L-24-207, License Renewal Application for the Perry Nuclear Power Plant-Response to Request for Additional Information - Set 1

License Renewal Application for the Perry Nuclear Power Plant-Response to Request for Additional Information - Set 1

ML24260A266
Person / Time
Site:	Perry
Issue date:	09/16/2024
From:	Penfield R Vistra Operations Company
To:	Office of Nuclear Reactor Regulation, Document Control Desk
References
L-24-207
Download: ML24260A266 (1)

Text

L-24-207 September 16, 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-Response to Request for Additional Information - Set 1

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. ML232618019) 6555 SIERRA DRIVE IRVING, TEXAS 75039 o 214-812-4600 VISTRACORP,COM

Perry Nuclear Power Plant L-24-207 Page 2 of 3

5. Letter L-24-109, from Rod L. Penfield to the Nuclear Regulatory Commission, dated May 30, 2024, submitting the Perry Nuclear Power Plant License Renewal.Application Revision 0, Supplement 1 (ADAMS Accession No. ML24151A637)

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-24-178, from Rod L. Penfield to the Nuclear Regulatory Commission, dated August 8, 2024, submitting the Perry Nuclear Power Plant License Renewal Application Revision 0, Supplement 4 (ADAMS Accession No. ML24221A093)

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

10. 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)

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 (EPID L-2024-LLM-0000) (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 9). In addition, as a result of the NRC's review of the PNPP LRA, on August 14, 2024, the NRC Staff has identified several requests for additional information (RAls), which were Set 1 of several expected RAls (Reference 10). The attachments to this letter provide the responses to the RAls - Set 1.

The commitments provided in the PNPP LRA Appendix A (Table A.3) that are updated are indicated in the attachments.

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.

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

Perry Nuclear Power Plant L-24-207 Page 3 of 3 I declare under penalty of perjury that the foregoing is true and correct. Executed on September 16, 2024.

Rod L. Penfield Attachments:

PNPP LRA - Response to RAI Set 1 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 LRA Set 1 RAI Responses L-24-207 Attachments Index Page 1 of 2 PNPP LRA Set 1 RAI Responses Attachments Index Attachment No.

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

RAI SNSB-RAI-10201-R1 Question 1 & 2 2

RAI NCSG-RAI-10233-R1 RAI B.2.8-1 & RAI B.2.8-2 3

RAI NCSG-RAI-10255-R1 Requests 1, 2 & 3 4

RAI NPHP-RAI-10137-R1 RAI 4.3.3-1 and RAI 4.3.3-2 5

RAI NCSG-RAI-10183-R1 Requests 1, 2 & 3 6

RAI SCPB-RAI-10192-R1 Requests 1, 2 & 3 7

LRA Update NCSG-RAI-10233-R1 Section A.1.8 Table A.3 Section B.2.8 8

LRA Update NCSG-RAI-10255-R1 Table 3.3.2-44 Note for Table 3.3.2-1 through Table 3.3.2-63 9

LRA Update SNSB-RAI-10201-R1 Section 4.2.1

Perry Nuclear Power Plant LRA Set 1 RAI Responses L-24-207 Attachments Index Page 2 of 2 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 7, 8 and 9 provide LRA page updates as a result of the RAI responses.

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-24-109)

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)

Therefore, the LRA changes made as a result of Attachments 7, 8 and 9 build on, and are made on clean LRA pages that reflect the LRA updates from the previously docketed Vistra correspondence listed above.

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 7. 8 and 9 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 Response to LRA NRC RAIs Set 1 L-24-207 Attachment 1 Page 1 of 5 SNSB RAI-10201-R1

Background

By letter dated July 3, 2023, (Agency-wide Documents Access and Management System (ADAMS) Accession No. ML23184A081), Energy Harbor Nuclear Corp. submitted an operating license renewal application (LRA) for the for the Perry Nuclear Power Plant (PNPP), Unit 1 to extend the current operating licenses an additional 20 years beyond the current expiration date from midnight, November 7, 2026, to midnight, November 7,2046.

Within the scope of the Nuclear Systems Performance Branch (SNSB) review, the staff evaluated the licensees application and has determined that additional information is needed for TLAA Section 4.2.1, Neutron Fluence to make a safety finding.

Regulatory Basis The NRC staff used Regulatory Guide (RG) 1.190, 'Radiation Embrittlement of Reactor Vessel Materials as basis for review of Section 4.2.1 of LRA. RG 1.190 is based on General Design Criterion (GDC) 14, 30 and 31 provided in Appendix A to 10 CFR Part 50.

There is no specific guidance in the regulations governing the radiation exposure of the reactor vessel internal components. However, GDC 1, Quality Standards and Records requires that structures, systems and components important to safety shall be designed, fabricated, erected and tested to quality standards commensurate with the importance to the safety functions to be performed. Further reactor vessel internal components may be required to meet the provisions of 10 CFR 50.46 (b)(5) for maintaining a core geometry [that] shall be such that the core remains amenable to cooling. Sufficiently accurate fluence calculations may be required to ensure that in-service degradation does not impair the ability of the unit to meet the requirements of 10 CFR 50.46 (b)(5).

Question 1 In section 4.2.1, Neutron Fluence, of the license renewal application (LRA), the licensee states that:

The fluence values provided in this section were calculated using the Radiation Analysis Modeling Application (RAMA) Fluence Methodology. RAMA was developed for the Electric Power Research Institute and the Boiling Water Reactor [BWR] Vessel and Internals Project

[BWRVIP]. The NRC has reviewed and approved RAMA for BWR reactor pressure vessel (RPV) fluence predictions by letter dated February 7, 2008 [Reference 4.7-4].

The NRC staff notes that Reference 4.7-4 of the LRA points to the safety evaluation (SE) for BWRVIP-145, BWR Vessel and Internals Project, Evaluation of Susquehanna Unit 2 Top Guide and Core Shroud Material Samples Using RAMA Fluence Methodology (ADAMS Accession No. ML080390160), which evaluates Susquehanna Steam Electric Station (Susquehanna), Unit 2 Top Guide and Core Shroud fluence using the RAMA methodology rather than an overall RAMA fluence methodology for a BWR RPV.

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 1 Page 2 of 5 Provide the appropriate methods used to perform the transport calculations required to estimate the fluence for the RPV for Perry Nuclear Power Plant (PNPP).

Question 2 Reference 4.7-4 of the LRA is the SE for BWRVIP-145, which is used for calculation of neutron fluence for the vessel internals. The SE for the BWRVIP-145 states that the RAMA methodology can be used in determining fast neutron fluence values in the core shroud and top guide for applications such as irradiation-assisted stress corrosion cracking, crack propagation rates and weldability determinations. However, the BWRVIP-145-A SE specifically noted in a limitation that in order to use the methodology in a licensing action, sufficient justification must be provided that the computed fluence for the core shroud and top guide internal components are conservative.

Provide justification for use of BWRVIP-145 to calculate neutron fluence values for PNPP vessel internals to show that the proposed values are conservative for the intended application.

PNPP Response Question 1 Provide the appropriate methods used to perform the transport calculations required to estimate the fluence for the RPV for Perry Nuclear Power Plant (PNPP).

The NRC has reviewed the use of RAMA fluence methodology for BWR reactor pressure vessel (RPV) internal components and written the following two Safety Evaluations for the Proprietary EPRI BWRVIP Reports that support use of the RAMA fluence methodology.

NRC SER for "BWRVIP RAMA Fluence Methodology Manual (BWRVIP-114)," "RAMA Fluence Methodology Benchmark Manual (BWRVIP-115)," "RAMA Fluence Methodology - Susquehanna Unit 2 Surveillance Capsule Fluence Evaluation for Cycles 1-5 (BWRVIP-117)," and "RAMA Fluence Methodology Procedures Manual (BWRVIP-121)" and "Hope Creek Flux Wire Dosimeter Activation Evaluation for Cycle 1 (TWE-PSE-001-R-001)" (TAC No. MB9765), is dated May 13, 2005.

NRC SER for BWRVIP-145, BWR Vessel and Internals Project, Evaluation of Susquehanna, Unit 2 Top Guide and Core Shroud Material Samples Using RAMA Fluence Methodology (ML080390160) is dated February 7, 2008.

To clarify the NRC review and approval of the RAMA fluence methodology, PNPP LRA Section 4.2.1, Neutron Fluence, as revised by letter L-24-109, will be revised to read:

The fluence values provided in this section were calculated using the Radiation Analysis Modeling Application (RAMA) Fluence Methodology. RAMA was developed for the Electric Power Research Institute and the Boiling Water Reactor Vessel and Internals Project. The NRC has reviewed and approved RAMA for BWR reactor pressure vessel (RPV) fluence predictions by letters dated May 13, 2005 and February 7, 2008 [References 4.7-13 and 4.7-4].

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 1 Page 3 of 5 This LRA changes associated with SNSB RAI-10201-R1, Question 1, are provided in to this letter.

Question 2 Provide justification for use of BWRVIP-145 to calculate neutron fluence values for PNPP vessel internals to show that the proposed values are conservative for the intended application.

As discussed in the response to Question 1, the NRC has reviewed the use of RAMA fluence methodology for BWR reactor pressure vessel (RPV) internal components and written the following two Safety Evaluations for the Proprietary EPRI BWRVIP Reports that support use of the RAMA fluence methodology.

Section 4.2 of the NRC SER for BWRVIP-114, 115, 117, and 121 states that:

"the submittal does not include any benchmarking for reactor internals' neutron fluence calculations. Therefore, the staff will review qualification of RAMA for reactor internals applications on a case-by-case basis, based on consideration of C/M values and the associated accuracy requirements."

It further states that:

"Licensees who wish to use the RAMA methodology for the calculation of neutron fluence at reactor internals locations must reference, or provide, an analysis which adequately benchmarks the use of the RAMA methodology for uncertainty and calculational bias based on the consideration of: (1) the location at which the neutron fluence is being calculated, (2) the geometry of the reactor, and (3) the accuracy required for the evaluation. In addition, if a licensee qualifies RAMA for calculating, for example, helium generation at one location (e.g., the core shroud), this qualifies RAMA for the same reactor and purpose at other reactor internals locations (e.g., at the location of the jet pumps)."

BWRVIP-145 was submitted to the NRC for the purpose of supporting generic regulatory improvements to enable the evaluation of reactor internal component degradation by providing a methodology to determine fast neutron fluence values for BWR internal components. The BWRVIP-145 report was based upon using RAMA fluence methodology to calculate reactor internals fluence values. The methodology was applied to core shroud and top guide samples removed from Susquehanna Unit 2 after 11 cycles of irradiation. The report compares the actual dosimetry results from the Susquehanna samples with the corresponding RAMA fluence values.

The staff reviewed the BWRVIP-145 report for its suitability in applying the RAMA fluence methodology to calculation of fast neutron fluence values for BWR reactor vessel internals, specifically for the core shroud and top guide. The staff concluded for the core shroud and top guide comparison that:

"the calculated values are in excellent agreement with the measured values, thus, the RAMA fluence methodology in this particular case performs very well."

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 1 Page 4 of 5 "the calculated values for the top guide dosimetry are in reasonable agreement with the measured values and that the results are acceptable for determining fast neutron fluence values in the core shroud and top guide."

The staff further concluded that although the benchmarking guidance in RG 1.190 was not achieved, there is reasonable agreement between the calculated and measured dosimetry values of the limited data provided. Therefore, the staff found that for applications related to IASCC, crack propagation rates, and weldability determinations, the existing data provides adequate justification for applying the RAMA methodology to determine the fast neutron fluence values in the core shroud and top guide.

To reference BWRVIP-145 for satisfying the requirements specified in the NRC SER for BWRVIP-114, -115, -117, and -121 with respect to using the RAMA fluence methodology, the following limitation in Section 5.0 of the NRC SER for BWRVIP-145 must be met:

The staff will accept RAMA calculated fluence values for BWR core shrouds and top guides for licensing actions provided that the calculational results are supported by sufficient justification that the proposed values are conservative for the intended application.

PNPP has performed a site specific evaluation of the applicability of the RAMA methodology.

This evaluation included:

RV internals geometry modeling,

Comparisons were made between the calculated and measured specific activities for three sets of surveillance capsule dosimetry specimens removed from Perry, and

A determination that the fast neutron fluence uncertainty is within the expected uncertainty with no bias correction to the fluence. This demonstrates that the PNPP RAMA fluence evaluations produced results that meet the requirements of U. S.

NRC Regulatory Guide 1.190.

The calculation provides the benchmarking needed for the application of the RAMA fluence methodology for the RPV. The PNPP benchmarking was also documented in the submittal of BWRVIP-281NP, Revision 1: BWR Vessel and Internals Project, Testing and Evaluation of the Perry 177° Capsule, by letter from Andrew McGehee to Joseph Holonich, dated January 3, 2017 (ML17012A341).

Additionally, BWRVIP-189 BWRVIP Evaluation of RAMA Fluence Methodology Calculational Uncertainty, July 2008, includes an evaluation of Clinton Power Station, which is a BWR/6 of similar design to PNPP.

Based on this information, the RAMA fluence methodology is applicable to PNPP for the evaluation of the RPV internals fluence.

As discussed above, the site specific evaluation of the applicability of the RAMA methodology provides the benchmarking information to demonstrate the application of the RAMA methodology for PNPP meets the limitation in the NRC SER for BWRVIP-145, may be used at PNPP for core shroud and top guide applications, and, therefore, may also be used at PNPP for

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 1 Page 5 of 5 other reactor internal locations as provided in the NRC SER for BWRVIP-114, -115, -117, and -

121.

To clarify the use of the RAMA fluence methodology, Supplement 1 to the PNPP LRA was submitted (Reference Vistra Letter L-24-109, Attachment 6), which added the following supplemental information to PNPP LRA Section 4.2.1, TLAA Evaluation:

Therefore, PNPP has satisfied the benchmarking guidance in the NRC SERS for the BWRVIP-114, -115, -117, and -121. (Reference 4.7-13) and for BWRVIP-145 to demonstrate the applicability of the RAMA fluence methodology to the PNPP reactor vessel and internals.

