data for rates of boric acid corrosion of carbon and low-alloy steels in borated water environments.

These immersion tests included conditions representative of reactor coolant and borated refueling water, as well as conditions representative of concentrated (i.e., leaking or evaporating) reactor coolant. These test data were reviewed to identify test conditions representative of reactor coolant and borated refueling water. Data for highly concentrated boron slurries were appropriately excluded as they do not reflect conditions applicable to the reactor vessel interior (specifically, test solutions at or above 9090 ppm B (saturated solution of boric acid), 50:50 H3B04-water slurries, and 90:10 H3B04 water mixtures).

a. Refueling water: 0.015 inch/yr [4, Table A-1, Test Reference "A"]

(Maximum corrosion rate for relevant test conditions. Data subset considered: aerated, T < 212°F, pHT > 4)

b. Cold shutdown: 0.130 inch/yr [4, Table A-8, Test Reference "F"]

(Maximum corrosion rate for relevant test conditions. Data subset considered: aerated, T 2'.: 212°F, pHT > 4)

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c. Startup/shutdown: 0.01 inch/yr [4, Test Reference "MRP Task 3"] [12, Figure 3-12]

(Maximum corrosion rate for relevant test conditions. Data subset considered: deaerated, T 2: 212°F, pHT >4)

d. Normal operation: 0.0055 inch/yr [4, Test Reference "MRP Task l"] [13, Section 3.2]

(Maximum corrosion rate for relevant test conditions. Data subset considered: deaerated, T 2: 212°F, pHT >6)

7. The corrosion rate affecting the subject reactor vessel is assumed to be constant for each distinct operating condition, with the constant rate conservatively taken as the highest reported rate for each relevant dataset per Assumption 6.

8. To support this conservative assessment of the potential for future low-alloy steel corrosion, based on the lack of visually discernible low-alloy steel corrosion in Figure 3 and Figure 4, the current depth of corrosion of the underlying low-alloy steel at the location of each cladding defect is assumed to be conservatively bounded by the maximum width (about 0.25 inch, Input 2b) of the larger cladding defect.

5 ANALYSIS The purpose of this analysis is to assess the potential for corrosion of the low-alloy steel base metal due to missing or damaged cladding. Both normal operating and refueling environments are considered, with conservative assumptions regarding the relative time during refueling when increased corrosion rates are expected due to aerated conditions. Section 5 .1 considers the applicable chemical environments and associated duty times, Section 5.2 presents the applicable corrosion rate laboratory data considered, and Section 5.3 calculates the cumulative corrosion.

5. 1 Applicable Chemical Environments and Associated Duty Times

5. 1. 1 General Corrosion As discussed in the EPRI Primary Water Chemistry Guidelines [9], there are significant changes in the reactor vessel chemical environment between normal operating conditions and plant shutdown conditions. As temperature is reduced, concentrations of boric acid are increased to provide a negative reactivity margin during shutdown conditions. Furthermore, boric acid tends to become a stronger acid as temperature is lowered, although it remains a relatively weak acid even at room temperature.

Low-alloy steel is susceptible to boric acid corrosion. Key factors for boric acid corrosion rates include boron concentration, lithium concentration, pHT, the presence (or absence) of oxygen, and temperature.

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Evaluation of Potential Low-Alloy Steel Corrosion at Cladding Defects of NAPS 1 Reactor Vessel Calculation No.: C-4523-00-01-NP Revision No.: __o __ Page -of 21 A wide range of laboratory experiments using solutions of boric acid with various values for these key factors have been performed to characterize boric acid corrosion rates in various environments [4, Section 4 and Appendix A]. These experiments have demonstrated trends in corrosion rates as a function of these key factors, some of which have competing effects. There is a tendency for higher corrosion rates at higher temperatures due to the thermal activation of chemical processes. However, as temperature increases, boric acid also becomes a weaker acid (increasing pHT). Lower pHT also tends to increase boric acid corrosion rates. At sufficiently low pHT, high corrosion rates of up to multiple inches per year can occur due to active acid corrosion. Thus, conservative corrosion rates would be calculated by considering corrosion rate data for the minimum-expected pHT. Also, at near-neutral pHT values, there is a large reduction in the corrosion rate when comparing deaerated conditions with aerated conditions.

