L-24-208, License Renewal Application for the Perry Nuclear Power Plant - Responses to Request for Additional Information - Round 1 (Set 2)

License Renewal Application for the Perry Nuclear Power Plant - Responses to Request for Additional Information - Round 1 (Set 2)

ML24276A083
Person / Time
Site:	Perry
Issue date:	10/02/2024
From:	Penfield R Vistra Operations Company
To:	Office of Nuclear Reactor Regulation, Document Control Desk
References
L-24-208
Download: ML24276A083 (1)

Text

L-24-208 October 2, 2024 ATTN: Document Control Desk U.S. Nuclear Regulatory Commission Washington, DC 20555-0001

SUBJECT:

Perry Nuclear Power Plant, Unit No. 1 Docket No. 50-440, License No. NPF-58 Perry Nuclear Power Plant Rod L. Penfield Site Vice President 10 Center Road Perry, Ohio 44081 10 CFR 54 License Renewal Application for the Perry Nuclear Power Plant - Responses to Request for Additional Information - Round 1 (Set 2)

REFERENCES:

1. Letter L-23-146, from Rod L. Penfield to the Nuclear Regulatory Commission, dated July 3, 2023, submitting the Perry Nuclear Power Plant License Renewal Application Revision O (ADAMS Accession No. ML23184A081)

2. Nuclear Regulatory Commission issuance of Conforming License Amendment 203 to Facility Operating License NPF-58 (Enclosure 1) for the license transfer for the Perry Nuclear Power Plant (ADAMS Accession Nos. ML24057A075 and ML24057A077)

3. Letter L-24-110, from Rod L. Penfield to the Nuclear Regulatory Commission, dated July 3, 2024, submitting 10 CFR 54.21(b) Annual Amendment to the Perry Nuclear Power Plant License Renewal Application (ADAMS Accession No. ML24185A092)

4. Letter from Lauren K. Gibson to Rod L. Penfield, Perry Nuclear Power Plant, Unit No. 1 dated September 25, 2023 - Aging Management Audit Plan Regarding the License Renewal Application Review (ADAMS Accession No. ML23261B019)

5. Letter L-24-189, from Rod L. Penfield to the Nuclear Regulatory Commission, dated August 7, 2024, submitting the Perry Nuclear Power Plant License Renewal Application Revision 0, Supplement 1 (Non-Proprietary) (ADAMS Accession No. ML24220A270) 6555 SIERRA DRIVE IRVING, TEXAS 75039 o 214-812-4600 VISTRACORP. COM

Perry Nuclear Power Plant L-24-208 Page 2 of 3

6. Letter L-24-020, from Rod L. Penfield to the Nuclear Regulatory Commission, dated June 27, 2024, submitting the Perry Nuclear Power Plant License Renewal Application Revision 0, Supplement 2 (ADAMS Accession No. ML24180A010)

7. Letter L-24-108, from Rod L. Penfield to the Nuclear Regulatory Commission, dated July 24, 2024, submitting the Perry Nuclear Power Plant License Renewal Application Revision 0, Supplement 3 (ADAMS Accession No. ML24206A150)

8. Letter L-24-200, from Rod L. Penfield to the Nuclear Regulatory Commission, dated September 5, 2024, submitting the Perry Nuclear Power Plant License Renewal Application Revision 0, Supplement 4 Revision 1 (ADAMS Accession No. ML24249A123)

9. NRC Email from Vaughn Thomas to Rod Penfield - dated August 14, 2024 - Perry LRA -

Requests for Additional Information - Set 1 (ADAMS Accession No. ML24227A956 and ML24227A957)

10. Letter L-24-207, from Rod L. Penfield to the Nuclear Regulatory Commission, dated September 16, 2024, submitting the License Renewal Application for the Perry Nuclear Power Plant - Response to Request for Additional Information - Set 1 (ML24260A266)

11. NRC Email from Vaughn Thomas to Rod Penfield - dated August 28, 2024 - Perry LRA -

Requests for Additional Information -Set 2 (ADAMS Accession No. ML24241A100 and ML24241A101)

On July 3, 2023, Energy Harbor Nuclear Corp. submitted a license renewal application (LRA) for the Facility Operating License for the Perry Nuclear Power Plant, Unit No. 1 (PNPP) (Reference 1).

Subsequent to the submittal of the PNPP LRA, the PNPP Facility Operating License has been transferred to Vistra Operations Company LLC (VistraOps) per conforming license Amendment 203 and the license transfer transaction was closed on March 1, 2024 (Reference 2). The license transfer changes impacting the PNPP LRA are documented in the annual amendment required by 10 CFR 54.21 (b), submitted on July 3, 2024 (Reference 3).

During the Nuclear Regulatory Commission (NRC) staff's aging management audit of the PNPP LRA (Reference 4), the PNPP Staff agreed to supplement the LRA with clarifying information which has led to several LRA supplements (References 5 through 8).

In addition, as a result of the NRC's review and audit of the PNPP LRA, on August 14, 2024, the NRC Staff has submitted to the PNPP Staff the first set of several requests for additional information (RAls)

(Reference 9), which the PNPP Staff responded to on September 16, 2024, via Vistra Letter L-24-207 (Reference 10). Subsequently, the NRC Staff submitted Set 2 of the RAls on August 28, 2024 (Reference 11 ).

Attachments 1 to 5 of this letter provide the responses and the associated LRA updates to address the RAls (Set 2) submitted by the NRC Staff on August 28, 2024. In addition, an administrative LRA update is provided in Attachment 6.

For ease of reference, an index listing the RAI responses and the associated LRA updates is provided.

6555 SIERRA DRIVE IRVING. TEXAS 75039 o 214-812-4600 VISTRACORP.COM

Perry Nuclear Power Plant L-24-208 Page 3 of 3 The regulatory commitments identified in Appendix A, Table A,3 of the PNPP LRA are not impacted by this RAI response letter. If there are any questions or if additional information is required, please contact Mr. Mark Bensi, PNPP License Renewal Manager at (440) 280-6179 or via email at Mark.Bensi@vistracorp.com.

I declare under penalty of perjury that the foregoing is true and correct. Executed on October 2, 2024.

Attachments:

PNPP Responses to LRA NRC RAls Set 2 cc:

NRC Region Ill Administrator NRC Resident Inspector NRR Project Manager Executive Director, Ohio Emergency Management Agency, State of Ohio (NRC Liaison)

Utility Radiological Safety Board 6555 SIERRA DRIVE IRVING, TEXAS 75039 o 214-812-4600 VISTRACORP COM

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 2 L-24-208 Attachments Index Page 1 of 2 PNPP LRA Set 2 RAI Responses Attachments Index Attachment No.

RAI or LRA Update Associated RAI Applicable RAI or LRA Section/Table Updated 1

RAI NCSG RAI-10181-R1 Requests 1, 2 & 3 2

RAI NCSG RAI-10276-R1 Requests 1, 2 & 3, 4 & 5 3

RAI NVIP RAI-10231-R1 Questions 1, & 2 4

LRA Update NCSG RAI-10181-R1 Section A.1.27, B.2.27 and Table A.3 5

LRA Update NVIP RAI-10231-R1 Section A.1.13, Section B.2.13 and Appendix C 6

LRA Update N/A - Applicant Initiated Section B.2.34 Key for Attachments:

Acronyms:

LRA = License Renewal Application TRP = Technical Review Package from NRC aging management audit inquiry S&S = NRC Scoping and Screening audit inquiry Attachments 4, and 5 provide LRA page updates as a result of the associated RAI responses. provides an LRA update to address an administrative change. These attachments incorporate the Perry Nuclear Power Plant LRA changes made via the LRA supplements and the annual update which were submitted via the following Vistra correspondence:

1. LRA Supplement 1 (Vistra Letter L-24-189)

2. LRA Supplement 2 (Vistra Letter L-24-020)

3. LRA Annual Update (Vistra Letter L-24-110)

4. LRA Supplement 3 (Vistra Letter L-24-108)

5. LRA Supplement 4 Revision 1 (Vistra Letter L-24-200)

6. LRA Response to Request for Additional Information - Set 1 (Vistra Letter L-24-207)

Therefore, the LRA changes made as a result of Attachments 4, 5 and 6 build on, and are made on clean LRA pages that reflect the LRA updates from the previously docketed Vistra correspondence listed above.

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 2 L-24-208 Attachments Index Page 2 of 2 Revisions to LRA tables may be shown by providing excerpts from each affected table, i.e., only the affected parts of the table may be included in the attachment.

Consistent with LRA supplements and the annual update, changes for Attachments 4, 5 and 6 are indicated by, red, bolded and underlined text for added text and strikethrough for text to be deleted.

Note that text editing changes to some of the attachments such as spacing, font consistency changes etc., are not indicated via coloring as these are inconsequential.

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 2 L-24-208 Attachment 1 Page 1 of 9 NCSG RAI-10181-R1 Regulatory Basis Pursuant to Title 10 of the Code of Federal Regulations (10 CFR) section 10 CFR 54.21(a)(3) requires an applicant to demonstrate that the effects of aging for structures and components will be adequately managed so that the intended function(s) will be maintained consistent with the current licensing basis for the period of extended operation (PEO). One of the findings that the staff must make to issue a renewed license (10 CFR 54.29(a)) is that actions have been identified and have been or will be taken with respect to managing the effects of aging during the PEO on the functionality of structures and components that have been identified to require review under 10 CFR 54.21, such that there is reasonable assurance that the activities authorized by the renewed license will continue to be conducted in accordance with the current licensing basis. In order to complete its review and enable making a finding under 10 CFR 54.29(a), the staff requires additional information in regard to the matters described below.

Background

Generic Aging Lessons Learned (GALL) Report AMP XI.M42 Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks, as added by LR-ISG-2013-01, Aging Management of Loss of Coating or Lining Integrity for Internal Coatings/Linings on In-Scope Piping, Piping Components, Heat Exchangers, and Tanks, recommends managing the degradation of coatings/linings that can lead to loss of material of base materials and downstream effects such as reduction in flow, reduction in pressure or reduction in heat transfer when coatings/linings become debris. The program consists of periodic visual inspections of internal coatings/linings exposed to closed-cycle cooling water, raw water, treated water, treated borated water, waste water, fuel oil, and lubricating oil. Where the visual inspection of the coated/lined surfaces determines that the coating/lining is deficient or degraded, physical tests are performed, where physically possible, in conjunction with the visual inspection.