Letter L-24-109, Attachment 6, also added Reference 4.7-13:

4.7-13 William H Bateman to Bill Eaton, Safety Evaluation of Proprietary EPRI Reports BWRVIP RAMA Fluence Methodology Manual (BWRVIP-114)," "RAMA Fluence Methodology Benchmark Manual (BWRVIP-115)," "RAMA Fluence Methodology -

Susquehanna Unit 2 Surveillance Capsule Fluence Evaluation for Cycles 1-5 (BWRVIP-117)," and "RAMA Fluence Methodology Procedures Manual (BWRVIP-121)" and "Hope Creek Flux Wire Dosimeter Activation Evaluation for Cycle 1 (TWE-PSE-001-R-001)" (TAC No. MB9765), May 13, 2005.

There are no LRA changes associated with the response to SNSB RAI-10201-R1, Question 2.

References BWRVIP-145 Report, BWRVIP, Evaluation of Susquehanna Unit 2 Top Guide And Core Shroud Material samples Using RAMA Fluence Methodology (ML072850122)

BWRVIP-189 BWRVIP, Evaluation of RAMA Fluence Methodology Calculational Uncertainty (ML082480313)

Vistra Letter L-24-109, Supplement 1 to the PNPP LRA (ML24151A637)

Attachments (Question 1 response)

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 2 Page 1 of 7 NCSG RAI-10233-R1 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. 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 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.

RAI B.2.8-1

Background:

LRA Section B.2.8, Buried and Underground Piping and Tanks Program, states [d]irected inspections of buried and underground piping are consistent with LR-ISG-2015-01 Table XI.M41-1 and its accompanying footnotes.

As amended by letter dated June 27, 2024 (ML24180A010), Exception No. 1 to LRA Section B.2.8 states the following:

[t]he condensate transfer and storage system stainless steel buried piping was installed during the initial construction of PNPP. At that time, coating of buried stainless steel piping was not considered to be required. The buried condensate transfer and storage system stainless steel piping is installed at an elevation well above the normal site groundwater elevation. EPRIs mechanical tools indicates that SCC of stainless steels exposed to atmospheric conditions and contaminants is considered plausible only if the material temperature is above 140°F. In general, SCC very rarely occurs in austenitic stainless steels below 140°F. Since the condensate transfer and storage system operating temperatures are below 140F, the likelihood of SCC occurring in this buried stainless steel piping is very low. Recent operating experience indicates that cracking can occur in uncoated buried stainless steel piping. As discussed in the program enhancements the buried stainless steel piping will be visually inspected for cracking.

GALL-LR Report AMP XI.M41, Buried and Underground Piping and Tanks, as revised by LR-ISG-2015-01, Changes to Buried and Underground Piping and Tank Recommendations, recommends the following:

External coatings for buried stainless steel piping in chloride containing environments.

One inspection for buried stainless steel piping in each 10-year inspection interval.

The GALL-SLR Report notes that in environments where the chemistry is not controlled (e.g.,

air-outdoor and soil), stress corrosion cracking of stainless steel can occur at ambient temperatures.

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 2 Page 2 of 7 Issue:

The inspection quantities recommended in the GALL-LR Report for buried stainless steel piping are based on either external coatings being provided or the soil environment containing trace amounts of chlorides. The new exception did not provide results from soil corrosivity sampling; therefore, it is unclear to the staff if one inspection of buried stainless steel piping is appropriate in each 10-year inspection interval. The staff also notes that the 140°F limit for stress corrosion cracking is for environments where chemistry is controlled. Stress corrosion cracking can occur at lower temperatures when chemistry is not controlled (e.g., a soil environment).

Request:

Provide results from soil corrosivity sampling to demonstrate that buried stainless steel piping is not exposed to an environment containing more than trace amounts of chlorides. If soil corrosivity sampling results are not available, provide an alternative basis for why one inspection of buried stainless steel piping is appropriate in each 10-year inspection interval (e.g.,

results of previous inspections of uncoated buried stainless steel piping, more details on the amount of in-scope uncoated buried stainless steel piping in linear feet, discussion on alternative preventive actions applicable to this piping such as cathodic protection, etc.).

PNPP Response Provide results from soil corrosivity sampling to demonstrate that buried stainless steel piping is not exposed to an environment containing more than trace amounts of chlorides. If soil corrosivity sampling results are not available, provide an alternative basis for why one inspection of buried stainless steel piping is appropriate in each 10-year inspection interval (e.g., results of previous inspections of uncoated buried stainless steel piping, more details on the amount of in-scope uncoated buried stainless steel piping in linear feet, discussion on alternative preventive actions applicable to this piping such as cathodic protection, etc.).

This issue is limited to piping in the Condensate Storage and Transfer System, connecting the condensate storage tank to the Auxiliary building. The uncoated, buried, stainless steel piping includes two separate lines, each approximately 200' long. One is a safety-related line that is 18" NPS, the second is a nonsafety-related line that is 10" NPS. The grade elevation for Perry is approximately 620 feet elevation. Normally, site groundwater elevation is maintained near the 574 feet elevation. Both of these lines are installed in Class A fill at an elevation of about 615 feet, well above the normal groundwater elevation. Both of the subject condensate storage and transfer stainless steel lines are cathodically protected.

Since the initial installation both of these lines have been backfilled in Class A fill as required by construction and installation specifications. The Class A fill is installed around the pipe in horizontal lifts not exceeding 6, and the fill is compacted with each lift. The Class A fill consist of crushed stone or sand and gravel that is tested to meet properties for:

Particle-size gradation and uniformity Specific Gravity Particle soundness/abrasion loss

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 2 Page 3 of 7 Permeability coefficient Effective friction angle Recently, the installation specifications for backfill allow for the use of controlled low strength material (CLSM) as a pipe bedding material and to replace Class A fill where the Class A fill was used as a pipe bedding material. CLSM is to be manufactured using the guidelines as given in the ACI committee 229R-94 report. CLSM is comprised of sand, fly ash, water, and Portland cement. Based on its nature, CLSM is not compacted when installed.

Thus, the Class A fill or CLSM that is surrounding these lines is not expected to exhibit the same physical parameters as the remainder of the soil at the site.

Both of these lines were last inspected in 2013 as part of the buried and underground piping and tanks program. At the time of those inspections both lines had been buried for more than 30 years.

The 10 NPS line was inspected at 2 separate excavations, with approximately 5 lineal feet of piping at each location subject to ultrasonic thickness measurements over a 2" nominal grid pattern. The UT measurements required the pipe surface to cleaned to a smooth bright finish. The two inspections found no unacceptable areas of wall thinning or other defects.

The 18" line was inspected at one location over an approximate 6 feet length of piping.

Because of the proximity of the pipe to the excavation wall, the pipe was subject to ultrasonic thickness measurements over a 2" nominal grid pattern from the 10 o'clock to the 6 o'clock position. The UT measurements required the pipe surface to be cleaned to a smooth bright finish. The inspection found no unacceptable areas of wall thinning or other defects.

Perry's Underground Piping and Tanks Integrity Asset Management Plan includes an inspection of one of these lines prior to entry into the period of extended operation. Consistent with the Buried and Underground Piping and Tanks Program, as modified by LRA Supplement 2 (L 020), visual inspections of stainless steel piping for cracking will be performed.

NRC Regulatory Guide 1.147 Rev 21, titled Inservice Inspection Code Case Acceptability, ASME Section XI, Division 1, has categorized the ASME Code Section XI, Division 1, Code Case N-663-1, titled Alternative Requirements for Classes 1 and 2 Surface Examinations as acceptable to the NRC for implementation. Code Case N-663-1 identifies that surface examinations may be limited to areas identified by the Owner as susceptible to outside surface attack.

According to the Code Case, susceptibility criteria to outside surface attack include the following:

Mechanism External chloride stress corrosion cracking Criteria austenitic stainless steel base metal, welds, or heat affected zone (HAZ), and

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 2 Page 4 of 7 operating temperature >150°F, and a piping outside surface is within five pipe diameters of a probable leak path (e.g., valve stem) and is covered with nonmetallic insulation that is not in compliance with U.S. NRC Regulatory Guide 1.36 (e.g., chloride content) or equivalent requirements or austenitic stainless steel base metal, welds, or HAZ, and a piping outside surface is exposed to wetting from a concentrated chloride-bearing environment (e.g., seawater, brackish water, brine)

Mechanism Other outside surface initiated mechanisms Criteria Items identified as susceptible to outside surface attack by a periodic review of plant and industry operating experience, as applicable. This review should include plant-specific processes and programs that minimize chlorides and other contaminants.

The criteria for susceptibility to outside surface attack cited in the Code Case includes a piping outside surface that is exposed to wetting from a concentrated chloride-bearing environment (e.g., seawater, brackish water, brine), or periodic review of plant and industry operating experience. As noted in LRA Section 3.6.2.2.2 PNPP is in an area with moderate rainfall and where the outdoor environment is not subject to industry air pollution or salt spray, such that buried piping is not exposed to wetting from a concentrated chloride-bearing environment.

Further, site operating experience has not identified outside surface attack of this buried stainless steel piping. Thus, susceptibility of this piping to cracking is considered to be minimal.

Based on:

the minimal evidence of occurrence of external corrosion on the buried pipe wall no identified cracking occurring over their operating history the mild environment of the buried piping significantly above normal groundwater levels, with minimal susceptibility to cracking the piping is protected by cathodic protection It is judged that the combination of above factors supported by alignment with ASME Code Case N-663-1 provides a reasonable basis for a 10-year inspection interval for these 2 buried, uncoated, stainless steel condensate storage and transfer pipe lines.

There are no LRA changes associated with this RAI (B.2.8-1) response.

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 2 Page 5 of 7 RAI B.2.8-2

Background:

As amended by letter dated June 27, 2024, Enhancement No. 1 to LRA Section B.2.8 states the following:

[w]here damage to the coating has been evaluated as significant and the damage was caused by nonconforming backfill, an extent of condition evaluation will be conducted to determine the extent of degraded backfill in the vicinity of the observed damage.

As amended by letter dated June 27, 2024, Enhancement No. 8 to LRA Section B.2.8 states the following:

[a]lternatively, for steel piping cathodic protection, the acceptable Capacitive Shift criteria will be at least 100 mV from the Corrosion Potential. If this alternative acceptance criteria is implemented, then; Additional confirmatory testing will be performed to validate acceptable external loss of material rate, and subsequently confirmed every 2 years thereafter. The impact of significant site features such as shielding due to large objects in the vicinity of the protected pipe and local soil conditions will be factored into placement of the electrical resistance corrosion rate probes and use of probe data.

GALL-LR Report AMP XI.M41, as revised by LRISG201501, includes the following recommendations:

For coated piping or tanks, there is either no evidence of coating degradation, or the type and extent of coating degradation is evaluated as insignificant by an individual: (a) possessing a NACE Coating Inspector Program Level 2 or 3 inspector qualification; (b) who has completed the Electric Power Research Institute (EPRI) Comprehensive Coatings Course and completed the EPRI Buried Pipe Condition Assessment and Repair Training Computer Based Training Course; or (c) a coatings specialist qualified in accordance with an ASTM standard endorsed in Regulatory Guide 1.54, Rev. 2, Service Level I, II, and III Protective Coatings Applied to Nuclear Power Plants.

When electrical resistance corrosion rate probes will be used, the application identifies the qualifications of the individuals that will determine the installation locations of the probes and the methods of use (e.g., NACE CP4, Cathodic Protection Specialist).

Issue:

The staff seeks clarification with respect to the qualifications of individuals that will determine (a) whether the extent of coating degradation is significant (related to Enhancement No. 1); and (b) the installation locations of electrical resistance corrosion rate probes and the methods of use (related to Enhancement No. 8).

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 2 Page 6 of 7 Request:

Provide clarification (including appropriate revisions to LRA Sections B.2.8 and A.1.8) with respect to the qualifications of individuals that will determine (a) whether the extent of coating degradation is significant; and (b) the installation locations of electrical resistance corrosion rate probes and the methods of use. If the qualifications will not be consistent with GALL-LR Report AMP XI.M41, as revised by LRISG201501, state the basis for how the alternative qualification method(s) are appropriate to use.

PNPP Response Provide clarification (including appropriate revisions to LRA Sections B.2.8 and A.1.8) with respect to the qualifications of individuals that will determine (a) whether the extent of coating degradation is significant; and (b) the installation locations of electrical resistance corrosion rate probes and the methods of use. If the qualifications will not be consistent with GALL-LR Report AMP XI.M41, as revised by LRISG201501, state the basis for how the alternative qualification method(s) are appropriate to use.

Perry agrees certification levels have not been specified. The following enhancement will be added to the LRPY-AMP-XI.M41 aging management program, Sections A.1.8 and B.2.8, and Table A.3 of the LRA:

Coating inspectors who evaluate the type and extent of coating degradation will be certified to one of the following:

1. A National Association of Corrosion Engineers (NACE) Coating Inspector Level II or III.

2. An individual who has completed both the Electric Power Research Institute (EPRI)

Comprehensive Coatings Course and the EPRI Buried Pipe Condition Assessment and Repair Computer Based Training (CBT) Course, or

3. An American Society for Testing and Materials (ASTM) coating specialist qualified through an ASTM Standard endorsed by Regulatory Guide (RG) 1.54 Rev. 2.

An existing enhancement will be modified in LRPY-AMP-XI.M41 aging management program, Sections A.1.8 and B.2.8, and Table A.3 of the LRA by modifying the alternate criteria to read:

electrical resistance corrosion rate probes. Where it is determined electrical resistance corrosion rate probes are required, the location and use of the probes will be determined by a NACE Level CP-4 Cathodic Protection Specialist.

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

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 2 Page 7 of 7 References LRISG201501 - Changes to Buried and Underground Piping and Tank Recommendations (ML15125A377)

RG 1.54, Revision 2 - Service Level I, II, and III Protective Coatings Applied to Nuclear Power Plants (ML102230344)

Attachments to this letter.

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 3 Page 1 of 4 NCSG RAI-10255-R1 Regulatory Basis:

Section 54.21(a)(3) of Title 10 of the Code of Federal Regulations (10 CFR) 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. One of the findings that the U.S.