This assessment considers the relevant range of environments to which the interior of PWR reactor vessels is exposed, i.e. normal operation, refueling water, cold shutdown, startup, and shutdown conditions. During normal operation, the RCS has a very low oxygen concentration and near-neutral pHT. (During normal operation, pHT is typically maintained between 6.9 and 7.4 [9, Section 3] to minimize crud deposition on the fuel, as well as crud-enhanced cladding corrosion.) During refueling, the RCS is aerated, has an elevated boron concentration of about 2000-2200 ppm, and is typically at temperatures near about I00°F and up to about 120°F (per Assumption 2). During cold shutdown, the RCS has a temperature somewhat elevated when compared with conditions for refueling, but remains with otherwise similar boron and dissolved oxygen concentrations (per Assumption 3). For startup, plant technical specifications typically limit dissolved oxygen to less than 100 ppb prior to exceeding 250°F (121 °C) [10, Section 3]. After criticality, dissolved oxygen concentrations are not detectable.

Shutdown conditions are very similar to startup conditions, in opposite order, and with shutdown typically of shorter duration than startup.

Per Assumption 1, operating conditions are considered to be constant during each of the explicitly considered operating periods. Assumptions 2 through 5 specify the conservatively assumed constant operating conditions assumed for refueling water, cold shutdown, startup/shutdown, and normal operation, respectively. These operating conditions and their corresponding durations are also listed in Table 2 and depicted in Figure 5. For each of these operating conditions, the minimum-expected pHT was evaluated. Although pHT can decrease further if evaporation occurs, concentrating the PWR coolant, this condition is not credible for locations within the reactor vessel.

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[14]). If the bulk water is deaerated to the extent where the electrochemical potential is governed by the hydrogen concentration (as is the case for PWR primary coolant during power operation), then there is no potential gradient to cause electrochemical crevice corrosion. Pitting occurs by a mechanism similar to electrochemical crevice corrosion, but occurs on a macroscopic scale, often initiated at inclusions exposed to the metal surface. Both time and temperature at oxygenated conditions are limited in PWRs limiting the relevance of aerated conditions. The effect of galvanic coupling between low-alloy steel base metal and stainless steel cladding is modest (acceleration factors of about 1.5 observed both in the field and laboratory [4]) versus the inherent conservatisms considered in this calculation. Therefore, localized corrosion is not considered to be a significant concern for the case of cracked, damaged, missing, or removed cladding of the reactor vessel.

5.1.3 Flow-Accelerated Corrosion (F AC)

As discussed by Chexal et al. [15] and Appendix A.1.3 of the EPRI Materials Degradation Matrix report [14], FAC of carbon steels is dependent on factors including temperature, material composition (chromium, copper, and molybdenum contents), fluid velocity, turbulence, steam quality, and water chemistry (including dissolved oxygen and pH). For single-phase conditions, the maximum dissolution rate of carbon steel has been determined to occur at a temperature of about 130 to 140°C (265 to 285°F) ([14], [15]). Chexal et al. [15], who cite 280°C (536°F) as an upper bound for applicability of the mechanism, present several experimental datasets and predictive models that show a very large reduction in dissolution rate as the temperature approaches and exceeds 250°C (482°F). Like for other PWRs, the NAPS Unit 1 reactor inlet temperature [16] is in the range from 285 to 293°C (545 to 560°F), above the 280°C bound as cited by Chexal et al. A secondary factor is that the shell flange section of the NAPS Unit 1 reactor vessel was fabricated using an SA-508 Class 2 (now referred to as SA-508 Grade 2 Class 1) low-alloy steel forging [8]. This alloy has a nominal chromium content of 1/3 wt% and a molybdenum content of about 0.6 wt% [17]. The shell-to-head transition region ofthe

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- - -of 21 NAPS Unit 1 reactor vessel comprises SA-508 Class 2 low-alloy steel forging material welded to SA-533 Grade B Class 1 plate material [8], which has a molybdenum content of about 0.5 wt% [17].