License renewal application (LRA) section B.2.27, Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks Program, specifies periodic visual inspection of internal coatings/linings for in-scope components to manage the loss of coating integrity in heat exchangers, piping, piping components, piping elements, and tanks consistent with the GALL Report AMP XI.M42 in LR-ISG-2013-01. Section B.2.27 of LRA also specifies a baseline coating/lining inspection in the 10-year period prior to the PEO and states that the maximum interval of subsequent inspections will be consistent with Table 4a of the GALL Report AMP XI.M42 in LR-ISG-2013-01.

By letter dated June 27, 2024 (ML24180A010), LRA Supplement 2 revised Section B.2.27 to add exceptions to LRA Section B.2.27. The exceptions are applicable only to the Division 3 high pressure core spray (HPCS) fuel oil day tank (see issue below).

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 2 L-24-208 Attachment 1 Page 2 of 9 Issue During the operating experience (OpE) audit, NRC staff reviewed recent inspection history on the following internally coated in-scope tanks:

Division 1 and 2 emergency diesel generator (EDG) fuel oil storage tanks (PY-1R45A0002A(B))

Division 1 and 2 EDG fuel oil day tanks (PY-1R45A0003(B))

Division 3 EDG and/or HPCS fuel oil storage tank (PY-1R45A0004)

Division 3 HPCS fuel oil day tank (PY-1R45A0005)

Also, during the OpE audit, the applicant stated that, except for the Division 3 HPCS fuel oil day tank, the above in-scope tanks would be visually inspected during the period of extended operation consistent with Table 4a of the GALL Report AMP XI.M42 in LR-ISG-2013-01 (confirmation of this statement is contingent on the applicants response to RCI B.2.27, Question No. 1). However, LRA Supplement 2 states that the Division 3 HPCS fuel oil day tank (PY-1R45A0005), which was last visually inspected in 2010, would not be visually inspected during the PEO unless coating conditions are suspected to be degraded based on leading indicators in other EDG day tanks or the Division 3 HPCS fuel oil storage tank (identified as PY-1R45A0004 above). LRA Supplement 2 also states that debris found in the HPCS fuel oil pump suction strainers will also provide evidence if coatings are degrading.

Request

1. Explain how the Division 3 HPCS fuel oil storage tank and the Division 1 and 2 EDG fuel oil day tanks are considered to be leading indicators of coating/lining degradation of the Division 3 HPCS fuel oil day tank. The applicants justification should include a discussion of the following as a minimum:

Similarity or differences between the tank base material types.

Similarity or differences between the internal coating types (use specific coating identifiers such as Carboline 187).

Similarity or differences between the coating application dates and quality of the application, including similarities or differences in surface preparation between the tanks.

Similarity or differences between tank internal environments (e.g. fluid type, stagnant or non-stagnant conditions, frequency of tank inventory turnover).

Similarity or differences between tank geometries (if relevant to applicants justification).

2. In order to support the claim that debris found in the HPCS fuel oil pump suction strainers will provide evidence of coating degradation, describe the following:

Mesh size of the strainers.

How frequently will these suction strainers be checked for debris?

How frequently will these suction strainers see flow due to demand for equipment testing and/or recirculation of the fuel oil in the tank?

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 2 L-24-208 Attachment 1 Page 3 of 9 How much coating debris can these suction strainers accommodate before flow is reduced below demand?

3. Discuss the risk of an undetected failure of the coating/lining of the Division 3 HPCS fuel oil day tank preventing the HPCS from performing its intended function. The applicants discussion of the consequences of this undetected failure should address the following risks as a minimum:

Risk of fuel unavailability due to blocked suction strainers Risk of adverse consequences downstream of the suction strainers due to small size coating debris bypassing the strainers Risk of disabled or degraded HPCS system PNPP Response

1. Explain how the Division 3 HPCS fuel oil storage tank and the Division 1 and 2 EDG fuel oil day tanks are considered to be leading indicators of coating/lining degradation of the Division 3 HPCS fuel oil day tank. The applicants justification should include a discussion of the following as a minimum:

Similarity or differences between the tank base material types.

The material specifications for all of the diesel fuel oil storage tanks and day tanks are carbon steel plate with no significant differences relevant to aging effects.

Similarity or differences between the internal coating types (use specific coating identifiers such as Carboline 187).

The HPCS diesel generator fuel oil day tank and its fuel oil storage tank were both built by the same manufacturer (Bishopric) according to the same PNPP procurement specification requirements using the same surface preparation and coating system. The EDG fuel oil storage tanks were also supplied by the same manufacturer, according to the same procurement specification, with the same surface preparation and internal coating.

All of these tanks internal (and external) surfaces were abrasive blasted (commercial grade) in compliance with specification SSPC-SP6. Interior surfaces were coated with Rust-Oleum Orange Primer #9373 to a 2 mils minimum thickness. Rust-Oleum Orange No. 9373 is a heavy-duty epoxy system. In 1990, coating repairs using Carboline 187 (a similar 2-part epoxy coating) were authorized for the three fuel oil storage tanks. Based on unavailability of both Rust-Oleum #9373 and Carboline 187, Phenoline Tank Shield (a Carboline 2-part epoxy coating system) is currently authorized for coating repairs for the interior of each of the fuel oil storage tanks.

The EDG fuel oil day tanks internal surface preparation and coating were not identical to the other tanks. These tanks were supplied under a different procurement specification, and manufactured by Thermxchanger.

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 2 L-24-208 Attachment 1 Page 4 of 9 Although prior inspections of each of the day tanks show similar results of no damage to internal coatings, PNPP cannot speak in detail to the differences in the application process between two manufacturers and therefore will use the information from the HPCS storage tank and results of inspections in the two engine strainers rather than the EDG day tank to draw inferences regarding the condition of the coating in the HPCS day tank.

Similarity or differences between the coating application dates and quality of the application, including similarities or differences in surface preparation between the tanks.

The HPCS day and HPCS and EDG storage tanks were fabricated around the same time in 1977 by the same manufacturer, Bishopric. The surface preparations were abrasive blasted (commercial grade) per specification SSPC-SP6 for all of these Bishopric manufactured tanks.

Like all the PNPP fuel oil tanks, the coating in the HPCS day tank has been in service from before commercial operation in 1986. No coating damage was reported in the day tanks in September 2010 internal inspection, twenty four (24) years after commercial operation. Consequently, PNPP believes it is very unlikely that a gross failure of the coating will occur.

Although the EDG day tanks were built within a year or two of the HPCS day tanks, PNPP will use the information from the HPCS storage tank rather than the EDG day tank to draw inferences regarding the condition of the coating in the HPCS day tank. Further evaluations will focus on the HPCS Day Tank and HPCS Storage Tank.

Similarity or differences between tank internal environments (e.g. fluid type, stagnant or non-stagnant conditions, frequency of tank inventory turnover).

All of the tanks are maintained mostly full of the same grade of number 2 diesel fuel oil.

Fuel oil quality is maintained by monitoring and controlling fuel oil contamination in accordance with the plants technical specifications and ASTM standards. Exposure to fuel oil contaminants, such as water and microbiological organisms, is minimized by periodic draining or cleaning of tanks and by verifying the quality of new oil before its introduction into the storage tanks, including the addition of a biocide.

Day tank fuel oil turnover - The PNPP fuel oil transfer system utilizes eductors located in the fuel oil storage tanks. When the fuel transfer system operates, the transfer pumps withdraw fuel oil from the day tank to serve as driving flow for the storage tank eductor.

The eductor draws fuel from the storage tank and the combined flow is returned to the day tank, at a rate higher than the transfer pump withdrawal. Transfer pump flow from the day tank is withdrawn through the suction nozzles located 1/3 up the tank wall from the dished bottom head. Fuel oil is returned by the day tank return nozzle that is fitted with a stilling well with a mitered discharge near the bottom head.

During a monthly HPCS diesel generator test, the diesel engine consumes approximately 3 gpm of fuel oil at rated load. Because the diesel engine fuel pumps will over-supply the engine, about 450 gallons of fuel oil will be drawn from the day tank over

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 2 L-24-208 Attachment 1 Page 5 of 9 a one-hour test. Based on the setpoints for transfer pump level switches, it is expected a transfer pump will operate during the test to restore day tank inventory and maintain day tank fuel oil level well above the transfer pump suction nozzles and PNPP Technical Specification limits. Thus, day tank fuel inventory is mixed for several minutes over every hour of engine operation from the described fuel oil level changes.

The storage tank fuel inventory remains mostly quiescent due to tank geometry (12 ft dia.), low suction flow into the eductor, and the storage tank fill nozzle is fitted with a stilling well that discharges close to the tank bottom, away from the eductors. The HPCS diesel storage tank has a capacity of over 39,000 gallons, and fuel inventory is normally maintained greater than the 7-day required inventory of 36,700 gallons. Based on required HPCS diesel engine testing and maintenance, fuel oil is added to the tank every few months to offset the consumption.

Similarity or differences between tank geometries (if relevant to applicants justification).

The 48 diameter HPCS fuel oil day tank is oriented vertically with an overall length (height) of about 80 (6.6 feet) with dished top and bottom heads. The day tank is located in the HPCS diesel generator room and is encased in pycrocrete fireproofing.

The 12 diameter HPCS fuel oil storage tank is a horizontal cylindrical storage tank with dished heads on each end. The tank is over 48 long. The EDG fuel oil storage tanks are 13.8 diameter horizontal cylindrical tanks over 82 long with dished heads on each end. The diesel fuel oil storage tanks are buried in the yard outside of the diesel generator building.

The EDG day tanks are vertical cylindrical tanks that were supplied by the diesel generator vendor (Transamerica Delaval) and differ in design configuration. Although the fuel oil transfer scheme is the same for all of the diesel generators, the EDG day tanks will not be discussed further in terms of a leading indicator. See the LRA change to the exception in Attachment 4.

2. In order to support the claim that debris found in the HPCS fuel oil pump suction strainers will provide evidence of coating degradation, describe the following:

General description of the fuel oil system:

There are two primary functions of the diesel generator fuel oil system: 1) the transfer of fuel oil from the storage tank to the day tank, and 2) the supply of fuel oil to the diesel generator. The transfer of fuel oil from the storage tank to the day tank has been described above and is similar for all of the diesel generators.