Nuclear Regulatory Commission (NRC) 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, systems 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 in the requests for information.

Background:

Aging Management Review (AMR) item 3.3.1-119 in Revision 2 of NUREG-1800, Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants (ML103490036), cites no aging effects/mechanisms or Aging Management Program (AMP) for PVC piping, piping components, and piping elements exposed to air with borated water leakage, indoor uncontrolled air, condensation (internal), and waste water.

The License Renewal Application (LRA) annual update dated July 3, 2024 (ML24185A092),

revised LRA Table 3.3.2-44 to add new rows 4 and 8 that cite no aging effects/mechanisms or AMP for polymer piping and valve bodies exposed internally to raw water with standard note A.

The LRA defines standard note A for LRA Table 3.3.2-44 as Consistent with NUREG-1801 item for component, material, environment and aging effect. AMP is consistent with NUREG-1801 AMP.

Issue:

The use of standard note A is unclear because the internal environment of raw water is not consistent with AMR item 3.3.1-119 in Revision 2 of NUREG-1800.

While the LRA discusses installation of the non-safety related automatic dewatering pumping system as part of Engineering Changes 22-0026-001 through 22-0026-005, it does not discuss what polymer materials the piping and valve bodies are made from. In addition, no discussion was provided as to why these component/material/environment combinations have no applicable aging effects.

Request:

1.

Please discuss the use of standard note A where AMR item 3.3.1-119 is cited for polymer piping and valve bodies exposed internally to raw water.

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 3 Page 2 of 4 2.

Please identify what polymer materials the piping and valve bodies in the non-safety related automatic dewatering pumping system are made from. In addition, please discuss changing the LRA to identify the polymer material, for example, a plant-specific note.

3.

Please provide sufficient technical information supporting the conclusion that there are no applicable aging effects for the polymer piping and valve bodies exposed internally to raw water. In addition, please discuss changing the LRA to include information supporting that there are no applicable aging effects, for example, a plant-specific note.

PNPP Response

1. Please discuss the use of standard note A where AMR item 3.3.1-119 is cited for polymer piping and valve bodies exposed internally to raw water.

PNPP agrees the use of Standard Note A is inappropriate since NUREG-1801 does not address a raw water environment for polymers. Consequently, PNPP has changed this Note to Standard Note G, Environment not in GALL for this material, and removed the NUREG-1801 Item VII.J.AP-269 and the Table 1 item in Table 3.3.1-119 from LRA Table 3.3.2-44 as modified in the Annual Update (PNPP licensing letter L-24-110). The revised LRA content is in Attachment 8 of this transmittal.

2. Please identify what polymer materials the piping and valve bodies in the non-safety related automatic dewatering pumping system are made from. In addition, please discuss changing the LRA to identify the polymer material, for example, a plant-specific note.

Per line specification number M15-4 of Installation Standard Specification (ISS-2000) for piping and mechanical equipment, the polymer material for PVC Valves is ASTM D 1784 Class 12454-B and for PVC piping is ASTM D1785, PVC-1120. The plant specific note is discussed in response to question 3.

3. Please provide sufficient technical information supporting the conclusion that there are no applicable aging effects for the polymer piping and valve bodies exposed internally to raw water. In addition, please discuss changing the LRA to include information supporting that there are no applicable aging effects, for example, a plant-specific note.

As noted in LRA Section 2.3.3.44 (as modified in the Annual Update L-24-110), the Electrical Manholes Dewatering System provides automatic dewatering for Electrical Manholes #1, #2, #3,

1. 4, and #7. Each of these electrical manholes contain a submersible pump with float and level switch that initiate the automatic start/stop operation of the pump. Discharge piping from the pumps are routed vertically in the Electrical Manholes and penetrate out at an elevation below the Perry frost line. As such, this system is considered a standby system that operates after a significant rain fall and where water drains into and collects in the manholes.

The raw water environment is mild without containing aggressive chemicals. Rainwater and snowmelt is the direct source of water that drips through the concrete manhole covers as the groundwater elevation is maintained well below the base elevation of the manholes. Surface water runoff is prevented from entering the manhole. The manhole covers are typically surrounded by high metal curbs and / or the surrounding topography and site drainage features

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 3 Page 3 of 4 are such that surface runoff does not collect on the covers. PNPP is not in a coastal, saltwater area nor is it in an industrial area where pollutants of any significant quantity are expected to be present. Consequently, there would be no aggressive chemicals in the raw water environment.

The manhole enclosure encapsulating the dewatering system equipment has been modeled as Air-indoor, uncontrolled. The manholes are installed below grade, with only the covers at grade level. The ambient temperature is consistent with buried structures, which is much less than 95 degrees F throughout the year. There is a PVC check valve in the pump discharge trapping water in the discharge piping. Although the check valve may leak and slowly drain the water by backflow through the submersible pump, the internal piping and piping component environment is conservatively modeled as raw water. As a standby system, both the internal and external surfaces are modeled as being at ambient temperature.

Since the dewatering system has been in service for about a year, there is no relevant operating experience that could inform PNPP of unforeseen aging effects. Any failures would be expected to fall within infant mortality mechanisms, such as design or installation errors. Regardless, a corrective action program search did not identify any component degradation of the dewatering system.

LRA Table 3.3.2-44 was revised in the annual update to include new rows 3, 4, 7 and 8 modeling the PVC components (polymers) exposed to Air-indoor uncontrolled on the external surface and raw water on the internal surfaces.

Regarding raw water on the internal surfaces Rows 4 and 8, PNPP methodology resulted in no aging effects. The intended function is leakage boundary, therefore, flow blockage has no bearing on the intended function. PNPP uses EPRIs Mechanical Tools, Appendix A, Section 3.6.2, for evaluating aging effects and concluded there are no aging effects. The equipment is located within a manhole and rainwater is the source of fluid. Based upon these facts, PNPP noted that the surfaces are:

not exposed to temperatures exceeding 150 degrees F (considered the threshold temperature for PVC),

not exposed to aggressive chemicals, and

not exposed to Ultraviolet light, ozone, or ionizing radiation.

PNPP added the following plant specific note 343 to the above reference rows 3, 4, 7 and 8:

These PVC piping and piping components are not expected to experience aging effects per Appendix A, Section 3.6.2 of the EPRI Report 1010639, Non-Class 1 Mechanical Implementation Guideline and Mechanical Tools, Revision 4, because they are not exposed to elevated temperatures above 150 degrees F, ozone, nor ultraviolet or ionizing radiation. These components are located within covered manholes that collect rainwater after sufficient rain or melting ice and snow from a significant ground accumulation. Rainwater, ice and snow that seeps past the manhole covers does not contain aggressive chemicals capable of attacking the PVC components. PNPP is not in a coastal, saltwater area nor is it in an industrial area with heavy air pollution.

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 3 Page 4 of 4 The discussion text for AMR line 3.3.1-119 was reviewed and no revision to the text is considered necessary with the addition of plant specific note 343 added to Rows 3 and 7 in Table 3.3.2-44.

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

References EPRI Report 1010639, Non-Class 1 Mechanical Implementation Guideline and Mechanical Tools, Revision 4. (ML12335A508)

Attachments to this letter

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 4 Page 1 of 3 NPHP RAI-10137-R1 RAI 4.3.3-1 Regulatory Basis Pursuant to 10 CFR 54.21(c), the LRA must include an evaluation of time-limited aging analyses (TLAAs). The applicant must 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.

Background

LRA Section 4.3.3 addresses the environmental fatigue TLAA, which is also called environmentally assisted fatigue (EAF) TLAA, including the screening evaluation to determine the limiting EAF locations.

Issue The LRA does not clearly describe how the applicant determined thermal zones or sections that group certain components and piping lines for proper comparisons of the screening CUFen values considering the applicable transient conditions.

Request Clarify how the applicant determined thermal zones or sections that group certain components and piping lines for proper comparisons of the screening CUFen values.

PNPP Response Clarify how the applicant determined thermal zones or sections that group certain components and piping lines for proper comparisons of the screening CUFen values.

The initial step in the determination of the EAF locations is to start with all reactor pressure vessel (RPV) components and piping systems that include a location monitored by the Fatigue Management Program. The set of components and piping is then reduced by eliminating a location that meets one of the following criteria:

The location is only exposed to air (that is, not exposed to reactor water), and therefore EAF is not applicable.

The location is not a reactor coolant pressure boundary location.

The location has a CUF such that, even if the maximum possible environmental fatigue correction factor (Fen) were applied, the resulting EAF usage (Uen) would be less than 0.8.

The location has a CUF that is caused by dynamic loads only, and therefore Fen = 1.0.

The location is not Class 1.

Following the identification of the set of components and piping that require EAF evaluation, piping and/or vessel components are grouped into thermal zones.

A thermal zone is defined as a collection of piping and/or vessel components which undergo essentially the same group of thermal and pressure transients during plant operations. Thermal zones are determined on the basis of common plant transients during plant operation. The differences in stresses experienced by each component in a thermal zone are generally the result of material and geometry differences when stress evaluation methods are similar.

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 4 Page 2 of 3 For PNPP, the thermal zones were determined by:

The thermal zones identified on reactor vendor supplied drawings, Plant chemistry data, and The EPRI BWR Vessel and Internals Application (BWRVIA) for Radiolysis and ECP Analysis computer program.

Then, within each material type in a thermal zone, the location with the highest Uen* (estimated Uen) is selected during initial screening; the location with the second highest Uen* is also selected if the top two Uen

• values are within a factor of two. However, if the third-highest Uen*

value is within 25% of the highest Uen* value within a thermal zone, then the top three locations in that thermal zone are selected. Also, all NUREG/CR-6260 locations are retained as sentinel locations, and any locations with Uen* that is less than half of the lowest Uen* for any NUREG/CR-6260 location in that thermal zone can be removed as a potential sentinel location.

The Uen for each of the identified locations is then projected to 60-years. The projected 60-year Uen are then used to determine the bounding EAF locations for each thermal region.

There are no LRA changes associated with this RAI response.

RAI 4.3.3-2 Regulatory Basis Pursuant to 10 CFR 54.21(c), the LRA must include an evaluation of time-limited aging analyses (TLAAs). The applicant must 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.

Background

LRA Section 4.3.3 addresses the environmental fatigue TLAA, which is also called environmentally assisted fatigue (EAF) TLAA, including the screening evaluation to determine the limiting EAF locations.

Issue LRA Section 4.3.3 indicates that the EAF screening evaluation uses the bounding environmental fatigue correction factor (Fen) values. However, the LRA section does not clearly discuss how the applicant determined the bounding Fen values in the screening evaluation.

In addition, LRA Section 4.3.3 indicates that, after the screening evaluation, the applicant performed more detailed EAF evaluation to remove some conservatisms and determine the refined CUFen values for 60 years of operation, as described in LRA Table 4.3-5. However, the LRA does not clearly describe how the conservatisms associated with the screening CUFen values were removed to refine the 60-year projected CUFen values.

Request

1. Describe how the bounding Fen values in the screening evaluation were determined. As part of the response, clarify how the temperature, strain rate and sulfur content of steel materials in the calculation of the bounding Fen were determined

2. Clarify how the conservatisms associated with the screening CUFen values were removed to refine the 60-year projected CUFen.

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 4 Page 3 of 3 PNPP Response

1. Describe how the bounding Fen values in the screening evaluation were determined.

As part of the response, clarify how the temperature, strain rate and sulfur content of steel materials in the calculation of the bounding Fen were determined.

A site specific evaluation was performed to determine the bounding Fen values. As discussed in LRA Section 4.3.3 (as revised by L-24-109), the site specific evaluation for the Fen for steel materials was calculated based upon the applicable formulas provided in Appendix A of NUREG/CR-6909. To ensure that Fen values in the screening evaluation were bounding, the Fen values were determined using bounding input values for sulfur content, material temperature, and strain rate, as follows:

The maximum temperature for each thermal zone.

The most conservative strain rate.

The most conservative value for sulfur content of steel materials.

2. Clarify how the conservatisms associated with the screening CUFen values were removed to refine the 60-year projected CUFen.

The site specific EAF evaluation used the following methods to remove conservatism:

Calculate Fen and Uen on a pair-by-pair basis in a fatigue table.

Where original analyses conservatively grouped multiple transients into one fatigue pair, the transients were separated and used to create separate pairs for each transient.

Recalculate stress for individual load pairs to remove conservatism from original analyses.

Using the guidance of NUREG/CR-6909, Revision 1, average temperature is sometimes used in the calculation of Fen.

Perform a detailed ASME Code NB-3200 analysis.

Calculate strain rate to reduce conservatism for individual load pairs.

For specific piping locations, to reduce excess conservatism, Sn, Sp, Ke, and Salt are recalculated in accordance with the 1977 ASME Code with Addenda through Summer 1979.

There are no LRA changes associated with this RAI response.

References None Attachments None

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 5 Page 1 of 12 NCSG RAI-10183-R1 Regulatory Basis Title 10 of the Code of Federal Regulations section 54.21(a)(3) requires the applicant to demonstrate that the effects of aging for structures and components will be adequately managed so that the intended function will be maintained consistent with the current licensing basis (CLB) for the period of extended operation. As described in the NUREG-1800, Standard Review Plan [SRP] for Review of License Renewal [LR] Applications for Nuclear Power Plants, SRP-LR, an applicant may demonstrate compliance with 10 CFR 54.21(a)(3) by referencing the NUREG-1801, Generic Aging Lessons Learned License Renewal (GALL) Report when evaluation of the matter in the GALL Report applies to the plant.

Background

Condition Report (CR) CR-2019-10233, dated December 9, 2019, 2019 Triennial Heat Sink Inspection: Roll Up CR, documented issues and problems found during the 2019 triennial heat sink inspection, which was performed in December 2019. Perrys open cycle cooling water system program is implemented through procedure NOP-ER-2006, Rev 6, Service Water Reliability Management Program. As noted in CR-2019-10233, NOP-ER-2006 was revised in September of 2019 to incorporate tighter handoffs between maintenance procedures and to clearly delineate responsibilities between System Engineers, Site Managers, and the Fleet Engineering Program Manager. After identifying program deficiencies in advance of the triennial heat sink inspection and revising NOP-ER-2006 in September 2019, the applicant incorporated a system trending improvement plan (ATL-2022-0277) in March of 2022. During the audit in December 2023, the staff reviewed CR-2022-01183, dated February 16, 2022, Rollup CR for a Gap Identified in Strategic Mechanical Engineering Performance, which documented that performance testing on the A emergency closed cooling water heat exchanger failed to meet the acceptance criteria in December of 2021 and that the issue would be resolved under CR-2022-02280, dated March 16, 2022. In addition, CR-2022-01183 also documented that heat exchanger system trending was not performed for multiple years on the Division I and III diesel generator jacket water heat exchangers and on the Division I and II residual heat removal heat exchangers.