These minor alloying contents have a substantial benefit in reducing the FAC rate ([14], [15]). Based on these factors, F AC is not expected to be a relevant degradation mode for any low-alloy steel material exposed to flowing reactor coolant at the location of either subject cladding defect.

5.2 Corrosion Rate Laboratory Data The BAC Guidebook [4, Section 4 and Appendix A] documents extensive sets of laboratory data for rates of boric acid corrosion of carbon and low-alloy steels in borated water environments. These immersion tests included conditions representative of reactor coolant and borated refueling water, as well as conditions representative of concentrated (i.e., leaking or evaporating) reactor coolant. This assessment appropriately focuses on the available test data relevant to unconcentrated conditions. Data for highly concentrated boron slurries were appropriately excluded as they do not reflect conditions applicable to the reactor vessel interior. Tests with boron concentrations significantly higher than primary coolant or refueling water were excluded (per Assumption 6), specifically test solutions at or above 9090 ppm B (saturated solution of boric acid), 50:50 H3BQ4-water slurries, and 90: 10 H3BQ4 water mixtures. Test conditions below 9090 ppm B were conservatively included in the assessment.

For refueling, cold shutdown, and startup/shutdown conditions, included data from the appropriate data subsets (aerated or deaerated, and T < 212°F or T ~ 212°F) with pHT above 4 were applied for the boric acid corrosion assessment. Similarly, for normal operation, included data with pHT above 6 were applied. Assumption 6 and Table 3 list the maximum reported corrosion rate for each operating condition based on each of these subsets of included data.

5.3 Cumulative Corrosion For each operating condition, the corrosion rate listed in Assumption 6 is multiplied by the conservatively assumed duration per Assumptions 2 through 5 and Table 2 to determine the amount of corrosion for that operating condition in one 18-month cycle.

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Page-13- -of 21 Refueling 30- day outage: 0.015 in. x 30 days x __ 1 .,_

vr 0.00123 in.

A -

=

yr 18-month cycle 365.25 days 18-month cycle [5-1]

5 4 5-day outage: O.Ol in. x 45 days x __ 1 yr

__ 0.00185 in.

yr 18-month cycle 365 .25 days 18-month cycle Cold Shutdown 0.130 in. 7 days 1 yr 0.00249 in. [5-2]

X X yr 18-month cycle 365.25 days 18-month cycle Startup/Shutdown 0.01 in. x 7days x 1 yr = 0.00019 in. [5-3]

yr 18-month cycle 365.25 days 18-month cycle Normal Operation 30-day outage : 0.0055 in. x 503 .9 UUJ" rl,:iuc, 1 yr = 0 .00759 1'n.

yr 18-month cycle 365 .25 days 18-month cycle [5-4]

55 45-day outage: o.oo in. x 488.9 days x 1 yr = 0.00736 in.

yr 18-month cycle 365.25 days 18-month cycle The individual corrosion contributions for each operating condition are then added to determine the total amount of corrosion. For 30-day refueling outages, this results in a total amount of corrosion of about 0.012 inch in one 18-month cycle, 0.077 inch in 10 years, 0.153 inch in 20 years, and 0.307 inch in 40 years. The total corrosion is only slightly different (by about 3%) assuming 45-day refueling outages. It is noted that the 60-year license expiration date (April 1, 2038, per Input 4) is 20 years after the examination of the cladding defects in March 2018. It is also noted that an 80-year license

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0 Page -of 21 expiration date (April 1, 2058) would be 40 years after the examination of the cladding defects in March 2018.

The total amount of corrosion estimated for the full 80-year period of operation is 0.619 inch. Per Assumption 2f, 45-day refueling outages are assumed for the first 20 years of operation, followed by 30-day refueling outages for operation from 20-80 years. This is less than the allowable corrosion feature depth of at least 1.0 inch for which the applicable ASME Section III design Code stress limits are satisfied, as determined in C-4523-00-02 [6].