For the HPCS diesel engine, fuel oil is drawn from the day tank through a suction strainer for each of the engine driven and dc motor driven fuel pumps. Each pump will supply fuel at low pressure through a relief valve, through the engine mounted fuel filter, to the engine. Both fuel oil pumps continue to operate during engine operation.

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 2 L-24-208 Attachment 1 Page 6 of 9 Fuel oil is supplied to the engine from the bottom nozzle in the center of the bottom head of the day tank. This supply nozzle protrudes 1 above the bottom head minimizing the potential for debris that may enter the fuel oil supply lines. The HPCS diesel engine driven fuel oil pump has a rated capacity of 4 gpm at 60 psig. The dc motor driven fuel pump has a rated capacity of 3.6 gpm at 60 psig.

Mesh size of the strainers.

Each fuel pump suction strainer element is 28 to 30 mesh.

The two fuel transfer lines from the storage tank to the day tank each have a strainer with an element that has a perforation size of 1/8 diameter.

How frequently will these suction strainers be checked for debris?

Periodic cleaning of fuel oil pump strainers for the Division 3 HPCS diesel generator engine is currently planned for every 4 years. To ensure that the engine driven fuel pump and dc pump suction strainers are inspected for coating material, the fuel oil maintenance procedure will be enhanced to check for coating material trapped in strainers. If coating debris is found anywhere in the system including the strainers, the results will be evaluated by engineering for determining the scope and schedule for day tank inspections. The new program implementing documents will state that these inspections for coating material trapped in strainers will be performed at every cleaning and at least every 3 refueling cycles (6 years).

See Attachment 4 for the LRA program description changes and the changes in the justification for exception 2 described in LRA Section B.2.27 and as modified by 5 to the LRA Supplement transmitted in Letter L-24-020.

How frequently will these suction strainers see flow due to demand for equipment testing and/or recirculation of the fuel oil in the tank?

The HPCS diesel generator is operated monthly for surveillance testing. Other operation includes engine maintenance runs following maintenance outages, and a bi-annual 24-hour surveillance tests. That amount of engine operation would average around 30 hours3.472222e-4 days <br />0.00833 hours <br />4.960317e-5 weeks <br />1.1415e-5 months <br /> annually. A fuel oil transfer pump is expected to operate for around 10 minutes for each hour of engine operation. Additionally, the fuel oil transfer pumps are surveillance tested quarterly where each pump is operated over an hour.

Both engine fuel oil pump supply strainers experience flow during HPCS generator operation. Additionally, the dc driven pump may be operated to prime the engine post maintenance.

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 2 L-24-208 Attachment 1 Page 7 of 9 How much coating debris can these suction strainers accommodate before flow is reduced below demand?

Quantifying coating debris vs. head loss for the HPCS diesel fuel oil strainers would warrant empirical data that is not available. Instead of providing a specific answer to this question, PNPP commits to periodically inspect the strainers. See the response to the second bullet above. The basis for these periodic inspections of the strainer elements is presented there and responds to this concern.

The Orange No. 9373 primer is a high performance, polyamide cured heavy duty epoxy system which was originally designed for long-term use on surfaces subjected to heavy abrasion, moisture, or spills and fumes of acids, alkalis, solvents, greases, or oils. The primer provides excellent coverage due to the high solids (42%) rust-inhibitive formulation, has superior adhesion due to good penetrating and wetting characteristics, and produces an extremely tough, impermeable film.

Compared to a catastrophic coating failure, the more likely scenario would be an accumulation of coating failure over time, which would be addressed during surveillance testing. A blocked, DC or engine driven fuel pump supply strainer will experience a low discharge pressure with the pump operating and low differential pressure across the fuel oil filter differential pressure indicating degraded or no flow. SOI-E22B provides normal operations data to be observed during generator operations. If this were to occur, low fuel pump discharge pressure alarms would annunciate in the local panel and trouble alarm in the control room.

Additionally, when transferring fuel oil from the storage tank to the day tank, both fuel oil transfer strainers have differential pressure switches monitoring them. These pressure switches alarm and annunciate in the control room on high differential pressure.

3. Discuss the risk of an undetected failure of the coating/lining of the Division 3 HPCS fuel oil day tank preventing the HPCS from performing its intended function. The applicants discussion of the consequences of this undetected failure should address the following risks as a minimum:

Risk of fuel unavailability due to blocked suction strainers Catastrophic failure of the coating capable of suddenly blocking both strainers is highly unlikely and inconsistent with PNPP history and industry experience with epoxy coatings. The coating degradation observed in fuel oil storage tanks is of small flakes due either to mechanical damage or other localized mechanism. There has been no gross degradation involving large surface areas in the storage tanks. The day tanks have not experienced any loss, so it is assumed any degradation would be no worse than observed in the storage tanks.

The fine mesh in the fuel oil pump suction strainers is capable of trapping coating degradation seen in the fuel oil storage tanks. The coating applied to the interior of the fuel oil storage and day tanks has been prescribed to be 2 mils minimum. Depending on the actual coating thickness applied, the total coating volume will vary. It is expected that if a catastrophic coating failure occurred, the HPCS diesel engine could not perform its intended function because of fuel oil flow blockage.

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 2 L-24-208 Attachment 1 Page 8 of 9 Risk of adverse consequences downstream of the suction strainers due to small size coating debris bypassing the strainers The design of the fuel supply system eliminates this risk. There are two filters downstream that would prevent small size coating debris that might bypass these strainers and interfere with injector flow to the cylinders. UFSAR section 9.5.9.1.2 describes the configuration as follows (refer to scoping boundary Drawing 302-0356): A strainer in the inlet lines to each of the HPCS diesel fuel pumps (priming or booster) and a duplex filter in each line from the fuel pumps to the engine are provided to remove particulates which could hamper engine operation. To further purify the oil, the injector assemblies each contain filters, one in the inlet and one in the return line to the day tank.

Risk of disabled or degraded HPCS system Per UFSAR Section 8.3.1.1.3.3.a, The HPCS system and its power supply unit is part of the ECCS. HPCS and the diesel generator by itself does not meet the single failure criterion, although the criterion is applicable at the ECCS level. Consequently, loss of the HPCS system will not prevent safely shutting down the plant or preventing the mitigation of the consequences of any of the postulated accidents except for a station blackout event. In the case of the accidents described in Chapter 15 of the UFSAR and as part of the ECCS systems, the HPCS system is supported by other safety systems, such as the diverse Reactor Core Isolation Cooling System and the Automatic Depressurization System (ADS) in conjunction with Low Pressure Core Spray (LPCS) system and the Residual Heat Removal (RHR) system.

The High Pressure Core Spray Diesel Generator System (HPCS DG) provides an independent source of AC power to the Division 3 Class 1E bus, EH13. The Unit 1 Interbus Transformer (LH 1 A) is considered the preferred source, the HPCS DG is the emergency source and the Unit 2 Interbus Transformer (LH 2 A) is the alternate-preferred. The HPCS Diesel Generator is capable of quickly restoring power to the HPCS System in the event that off-site power is unavailable. The PNPP station blackout coping strategy described in UFSAR section 15H.2.2 credits the function of the HPCS diesel generator.

Supporting the above discussion, Section 8.3.1.1 of the Safety Evaluation Report, NUREG-0887, SER related to the operation of Perry Nuclear Power Plant, Units 1 and 2, the staff reviewed onsite the AC power system and has determined among other requirements The three divisions of the emergency power distribution system are independent, meet the single-failure criterion, and have the required capability and capacity as required by GDC 17.

LRA changes associated with this RAI response are provided in the associated attachment identified below.

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 2 L-24-208 Attachment 1 Page 9 of 9 References PNPP UFSAR Rev 23 Sections 8.3.1.1.3.3.a, 9.5.9.1.2 (ADAMS Accession No. ML23303A133)

PNPP LRA Supplement 2 transmitted via Vista Letter L-24-020 (ADAMS Accession No. ML24180A010)

Attachments to this letter

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 2 L-24-208 Attachment 2 Page 1 of 9 NCSG RAI-10276-R1 XI.M36 External Surfaces - Stainless Steel Flex Hose Failures Regulatory Basis 10 CFR 54.21(a)(3) requires an applicant to demonstrate that the effects of aging for structures and components will be adequately managed so that the intended function(s) will be maintained consistent with the current licensing basis for the period of extended operation. For structures and components requiring review under 10 CFR 54.21, the staff must find (as required by 10 CFR 54.29(a)) that actions have been identified and have been or will be taken with respect to managing the effects of aging during the period of extended operation. To complete its review and enable the formulation of a finding under 10 CFR 54.29(a), the staff requests additional information regarding the matters described below.

RAI B.2.22-1: XI.M36 External Surfaces - Stainless Steel Flex Hose Failures

Background:

Perry license renewal report LRPY-OE-001, Revision 3, Operating Experience Review includes CR-2021-2192 and CR-2021-2296 that document leaking stainless steel flexible air supply hoses for safety relief valves 1B21F041B and 1B21F051B, respectively. The condition reports cite the suspected failure causes as cyclic fatigue or cracking due to stress corrosion cracking. Both CRs note that the causes of leaks are not yet known and that a failure analysis is needed to definitively determine the cause. The operating experience report tentatively assigns the condition reports to XI.M36 (External Surfaces Monitoring of Mechanical Components) with a citation to aging management review (AMR) item AP-209, which is associated with NUREG-1800, Revision 2, "Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants," (SRP-LR) Further Evaluation Section 3.3.2.2.3, Cracking Due to Stress Corrosion Cracking.

Although failure analyses were ultimately not performed on the flex hoses for the leaks identified in 2021, the NRC identified more recent condition reports (CR-2023-02255 and CR-2023-02318) that document additional leaking stainless steel flexible air hoses for safety relief valves 1B21F041B and 1B21F047B, respectively. Perrys operating experience review performed for these condition reports identified that previous leaks in the flexible air hoses for the same system had occurred in 2021 (SRV-0041B and -0051B), in 2017 (SRV-0041B), and in 2011 (SRV-0051B). An outside vendor performed a failure analysis for the leaking flex hoses from 2023, and their February 2024 (draft) and April 2024 (final) failure analysis reports determined the cause to be outside diameter chloride induced stress corrosion cracking.