Section 4.2.2.2.a of NOP-ER-2006, Implementation notes that the heat transfer capability of heat exchangers is verified by periodic testing, and states that the basis for the test frequency should be documented or accepted in the evaluation of periodic test results by acknowledging the acceptability of the test frequency based upon review of previous test results, applicable margins, and related variables.

The approach delineated in NOP-ER-2006 implements the monitoring and trending portion of aging management programs delineated in SRP-LR section A.1.2.3.5, which states, This includes an evaluation of the results against the acceptance criteria and a prediction regarding the rate of degradation in order to confirm that timing of the next scheduled inspection will occur before a loss of [structure or component] SC-intended function.

The documentation described in NOP-ER-2006 (regarding an acknowledgement of the acceptability of the test frequency based upon review of previous test results), was not found in the evaluation of the test data for the Division III emergency diesel generator (EDG) jacket water

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 5 Page 2 of 12 heat exchanger, which was documented in CR-2022-00950, dated February 8, 2022, Triennial Ultimate Heat Sink Self-Assessment: Division III Diesel Generator Jacket Water Heat Exchanger Performance Degradation.

Issue: It is not clear to the staff that an evaluation was being performed to confirm that the timing of the next inspection would occur before a loss of the heat exchangers intended function.

LRA section B.2.37, Open Cycle Cooling Water System Program, includes the following discussion in the associated Operating Experience section:

In February 2022, a CR documented that a heat sink self-assessment identified that the Division I diesel generator jacket water heat exchanger had a degrading trend in performance and as a result, corrective actions were established to ensure cleaning and restoration of margin in the heat transfer coefficient.

However, section B.2.37 of the LRA did not include a discussion about either CR-2022-00950, dated February 8, 2022, which documented a degrading trend in the Division III diesel jacket water heat exchanger, or CR-2022-03813, dated May 3, 2022, Division III Emergency Diesel Generator Water Heat Exchanger Inspection Unsatisfactory, which documented an unsatisfactory condition of the Division III diesel jacket water heat exchanger when it was opened and inspected.

The Description section (page 2) of CR-2022-03813 identified that there were 72 tubes more than 50 percent blocked, primarily by zebra mussel shells. The Supervisor Comments section (page 3) of CR-2022-03813 stated that the material was reddish-brown and magnetic, indicating corrosion products from carbon steel piping. The Corrective Actions Taken section (page 3) states that an as-left inspection was performed, and no tubes were blocked with the metallic material or zebra mussels initially found. Additionally, the tuberculation and buildup in the waterboxes were removed.

In response to a breakout question about CR-2022-03813, asked by the NRC staff in December 2023, the applicant responded by stating that, The Condition Report was initiated by engineering based on the initial inspection of the heat exchanger. After further analysis of the debris, the zebra mussels initially thought to be inside the Division III Emergency Diesel Generator Jacket Water Heat Exchanger as identified in CR-2022-003813 were later determined to be predominately metallic corrosion debris from the carbon steel piping (ref NOP-ER-2006 Attachment 1 - Heat Exchanger Visual Inspection Checklist as completed by the system engineer). As such, an infestation of live zebra mussels did not occur.

Issue: While it may be possible that reddish-brown metallic corrosion products could be mistaken for primarily zebra mussel shells, if such a determination was made during the processing of CR-2022-03813, then it apparently was not accurately documented on page 3, since the zebra mussels initially found was still referenced. Therefore, this appears to be an example of inaccurate reporting.

The documentation in CR-2022-03813 indicated that the Division III EDG jacket water heat exchanger would be cleaned, and performance testing would be performed following maintenance. However, it did not indicate whether the degraded condition of the heat exchanger

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 5 Page 3 of 12 provided acceptable heat transfer capability, to demonstrate that the aging management program was taking corrective actions prior to unacceptable heat exchanger performance. This heat exchanger was tested in October 2014 and June 2019. Based on the NRC staffs calculated rate of degradation from these previous tests (i.e., trending), the heat exchanger would not meet its acceptance criteria sometime in December 2021. The data evaluation for the 2019 test does not include any statement about the acceptability of the test frequency (i.e., a prediction of the degradation rate to confirm that the next scheduled inspection will occur before a loss of intended function).

Issue: Since there is no corrective action program document stating that Perry failed to implement the program as delineated in the controlling procedure, the program needs to be enhanced to ensure that in the future, evaluations will be conducted to ensure that the next scheduled inspection will occur before a loss of intended function.

As discussed above, LRA section B.2.37 refers to a CR without a number designation and based upon the staffs operating experience review, the undesignated CR appears to be CR-2022-01183, which states:

This report will only evaluate the common trend associated with not recording the degraded trends within the Corrective Action Program. None of these events fell below performance acceptance criteria; however, there was reduced margin from the previous performances. This document shows issues with lack of low threshold for CR documentation and a gap in trending performance. [emphasis added by NRC staff]

However, contrary to the statement above that none of these events fell below performance acceptance criteria, the graph on page 7 of 34 in CR-2022-01183 shows that emergency closed cooling (ECC) A heat exchanger did not pass acceptance criteria during the latest performance test, on September 21, 2021. Section 4.2.2.2.f of NOP-ER-2006, Implementation notes that the heat transfer capability of heat exchangers are verified by periodic testing, and states, A post maintenance heat transfer test shall be conducted following corrective action to a heat exchanger that failed a heat transfer test.

Issue: There is no indication on the graph on page 7 of 34 in CR-2022-01183 that a post maintenance heat transfer test was conducted.

On pages 20 - 22 of 34 in CR-2022-01183, identification of a degrading trend is discussed, and it is noted that, One outlying point is abnormal, two is a correlation, and three make a trend.

The graphs on pages 5 and 6 of 34 in CR-2022-01183 show the trending of the heat transfer coefficient for the residual heat removal (RHR) A and Division I jacket water heat exchangers, respectively. While both graphs only show a correlation of decreasing performance between two data points, both graphs also show an extension of the time between performance tests, such that had the original testing frequency been maintained, a degraded trend (i.e., three points) would have been identified. Also, on page 30 of 34 in CR-2022-01183, the extent of condition discussion states that the ECC A heat exchanger did not meet the acceptance criteria, due to a negative step change in performance but was not found to have a declining trend.

Issue: It appears to the NRC staff that the definition of a degrading trend, One outlying point is abnormal, two is a correlation, and three make a trend is inappropriate for monitoring heat

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 5 Page 4 of 12 exchanger performance, which typically shows a decreasing trend over time, in between heat exchanger cleanings. The definition Perry is using appears to a have been adopted from a statistical process control definition commonly used in manufacturing, which typically includes a measured parameter mean, standard deviation, and upper and lower control limits.

Issue: The information contained in CR-2022-01183 appears to be neither accurate nor consistent with respect to either the ECC A heat exchanger meeting acceptance criteria or having a negative performance trend. In addition, a CR documenting this heat exchangers failure to meet acceptance criteria, CR-2022-02280, Division I Emergency Closed Cooling Water heat exchanger performance testing did not meet acceptance criteria, was written on March 16, 2022, almost six months after the failed test. If the revisions to NOP-ER-2006 in September 2019 were to incorporate tighter handoffs between maintenance procedures and to clearly delineate responsibilities between System Engineers, Site Managers, and the Fleet Engineering Program Manager, the timeliness and accuracy of documentation regarding the heat exchangers degraded performance is not indicative of an improving or effective aging management program.

Condition report CR-2022-05199, dated June 29, 2022, Division I Emergency Closed Cooling Water Heat Exchanger performance test did not meet acceptance criteria, notes that the Division I ECC heat exchanger again did not meet acceptance criteria.

The Standard Review Plan, NUREG-1800, Rev. 2, section A.1.2.3 Aging Management Program

[AMP] Elements also contains a description of Element 10, Operating Experience, and states, in part, The operating experience of AMPs that are existing programs, including past corrective actions resulting in program enhancements or additional programs, should be considered. A past failure would not necessarily invalidate an AMP because the feedback from operating experience should have resulted in appropriate program enhancements or new programs. This information can show where an existing program has succeeded and where it has failed (if at all) in intercepting aging degradation in a timely manner. This information should provide objective evidence to support the conclusion that the effects of aging will be managed adequately so that the structure-and component intended function(s) will be maintained during the period of extended operation.

Issue: While the applicant appears to have taken many actions to improve the documentation of heat exchangers covered by the open cycle cooling water AMP, it is not clear to the staff that the changes have resulted in improved trending.

Issue: The information in the LRA was not complete and accurate as required by 10 CFR 54.13.

The statements in the LRA regarding heat exchanger performance tests were incomplete because they did not include all the relevant operating experience documented by the applicant in their corrective action program and the statement that No unacceptable performance has been documented was inaccurate since unacceptable performance was documented, as shown above in CR-2022-1183, CR-2022-02280, CR-2022-03813, and CR-2022-05199.

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 5 Page 5 of 12 Requests

1. State the basis for why changes to procedures to improve the accuracy of statements recorded in CRs regarding the performance of the various heat exchangers covered by the open cycle cooling water AMP are not warranted.

2. State the basis for why changes to procedures to improve the documentation and accuracy of predictions regarding when heat exchangers will not meet acceptance criteria are not warranted.

3. State the basis for why changes to the definition of a degraded trend, such that negative step changes to the heat exchanger performance that result in not meeting performance acceptance criteria will no longer be misclassified as not also being in a degraded trend, are not warranted.

PNPP Response This RAI involves numerous issues that warrant a detailed discussion to provide clarification of information. Significantly, one result of this RAI response will be an enhancement to the Open Cycle Cooling Water aging management program that is intended to improve the effectiveness of open cycle heat exchanger thermal performance trending and minimize the potential for the issues identified herein.

Request 1 State the basis for why changes to procedures to improve the accuracy of statements recorded in CRs regarding the performance of the various heat exchangers covered by the open cycle cooling water AMP are not warranted.

Statements that are recorded in condition reports are governed by PNPP procedure NOP-LP-2001, the Corrective Action Program. This program has specific requirements applicable to initiators of condition reports regarding (NOP-LP-2001, Section 4.3.5):

Description of the problem, including what, where, when, how, and why, if they are known.

The amount of detail in the description to clearly identify the originators intent in initiating the CR.

If the initiator has knowledge of the actual or potential consequences of the condition, THEN the description should include a discussion of the consequences.

Once a condition report is initiated, it is subject to a supervisory review (NOP-LP-2001, Section 4.4). A requirement of the supervisory review is to ensure that the information in the condition report is accurate and complete. If the description of condition needs to be revised, then the supervisor must contact the condition report originator to revise the information or enter clarifying information as supervisor comments.

In the issues identified for this RAI, there are two allegations of statements made in PNPP condition reports involving their accuracy:

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 5 Page 6 of 12 CR-2022-03813, dated May 3, 2022, Division III Emergency Diesel Generator Water Heat Exchanger Inspection Unsatisfactory, which documented an unsatisfactory condition of the Division III diesel jacket water heat exchanger when it was opened and inspected.

The Description section (page 2) of CR-2022-03813 identified that there were 72 tubes more than 50 percent blocked, primarily by zebra mussel shells. The Supervisor Comments section (page 3) of CR-2022-03813 stated that the material was reddish-brown and magnetic, indicating corrosion products from carbon steel piping. The Corrective Actions Taken section (page 3) states that an as-left inspection was performed, and no tubes were blocked with the metallic material or zebra mussels initially found. Additionally, the tuberculation and buildup in the waterboxes were removed.

While it may be possible that reddish-brown metallic corrosion products could be mistaken for primarily zebra mussel shells, if such a determination was made during the processing of CR-2022-03813, then it apparently was not accurately documented on page 3, since the zebra mussels initially found was still referenced.

The information contained in CR-2022-01183 appears to be neither accurate nor consistent with respect to either the ECC A heat exchanger meeting acceptance criteria or having a negative performance trend. In addition, a CR documenting this heat exchangers failure to meet acceptance criteria, CR-2022-02280, Division I Emergency Closed Cooling Water heat exchanger performance testing did not meet acceptance criteria, was written on March 16, 2022, almost six months after the failed test.

In the first case, CR 2022-03813, the CR originator described conditions believed to be accurate based on the evidence and perspective available to the originator at the time. The supervisor provided a clarifying statement for the condition description as required by procedure, citing that the material was reddish-brown and magnetic, in order to clarify that the fouling was not primarily zebra mussel shells. Photographs attached to the condition report support the supervisors clarification. Note that PNPP procedure EMARP-0008 describes zebra mussels as follows:

Dreissena (Dreissena Polymorpha; Zebra Mussel) Dreissena is a small freshwater mussel with a distinct black and cream stripped pattern on its shell. It develops a fibrous attachment on anything relatively clean, smooth, and hard. It is not usually found in sediments.

The condition report investigation summarized the results of the heat exchanger as-left inspection, indicating (after cleaning) that no tubes were blocked with the metallic material or zebra mussels initially found. Based on the above observations:

The CR description was based on the originators initial observations and perspective; The Supervisors comment clarified the as-found condition description; The CR investigation concluded that an as-left inspection was performed, and no tubes were blocked with the metallic material or zebra mussels initially found.

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 5 Page 7 of 12 The condition report identified the presence of heat exchanger fouling. As a result of the condition report, actions were taken to resolve the fouled condition. The purpose of the corrective action program, to identify and resolve degraded conditions, was met. Although there were differences between statements in the condition description and clarifying supervisor comments, a conclusion that the CR 2022-03813 was inaccurate is not supported. PNPP acknowledges that the text in the closure summary of CR 2022-03813 is not ideal insofar as it includes the term zebra mussels. However, the statement in question accurately communicates that, regardless of the material type or source, the fouling was satisfactorily removed, and the heat exchanger was left in a satisfactory material condition.