The total amount of corrosion conservatively estimated over 9 years (i.e., since the 2009 detection of the indication in the shell flange section of the reactor vessel) is 0.069 inch. This value is considered to be consistent with the lack of discemable corrosion observed in 2018. It is also noted that the maximum extent of the cladding defect along the surface of the shell flange section of the reactor vessel did not change significantly from 2009 to 2018. The minor discrepancy in the measured defect sizes is attributed to the improved photo quality in 2018 (Figure 2 vs. Figure 1); it appears that the 2009 length dimension did not capture the narrow right end of the indication.

The conservative estimate of a depth which bounds any corrosion of the underlying low-alloy steel at either cladding defect, as examined in March 2018, is 0.25 inch (per Assumption 8). Thus, the conservatively estimated total depth of either defect is less than 0.262 inch in an additional 18-month cycle of operation, less than 0.327 inch in 10 additional years of operation, less than 0.403 inch in 20 additional years of operation, and less than 0.557 inch in 40 additional years of operation.

These results conservatively characterize the actual depth of corrosion that would be expected at a region of missing cladding for the following reasons:

• The highest reported corrosion rate for each applicable set of test conditions was applied, with conservative definition of the environmental conditions for each assumed operating condition (Assumption 6).

• The durations applied for cold shutdown and startup/shutdown (7 days each) are conservative versus typical durations in those conditions (Assumption 3f and 4f). Furthermore, although the corrosion rate during cold shutdown is conservatively evaluated to be the highest (at 0.130 in/yr),

due to the limited duration when the RCS is under those conditions, the overall fraction of corrosion due to this operating condition is only 22%. Thus, the overall result is not especially sensitive to the assumptions for the cold shutdown and startup/shutdown conditions.

• Because corrosion rates during refueling are relatively low (conservatively 0.015 in/yr), the overall corrosion results are not sensitive to the assumed outage duration length. For example, the

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0 Page -of 21 additional corrosion that would occur due to a two-year long extended outage is conservatively only 0.03 inch, which is not significant compared to the long-term overall results.

6 REFERENCES

1. Galbraith, R. S. (Dominion Energy), E-mail transmittal to Glenn White, John Broussard, and Markus Burkardt (Dominion Engineering, Inc.), March 2, 2018. "RE: [External] RE: Reactor Vessel Cladding Issue details." DEI Incoming Correspondence IC-4523-00-02.

a.

Attachment:

NAPS Ul RV Cladding indication for DEI.pptx

2. "North Anna N1R26 Remote Visual Examination Indication Notification Report," Framatome INR-NIR26-18-001, dated March 22, 2018.

3. "North Anna N1R26 Remote Visual Examination Indication Notification Report," Framatome INR-N1R26-18-002, dated March 23, 2018.

4. Boric Acid Corrosion Guidebook, Revision 2: Managing Boric Acid Corrosion Issues at PWR Power Stations (MRP-058, Rev 2), EPRI, Palo Alto, CA: 2012. 1025145.

5. NRC: North Anna Power Station, Unit 1, Accessed March 16, 2018. https://www.nrc.gov/info-finder/reactors/na I .html.

6. Dominion Engineering, Inc. Calculation C-4523-00-02, Revision 0, April 2018.

7. WCAP-15338-A, "A Review of Cracking Associated with Weld Deposited Cladding in Operating PWR Plants," October 2002. [NRC ADAMS Accession No.:ML083530289]

8. "Instruction Manual - 157 Inch I.D. Reactor Pressure Vessel-Project VRA-RCPCRV - Virginia Electric and Power Company- North Anna Power Station," The Rotterdam Dockyard Company, for RDM Order 30661/30662, Revision 2, including Addenda 1 to 4 (also Virginia Power Control No. 59-W893-00125).

9. Pressurized Water Reactor Primary Water Chemistry Guidelines: Volume 2, Revision 7. EPRI, Palo Alto, CA: 2013. 3002000505.

IO. Pressurized Water Reactor Primary Water Chemistry Guidelines: Volume 1, Revision 7. EPRI, Palo Alto, CA: 2013. 3002000505.