As recommended in the vendors failure analysis report, Perry initiated CR-2024-01530 on February 27, 2024, to identify the source of the chloride found on the flexible hoses. However, the investigation did not find the source of the chloride contamination. The aging management evaluation performed as part of the condition report and completed on April 24, 2024, stated, This does not appear to be an aging management issue. The failure in the report is some type

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 2 L-24-208 Attachment 2 Page 2 of 9 of stress-based cracking, potentially from chloride. Additionally, the condition report states, Available replacement hoses contain no detectable contaminants.

Perrys operating experience report, LRPY-OE-001, also states that, consistent with Regulatory Issue Summary 2014-06, Revision 1, Consideration of Current Operating Issues and Licensing Actions in License Renewal (ML23167A044), Perry will monitor significant operating experience that could challenge the adequacy of the aging management programs after the license renewal application submittal and supplement the application as appropriate. The regulatory issue summary specifically discusses the need for the NRC staff to receive information about late-breaking operating experience if it materially affects the license renewal application (LRA). The staff notes that Perrys first annual update, issued on July 3, 2024, did not include the late-breaking operating experience information from the recently completed failure analysis report.

Perrys LRA Supplement 2 (dated June 27, 2024 (ML24180A010)) modified LRA Sections 3.2.2.2.6, 3.3.2.2.3, and 3.4.2.2.2, Cracking Due to Stress Corrosion Cracking, and LRA Sections 3.2.2.2.3, 3.3.2.2.5, 3.4.2.2.3, Loss of Material due to Pitting and Crevice Corrosion, to include statements This section follows up supporting this assertion [concerning no environmental halides] by not identifying operating experience typically related to having salt deposits or other industrial contamination.

Issue:

The NRC staff identified the following issues with the above information.

1. Perrys aging management evaluation, conducted for CR-2024-01530, concluded that the failure analysis reports determination (i.e., chloride induced stress corrosion cracking of the stainless-steel flexible air supply hoses) was not an aging management issue. The staff notes that chloride induced stress corrosion cracking, as discussed in SRP-LR Sections 3.2.2.2.6, 3.3.2.2.3, and 3.4.2.2.2, is an aging effect requiring management for stainless steel components exposed to air environments containing halides. Although the above SRP-LR sections pertain to chloride sources from outdoor air, based on Perrys plant-specific operating experience, some stainless-steel components in an indoor uncontrolled air environment are being exposed to an unidentified source of chlorides, causing stress corrosion cracking. For the associated stainless steel flexible hose AMR items, LRA Table 3.1.2-2 notes that there are no aging effects requiring management and there is no associated aging management program. This is inconsistent with the failure analysis conclusions.

2. Because Perry was unable to identify the source of the chlorides causing the stress corrosion cracking, comparable components (i.e., stainless steel flexible hoses exposed to indoor uncontrolled air) may also be susceptible to the same plant-specific operating experience aging effect (i.e., chloride induced stress corrosion cracking).

3. The NRC staff specifically discussed the associated issues during the XI.M36 audit breakout session in January and expressed an interest in the results of the failure analysis. The failure analysis vendor provided draft and final versions of its report in February and April 2024, respectively. Perry initiated follow-up condition report CR-2024-01530 on February 27, 2024, and completed its aging management review on April 24, 2024. However, Perry did

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 2 L-24-208 Attachment 2 Page 3 of 9 not provide the late-breaking operating experience information in its annual update issued on July 3, 2024. Although Perry said that it will monitor significant operating experience that could challenge the adequacy of the aging management programs, the process for controlling this review and for determining the effects on the LRA is unclear..

4. It is not clear how Perry determined that all flex hoses in the warehouse did not contain any chlorides. The outer surface of the stainless-steel pressure retaining portion of the flexible hose is covered by an integral metal mesh. The results of the testing may not be valid unless the test looking for chlorides was conducted on the pressure retaining surface of the flex hose.

5. Based on the plant-specific operating experience for failures of stainless steel flex hoses, it can be reasonably concluded that chloride induced stress corrosion cracking has occurred on multiple occasions at Perry. However, because the source of the chloride contamination could not be identified, it is unclear whether the supplemented statements for LRA Sections 3.2.2.2.3, 3.2.2.2.6, 3.3.2.2.3, 3.3.2.2.5, 3.4.2.2.2, and 3.4.2.2.3 regarding not identifying operating experience related to chloride contamination is correct.

Request:

1. Because chloride induced stress corrosion cracking was concluded to be the cause of the degradation of the stainless-steel flexible air supply hoses to the safety relief valves, either update LRA Table 3.1.2-2 to identify this aging effect requiring management or provide a basis for why this age-related degradation does not need to be managed. If applicable, include the aging management program to be used for managing this aging effect and provide information for how degradation prior to a loss of intended function of an air system will be detected with the program. Specifically discuss how the outside diameter initiated cracking will be detected, given that the pressure retaining surface is covered by an integral metal mesh.

2. Because the source of the chlorides causing the stress corrosion cracking was not able to be identified, either update other LRA Tables for comparable components (i.e., stainless steel flexible hose exposed to indoor uncontrolled air) or provide a basis for why this aging effect requiring management does not apply to the other comparable components.

3. Because Perry did not provide the recently developed information relating to the failure analysis results (i.e., the leaks on the stainless-steel flexible hoses were caused by chloride induced stress corrosion cracking), provide information about the process for performing the reviews described in LRPY-OE-001 of post submittal operating experience and for determining any effects on the LRA.

4. Because the outer surface of the stainless-steel pressure retaining portion of the flexible hose is covered by an integral metal mesh, provide information about how the testing was performed to determine that all other stainless steel flexible hoses in the warehouse do not contain chloride contaminants and the associated aging effect requiring management would not apply to the replacement components.

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 2 L-24-208 Attachment 2 Page 4 of 9

5. Because recent operating experience has identified chloride induced stress corrosion cracking, either provide the basis for the accuracy of the statements in the supplemented statements for LRA Sections 3.2.2.2.3, 3.2.2.2.6, 3.3.2.2.3, 3.3.2.2.5, 3.4.2.2.2, and 3.4.2.2.3 regarding not identifying operating experience related to chloride contamination that could cause stress corrosion cracking or loss of material (due to pitting or crevice corrosion) of stainless steel, or update these LRA sections as necessary.

PNPP Response:

1. Because chloride induced stress corrosion cracking was concluded to be the cause of the degradation of the stainless-steel flexible air supply hoses to the safety relief valves, either update LRA Table 3.1.2-2 to identify this aging effect requiring management or provide a basis for why this age-related degradation does not need to be managed. If applicable, include the aging management program to be used for managing this aging effect and provide information for how degradation prior to a loss of intended function of an air system will be detected with the program.

Specifically discuss how the outside diameter initiated cracking will be detected, given that the pressure retaining surface is covered by an integral metal mesh.

The failure analysis report identified the failure mechanism for the flex hoses as chloride induced, transgranular, stress corrosion cracking (SCC) in the replacement hose installed in 2021 that supplied to Safety Relief Valve (SRV) actuator 1B21F0041B (manufactured in 2011) and original installation hose suppling SRV actuator 1B21F0047B installed prior to commercial operation more than 37 years ago.

PNPP Condition Report (CR) 2024-07520 was written to identify that the investigation for chloride contamination sources was ineffective and deemed invalid due to the inconclusive nature of the testing performed. Although the failure analysis report established a cause of the flexible hose failures, it is not definitive that the source of the chlorides was plant-specific and not clear that the requirements the ASME Code Section IWA-4160 were addressed in earlier CRs addressing SRV hose failures and replacement activities.

CR-2024-07520 description includes recommended actions needed to be documented that will satisfy the Corrective Action Program and ASME Code requirements, to establish sufficient equipment reliability for these SRV stainless steel flex hoses supplying air to the relief function.

The recommended actions for the CR include the following:

• a population of the flex hoses available in the warehouse should be analyzed (destructive testing) to determine if the presence of chlorides, determined previously to be causal to hose failure, is the result of a manufacturing issue

• in-plant sampling should be performed in the area of the SRVs to definitively conclude that the chloride source is not plant-specific

• address any latent issues which may exist with currently installed hoses, such as expedited replacement activities

• document compliance with the above cited ASME Section XI requirements

• identify a satisfactory replacement flex hose design and periodic leak testing for continued reliability

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 2 L-24-208 Attachment 2 Page 5 of 9 Based on industry Operating Experience (OE), the NRC is asserting that outside air can include contaminants that could contribute to SCC. Although the Drywell environment is not supplied with outdoor air, the presence of chloride contamination on hoses originally installed at PNPP and subsequent SCC failures, warrants further evaluation. The first two bulleted recommended actions in CR-2024-07520 above will address these issues.

Leak testing sufficiency to identify leakage prior to loss of the SRVs relief and Automatic Depressurization System (ADS) functions will be addressed under compliance with ASME Section XI requirements. ASME Code Section IWA 4160 states:

(a) If an item does not satisfy the requirements of this Division, the Owner shall determine the cause of unacceptability. Prior to returning the item to service the Owner shall evaluate the suitability of the item subjected to the repair/replacement activity. If the requirements for the original item are determined to be deficient, appropriate corrective provisions shall be included in the Owners Requirements and Design Specification, as applicable.

(b) Whether or not the repair/replacement activity results from a failure to satisfy the requirements of this Division, the following requirements shall be met. If the expected life of the item after completion of the repair/replacement activity is less than the remainder of the previous intended life [IWA-4150(c)(5)], the Owner shall initiate actions that will result in a plan for additional examinations and evaluations to verify the acceptability of the item for continued service or shall schedule subsequent repair/replacement activities prior to the end of the expected life of the item.

The last two bulleted CR recommended actions suggest periodic replacement of these flexible hoses, which in turn would make these components short-lived and no longer subject to aging management review. Nevertheless, the LRA changes need to reflect the current conditions affecting aging management review. With this perspective in mind, the proposed changes to the LRA are discussed below:

Changes to LRA Table 3.1.2-2, Nuclear Boiler System:

Rows 10 and 11 will be removed or replaced with a different material, if appropriate.

These rows reflect a design change to accommodate a nickel alloy flex hose material that will not be implemented Plant Specific Note 111 on LRA Page 3.1-110 is no longer applicable since Row 10 is being removed or replaced with an improved material. The note will be deleted or revised accordingly.