In the second case, CR 2022-01183 the extent of condition conclusion and evaluation applicable to the emergency closed cooling water (ECC) A heat exchanger includes the following two statements:

Extent of condition was completed and found no historical performance degradation with the remaining four GL 89-13 heat exchangers.

Emergency Closed Cooling A Heat Exchanger Heat Transfer Coefficient was not found to have a declining trend. However, during the latest performance of the heat exchanger performance test, on 9/23/2021, there was a negative step change in performance and the heat exchanger did not meet the acceptance criteria. This was documented and will be resolved under CR-2022-02280. This is a good example of identifying a negative trend and generation of a condition report.

The fact that the above statements contain conflicting information and appear to be inaccurate is indisputable.

PNPP Condition Report 2024-07137 has been initiated that addresses the accuracy of the statements made in Condition Report 2022-01183.

Three subsequent condition reports were written shortly after CR 2022-01183 addressing the unsatisfactory thermal performance of the ECC A heat exchanger:

CR 2022-02280 - Emergency Closed Cooling (ECC) A heat exchanger (1P42B0001A) performance (originated 3/16/22)

The condition report description identifies that during evaluation of performance test data for the Emergency Closed Cooling A heat exchanger recorded during performance of PTI-P42-P0001 on 9/23/2021, when the test results were projected to design basis conditions, the test acceptance criteria were not met. The description also indicated that in comparing previous test results, there was a step change in calculated results.

The investigation of the condition report identified that during performance of the test, there was not enough heat load present to perform the test in order to obtain valid results, as required by the test instruction. The heat exchanger test results are considered invalid, and the heat exchanger performance test was rescheduled to be performed in June 2022.

Because GL 89-13 heat exchanger testing normally cannot be performed at design basis conditions, the test data is analyzed at the test conditions, and then the results are projected to design basis conditions. PNPP has test protocol documents that have evaluated heat

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 5 Page 8 of 12 exchanger test conditions and have prescribed test parameters that will ensure valid test results, minimizing the effects of test measurement uncertainties. Heat exchanger tests that are performed outside of the prescribed test parameters cited in the test protocols will reflect the increased effects of test measurement uncertainty. When those test results are subsequently extrapolated to design basis conditions for the heat exchanger, the effect of the test error is increased. In this case, the increased test error presented itself as a significant decrease in heat exchanger thermal performance.

CR 2022-02469 - Periodic Test Instruction (PTI-P42-P0001, Division 1 Emergency Closed Cooling Heat Exchanger Performance Test) procedural usage issues (originated 3/21/22)

The CR description states:

Multiple procedure usage issues have been identified with performance of Periodic Test Instruction (PTI) PTI-P42-P0001 conducted in September 2021. The most significant issue could result in questionable validation of the raw data (heat load potentially not satisfying minimum required).

The CR investigation concluded that inadequate heat load was present during the data collection portion of the test. Therefore, the test was invalidated and reperformance of PTI-P42-P0001 was scheduled for June 2022.

CR 2022-05199 - Emergency Closed Cooling (ECC) A heat exchanger (1P42B0001A) performance (originated 6/29/22)

Heat exchanger test procedure PTI-P42-P0001 was performed on 6/22/2022, prompted by earlier CRs 2022-02280 and 2022-02469 to re-perform the heat exchanger thermal performance test. This test procedure records temperature and flow data used to evaluate the thermal performance of the heat exchanger. The initial calculation indicated that the acceptance criteria for the overall heat transfer coefficient (U) and the heat removal rate (Q) were not met (not satisfied). That calculation acceptance criteria is based on guidance which includes additional margin through conservatisms. With excess conservatisms appropriately removed, the recalculated performance data for heat removal rate (Q) and overall heat transfer coefficient (U) projected to worst case conditions showed satisfactory results.

Referring to the above invalid ECC A heat exchanger performance test, when a valid heat exchanger test was performed, the errant step change in performance was no longer evident.

Work Order 200563443 was executed in March 2023 to clean and inspect this heat exchanger, restoring design margin. A review of work order history identifies the ECC A heat exchanger was previously cleaned in the spring of 2013 (order 200342057). Thus, the fouling for this heat exchanger occurred over a 10-year interval.

In the response to Request 2 to this RAI, an enhancement to the open cycle cooling water aging management program is proposed to improve heat exchanger thermal performance trending and evaluation. The enhancement is also expected to minimize the potential for conditions like those identified in CR 2022-01183. Further, NOP-LP-2001, Corrective Action Program, includes the following general requirement, applicable to all corrective action program activities encompassing any associated with the Open Cycle Cooling Water Program.

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 5 Page 9 of 12 Procedure Step 4.1.4: All documentation should be complete and accurate in all material respects, such that a third-party individual could generally reconstruct/understand what was done and the basis for conclusions.

As mentioned above, CR 2024-07137, generated as a result of this RAI response development, will ensure appropriate actions are taken to address the inaccuracies noted in this RAI regarding CR 2022-01183 and the ECC A Heat exchanger.

Based on the above information, PNPP has concluded that changes to procedures to improve the accuracy of statements recorded in CRs regarding the performance of the various heat exchangers covered by the open cycle cooling water AMP are not warranted.

Request 2 State the basis for why changes to procedures to improve the documentation and accuracy of predictions regarding when heat exchangers will not meet acceptance criteria are not warranted.

In CR 2022-01183, the condition report description states that as the result of an internal self-assessment to prepare for an NRC Triennial Ultimate Heat Sink NRC inspection, a performance gap was identified. CR 2022-01183 served as a roll up CR based on documentation of four degraded trends associated with GL 89-13 heat exchangers. These four separate heat exchangers had exhibited degrading heat transfer performance that were not documented in either the corrective action program or work control process.

The four heat exchanger performance trends cited in the CR follow:

1. Residual heat removal (RHR) heat exchanger train A CR 2022-00266 dated 1/12/2022 identified:

Based on updated performance data from November 2020 there is a degrading trend on the Division 1 RHR heat exchangers thermal performance. The margin between calculated HX performance and acceptance criteria was identified as slim.

Subsequent to CRs 2022-01183 and 2022-00266, a heat exchanger performance test was performed in November 2022 and evaluated in calculation E12-106 R6 that indicated adequate heat exchanger thermal performance, still with low margin. As a result of CR 2022-00266, maintenance Notification 601344653 was created that resulted in Work Order 200871691 to clean the heat exchanger(s). That order was completed in April 2023.

2. Residual heat removal (RHR) heat exchanger train B CR 2022-00284 dated 1/13/2022 identified:

Based on the updated performance data, there is a degrading trend on Division 2 RHR heat exchangers. There is a slim margin remaining for the Acceptance Criteria (Reference Calculation E12-102 Rev. 4). Calculation E12-102 Rev 4 evaluated heat exchanger test data recorded on 5/31/2018. Addendum 1 to calculation E12-102 Rev. 4 analyzed another segment of test data from the same thermal performance test compared to the initial analysis in calculation E12-102 Rev 4 and identified additional thermal performance margin.

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 5 Page 10 of 12 Subsequently, a heat exchanger performance test was performed in June 2022 and evaluated in calculation E12-102 R5 that indicated adequate heat exchanger thermal performance with margin.

CR 2022-00284 identifies a planned corrective action per order 200874059 to perform a fill and vent of the RHR B/D heat exchangers. According to notes for that order, the order was subsequently voided. The basis for voiding the order was that the action was performed following 1R19 (Spring 2023) and can be reperformed as needed without the use of a work order. Site procedures SOI-P45 and SVI-P45-T2002 can be used to vent the HX Tube side.

Work Orders 200871703 and 200892942 to clean the RHR B train heat exchangers is reflected in the work control database to be performed in early 2025. However, no heat exchanger thermal performance test has been performed since June 2022. Work Order 200901750 is scheduled in November 2024 to test the thermal performance of the RHR B train heat exchangers.

3. Division 1 emergency diesel generator jacket water heat exchanger CR 2022-00932 dated 2/07/2022 identified:

There is a degrading trend for thermal performance. Calculation R46-023 Rev. 4 that analyzed test data from October 2020 identified a slim margin remaining between heat exchanger measured performance and the acceptance criteria. The heat transfer coefficient (U) was determined to be 285.4 (Btu/hr-ft2-°F) with an acceptance criteria of 265.3 (Btu/hrft2-° F).

According to the work control database, the heat exchanger PY-1R46B0002A was last cleaned in 2009 via Work Order 200068835. Work Order 200875576 to clean the heat exchanger is scheduled to be performed in late 2025. Work Order 200872586 is scheduled to test the thermal performance of the Division 1 diesel generator jacket water heat exchanger in October 2024.

4. Division 3 diesel generator jacket water heat exchanger CR 2022-00950 dated 2/08/2022 identified:

There is a degrading trend for thermal performance. Calculation E22-042 Rev. 4 analyzed test data from June 2019 and indicates a slim margin remaining between heat exchanger measured performance and the acceptance criteria. The heat transfer coefficient (U) for the calculation was determined to be 339.18 (Btu/hr-ft2-°F) with an acceptance criterion of 320.1 (Btu/hr-ft2- °F). Work order 200875642 was completed in May 2022 to clean the heat exchanger.

Following cleaning, the Division 3 diesel generator jacket water heat exchanger was subsequently tested for thermal performance in August 2022 with acceptable test results (Calculation E22-042 Rev. 5).

Based on the evidence from CR 2022-01183, and the issues identified in this RAI, PNPP proposes to add the following enhancement to the Open-Cycle Cooling Water System aging management program in sections A.1.37, A.3 and B.2.37 of the LRA. The proposed enhancement will state:

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 5 Page 11 of 12 The implementing procedures for heat exchanger thermal performance testing will be enhanced to require each heat exchanger thermal performance periodic test instruction to include the following steps (or similar) to evaluate the test results:

Provide the work order and planned date for the next scheduled test or cleaning for this heat exchanger.

Since the latest cleaning of this heat exchanger, if 2 or more valid heat exchanger test results are available, project the date for no margin to the acceptance criteria based on the current performance trend.

If the projected date for no margin will occur before the planned date for the next heat exchanger test or cleaning, initiate a Condition Report.

This proposed enhancement, engraining trend projection into the implementing procedures, is expected to improve the documentation and accuracy of predictions regarding when heat exchangers will not meet acceptance criteria.

Request 3 State the basis for why changes to the definition of a degraded trend, such that negative step changes to the heat exchanger performance that result in not meeting performance acceptance criteria will no longer be misclassified as not also being in a degraded trend, are not warranted.

When an open cycle cooling water heat exchanger is placed in service, it is expected that exposure of its heat transfer surfaces to raw water will result in fouling that accumulates with time. Thus, the thermal performance trend of all open cycle cooling water heat exchangers is continually degrading. Using the phrase degraded trend to assess open cycle cooling water heat exchanger thermal performance should be avoided because of its ambiguity. A review of PNPP procedures relevant to open cycle cooling water heat exchanger thermal performance monitoring did not cite or define the phrase degraded trend. Thus, no change to the definition of the phrase degraded trend is considered to be warranted.

The following discussion is intended to provide clarification regarding the specific observation of the step change in the ECC A heat exchanger performance.

Also, on page 30 of 34 in CR-2022-01183, the extent of condition discussion states that the ECC A heat exchanger did not meet the acceptance criteria, due to a negative step change in performance but was not found to have a declining trend.

As explained in the response to request 1 above:

Heat exchanger tests that are performed outside of the prescribed test parameters cited in PNPP test protocol reports will reflect the effects of increased test measurement uncertainty.

When the test results are subsequently extrapolated to design basis conditions for the heat exchanger, the effect of the test error is increased. In this case, the increased test error presented itself as a significant decrease in heat exchanger thermal performance. When a

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 5 Page 12 of 12 subsequent valid heat exchanger test was performed, the errant step change in performance was no longer evident.

The response to request 2 identifies a proposed enhancement to the Open-Cycle Cooling Water System aging management program in sections A.1.37, A.3 and B.2.37 of the LRA. That enhancement is expected to minimize the potential for a negative step change in heat exchanger performance that results in not meeting performance acceptance criteria to be misclassified as not also being in a degraded trend.

Operating Experience In addition to addressing the above requests cited in this RAI, PNPP proposes to update the operating experience section of the Open Cycle Cooling Water aging management program, LRA section B.2.37, to include discussion that addresses the following condition reports:

CR-2022-00266 CR-2022-00284 CR-2022-00950 CR-2022-01183 CR-2022-02280 CR-2022-02469 CR-2022-03813 CR-2022-05199 Although the above CRs could have been included in the discussion of the Operating Experience section of LRA section B.2.37 for the Open Cycle Cooling Water Aging Management Program, the summary of that Operating Experience section that asserts no unacceptable performance has been documented is considered to be accurate, in light of these condition reports. Added discussion of these condition reports in the operating experience section of LRA section B.2.37 for the Open Cycle Cooling Water Aging Management Program is expected to better reflect the issues and evaluations made to manage the aging of open cycle cooling water components to maintain their intended functions.

PNPP LRA Changes The above proposed changes to LRA will be made by a supplement to the LRA, planned to be submitted before October 21, 2024.

References None Attachments None

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 6 Page 1 of 4 SCPB RAI-10192-R1 Regulation Screening is governed by Title 10 of the Code of Federal Regulations (10 CFR) section 54.21(a).

Issue Updated Final Safety Analysis Report (UFSAR) section 9A.4.13.2 Analysis reads in part:

Combustibles in the offgas building include charcoal and hydrogen gas. Special consideration was given to the charcoal filters and to a possible explosive hydrogen mixture, as hazards in this building. The charcoal filters are provided with heat sensors that initiate signals in the control room so that the deluge system can be manually actuated. The components and piping for the offgas system up to the recombiners are designed to withstand a hydrogen explosion. The ventilation system supplies sufficient circulation of room air so that any hydrogen leakage will be limited to levels below 4 percent by volume hydrogen concentration.