11. EPRI ChemWorks Tools Version 3.3, EPRI, Palo Alto, CA. 1023225.

12. Materials Reliability Program, Reactor Vessel Head Boric Acid Corrosion Testing: Task 3 -

Separate Effects Testing (MRP-165). EPRI, Palo Alto, CA: 2005. 1011807.

13. Materials Reliability Program: Reactor Vessel Head Boric Acid Corrosion Testing (MRP-163),

Task 1: Stagnant and Flow Primary Water Tests. EPRI, Palo Alto, CA: 2005.1013030.

14. EPRI Materials Degradation Matrix, Revision 3. EPRI, Palo Alto, CA: 2013. 3002000628.

[Freely available at W\VW.epri.com]

15. Flow-Accelerated Corrosion in Power Plants. EPRI, Palo Alto, CA: 1998. TR-106611-Rl.

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Page 16

- - -of 21

16. Naughton, P. (Dominion Energy), E-mail transmittal to Glenn White (Dominion Engineering, Inc.), January 10, 2017. "RE Nominal Operating Conditions." DEI Incoming Correspondence IC-4520-00-01.

17. "Carbon and Low Alloy Steels for Pressure Vessels,"Section I, Chapter 1 in Materials Handbook for Nuclear Plant Pressure Boundary Applications (2018). EPRI, Palo Alto, CA:

2018. 3002012420.

18. Westinghouse NSAL 12-1, "Steam Generator Channel Head Degradation," dated January 5, 2012.

19. Steam Generator Management Program: Steam Generator Channel Head Degradation Failure Modes and Effects Analysis. EPRI, Palo Alto, CA: 2013. 3002000473.

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Evaluation of Potential Low-Alloy Steel Corrosion at Cladding Defects of NAPS 1 Reactor Vessel Calculation No.: C-4523-00-01-NP Revision No.: 0 Page 17 of 21 Table 1. Summary of Conservatively Calculated Corrosion Depth Assumed RFO Initial Defect Corrosion During Final Defect Case Description Length Depth (in.) Interval (in.) Depth (in.)

1 Next 10 years 30 days <0.25 0.077 <0.327 Next 20 years 2 (time to 60-year license 30 days <0.25 0.153 <0.403 expiration date<1>)

Next 40 years 3 (time to 80-year license 30 days <0.25 0.307 <0.557 expiration date<2>)

45 days (first 20 years) 4 Full 80 years 0 0.619 0.619 30 days (20-80 years)

Since 2009 detection 5 30 days 0 0.069 0.069 (9 years)

NOTES:

(1) The current (i.e., first) renewed license for North Anna Unit 1 expires on April 1, 2038 [5].

(2) A subsequent renewed license for North Anna Unit 1 would be expected to expire on April 1, 2058.

Dominion fn~ineerin~. Inc. NON-PROPRIETARY

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Evaluation of Potential Low-Alloy Steel Corrosion at Cladding Defects of NAPS 1 Reactor Vessel Calculation No.: C-4523-00-01-NP Revision No.: 0 Page 18 of 21 Table 2. Summary of Conservatively Assumed PWR Operating Conditions for BAC Assessment Operating Oxygen pH Minimum Region Description Temperature Condition Condition pHT Duration

<49°C 2200 ppm B, 1 Refueling Aerated 4.64 30 days

(<120°F) 0 ppm Li

<121°C 2200 ppm B, 2 Cold Shutdown Aerated 4.69 7 days

(<250°F) 0 ppm Li 121-300°C 2200 ppm B 3 Startup/Shutdown Deaerated 4.7 7 days (250-572°F) 0 ppm Li Remainder 4 Normal Operation 300°C (572°F) Deaerated >6.9 6.9 of 1.5 years Table 3. Summary of Relevant Corrosion Rates for Conservatively Assumed Operating Conditions Data Maximum Operating Oxygen Minimum Subset Corrosion Region Description Temperature Condition pHT Considered Rate (in/yr)