A new line item similar to Row 13 will be added replacing None with an aging effect of Cracking (due to SCC) and the aging management program with the External Surfaces Monitoring of Mechanical Components. The same NUREG-1801 Item and Table 1 Item will be listed. Standard Note F and a plant specific note assigned to clarify the limitations to this component based upon the conclusions regarding the extent of chloride contamination.

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 2 L-24-208 Attachment 2 Page 6 of 9 Note that Rows 12 thru 14 will remain unchanged. Row 12 represents the subject SRV flexible hoses with dry air internally with no aging effects. Per the failure analysis report, the cracks resulting in air leakage originated from the outer surface. However, Rows 13 and 14 represent the stainless steel flexible hoses in the SRV leakoff lines. These lines are not normally pressurized since they do not normally contain liquid or steam. The normal internal environment consist of Air - indoor, uncontrolled. These leakoff line flexible hoses are treated as any other stainless steel component in the Drywell.

Based upon findings from the first two bullets above, appropriate assignments will be made for other susceptible components.

Change to LRA Table 3.1.1, Line 3.1.1-107 Discussion Text as follows:

Consistent with NUREG-1801, with the following clarification and a different program, the External Surfaces Monitoring of Mechanical Components program will manage cracking due to stress corrosion cracking of stainless steel flexible hoses suppling compressed air to the safety relief valves in the Nuclear Boiler system. See LRA Appendix B, B.2.18 for the associated commitments. In addition to the Reactor Vessel, Internals, and Reactor Coolant systems; stainless steel commodities in concrete in the Bulk Civil Commodities, Containment Structure, and Turbine Buildings and Associated Structures, Process Facilities, and Yard Structures have been aligned with this item.

Changes to LRA Appendix A, Section A.1.18 and Appendix B, B.2.18 are as follows:

In a future supplement to the LRA to be submitted after completion of CR-2024-07520 investigation, the following two changes are proposed Based on the completed Condition Report 2024-07520 investigation and identified corrective actions, a commitment will be added to LRA Sections A.1.18 and B.2.18 that address actions to be completed before entry into the PEO regarding determining the extent of chloride contamination in the PNPP Drywell. Based on the results of those actions, the aging effect of Cracking will be added to AMR tables for stainless steel components in an indoor air (uncontrolled) environment in the Drywell, if the aging affect is found to apply, to be managed by the External Surfaces Monitoring of Mechanical Components aging management program.

The operating experience section of LRA Appendix B, Section B.2.18, External Surfaces Monitoring of Mechanical Components, will be revised to include a discussion involving Condition Report 2024-01530 and related, recent Condition Reports 2024-07520 and 2024-07527.

The time required to complete all actions to fully resolve these CRs are not anticipated prior to the PEO.

Other LRA changes will be discussed below as appropriate.

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 2 L-24-208 Attachment 2 Page 7 of 9

2. Because the source of the chlorides causing the stress corrosion cracking was not able to be identified, either update other LRA Tables for comparable components (i.e.,

stainless steel flexible hose exposed to indoor uncontrolled air) or provide a basis for why this aging effect requiring management does not apply to the other comparable components.

In the response to Request 1 the resolution to the first two bulleted items under the investigations in CR 2024-07520, the resolutions will be aimed at determining whether the concerns about chloride contamination in the PNPP Drywell environment is warranted and what actions are required to eliminate or mitigate the associated aging effects.

See Response to Request 1 above for additional details and proposed LRA changes.

3. Because Perry did not provide the recently developed information relating to the failure analysis results (i.e., the leaks on the stainless-steel flexible hoses were caused by chloride induced stress corrosion cracking), provide information about the process for performing the reviews described in LRPY-OE-001 of post submittal operating experience and for determining any effects on the LRA.

Condition Reports are screened bi-weekly by site management as part of a Management Review Board (MRB) meeting. Input is provided to MRB members for assignment of aging management evaluation (AME) forms. AME forms are completed based on available information to determine if the CR content represents a new Material/Environment/Aging Effect requiring management. The AME form content is utilized during OE updates to determine if the event is relevant to LRA content. In this case, although the CR was flagged appropriately, the AME incorrectly concluded that it was not an aging management issue. This mistake resulted in the CR/OE being excluded during the annual update OE review.

PNPP agrees that the event was inappropriately excluded. A separate condition report, CR 2024-07527, identifies this issue and is intended to drive revision of the AME for future LRA incorporation. However, as evident from CR 2024-7520 and the content of this RAI response, the potential new material/environment/aging mechanism is indeterminate and requires further site evaluation. As noted above, CR 2024-07520 is intended to drive this action. Upon conclusive information becoming available, appropriate LRA edits will be initiated including removal from aging management review if these components are periodically replaced.

As noted above in response to Request 1, the site operating experience relevant to the flexible hose failures identified in this RAI will be incorporated into LRA Appendices A.1.18 and B.2.18.

4. Because the outer surface of the stainless-steel pressure retaining portion of the flexible hose is covered by an integral metal mesh, provide information about how the testing was performed to determine that all other stainless steel flexible hoses in the warehouse do not contain chloride contaminants and the associated aging effect requiring management would not apply to the replacement components.

Responsive to the failure analysis report, an investigation to find chloride contamination on spare flex hoses stored in the warehouse had negative results. However, an inferential method was used to detect chloride contamination based upon an assumption that cannot be validated.

The method used was limited to sampling of the metallic powder/granule debris within the

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 2 L-24-208 Attachment 2 Page 8 of 9 packaging containing the hoses. The method assumed any chloride contamination on the hose under the mesh would also be present in the debris sampled. As pointed out in the background section of this RAI and PNPP agrees, the method used could not definitively rule out chloride contamination under the stainless steel mesh.

In the response to Request 1, adequacy of testing methods will be addressed along with adequacy of periodic requirements for testing such that leakage will be detected prior to loss of the relief and ADS functions of these SRVs. LRA changes are also discussed in the response to Request 1.

5. Because recent operating experience has identified chloride induced stress corrosion cracking, either provide the basis for the accuracy of the statements in the supplemented statements for LRA Sections 3.2.2.2.3, 3.2.2.2.6, 3.3.2.2.3, 3.3.2.2.5, 3.4.2.2.2, and 3.4.2.2.3 regarding not identifying operating experience related to chloride contamination that could cause stress corrosion cracking or loss of material (due to pitting or crevice corrosion) of stainless steel, or update these LRA sections as necessary.

PNPP believes the evidence thus far remains consistent with the information presented in these sections and the OE regarding stainless steel flexible hoses have no bearing on these Further Evaluation Items in NUREG-1800. The Drywell and in particular these flexible hoses have no components exposed to air which could be introduced into buildings, i.e., components near intake vents. Therefore, this OE is not relevant to the conclusions in these further evaluation sections.

It is significant that the flexible hose failures have all occurred in a localized area of the Drywell (the first 3 SRVs on Main Steam Line B). If the chlorides were ubiquitous in the Drywell, then this localized failure pattern would be inconsistent with that condition. These components are not near outdoor air intake vents. Additional evidence that the condition is not widespread, consider that if the indoor air, uncontrolled environment had enough halogens (chloride in particular) from any source, other effects such as widespread pitting and crevice corrosion in stainless steel components would be occurring in the Drywell. This condition is not being observed based on lack of OE. Nevertheless, based upon finding stress corrosion cracking in thin hoses (20 mill stainless steel wall thickness of the stainless steel flexible hose pressure boundary), additional evaluation to support the rationale is required.

CR 2024-07520 addresses the source of chloride contamination and will include corrective actions to mitigate the condition. Because of the changes to LRA Appendix A, Section A.1.18, the effects on aging management program will be included in future UFSAR updates.

No changes to LRA Sections 3.2.2.2.3, 3.2.2.2.6, 3.3.2.2.3, 3.3.2.2.5, 3.4.2.2.2, and 3.4.2.2.3 as modified by the LRA supplements as listed below are warranted.

PNPP LRA Supplement 2 (Vistra Letter L-24-020) and the following attachments of that letter as listed below 3, LRA Section 3.2.2.2.3 5, LRA Section 3.2.2.2.6

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 2 L-24-208 Attachment 2 Page 9 of 9 1, LRA Section 3.3.2.2.3 2, LRA Section 3.3.2.2.5 PNPP LRA Supplement 3 (Vistra Letter L-24-108) and the following attachments of that letter as listed below 1, LRA Section 3.4.2.2.2 2, LRA Section 3.4.2.2.3 LRA changes associated with this RAI response will be provided in a future LRA supplement after completing the investigation of CR-2024-07520. PNPP anticipates that completion of all corrective actions associated with the SRV flexible hose issue will not occur until after the start of the PEO. Future updates to the UFSAR will capture the impacts.

References NUREG-1800, Rev. 2 Attachments None

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 2 L-24-208 Attachment 3 Page 1 of 6 NVIP RAI-10231-R1 Question 1 Regulatory Basis 10 CFR Part 54.3 defines a time limited aging analyses as those licensee calculations and analyses that:

(1) Involve systems, structures, and components within the scope of license renewal, as delineated in § 54.4(a);

(2) Consider the effects of aging; (3) Involve time-limited assumptions defined by the current operating term, for example, 40 years; (4) Were determined to be relevant by the licensee in making a safety determination; (5) Involve conclusions or provide the basis for conclusions related to the capability of the system, structure, and component to perform its intended functions, as delineated in § 54.4(b); and (6) Are contained or incorporated by reference in the CLB.

10 CFR 54.21(c)(1) states a list of time-limited aging analyses, as defined in § 54.3, must be provided. The applicant shall demonstrate that:

(i) The analyses remain valid for the period of extended operation; (ii) The analyses have been projected to the end of the period of extended operation; or (iii) The effects of aging on the intended function(s) will be adequately managed for the period of extended operation.

Request for Additional Information 4.2-1

Background

LRA Table 4.2-2, PNPP RPV Beltline USE Data for 54 EFPY and LRA Table 4.2-3, PNPP Beltline RPV Material ART Data for 54 EFPY provide material property information for reactor pressure vessel materials.