UFSAR Appendix 9A.4.13.1 reads in part:

The ventilation system for the offgas building consists of supply plenums and supply fans blowing cooled outdoor air to various areas.

This supply air is discharged to the atmosphere by the exhaust fans.

License Renewal Application (LRA) section 2.3.3.41, Offgas Building Ventilation (M36) reads in part:

Components located below elevation 660 of the offgas building are designed to satisfy system space requirements and to satisfy the requirements for Safety Class 3 and Seismic Category I items.

LRA section 2.3.3.35, MCC [Motor Control Center] Switchgear and Miscellaneous Electrical Area HVAC [Heating, Ventilation, and Air-Conditioning], and Battery Room Exhaust (M23 &

M24), subsection System Functions (and scoping criteria, if intended function) contains the intended function:

Prevent the accumulation of combustible gas in the battery rooms. [10 CFR 54.4(a)(1),

(a)(3) - FP [fire protection))

LRA section 2.3.3.35, subsection References, License Renewal Drawings: 912-0609 displays as being subject to aging management review (AMR) for both supply and exhaust ventilation duct/registers to/from the Unit 1 divisional DC [direct current] switchgear room(s) and battery room(s) [coordinates F-4 & F-8] to prevent the buildup of Hydrogen within the battery rooms.

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 6 Page 2 of 4 In contrast, LRA section 2.3.3.41, subsection, System Functions (and scoping criteria, if intended function) does not contain an intended function that parallels LRA section 2.3.3.35 system intended function; that is:

Prevent the accumulation of combustible gas in the Offgas Building. [10 CFR 54.4(a)(1),

(a)(3) - FP]

LRA section 2.3.3.41, subsection References, License Renewal Drawings: 912-0622 displays as NOT being subject to AMR for the supply ventilation duct / registers from the turbine building cooling and ventilation system at all three elevations of the offgas building.

In addition, LRA section 2.3.3.63, Turbine Building Ventilation (M35), subsection, System Functions (and scoping criteria, if intended function) does not contain an intended function that parallels LRA section 2.3.3.35 system intended function. Specifically:

Prevent the accumulation of combustible gas in the Offgas Building. [10 CFR 54.4(a)(1),

(a)(3) - FP]

Request The NRC staff requests that the licensee:

1. justify the discrepancy noted above. More specifically, how combustible gas threats are mitigated in the offgas building versus how these same threats are mitigated in the Unit 1 divisional DC switchgear room(s) and battery room(s) of the Units 1 and 2 control complex buildings.

2. justify the absence of a system intended function, Prevent the accumulation of combustible gas in the offgas building for the turbine building ventilation system.

3. establish that the Perry offgas building exhaust system by itself can maintain Hydrogen levels at less than 4% throughout the offgas building without fresh supply air from the turbine building cooling and ventilation system during normal plant power operations.

PNPP Response The NRC staff requests that the licensee:

1.

justify the discrepancy noted above. More specifically, how combustible gas threats are mitigated in the offgas building versus how these same threats are mitigated in the Unit 1 divisional DC switchgear room(s) and battery room(s) of the Units 1 and 2 control complex buildings.

2.

justify the absence of a system intended function, Prevent the accumulation of combustible gas in the offgas building for the turbine building ventilation system.

3.

establish that the Perry offgas building exhaust system by itself can maintain Hydrogen levels at less than 4% throughout the offgas building without fresh supply air from the turbine building cooling and ventilation system during normal plant power operations.

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 6 Page 3 of 4 PNPP evaluated the prevention and mitigation of combustible gas threats in the ventilation systems, such as the battery room ventilation and the Offgas building ventilation system, consistently. Preventing a fire from affecting safe shutdown equipment is achieved in both cases. For the Offgas building, its ventilation system is not relied upon. See USAR section 9A.3.2, Systems for Safe Shutdown. Whereas, preventing a fire in the Control complex does rely on the MCC Switchgear and Miscellaneous Electrical Area HVAC, and Battery Room Exhaust (M23 & M24) systems. This difference is not a discrepancy since they achieve the same goal in different ways. These MCC Switchgear and Miscellaneous Electrical Area HVAC, and Battery Room Exhaust (M23 & M24) systems are included in structures that contain safe shutdown equipment while the Offgas building does not.

The USAR does discuss the combustible gas threats in the Offgas building and the system features addressing them. However, these considerations are addressing these concerns from an economic and good engineering practice perspective.

As stated in UFSAR Section 9A.4.13.3:

"The objective of preventing a fire in the offgas building from affecting safe plant shutdown is achieved. This is accomplished by the absence of safe shutdown equipment in this building and adjacent buildings, provision of early warning fire detection and a manually actuated deluge system in the charcoal filters."

Therefore, the system level intended function for the Offgas Building ventilation system described below is not applicable to the Offgas Building:

Prevent the accumulation of combustible gas in the Offgas Building. [10 CFR 54.4(a)(1),

(a)(3) - FP]

Although there was engineering considerations in the design for hydrogen leakage into the building, no licensing credit (10CFR 54.4 (a)(3)) is taken for operation of the Offgas Building Ventilation System for preventing a hydrogen combustion event or fire. As described in LRA Section 2.3.3.41 the only credit for mitigating a hydrogen combustion event or fire is the isolation of system fire dampers to prevent the spread of fires.

Condition Report (CR) 2024-06374 was written to identify an inaccuracy in the second paragraph of UFSAR Section 9A.4.13.1. The incorrect statement quoted above under the Issue description says:

The ventilation system for the offgas building consists of supply plenums and supply fans blowing cooled outdoor air to various areas."

Referring to boundary Drawing 912-0622, the Offgas building ventilation does not contain a supply fan blowing cooled outdoor air into the building. Instead, the Offgas ventilation system draws air from the Turbine Building and Turbine Power Complex as shown on the scoping drawing. This incorrect information has no bearing on the basis for the conclusion in Section UFSAR 9A.4.13.3, which does not rely on the ventilation system as described above.

There are no LRA changes associated with this RAI response.

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 6 Page 4 of 4 References UFSAR Section 9A.4.13, Revision 23 (ML23303A133)

Attachments None

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 7 Page 1 of 13 LRA Section: Section A.1.8, Table A.3 and Section B.2.8 LRA Page Number(s): A-15, A-63 and B-33-B36

Reference:

NCSG-RAI-10233-R1 Description of Change: Section A.1.8, B.2.8 and Table A.3 are revised to address the response to NCSG RAI-10233-R1.

PNPP LRA Section A.1.8, as modified by PNPP LRA Supplement 2 (Vistra Letter L-24-020),

Page A-15 is revised as follows:

A.1.8 BURIED AND UNDERGROUND PIPING AND TANKS PROGRAM The Buried and Underground Piping and Tanks Program is an existing condition monitoring program that manages the aging effects associated with the external surfaces of buried and underground piping and tanks such as loss of material, cracking, and changes in material properties (for cementitious piping).

The program also manages aging through actions that include protective coatings, backfill quality, and cathodic protection as preventive measures to mitigate corrosion. The number of inspections is based on the effectiveness of the preventive and mitigative actions.

Annual cathodic protection surveys are conducted. The acceptance criteria for the effectiveness of the cathodic protection is less than or equal to -850 mV. Loss of material rates for those test wells with alternate acceptance criteria are measured.

Visual inspection of stainless steel piping for cracking will be performed when the surface is exposed.

Inspections are conducted by qualified individuals. Sample sizes of exposed piping examined are increased when the depth or extent of degradation of base metal could result in loss of pressure boundary function when extrapolated to the end of the period of extended operation.

Directed inspections are conducted during each 10-year period beginning 10 years prior to commencing the period of extended operation. The first inspection will be completed no later than six months prior to the period of extended operation.

The program will be enhanced as follows:

Coating inspectors who evaluate the type and extent of coating degradation will be certified to one of the following:

1. National Association of Corrosion Engineers (NACE) Coating Inspector Level II or III

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 7 Page 2 of 13

2. An individual who has completed both the Electric Power Research Institute (EPRI) Comprehensive Coatings Course and the EPRI Buried Pipe Condition Assessment and Repair Computer Based Training (CBT) Course, or

3. An American Society for Testing and Materials (ASTM) coating specialist qualified through an ASTM Standard endorsed by Regulatory Guide (RG) 1.54 Rev. 2.

Where damage to the coating has been evaluated as significant and the damage was caused by nonconforming backfill, an extent of condition evaluation will be conducted to determine the extent of degraded backfill in the vicinity of the observed damage.

If coated or uncoated metallic piping or tanks show evidence of corrosion, the remaining wall thickness in the affected area is determined to ensure that the minimum wall thickness is maintained. This may include different values for large area minimum wall thickness, and local area wall thickness. If the wall thickness is extrapolated to the end of the period of extended operation meets minimum wall thickness requirements, recommendations for expansion of sample size is not required.

Where the coatings, backfill, or the condition of exposed piping does not meet acceptance criteria, the degraded condition is repaired or the affected component is replaced. In addition, where the depth or extent of degradation of the base metal could have resulted in a loss or pressure boundary function when the loss of material is extrapolated to the end of the period of extended operation, an expansion of sample size shall be implemented as prescribed by LR-ISG-2015-01.

Sources of leakage detected during pressure tests are identified and corrected.

When using the option of monitoring the activity of a jockey pump instead of inspecting buried fire water system piping, and unexplained changes in jockey pump activity (or equivalent equipment or parameter) are observed, a flow test or system leak rate test is conducted by the end of the next refueling outage or as directed by the current licensing basis, whichever is shorter.

Visual inspection of stainless steel piping for cracking will be performed when the surface is exposed.

For steel piping cathodic protection, the acceptable Instant OFF criteria is greater than or equal to -850 mV with a maximum of -1200 mV.

Alternatively, for steel piping cathodic protection, the acceptable Capacitive Shift criteria will be at least 100 mV from the Corrosion Potential. If this alternative acceptance criteria is implemented then:

Additional confirmatory testing will be performed to validate acceptable external loss of material rate, and subsequently confirmed every 2 years thereafter. The impact of significant site features such as shielding due to large objects in the vicinity of the protected pipe and local soil conditions will be factored into placement of the electrical resistance corrosion rate probes and use of probe data.

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 7 Page 3 of 13 Where it is determined electrical resistance corrosion rate probes are required, the location and use of the probes will be determined by a NACE Level CP4 Cathodic Protection Specialist.

Unacceptable cathodic protection survey results are entered into the plant corrective action program.

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

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 7 Page 4 of 13 Table A.3, (As modified by PNPP LRA Supplement 2 (Vistra Letter L-24-020), Page A-63 is revised as follows:

NOTE: Only a portion of Table A.3, Item No. 8 is affected. The remainder of the table is unchanged. Changes made to Table A.3 via previous application supplements are shown in this attachment for consistency.

Table A.3 License Renewal Commitments Item No.

AMP Commitment Implementation Schedule Related LRA Sections 8

XI.M41 Complete the following enhancements to the existing Buried and Underground Piping and Tanks Program:

1. The program will be enhanced as follows:

Coating inspectors who evaluate the type and extent of coating degradation will be certified to one of the following:

1. National Association of Corrosion Engineers (NACE) Coating Inspector Level II or III.

2. An individual who has completed both the EPRI Comprehensive Coatings Course and the EPRI Buried Pipe Condition Assessment and Repair Computer Based Training (CBT)

May 8, 2026 A.1.8 B.2.8

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 7 Page 5 of 13 Item No.

AMP Commitment Implementation Schedule Related LRA Sections Course.

3. An ASTM coating specialist qualified through an ASTM Standard endorsed by RG 1.54 Rev. 2.

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 7 Page 6 of 13 Item No.

AMP Commitment Implementation Schedule Related LRA Sections 8

(Cont)

Where damage to the coating has been evaluated as significant and the damage was caused by nonconforming backfill, an extent of condition evaluation will be conducted to determine the extent of degraded backfill in the vicinity of the observed damage.

If coated or uncoated metallic piping or tanks show evidence of corrosion, the remaining wall thickness in the affected area is determined to ensure that the minimum wall thickness is maintained. This may include different values for large area minimum wall thickness and local area wall thickness. If the wall thickness extrapolated to the end of the period of extended operation meets minimum wall thickness requirements, recommendations for expansion of sample size is not required.

Where the coatings, backfill, or the condition of exposed piping does not meet acceptance criteria, the degraded condition is repaired or the affected component is replaced. In addition, where the depth or extent of degradation of the base metal could have resulted in a loss of pressure boundary function when the loss of material is extrapolated to the end of the period

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 7 Page 7 of 13 Item No.

AMP Commitment Implementation Schedule Related LRA Sections 8

(Cont) of extended, operation, an expansion of sample size shall be implemented as prescribed by LR-ISG-2015-01.

Sources of leakage detected during pressure tests are identified and corrected.

When using the option of monitoring the activity of a jockey pump instead of inspecting buried fire water system piping, and unexplained changes in jockey pump activity (or equivalent equipment or parameter) are observed, a flow test or system leak rate test is conducted by the end of the next refueling outage or as directed by the current licensing basis, whichever is shorter.

Visual inspection of stainless steel piping for cracking will be performed when the surface is exposed.

For steel piping cathodic protection, the acceptable Instant OFF criteria is greater than or equal to -850 mV with a maximum of -1200 mV.

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 7 Page 8 of 13 Item No.

AMP Commitment Implementation Schedule Related LRA Sections 8

(Cont)

Alternatively, for steel piping cathodic protection, the acceptable Capacitive Shift criteria will be at least 100 mV from the Corrosion Potential. If this alternative acceptance criteria is implemented, then; Additional confirmatory testing will be performed to validate acceptable external loss of material rate, and subsequently confirmed every 2 years thereafter. The impact of significant site features such as shielding due to large objects in the vicinity of the protected pipe and local soil conditions will be factored into placement of the electrical resistance corrosion rate probes and use of probe data. Where it is determined electrical resistance corrosion rate probes are required, the location and use of the probes will be determined by a NACE Level CP4 Cathodic Protection Specialist.

Unacceptable cathodic protection survey results are entered into the plant corrective action program.