Aerated,

<49°C 1 Refueling Aerated 4.64 T < 212°F, 0.015

(<120°F) pHT>4 Aerated,

<121°C 2 Cold Shutdown Aerated 4.69 T ~ 212°F, 0.130

(<250°F) pHT>4 Deaerated, 121-300°C 3 Startup/Shutdown Deaerated 4.7 T ~ 212°F, 0.01 (250-572°F) pHT>4 Deaerated, 4 Normal Operation 300°C (572°F) Deaerated 6.9 T ~ 212°F, 0.0055 pHT> 6

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....;_;..__of 21 Figure 1. Photo of Cladding Defect in the Shell Flange Section of the Reactor Vessel from 2009 Examination with Indication Measurement (1 a]

Figure 2. Photo of Cladding Defect in the Shell Flange Section of the Reactor Vessel from March 2018 Examination with Indication Measurement [2]

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- - -of 21 Figure 3. Close-Up Photo of Cladding Defect in the Shell Flange Section of the Reactor Vessel from March 2018 Examination [2]

Figure 4. Photo of Cladding Defect near a Radial Support Keyway from March 2018 Examination with Indication Measurement [3]

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..=.;.._ _ of 21 350 0

e......300 e

-  ::l f(I)!

C..250 E(I) t-

.s

~ 200 C)

C:

~ 150 a=

-- C:

.!2 100 0

0 0

-a=

0

~

(I) 50 ..M19,...,.........i....,......-,..,....._,.._

10 20 30 40 50 60 70 80 90 100 Days Figure 5. Diagram Depicting Conservatively Assumed Operating Conditions for Refueling, Cold Shutdown, Startup/Shutdown, and Normal Operation

Serial No.: 19-156 Attachment 6 Dominion Engineering Affidavit Pursuant to 10 CFR 2.390 Virginia Electric and Power Company

{Dominion Energy Virginia)

North Anna Power Station Unit 1

Dominion fn~ineerin:,Y May 24, 2019 L-4523-00-0t Rev. 0 U.S. Nuclear Regulatory Commission Document Control Desk 11555 Rockville Pike Rockville, MD 20852

Subject:

Application for Withholding Proprietary Information from Public Disclosure Attachments: (1) Affidavit

Dear Sir or Madrun:

This Application for Withholding Proprietary Information from Public Disclosure is submitted by Dominion Engineering, Inc. ("DEI"), pursuant to the provisions of paragraph (b)(1) of Section 2.390 of the NRC's regulations.

The proprietary information for which withholding is being requested in calculation C-4523-00-02-P, Rev. 0, "North Anna Power Station Unit 1 RPV Corrosion Feature Evaluation,

(Proprietary) is marked within the calculation document as "Confidential Commercial Information. The attached Affidavit sets forth the basis on which the information may be withheld from public disclosure by the Commission in accordance with 10 CFR Section 2.390 of the Commission's regulations.

Correspondence \\'1th respect to the Application for Withholding or the DEI Affidavit should be addressed to Glenn A. White, P.E., Principal Officer, Dominion Engineering Inc., 12100 Sunrise Valley Drive, Suite 220, Reston, Virginia 20191.

Sincerely, Glenn A. White, P.E.

Principal Officer 12100 Sunrise Valley Drive, Suite 220 Reston, VA 20191 PH 703.657.7300 FX 703.657.7301

Dominion fn~ineerin~, Inc. L-4523-00-01, Rev. 0 Attachment 1, p. 1 of 4 ATTACHMENT 1 AFFIDAVIT COMMONWELTH OF VIRGINIA COUNTY OF FAIRFAX I, Glenn A. White, am authorized to execute this Affidavit on behalf of Dominion Engineering, Inc. ("DEI"). I have been specifically delegated the function of reviewing the proprietary information sought to be withheld from public disclosure in connection with nuclear power plant licensing and rulemaking proceedings. I attest that the averments of fact set forth in this Affidavit are true and correct to the best of my knowledge, information, and belief.

. f'-

Dated this the2.lf day of M.., 'f ,2019 Glenn A. White, P.E.