Issue During its audit, the staff reviewed the certified material test reports associated with the applicants reactor pressure vessel materials to determine whether the material information (e.g., initial RTNDT, %Cu, %Ni, initial USE, margin values) for the RPV materials contained in LRA Tables 4.2-2 and 4.2-3, were consistent with the applicants current licensing basis or based on information from certified material test reports or fabrication records for the specific material or weld type.

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 2 L-24-208 Attachment 3 Page 2 of 6 During its review, the staff noted that the %Cu and %Ni content values for Lower Shell Plate (i.e., Heat Nos C2448-1, C2448-2 and A1068-1) in LRA Tables 4.2-2 and 4.2-3 were inconsistent with the check values (i.e., measurements taken from the product form) documented in the CMTRs.

Request For the Lower Shell Plate (i.e., Heat Nos C2448-1, C2448-2 and A1068-1), justify that the %Cu and %Ni content values for these RPV materials in LRA Tables 4.2-2 and 4.2-3 are inconsistent with the check values (i.e., measurements taken from the product form) documented in the certified material test reports.

Question 2 Regulatory Basis 10 CFR 54.21(a)(3) requires an applicant to demonstrate that the effects of aging for structures and components will be adequately managed so that the intended function(s) will be maintained consistent with the current licensing basis for the period of extended operation. 10 CFR 54.21(d) requires the FSAR supplement for the facility to contain a summary description of the programs and activities for managing the effects of aging for the period of extended operation determined by 10 CFR 54.21(a). One of the findings that the staff must make to issue a renewed license (10 CFR 54.29(a)) is that actions have been identified and have been or will be taken with respect to managing the effects of aging during the period of extended operation on the functionality of structures and components that have been identified to require review under 10CFR 54.21, such that there is reasonable assurance that the activities authorized by the renewed license will continue to be conducted in accordance with the current licensing basis. In order to complete its review and enable making a finding under 10 CFR 54.29(a), the staff requires additional information in regard to the matters described below.

Background

The Program Description for the BWR Vessel ID Attachment Welds AMP (XI.M4) in Revision 2 of NUREG-1801, Generic Aging Lessons Learned (GALL) Report (ML103490041) states that the program includes inspection and flaw evaluation in accordance with the guidelines of a staff-approved Boiling Water Reactor Vessel and Internals Project report (BWRVIP-48-A) to provide reasonable assurance of the long-term integrity and safe operation of boiling water reactor (BWR) vessel inside diameter (ID) attachment welds.

In Appendix A of the PNPP LRA, the Updated Final Safety Analysis Report Supplement, paragraph A.1.13 states, The BWR Vessel ID Attachment Welds aging management program is an existing condition monitoring program that includes the inspection and evaluation recommendations within BWRVIP-48 and the requirements of ASME Code,Section XI.

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 2 L-24-208 Attachment 3 Page 3 of 6 Appendix C of the LRA, BWRVIP Applicant Action Items, lists among BWRVIP documents credited for PNPP license renewal, BWRVIP-48, Revision 1, Vessel ID Attachment Weld Inspection and Flaw Evaluation Guidelines.

In LRA Supplement 2, Attachment No. 51, Section B.2.13 states, prior to entering the subsequent 10-year ISI intervals, PNPP would have to either comply with the ASME Code requirements and NRC approved BWRVIP-48 guidance, or request [NRC approval of an alternative to] the requirements consistent with what PNPP has done during the initial operating period.

Issue There is a discrepancy among the descriptions of requirements and guidance that will be used to provide reasonable assurance of the long-term integrity of the ID attachment welds. In addition to meeting the requirements of ASME Code Section XI, the inspection and flaw evaluation guidelines approved by the staff are in BWRVIP-48-A. The LRA, as supplemented, does not make clear whether the applicant intends to use BWRVIP-48-A.

Request Confirm that the UFSAR will credit the staff-approved guidance in addition to the ASME Code requirements, or that staff approval for an alternative to the approved guidance will be sought prior to the start of subsequent 10-year ISI intervals.

PNPP Response Question 1 For the Lower Shell Plate (i.e., Heat Nos C2448-1, C2448-2 and A1068-1), justify that the

%Cu and %Ni content values for these RPV materials in LRA Tables 4.2-2 and 4.2-3 are inconsistent with the check values (i.e., measurements taken from the product form) documented in the certified material test reports.

PNPP agrees that some of the material chemistry values used as input to the ART and USE calculations were non-conservative. A condition report has been generated to document the use of the non-conservative input values for the calculation.

A qualitative evaluation based on the guidance in Regulatory Guide 1.99, Rev.2 was performed to determine the impact of these non-conservative values on the ART and USE values for the affected heats. This evaluation indicated that the use of the non-conservative chemistry values did not invalidate the USE and ART evaluations included in the PNPP LRA.

An update of the ART and USE calculations using the appropriate material chemistry values was also initiated. The update is expected to be completed by the end of September 2024.

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 2 L-24-208 Attachment 3 Page 4 of 6 An update to LRA Tables 4.2-2 and 4.2-3 to provide the revised ART and USE calculation results will be provided in an LRA supplement no later than October 21, 2024 to address this RAI question.

Question 2 Confirm that the UFSAR will credit the staff-approved guidance in addition to the ASME Code requirements, or that staff approval for an alternative to the approved guidance will be sought prior to the start of subsequent 10-year ISI intervals.

PNPP agrees that the PNPP BWR Vessel ID Attachment Welds Program should follow staff-approved guidance in addition to the ASME Code requirements, or that staff approval for an alternative to the approved guidance for the subsequent 10-year ISI intervals.

To clarify this, the following LRA sections will be revised to read as follows:

Section A.1.13 The BWR Vessel ID Attachment Welds aging management program is an existing condition monitoring program that includes the inspection and evaluation of the reactor vessel internal attachment welds that follows the requirements of the ASME Code Section XI, Subsection IWB, Examination Category B-N-2 enhanced consistent with the inspection and evaluation guidelines of an NRC approved BWRVIP-48, BWR Vessel and Internals Project Vessel ID Attachment Weld Inspection and Flaw Evaluation Guidelines or a staff approved alternative to the approved guidance. The program is implemented Section B.2.13 The program is implemented through station procedures that provide for condition monitoring through in-vessel examinations of the reactor vessel internal attachment welds in accordance with the requirements of the ASME Code Section XI, Subsection IWB, Examination Category B-N-2 enhanced consistent with the inspection and evaluation guidelines of an NRC approved BWRVIP-48, BWR Vessel and Internals Project Vessel ID Attachment Weld Inspection and Flaw Evaluation Guidelines or a staff approved alternative to the approved guidance.

Section B.2.13, Justification for Exception It is understood that for subsequent 10-year ISI intervals, PNPP would have to either comply with the ASME Code requirements and NRC approved BWRVIP-48 guidance, or request staff approval for an alternative to the approved guidance prior to the start of the subsequent 10-year ISI intervals.

It is recognized that

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 2 L-24-208 Attachment 3 Page 5 of 6 LRA Appendix C of the LRA evaluates the applicant action items included in the NRC SERs for the BWRVIP documents credited for PNPP license renewal. As discussed in Section B.2.13, PNPP took exception using BWRVIP-48-A as a basis for the BWR Vessel ID Attachment Welds Program. BWRVIP-48 was inadvertently included in the list of BWRVIP documents to be addressed since the revision of the document that PNPP did credit does not have an NRC SER.

BWRVIP-48 will be deleted from the Appendix C list.

However, the Renewal Applicant Action Items from the SER for BWRVIP-48-A are addressed below:

(1) The license renewal applicant is to verify that its plant is bounded by the BWRVIP-48 report. Further, the renewal applicant is to commit to programs described as necessary in the BWRVIP-48 report to manage the effects of aging on the functionality of the bracket attachments during the period of extended operation. Applicants for license renewal will be responsible for describing any such commitments and identifying how such commitments will be controlled. Any deviations from the aging management programs within the BWRVIP-48 report described as necessary to manage the effects of aging during the period of extended operation and to maintain the functionality of the reactor vessel components or other information presented in the report, such as materials of construction, will have to be identified by the renewal applicant and evaluated on a plant-specific basis in accordance with 10 CFR 54.21(a)(3) and (c)(1).

PNPP uses BWRVIP-48 as guidance for the inspection and evaluation of the bracket attachments. As discussed in LRA Section B.2.13, the bracket inspections are currently based on BWRVIP-48, R1, which is a staff approved alternative to the approved guidance for PNPP.

(2) 10 CFR 54.21(d) requires that an FSAR supplement for the facility contain a summary description of the programs and activities for managing the effects of aging and the evaluation of TLAA for the period of extended operation. Those applicants for license renewal referencing the BWRVIP-48 report for the bracket attachments shall ensure that the programs and activities specified as necessary in the BWRVIP-48 report are summarily described in the FSAR supplement.

LRA Section A.1.13 provides the required USAR (FSAR) supplement.

(3) 10 CFR 54.22 requires that each application for license renewal include any technical specification changes (and the justification for the changes) or additions necessary to manage the effects of aging during the period of extended operation as part of the renewal application. In its Appendix A to the BWRVIP-48 report, the BWRVIP stated that there are no generic changes or additions to technical specifications associated with the bracket attachments as a result of its aging management review and that the applicant will provide the justification for plant-specific changes or additions. Those applicants for license renewal referencing the BWRVIP-48 report for the bracket attachments shall ensure that the inspection strategy described in the BWRVIP-48 report does not conflict or result in any changes to their technical specifications. If technical specification changes do result, then the applicant should ensure that those changes are included in its application for license renewal.

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 2 L-24-208 Attachment 3 Page 6 of 6 PNPP currently uses BWRVIP-48 as guidance for inspection and evaluation of bracket attachments. No technical specification changes are required.

The following LRA sections/appendices will be updated with this response.

Section A.1.13, Section B.2.13, and Appendix C LRA changes associated with this RAI response are provided in the associated attachments identified below.

References None Attachments to this letter

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 2 L-24-208 Attachment 4 Page 1 of 5 LRA Sections: A.1.27 and B.2.27 LRA Page Number(s): A-29 and B-84 through B-86

References:

NCSG RAI-10181-R1, LRA Supplement transmitted in Vistra Letter L-24-020 Description of Change: Revise program descriptions in LRA Appendices A.1.27 and B.2.27, and exceptions 1 and 2 and the justifications. These changes result from the response to the RAI NCSG RAI-10181-R1. Exceptions 1 and 2 were included in LRA Section B.2.27, as modified by 5 to the LRA Supplement transmitted in Letter L-24-020. The program descriptions were revised to reflect that many baseline inspections have been completed, but not all completed.