9 XI.M6 Continue the existing BWR Control Rod Drive Return Line Nozzle Program Ongoing A.1.9 B.2.9 10 XI.M5 Continue the existing BWR Feedwater Nozzle Program Ongoing A.1.10 B.2.10

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 7 Page 9 of 13 PNPP LRA Section B.2.8, as modified by PNPP LRA Supplement 2 (Vistra Letter L 020), Page B-33 through B-36 is revised as follows:

B.2.8 BURIED AND UNDERGROUND PIPING AND TANKS PROGRAM Program Description The Buried and Underground Piping and Tanks Program is an existing condition monitoring program that manages the loss of material, cracking, and changes in material properties of external surfaces of piping and tanks exposed to a buried environment.

The program also manages the aging of the external surfaces of underground piping.

The program includes protective coatings for buried piping and tanks, backfill quality, and cathodic protection as preventive measures to mitigate corrosion.

The program includes visual inspections of the pipe or tank from the exterior as permitted by opportunistic or directed excavations. If damage to the protective coatings is found and the piping surface is exposed, the pipe will be inspected for loss of material due to general, pitting, crevice, or microbiologically influenced corrosion. If corrosion has occurred, the wall thickness will be determined. Additionally, stainless steel piping will be visually inspected for cracking.

Annual ground potential surveys of the cathodic protection system are conducted to assess the effectiveness of the cathodic protection system.

Preventive measures are in accordance with standard industry practice for maintaining external coatings, wrappings, and cathodic protection.

Directed inspections of buried and underground piping are consistent with LR-ISG-2015-01 Table XI.M41-1 and its accompanying footnotes.

Directed inspections of buried tanks are also consistent with LR-ISG-2015-01 Table XI.M41-1 and its accompanying footnotes. The Fuel Oil Storage Tanks A and B, and the HPCS Fuel Oil Storage Tank are within the scope of buried tanks.

The activity of the jockey fire pump or equivalent parameter is monitored on at least a monthly interval. When unexplained changes in jockey pump activity are observed, a flow test will be conducted by the end of the next refueling outage.

Degradation or leakage found during inspections is entered into the Corrective Action Program to ensure evaluations are performed and appropriate corrective actions are taken. If adverse indications are detected, additional inspections will be performed in order to provide reasonable assurance of the integrity of the piping and tanks. The selection of components to be examined will be based on previous examination results, trending, risk ranking, and areas of cathodic protection failures or gaps, if applicable.

Additional sampling continues until reasonable assurance of intended function of the subject components is provided.

Directed inspections are conducted during each 10-year period beginning 10 years prior to the period of extended operation and continued through the period of extended operation.

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 7 Page 10 of 13 NUREG-1801 Consistency The Buried and Underground Piping and Tanks 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.M41 Buried and Underground Piping and Tanks, and revised by LR-ISG-2015-01 with the following exception.

Exceptions to NUREG-1801 The condensate transfer and storage system stainless steel buried piping is not coated as recommended in NUREG-1801 revised by LR-ISG-2015-01. Program Elements Affected:

Preventive Actions (Element 2)

Justification for Exception The condensate transfer and storage system stainless steel buried piping was installed during the initial construction of PNPP. At that time, coating of buried stainless steel piping was not considered to be required The buried condensate transfer and storage system stainless steel piping is installed at an elevation well above the normal site groundwater elevation. EPRI's mechanical tools indicates that SCC of stainless steels exposed to atmospheric conditions and contaminants is considered plausible only if the material temperature is above 140°F. In general, SCC very rarely occurs in austenitic stainless steels below 140°F. Since the condensate transfer and storage system operating temperatures are below 140°F, the likelihood of SCC occurring in this buried stainless steel piping is very low. Recent operating experience indicates that cracking can occur in uncoated buried stainless steel piping. As discussed in the program enhancements the buried stainless steel piping will be visually inspected for cracking.

Enhancements The program will be enhanced as follows:

Coating inspectors who evaluate the type and extent of coating degradation will be certified to one of the following: Program Element Affected:

Parameters Monitored/Inspected (Element 3)

1. National Association of Corrosion Engineers (NACE) Coating Inspector Level II or III

2. An individual who has completed both the Electric Power Research Institute (EPRI) Comprehensive Coatings Course and the EPRI Buried Pipe Condition Assessment and Repair Computer Based Training (CBT) Course.

3. An American Society for Testing and Materials (ASTM) coating specialist qualified through an ASTM Standard endorsed by Regulatory Guide (RG) 1.54 Rev. 2.

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 7 Page 11 of 13

Where damage to the coating has been evaluated as significant and the damage was caused by nonconforming backfill, an extent of condition evaluation will be conducted to determine the extent of degraded backfill in the vicinity of the observed damage. Program Elements Affected:

Acceptance Criteria (Element 6)

If coated or uncoated metallic piping or tanks show evidence of corrosion, the remaining wall thickness in the affected area is determined to ensure that the minimum wall thickness is maintained. This may include different values for large area minimum wall thickness, and local area wall thickness.

If the wall thickness is extrapolated to the end of the period of extended operation meets minimum wall thickness requirements, recommendations for expansion of sample size is not required. Program Elements Affected:

Acceptance Criteria (Element 6)

Where the coatings, backfill, or the condition of exposed piping does not meet acceptance criteria, the degraded condition is repaired or the affected component is replaced. In addition, where the depth or extent of degradation of the base metal could have resulted in a loss or pressure boundary function when the loss of material is extrapolated to the end of the period of extended operation, an expansion of sample size shall be implemented as prescribed by LR-ISG-2015-01. Program Elements Affected: Acceptance Criteria (Element 6)

Sources of leakage detected during pressure tests are identified and corrected. Program Elements Affected: Parameters Monitored/Inspected (Element 3)

When using the option of monitoring the activity of a jockey pump instead of inspecting buried fire water system piping, and unexplained changes in jockey pump activity (or equivalent equipment or parameter) are observed, a flow test or system leak rate test is conducted by the end of the next refueling outage or as directed by the current licensing basis, whichever is shorter. Program Elements Affected: Detection of Aging Effects (Element 4)

Visual inspection of stainless steel piping for cracking will be performed when the surface is exposed. Program Elements Affected: Detection of Aging Effects (Element 4)

For steel piping cathodic protection, the acceptable Instant OFF criteria is greater than or equal to -850 mV with a maximum of -1200 mV. Program Elements Affected: Acceptance Criteria (Element 6)

Alternatively, for steel piping cathodic protection, the acceptable Capacitive Shift criteria will be at least 100 mV from the Corrosion Potential. If this alternative acceptance criteria is implemented then:

Additional confirmatory testing will be performed to validate acceptable external loss of material rate, and subsequently confirmed every 2 years thereafter. The impact of significant site features such as shielding due to large objects in the vicinity of the protected pipe and local soil conditions will be factored into placement of the electrical resistance corrosion rate probes and use of probe data. Where it is determined electrical resistance

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 7 Page 12 of 13 corrosion rate probes are required, the location and use of the probes will be determined by a NACE Level CP4, Cathodic Protection Specialist.

Program Elements Affected: Acceptance Criteria (Element 6)

Unacceptable cathodic protection survey results are entered into the plant corrective action program. Program Elements Affected: Acceptance Criteria (Element 6)

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

Operating Experience The following operating experience review provides objective evidence that the Buried and Underground Piping 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.

The review process of plant-specific and industry operating experience since 2013 has been documented. A thorough search of plant Corrective Action Program documents and industry OE found few instances of operating experience related to cathodic protection, jockey pump cycling, or underground leaks. The industry experience is bounded by the guidance of NUREG-1801. All plant specific instances were promptly corrected through the Corrective Action Program.

A work order completed in June 2013 (Refuel Outage 14) internally inspected, by remote camera, Emergency Service Water piping. No evidence of leaking through wall was found, In June 2014 a Condition Report (CR) documented a water leak south of fire hydrant 37. The leak was isolated, 8 PVC pipe and Hydrant 37 were replaced, MIC inspection found no evidence of MIC. Coating applied to flanges and fasteners.

Post maintenance testing was completed successfully.

In January 2020 a CR documented the fire service jockey pump was cycling on too frequently. Fire Jockey pump off time of 7 minutes is less than the minimum expected off time of 10 minutes. Found the motor fire pump discharge check valve was leaking by. Replaced the valve.

In October 2020 a CR documented a sink hole forming. A P54 fire water leak was suspected. Excavation found the leak to be from construction bathroom piping. Replaced section of pipe. Backfilled the excavation.

Cathodic protection has been found to be ineffective for buried piping by not meeting the acceptance criteria of at least 80 percent effective for 10 years prior to the period of extended operation.

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 7 Page 13 of 13 The regularly scheduled underground and buried piping and tanks inspections identified no significant instances of aging mechanisms.

In November 2013 a CR documented Condensate Transfer & Storage (P11) pipe coating to be degraded and disbonded during a planned excavation.

Inspection and testing of P11 and Emergency Service Water (P45) piping found that the coating on the 4 P11 piping came off with the dirt and sand, about 5 of piping outside the area of interest. Some general pitting and corrosion was observed and removed. Wall thickness was evaluated, and the piping was approved for continued operation. Post maintenance testing was completed successfully.

Operating experience demonstrates that the Buried and Underground Piping and Tanks Program effectively manages loss of material, cracking, and changes in material properties of external surfaces of piping and tanks exposed to a buried environment.

Conclusion The Buried and Underground Piping and Tanks Program, with enhancement, will provide reasonable assurance that aging effects will be managed such that applicable components will continue to perform their intended functions consistent with the current licensing basis for the period of extended operation.

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 8 Page 1 of 7 LRA Section: Table 3.3.2-44 and Notes for Table 3.3.2-1 through 3.3.2-63 LRA Page Number(s): 3.3-391 and 3.3-464 through 3.3-468

References:

NCSG-RAI-10255-R1, L-24-020, L-24-110 Description of Change: Table 3.3.2-44 and Notes for Table 3.3.2-1 through 3.3.2-63 are revised to:

Add description in the form of a plant specific note identifying more specifically the material represented by Polymer in LRA Table 3.3.2-44 Remove NUREG-1801 alignment and Standard note for rows where an environment is not in NUREG-1801 for a component and material combination.

Self reported change (voluntary and not part of the RAI): Row 5 in Table 3.3.2-44 was mistakenly changed to Standard Note B in supplement 2 reference letter L-24-020 and shown correctly in the Annual Update L-24-110. It is shown as a change here for NRC records.

Note: Prior changes to LRA Table 3.3.2-44 and notes for chapter tables made by PNPP Licensing letters L-24-020 and L-24-110 are included but not shown as a change here.

PNPP LRA Table 3.3.2-44, (as modified by PNPP LRA Supplement 2 (Vistra Letter L-24-020) and the PNPP LRA Annual Update (Vistra letter L-24-110)), Page 3.3-391 is revised as follows:

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 8 Page 2 of 7 Table 3.3.2-44 Auxiliary Systems - Plant Foundation Underdrain and Electrical Manholes Dewatering Summary of Aging Management Evaluation Table 3.3.2 Plant Foundation Underdrain and Electrical Manholes Dewatering Systems Row Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Program NUREG-1801 Item Table 1 Item Notes 1

Bolting Pressure boundary Steel Soil (Ext)

Loss of material Buried and Underground Piping and Tanks VII.I.AP-241 3.3.1-109 B

2 Bolting Pressure boundary Steel Soil (Ext)

Loss of preload Bolting Integrity VII.I.AP-242 3.3.1-14 B

3 Piping Leakage boundary Polymers Air -

indoor, uncontroll ed (Ext)

None None VII.J.AP-268 3.3.1-119 A, 343 4

Piping Leakage boundary Polymers Raw water (Int)

None None N/A N/A G, 343 5

Piping Pressure boundary Steel Raw water (Int)

Loss of material Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components VII.C1.A-408 (LR-ISG-2012-02) 3.3.1-134 A

6 Piping Pressure boundary Steel Soil (Ext)

Loss of material Buried and Underground Piping and Tanks VII.C1.AP-198 3.3.1-106 B

7 Valve Body Leakage Boundary Polymers Air -

indoor, uncontroll ed (Ext)

None None VII.J.AP-268 3.3.1-119 A, 343 8

Valve Body Leakage Boundary Polymers Raw water (Int)

None None N/A N/A G, 343

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 8 Page 3 of 7 PNPP LRA Notes for Table 3.3.2-1 through 3.3.2-63, Pages 3.3-464 through 3.3-468, is revised as follows:

Notes for Table 3.3.2-1 through Table 3.3.2-63 Standard Notes A

Consistent with NUREG-1801 item for component, material, environment and aging effect. AMP is consistent with NUREG-1801 AMP.

B Consistent with NUREG-1801 item for component, material, environment and aging effect. AMP takes some exceptions to NUREG-1801 AMP.

C Component is different, but consistent with NUREG-1801 item for material, environment and aging effect. AMP is consistent with NUREG-1801 AMP.

D Component is different, but consistent with NUREG-1801 item for material, environment and aging effect. AMP takes some exceptions to NUREG-1801 AMP.

E Consistent with NUREG-1801 item for material, environment and aging effect, but a different aging management program is credited or NUREG-1801 identifies a plant-specific aging management program.

F Material not in NUREG-1801 for this component.

G Environment not in NUREG-1801 for this component and material.

H Aging effect not in NUREG-1801 for this component, material, and environment combination.

I Aging effect in NUREG-1801 for this component, material and environment combination is not applicable.

J Neither the component nor the material and environment combination are evaluated in NUREG-1801.

Plant-Specific Notes 301 Sodium pentaborate solution is a subset of treated water that results in similar aging effects for steel components.

Steel piping exposed to sodium pentaborate when system is tested, drained, or are tank overflow lines. Lines are typically drained.

302 LR-ISG-2013-01 did not add NUREG-1801 rows for loss of material in fuel oil. However, the XI.M42 program includes acceptance criteria which supports management of loss of material in the metallic substrate in closed-cycle cooling water, raw water, treated water, treated borated water, waste water, fuel oil, and lubricating oil. This loss of material of the metallic substrate exposed to fuel oil is also managed under the Fuel Oil Chemistry and the One-Time Inspection programs.