Principal Officer

Dominion fn~ineerin~, Inc. L-4523-00-01, Rev. 0 Attachment 1, p. 2 of 4 In accordance ,¥ith the provisions of 10 CFR Section 2.390 of the Nuclear Regulatory Commission's ("Commission's") regulations, including its paragraphs (b)(l)(ii) and (iii), the following is provided:

(1) The proprietary information for which withholding is being requested is within calculation C-4523-00-02-P, Rev. 0, "North Anna Power Station Unit 1 RPV Corrosion Feature Evaluation," (Proprietary) and marked within the calculation document as "Confidential Commercial Information."

(2) I am a Principal Officer of Dominion Engineering Inc. ("DEI"), and I have been specifically delegated the function of reviewing the proprietary information sought to be withheld from public disclosure in connection with nuclear power plant licensing and rulemaking proceedings. I am authorized to apply for its withholding on behalf of DEL I have personal knowledge of the criteria and procedures utilized by DEI in designating information as a trade secret, privileged, or as confidential commercial or financial information.

(3) The basis that the information be withheld is that it is confidential commercial information.

(4) Public disclosure of the information sought to be withheld is likely to cause substantial harm to DEI's competitive position because:

(i) The subject information has substantial commercial value to DEI as significant portions of DEI's future business of providing engineering consulting to nuclear utilities in this area is substantially based upon the information sought to be withheld.

(ii) Similar products and services are provided by DEI's major competitors. Acquiring of the information sought to be withheld would allow the competitors to take some share of the market for providing engineering consulting services in this area without commensurate expenses.

(iii) Public disclosure of the information would enable others to use the information to meet NRC requirements for licensing documentation without purchasing the right to use the information.

(iv) The development of the technology described in part by the information is the result of applying the results of many years of experience and the expenditure of a considerable sum of money.

Dominion fn~ineerin~, Inc. L-4523-00-01, Rev. 0 Attachment 1 p. 3 of 4 l

(v) There is expected to remain a marketplace for services in the areas related to the subject information and currently provided by DEI (i.e., proprietary finite element analysis of reactor pressure vessel structural integrity) for many years into the future.

(5) The proprietary information sought to be withheld in this submittal is that which is appropriately marked in C-4523-00-02-P, Rev. 0, for submittal to the Commission, being transmitted by Dominion Energy letter. The specific locations sought to be withheld are marked within the calculation document as "Confidential Commercial Information." The locations are within Sections 3 and 4 of the calculation text and its Tables 1, 2, and 3.

The detailed code input listing of Appendix A is also sought to be withheld.

(6) Pursuant to the provisions of paragraph (b)(4) of Section 2.390 of the Commission's regulations, the following is furnished for consideration by the Commission in determining whether the information sought to be withheld from public disclosure should be withheld.

(i) The information sought to be withheld from public disclosure is owned and has been held in confidence by DEL (ii) The information is of a type customarily held in confidence by DEI and not customarily disclosed to the public. Any disclosure to third parties has been made pursuant to regulatory provisions or proprietary agreements that provide for maintenance of the information in confidence.

DEI has a rational basis for determining the types of information customarily held in confidence by it. As described in this Affidavit under paragraph (4) above, the information is held in confidence by DEI because disclosure would substantially affect DEI's competitive business position. This information principally is related to the methodology, assumptions, and detailed analysis procedure of a proprietary structural analysis of a pressurized water reactor (PWR) reactor pressure vessel.

(iii) The information sought to be withheld is being submitted to the NRC in confidence by Dominion Energy, and, under the provisions of 10 CFR Section 2.390, is to be received in confidence by the Commission.

(iv) To the best of my and DEI's knowledge, no public disclosure of this information has been made, and it is not available in public sources. Information that is available in public sources is not being requested to be withheld, and as such is included in the accompanying non-proprietary version of the report.

Dominion fn~ineerinf, Inc. L-4523-00-01, Rev. 0 Attachment 1, p. 4 of 4 (v) Public disclosure of the information sought to be withheld is likely to cause substantial harm to DEI's competitive po,sition for the reasons listed above in this Affidavit under paragraph (4).