PNPP LRA Appendix A, Page A29 is revised as follows:

A.1.27 INTERNAL COATINGS/LININGS FOR IN-SCOPE PIPING, PIPING COMPONENTS, HEAT EXCHANGERS, AND TANKS PROGRAM The Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks Program is a new condition monitoring program that will perform periodic visual inspections of internal coatings of in-scope components. The program uses leading indicators to determine the scope and schedule for Division 3 fuel oil day tank internal inspections. The program will manage the loss of coating integrity in heat exchangers, piping, piping components, piping elements, and tanks.

Inspections will be performed for signs of coating failures and precursors to coating failures including peeling, delamination, blistering, cracking, flaking, chipping, rusting, and mechanical damage. When acceptance criteria are not met, physical testing will be performed where physically possible (i.e., sufficient room to conduct testing) in conjunction with repair or replacement of the coating/lining. Inspection results that do not satisfy established acceptance criteria will be entered into the corrective action program.

The training and qualification of individuals involved in coating/lining inspections of non-cementitious coatings/linings will be conducted in accordance with ASTM International standards endorsed in RG 1.54 including guidance from the NRC staff associated with a particular standard. For cementitious coatings, training and qualifications will be based on an appropriate combination of education and experience related to inspecting concrete surfaces. The maximum interval of subsequent coating inspections will be consistent with Table 4a of GALL Report AMP XI.M42 in LR-ISG-2013-01, Aging Management of Loss of Coating or Lining Integrity for Internal Coatings/Linings on In-Scope Piping, Piping Components, Heat Exchangers, and Tanks.

The program will be implemented no later than six months prior to the period of extended operation.

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 2 L-24-208 Attachment 4 Page 2 of 5 Baseline coating/lining inspections are being performed in the 10-year period prior to the period of extended operation and begin no later than six months prior to the period of extended operation. New implementing documents have been developed to support these activities.

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 2 L-24-208 Attachment 4 Page 3 of 5 PNPP LRA Appendix B, Pages B-84 and B-86 and as modified by Pages 1 through 3 of 5 to Supplement 2 in Vistra Letter L-24-020 are revised as follows:

B.2.27 INTERNAL COATINGS/LININGS FOR IN-SCOPE PIPING, PIPING COMPONENTS, HEAT EXCHANGERS, AND TANKS PROGRAM Program Description The Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks Program is a new condition monitoring program that will perform periodic visual inspections of internal coatings of in-scope components. The program uses leading indicators to determine the scope and schedule for Division 3 fuel oil day tank internal inspections. The program will manage the loss of coating integrity in heat exchangers, piping, piping components, piping elements, and tanks. Even though this is a new program, some aspects of this program already existed at PNPP, such as diesel generator fuel oil storage tank periodic draining, sludge and sediment removal, cleaning, and internal coating inspection.

Inspections will be performed for signs of coating failures and precursors to coating failures including peeling, delamination, blistering, cracking, flaking, chipping, rusting, and mechanical damage. When acceptance criteria are not met, physical testing will be performed where physically possible (i.e., sufficient room to conduct testing) in conjunction with repair or replacement of the coating/lining. Inspection results that do not satisfy established acceptance criteria will be entered into the corrective action program.

The training and qualification of individuals involved in coating/lining inspections of non-cementitious coatings/linings will be conducted in accordance with ASTM International Standards endorsed in RG 1.54 including guidance from the staff associated with a particular standard. For cementitious coatings, training and qualifications will be based on an appropriate combination of education and experience related to inspecting concrete surfaces. The maximum interval of subsequent coating inspections will be consistent with Table 4a of GALL Report AMP XI.M42 in LR-ISG-2013-01, Aging Management of Loss of Coating or Lining Integrity for Internal Coatings/Linings on In-Scope Piping, Piping Components, Heat Exchangers, and Tanks.

The program will be implemented no later than six months prior to the period of extended operation.

Baseline coating/lining inspections are being performed in the 10-year period prior to the period of extended operation and begin no later than the six months prior to the period of extended operation. New implementing documents have been developed to support these activities.

NUREG-1801 Consistency The Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks Program is a new program for PNPP that will be consistent with the 10 elements of an effective aging management program as described in NUREG-1801,Section XI.M42, Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks as revised by LR-ISG-2013-01 with exceptions.

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 2 L-24-208 Attachment 4 Page 4 of 5 Exceptions to NUREG-1801

1. The program requires Baseline coating/lining inspections occur in the 10-year period prior to the period of extended operation. This criterion requires baseline inspections be performed after 2016. The HPCS Division 3 Fuel Oil Day Tank (PY-1R45A0005) inspection was performed in September 2010 about 6 years before the earliest date. The HPCS day tank is encased in a pyrocrete fire barrier and the internal surfaces are considered inaccessible. Program Element Affected: Detection of Aging Effects (Element 4)

Justification for exception Coating conditions in the HPCS Division 3 fuel oil storage tank is considered a leading indicator for the conditions condition of the HPCS fuel oil day tank. The HPCS fuel oil storage tank was last inspected in May 2022. All acceptance criteria were met, and no repairs were recommended or required. No conditions adverse to quality were identified.

In 2010 the HPCS day tank coating was found satisfactory. Since the storage tank is considered as leading indicator, it is reasonable to conclude that coating conditions in the HPCS Division 3 Fuel Oil Day Tank are at least as good as in the storage tank and therefore acceptable. The HPCS diesel engine fuel oil suction strainers were cleaned in 2016 and 2020 with no issues. Prior to the PEO the strainers will be cleaned and inspected for coating debris. Adverse results will inform the scope and schedule for day tank inspections.

2. The program requires periodic coating/lining inspections and not to exceed those in Table 4a, Inspection Intervals for Internal Coatings/Linings for Tanks, Piping, Piping Components, and Heat Exchangers of GALL Report AMP XI.M42 in LR-ISG-2013-01. Periodic inspections for the HPCS Division 3 Fuel Oil Day Tank will not be performed due to the inaccessibility / difficulty in performing the inspection inside this tank unless coating conditions are suspected to be degraded based on leading indicators. in the other EDG Day Tanks or the HPCS Division 3 Fuel Oil Storage Tank. Leading indicators include the HPCS Division 3 Fuel Oil Storage Tank coating condition and coating debris found in HPCS Diesel Generator engine fuel oil pump suction strainers. Program Element Affected:

Monitoring and Trending (Element 5)

Justification for exception Coating conditions in the HPCS Division 3 Fuel Oil Storage Tank is considered a leading indicator for the conditions in the HPCS day tank. The Division 1 and 2 EDG fuel oil day tank inspections also provide additional data regarding coating conditions in the HPCS Division 3 Fuel Oil Day Tank. Additionally, debris found is found in HPCS fuel oil pump suction strainers will also provide evidence if coatings are degrading. Findings in the other tanks will be used to inform the need for inspections and the frequency. Program documentation will include provisions for inspections when cleaning HPCS fuel oil pump suction strainers to inspect the debris for evidence of coatings degradation.

Findings in the Division 3 Storage Tank and coating debris (e.g. Rustoleum) found in strainers will be evaluated to determine the scope and frequency of the Division 3, fuel oil day tank inspections. Strainer inspections will be performed whenever the strainers are cleaned for any reason and no less than every 6 years (three cycles).

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 2 L-24-208 Attachment 4 Page 5 of 5 HPCS Fuel Oil Maintenance procedure(s) will be revised to inspect for coating debris in the two suction strainers upstream of the HPCS fuel oil engine driven and electric pumps and two strainers in the HPCS day tank fuel oil supply from the HPCS storage tank whenever strainer cleaning takes place and no less frequent than every 6 years(three cycles).

Enhancements None Operating Experience The following operating experience examples provide objective evidence that the Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks Program will be effective in ensuring that component intended functions are maintained consistent with the current licensing basis during the period of extended operation.

A review was performed of PNPP operating experience related to Service Level III coatings.

In November 2010, the Division 2 Fuel Oil Tank internal surface area was inspected for defects, blistering, missing coating, and loss of material. Several areas of missing or blistering coating material were identified. The areas were reworked to restore the coating.

The elements that comprise the Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks Program inspections will be consistent with industry practice. Industry and plant specific operating experience will be considered in the implementation of this program. As additional operating experience is obtained, lessons learned will be incorporated, as appropriate.

Conclusion The Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks Program will monitor the condition of coatings and linings within mechanical components to ensure degraded coatings do not lead to flow blockage or unanticipated or accelerated corrosion that would result in a loss of component intended function during the period of extended operation. Implementation of the Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks Program will provide reasonable assurance that the effects of aging will be managed such that the coatings will be maintained consistent with the current licensing basis for the period of extended operation. New implementing documents have been developed to support these activities.

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 2 L-24-208 Attachment 5 Page 1 of 5 Attachment No. 5 LRA Section: A.1.13 LRA Page Number(s): A-17 and A-18

References:

NVIP RAI-10231-R1 Description of Change: The change is made to clarify that the PNPP BWR Vessel ID Attachment Welds Program will credit staff-approved guidance in addition to the ASME Code requirements, or that staff approval for an alternative to the approved guidance will be sought prior to the start of subsequent 10-year ISI intervals.

PNPP LRA Table A.1.13, Pages A-17 and A-18, is revised as follows:

A.1.13 BWR VESSEL ID ATTACHMENT WELDS PROGRAM The BWR Vessel ID Attachment Welds aging management program is an existing condition monitoring program that includes the inspection and evaluation of the reactor vessel internal attachment welds that follows the requirements of the ASME Code Section XI, Subsection IWB, Examination Category B-N-2 enhanced consistent with the inspection and evaluation guidelines of an NRC approved BWRVIP-48, BWR Vessel and Internals Project Vessel ID Attachment Weld Inspection and Flaw Evaluation Guidelines or a

staff approved alternative to the approved guidance recommendations within BWRVIP-48 and the requirements of ASME Code,Section XI, Subsection IWB. The program is implemented through station procedures that provide for mitigation of cracking of reactor vessel internal components through management of reactor water chemistry and monitoring for and evaluation of cracking through in-vessel examinations of the reactor vessel internal attachment welds.

At least 6 months prior to entering the period of extended operation the following enhancement will be completed:

1. The inservice inspections procedures will be revised to incorporate BWRVIP-14-A, BWRVIP-59-A, and BWRVIP-60-A as guidelines for evaluation of crack growth in stainless steels, nickel alloys, and low-alloy steels, respectively.

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 2 L-24-208 Attachment 5 Page 2 of 5 LRA Section: B.2.13 LRA Page Number(s): Pages B-45 through B-47

References:

NVIP RAI-10231-R1 Description of Change: The change is made to clarify that the PNPP BWR Vessel ID Attachment Welds Program will credit staff-approved guidance in addition to the ASME Code requirements, or that staff approval for an alternative to the approved guidance will be sought prior to the start of subsequent 10-year ISI intervals.

PNPP LRA B.2.13 (as revised by L-24-020), Pages B B-47, is revised as follows:

B.2.13 BWR VESSEL ID ATTACHMENT WELDS PROGRAM Program Description The BWR Vessel ID Attachment Welds Program is an existing condition monitoring program that manages cracking in structural welds for BWR reactor vessel internal integral attachments using inspection and flaw evaluation. The program is implemented through station procedures that provide for condition monitoring through in-vessel examinations of the reactor vessel internal attachment welds in accordance with the requirements of the ASME Code Section XI, Subsection IWB, Examination Category B-N-2 enhanced consistent with the inspection and evaluation guidelines of an NRC approved BWRVIP-48, BWR Vessel and Internals Project Vessel ID Attachment Weld Inspection and Flaw Evaluation Guidelines or a staff approved alternative to the approved guidance.

The scope of the program includes the steam dryer support and hold down bracket attachment welds, guide rod bracket attachment welds, feedwater sparger bracket attachment welds, jet pump riser brace leaf/arm attachment welds, core spray piping bracket attachment welds, and sample holder welded attachment.

Indications are evaluated consistent with ASME Code,Section XI, Subsections IWB-3500 and IWB-3600 and the additional guidance provided in BWRVIP-48. If flaws are found, the scope of the inspection is expanded in accordance with the guidance provided in BWRVIP-48. Repair and replacement procedures comply with the requirements of ASME Code,Section XI.

NUREG-1801 Consistency The BWR Vessel ID Attachment Welds Program is an existing PNPP program that will be consistent, with enhancement, with the 10 elements of an effective aging management program as described in NUREG-1801,Section XI.M4, BWR Vessel ID Attachment Welds, with the following exception.

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 2 L-24-208 Attachment 5 Page 3 of 5 Exceptions to NUREG-1801:

The BWR Vessel ID Attachment Welds Program is based on the requirements of BWRVIP-48,R1 in lieu of BWRVIP-48-A. Since BWRVIP-48, R1 is not staff approved this is an exception to the NUREG-1801 AMP. Program Elements affected: Detection of Aging Effects (Element 4), and Monitoring And Trending (Element 5).

Justification for Exception:

By letter date January 6, 2020, PNPP submitted 10 CFR 50.55a Request IR-056, Rev.

3. This request proposed to apply specific BWRVIP guidelines to affected ASME Code components in lieu of the requirements of ASME Code,Section XI, Paragraph IWB-2500(a) and Table IWB-2500-1, including the examination method, examination volume, frequency, training, successive and additional examinations, flaw evaluations, and reporting. One of the specific BWRVIP guidelines included in IR56 was BWVIP-48, R1. The NRC responded by letter dated January 29, 2021, and accepted the use of the identified BWRVIP guidelines, including BWRVIP-48, R1, in lieu of the ASME Code requirements. The NRC letter, which accepted IR-56, explicitly authorized the use of the proposed alternative the relief request for fourth 10-year ISI interval, which began on May 18, 2019, and is scheduled to expire on May 17, 2029. It is understood that prior to entering the for subsequent 10-year ISI intervals, PNPP would have to either comply with the ASME Code requirements and NRC approved BWRVIP-48 guidance, or request staff approval for an alternative to the approved guidance prior to the start of the subsequent 10-year ISI intervals relief from the requirements consistent with what PNPP has done during the initial operating period.

It is recognized that BWRVIP-48, R1 has not been generically approved by the NRC staff.

However, the use of this revision has been approved for use by PNPP, in accordance the NRC approval of IR-56.

Enhancements No later than 6 months prior to entering the period of extended operation the following enhancement will be completed:

The inservice inspections procedures will be revised to incorporate BWRVIP-14-A, BWRVIP-59-A, and BWRVIP-60-A as guidelines for evaluation of crack growth in stainless steels, nickel alloys, and low-alloy steels, respectively. Program Elements Effected:

Monitoring and Trending (Element 5).

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 2 L-24-208 Attachment 5 Page 4 of 5 LRA Section: C-1 LRA Page Number(s): Page C.1

References:

NVIP RAI-10231-R1 Description of Change: PNPP LRA Appendix C is being revised to delete BWRVIP-48 from the list of credited BWRVIP documents with NRC SERs that have applicant action items. PNPP has staff approval to use the inspection and evaluation guidelines in BWVIP-48, R1. This revision of the BWRVIP does not have an NRC SER so including the BWRVIP on the list was inappropriate.

PNPP LRA Section C.1, Page C-1, is revised as follows:

C.1 RESPONSE TO BWRVIP APPLICANT ACTION ITEMS Of the BWRVIP documents credited for PNPP license renewal, the following have NRC safety evaluation reports for license renewal.

BWRVIP-18 BWR Core Spray Internals Inspection and Flaw Evaluation Guidelines, Revision 2 BWRVIP-25 BWR Core Plate Inspection and Flaw Evaluation Guidelines, Revision 1 BWRVIP-26-A BWR Top Guide Inspection and Flaw Evaluation Guidelines BWRVIP-27-A BWR Standby Liquid Control System / Core Plate P Inspection and Flaw Evaluation Guidelines BWRVIP-38 BWR Shroud Support Inspection and Flaw Evaluation Guidelines BWRVIP-41 BWR Jet Pump Assembly Inspection and Flaw Evaluation Guidelines, Revision 4 BWRVIP-42 LPCI Coupling Inspection and Flaw Evaluation Guidelines, Revision 1 BWRVIP-47-A BWR Lower Plenum Inspection and Flaw Evaluation Guidelines BWRVIP-48 Vessel ID Attachment Weld Inspection and Flaw Evaluation Guidelines, Revision 1 BWRVIP-49-A Instrument Penetration Inspection and Flaw Evaluation Guidelines

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 2 L-24-208 Attachment 5 Page 5 of 5 BWRVIP-74-A BWR Vessel and Internals Project BWR Reactor Pressure Vessel Inspection and Flaw Evaluation Guidelines for License Renewal BWRVIP-76 BWR Core Shroud Inspection and Flaw Evaluation Guidelines Core Shroud Basis, Revision 1 BWRVIP-138 R-1A Updated Jet Pump Beam Inspection and Flaw Evaluation BWRVIP-139 R1-A BWR Vessel and Internals Project Steam Dryer Inspection and Flaw Evaluation Guidelines

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 2 L-24-208 Attachment 6 Page 1 of 2 Attachment No. 6 LRA Section: Appendix B, Section B.2.34

Reference:

The LRA change is applicant initiated Description of Change: LRA Section B.2.34 of Appendix B, Non-EQ Insulated Cables and Connections Program is revised to incorporate the associated program element.

PNPP Section B.2.34, Page B-97 to B-99, is revised as follows:

B.2.34 NON-EQ INSULATED CABLES AND CONNECTIONS PROGRAM Program Description The Non-EQ Insulated Cables and Connections Program is an existing Cable Aging Management program which includes the Cable Monitoring program that provides reasonable assurance that the intended functions of insulated cables and connections exposed to adverse localized environments caused by temperature, radiation, or moisture can be maintained consistent with the current licensing basis through the period of extended operation. The program provides for the periodic visual inspection of accessible, non-environmentally qualified electrical cables and connections, in order to determine if age-related degradation is occurring. Accessible electrical cables and connections installed in adverse localized environments are visually inspected for signs of age-related degradation such as embrittlement, discoloration, cracking, melting, swelling, or surface contamination.

The program is existing. The visual inspections will be performed on a 10-year interval, with the first inspection completed no later than six months prior to the period of extended operation.

NUREG-1801 Consistency The Non-EQ Insulated Cables and Connections Program is an existing PNPP program that, after enhancement, will be consistent with the 10 elements of an effective aging management program as described in NUREG-1801,Section XI.E1, Insulation Material for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements.

Exceptions to NUREG-1801 None Enhancements The following enhancement will be implemented no later than six months prior to the period of extended operation:

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 2 L-24-208 Attachment 6 Page 2 of 2 The program will be enhanced to include a plant-specific procedure for plant walkdowns of adverse localized environments. Program Element Afffected: Parameters Monitored/Inspected (Element 3)

Operating Experience The following operating experience examples provide objective evidence that the Non-EQ Insulated Cables and Connections Program will be effective in ensuring that component intended functions are maintained consistent with the current licensing basis during the period of extended operation.

The Non-EQ Insulated Cables and Connections Program is an existing Condition Monitoring program. Industry operating experience has been considered in the implementation of this program. Plant operating experience has been reviewed and additional OE occurring during the period of extended operation will be factored into the program via the confirmation and corrective action elements of the PNPP 10 CFR 50 Appendix B quality assurance program.

As stated in NUREG-1801, XI.E1, industry operating experience has shown that adverse localized environments caused by heat, radiation, or moisture for electrical cables and connections may exist near steam generators, pressurizers, or hot process pipes, such as feedwater lines. In this industry experience, such adverse localized environments have caused degradation of insulating materials on electrical cables and connections that is visually observable, such as color changes or surface cracking. These visual indications can indicate cable degradation. The examination techniques used in this program to detect aging effects are proven industry techniques that have been effectively used at PNPP in other programs.

Accordingly, there is reasonable assurance that this aging management program will be effective during the period of extended operation.

Conclusion The Non-EQ Insulated Cables and Connections Program will be capable of managing aging effects due to heat, moisture, and radiation in the presence of oxygen, for nonenvironmentally qualified cables and connections. The program, after enhancement, will provide reasonable assurance that aging effects will be managed such that the applicable components continue to perform their intended functions consistent with the current licensing basis for the period of extended operation.