303 Aging evaluation of glass with an internal environment of air is equivalent to the aging evaluation of glass with an external environment of indoor air.

304 Aging of the diesel fire pump jacket water HX is managed by the Fire Water System program.

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 8 Page 4 of 7 Plant-Specific Notes (Continued) 305 The Service Water supply to the Alternate Decay Heat Removal system is normally drained and blown dry. Internal and external environments are air.

306 Closed-cycle cooling water is considered a subset of Treated water for this GALL comparison. Erosion identified by site OE in this system is managed by the Flow-Accelerated Corrosion program.

307 Components provide only structural support, and are isolated, with internal environment of air. Internal aging effects are expected to be similar to those visible externally.

308 Condensation environment is considered to be equivalent to Air - outdoor (external) for Loss of preload aging management comparison.

309 The Compressed Air Monitoring program provides assurance that the quality of the "Air - dry" environment supports the conclusion that no aging effects are expected.

310 Based on plant operating experience, there are no aging effects requiring management for the polymeric (Acrylite)

Fire Protection water sight glasses. These polymers are not expected to experience aging effects unless exposed to elevated temperatures or radiation levels capable of attacking the specific chemical composition. The sight glass is not PVC, but is a transparent polymer (Acrylite, a thermoplastic treated similar to PVC). These components are exposed to indoor air externally, and to condensation or fire water internally. These environments do not include elevated temperatures or radiation levels. Therefore, there are no applicable aging effects.

311 Internal Environment of the exhaust side CS - Relief Valve body parts is Air-Uncontrolled. External surface is the same or more severe environment. So monitoring the external surfaces will be indicative of internal CS parts.

312 Galvanic Corrosion mechanism results since susceptibility assumes a more cathodic metal is connected to the piping system.

313 Only small portion of Potable water system has an internal lining. A part of this pipe section is in the Control Complex is treated as a separate component.

314 This piping section of pipe is connected to discharge flapper valve (0P64F0511) and encased in concrete. Internal surface of the valve is representative of the piping condition.

315 Visual inspection of bolts securing discharge flapper valve (0P64F0511) is needed since leakage is not expected in a normally depressurized pipe. This valve prevents backflow into Diesel Generator Buildings in the event of flooding.

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 8 Page 5 of 7 Plant-Specific Notes (Continued) 316 The 2 inch vent pipes on top of the Oil Interceptor Tank 0P64A0001 are exposed to soil and are included with piping in this AMP line item.

317 This component is PY-0P64F0511 and the attached piping up to the concrete Sludge Holding Sump.

318 External surface of vent pipes or intake filter housing is the same or more severe environment. So, monitoring the external surfaces will be indicative of internal surface.

319 Thermocouples in Reactor Recirculation System are installed in Nuclear Closed Cooling System piping.

320 Spray Header is normally below water level in the upper pools. When pools are drained down for refueling they are exposed to air indoors.

321 Liquid Radwaste is a waste water system and it has no downstream components in the scope of License Renewal. The program selected will manage loss of material due to corrosion.

322 Roof Drains are gray cast iron body in outdoor air and is treated as steel and managed by external surfaces program.

Selective leaching is not expected in an outdoor air environment. Moist air or condensation (Internal) is considered equivalent to Outdoor air.

323 In addition to the Chapter XI.M36, "External Surfaces Monitoring of Mechanical Components", additional testing, inspections, and reporting to be performed per Commitment L01090.

324 Bolting Integrity Program is enhanced to perform visual inspection of submerged bolting for ESW/ESW Screenwash pumps, diesel/motor fire pumps, Suppression Pool Suction Strainer, and Spent Fuel Rack Grid Structure for loss of material and loss of preload.

325 Although buried piping and tanks have special coatings or wrappings, no credit for mitigating aging effects are taken, and in this case, the material of steel is considered equivalent for comparison to NUREG-1801 table 2 Items.

326 The component is located within HVAC ducting and components, and the external surfaces of this component are subject to the internal HVAC environment during normal operation. The Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components program performs visual inspections which are capable of identifying aging mechanisms which cause reduction of heat transfer.

327 Represents miscellaneous floor drains, equipment drain pans, and funnels with leakage boundary intended function highlighted on system boundary drawings.

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 8 Page 6 of 7 Plant-Specific Notes (Continued) 328 In this section of stainless steel piping, the vast majority is below the threshold temperature for cracking due to SSC/IGSCC. The smaller amount up to the automatic vent valves are greater than the threshold temperatures.

329 Emergency Closed Cooling Pump Area fans do not normally operate, and chilled water does not bypass the coils.

Chilled water in NSR area coolers and SR plenums may bypass the coils based upon exit temperature, but are conservatively assumed to experience condensation. Reduction in heat transfer is assumed due to fouling from debris or corrosion, which can be detected by visual inspection.

330 This bolting attaches the external, fire pump inlet strainer elements to the suction bowls. Loss of preload is not applicable aging effect since this is not a joint and would not fail its intended function.

331 Ductile Iron is considered the same as Gray Cast Iron for assignment of aging effects and AMPs which is consistent with NUREG-2191 (GALL-SLR).

332 External surface of elastomers in ventilation system duct and flexible connections is the same as the internal environment. So, monitoring the external surfaces will be indicative of internal surface. In addition to the Chapter XI.M36, "External Surfaces Monitoring of Mechanical Components", additional testing, inspections, and reporting to be performed per Commitment L01090.

333 Per definitions in NUREG-1801,Section IX, Condensation is considered Raw Water.

334 Surfaces are not exposed to prolonged wetting other than humidity. Per EPRI Report 1010639, Non-Class 1 Mechanical Implementation Guideline and Mechanical Tools, Revision 4, Appendix E, Section 3.5, "Zinc is used (as a coating) because of its corrosion resistance in an external environment and because it provides galvanic protection of the base metal where discontinuities or damage of the coating has occurred." In this case, the valve body base material is zinc and not steel. In an air-dry and air-indoor, uncontrolled environments, Zinc is resistant to corrosion and similar to galvanized steel.

335 Aging effect is per EPRI Report 1010639, Non-Class 1 Mechanical Implementation Guideline and Mechanical Tools, Revision 4, Appendix G, Table 6-7. The assigned program is capable of detecting the aging effect.

336 Aging effect is per EPRI Report 1010639, Non-Class 1 Mechanical Implementation Guideline and Mechanical Tools, Revision 4, Appendix C, Table 4-2 with potential for water pooling assumed. The assigned inspection program is capable of detecting the aging effect and fuel oil chemistry program is preventative by ensuring water is removed.

337 Fatigue is a TLAA. See LRA Section 3.3.2.3 for further evaluation.

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 8 Page 7 of 7 Plant-Specific Notes (Continued) 338 Surfaces are not exposed to prolonged wetting other than humidity. Per EPRI Report 1010639, Non-Class 1 Mechanical Implementation Guideline and Mechanical Tools, Revision 4, Appendix E, Section 3.5, "Zinc is used (as a coating) because of its corrosion resistance in an external environment and because it provides galvanic protection of the base metal where discontinuities or damage of the coating has occurred." In this case, the valve body base material is zinc and not steel. In an air-dry and air-indoor, uncontrolled environments, Zinc is resistant to corrosion and similar to galvanized steel in either environment. The Compressed Air Monitoring program provides assurance that the quality of the "Air - dry" environment supports the conclusion that no aging effects are expected.

339 The component type is the glass sight glass in Level gauge installed for local indication of the water level in the Nuclear Closed Cooling Water Surge Tank. The steel parts are included in the component type Bolting and Piping.

340 Table IX.C of NUREG-1801, Rev 2 groups Gray Cast Iron and ductile iron under the broad term of "Steel". For the purpose of applying the aging effect of flow blockage, the material type is considered equivalent to Steel.

341 Volume 1 of NUREG-2191 includes flow blockage due to fouling for fiberglass piping and piping components exposed to raw water due to potential intrusion of fouling products in Raw water systems and managed by the Fire Water System program.

342 Flow Blockage of the pump vertical column, suction strainer is not expected due the upstream configuration of the ESW Pumphouse Intake configuration (USAR Safety Evaluation 9.2.1.3) and the ESW Pumphouse traveling screens. See the exception taken to checking the inlet screens after every use of the pump listed in the Fire Water System AMP in LRA Section B.2.27.

343 These PVC piping and piping components are not expected to experience aging effects per Appendix A, Section 3.6.2 of the EPRI Report 1010639, Non-Class 1 Mechanical Implementation Guideline and Mechanical Tools, Revision 4, because they are not exposed to elevated temperatures above 150 degrees F, ozone, nor ultraviolet or ionizing radiation. These components are located within covered manholes that collect rainwater after sufficient rain or melting ice and snow from a significant ground accumulation. Rainwater, ice and snow that seeps past the manhole covers does not contain aggressive chemicals capable of attacking the PVC components.

PNPP is not in a coastal, saltwater area nor is it in an industrial area with heavy air pollution.

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 9 Page 1 of 3 LRA Section: Section 4.2.1 (As modified by L-24-109)

LRA Page Number(s): Pages 4.2-2 through Page 4.2-4

Reference:

SNSB RAI-10201-R1 Description of Change: The LRA section is to be revised to clarify the NRC review and approval of the RAMA fluence methodology.

PNPP LRA Section 4.2.1 (as modified by PNPP LRA Supplement 1 (Vistra Letter L-24-109)),

Page 4.2-3, is revised as follows:

4.2.1 Neutron Fluence TLAA

Description:

Neutron fluence is the term used to represent the cumulative number of neutrons per square centimeter that contact the reactor vessel shell and its internal components over a given period of time. The fluence projections that quantify the number of neutrons that contact these surfaces have been used as inputs to the neutron embrittlement analyses that evaluate the loss of fracture toughness aging effect resulting from neutron fluence.

Fluence projections were performed to predict the neutron fluence expected to occur during 32 Effective Full Power Years (EFPY) of plant operation. The 32 EFPY fluence calculations were submitted in a letter dated June 4, 2002 [Reference 4.7-2] and approved by the NRC in a letter dated April 29, 2003 [Reference 4.7-3]. At the time the projections were prepared, 32 EFPY was considered to represent the amount of power to be generated over 40 years of plant operation, assuming a 40-year average capacity factor of 80 percent. These fluence projections have been identified as TLAAs requiring evaluation for the period of extended operation.

USAR Sections 4.3.2.8 and 5.3.1.6.2 provide evaluations of the effect of neutron fluence on reactor vessel materials. These evaluations are considered to be TLAAs. BWRVIP A, BWR Reactor Pressure Vessel Inspection and Flaw Evaluation Guidelines for License Renewal, [Reference 4.7-26] identified the evaluation of the loss of reactor vessel fracture toughness due to neutron fluence as a TLAA.

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 9 Page 2 of 3 TLAA Evaluation:

EFPY projections:

End-of-life fluence is based on a projected value of EFPY over the licensed life of the plant. The full power operating license (FPOL) for PNPP Unit 1 was issued in November 1986. PNPP Unit 1 was originally licensed for a maximum thermal power of 3579 MWt.

License Amendment No. 112, issued June 1, 2000, increased the maximum thermal power to 3758 MWt through a 5% thermal power uprate. License Amendment No. 191, issued on October 8, 2020, revised the expiration date of PNPP's FPOL such that it would expire 40 years from the date of issuance of the FPOL, as opposed to 40 years from the date of issuance of the fuel loading and low-power testing license. These changes to the Operating License are included in the fluence projections.

Operating cycle 18 was completed in the spring of 2021 with the accrued effective full power years (EFPY) of 27.3, representing approximately 35 years of operation. The projected EFPY though the end of the period of extended operation using a 96 percent average capacity factor (assumes 100 percent capacity factor between refueling outages and 30-day refueling outages every 2 years) is less than 54 EFPY at end of 60 years of operation.

Fluence projections:

The fluence values provided in this section were calculated using the Radiation Analysis Modeling Application (RAMA) Fluence Methodology. RAMA was developed for the Electric Power Research Institute and the Boiling Water Reactor Vessel and Internals Project. The NRC has reviewed and approved RAMA for BWR reactor pressure vessel (RPV) fluence predictions by letters dated May 13, 2005 and February 7, 2008

[References 4.7-13 and 4.7-4]. Use of this methodology for evaluations of fluence for PNPP was performed in accordance with guidelines presented in NRC Regulatory Guide 1.190, [Reference 4.7-5]. In compliance with these guidelines, comparisons to surveillance capsule flux wire and dosimetry measurements were performed to determine the accuracy of the RPV fluence model. An uncertainty analysis was also performed to determine if a statistical bias exists in the model. It was determined that the PNPP model does not have a statistical bias and that the best-estimate fluence is suitable for use in evaluating the effects of embrittlement on RPV material as specified in 10 CFR 50 Appendix G [Reference 4.7-6] and NRC Regulatory Guide 1.99, Revision 2 [Reference 4.7-7]. Therefore, PNPP has satisfied the benchmarking guidance in the NRC SERs for the BWRVIP-114, -115, -117, and-121. [Reference 4.7-13] and for BWRVIP-145 to demonstrate the applicability of the RAMA fluence methodology to the PNPP reactor vessel and internals.

Perry Nuclear Power Plant Response to LRA NRC RAIs Set 1 L-24-207 Attachment 9 Page 3 of 3 Fast neutron fluence evaluation was performed for the RPV based on operating data through cycle 14. Fluence was calculated at EOC 14 (20.0 EFPY) and projected to 54 EFPY. In LRA Table 4.2-1, PNPP RPV Beltline Fluence Data for 54 EFPY, fast neutron fluence for energy >1.0 MeV is reported for the RPV plates, welds and nozzles throughout the RPV beltline region at the interface of the base metal and cladding, hereafter denoted as the 0t location of the RPV wall. Fluence attenuations are performed through the RPV wall to the 1/4t locations using the displacement per atom (DPA) attenuation method prescribed in NRC Regulatory Guide 1.99, Revision 2.

Fluence values that exceed the threshold value of 1.0E+17 n/cm2 for 54 EFPY define the RPV beltline for the period of extended operation. The maximum fluence value is 4.79E+18 n/cm2 for the lower-intermediate shell plate at the 0t location.

Neutron fluence analysis valid for 54 EFPY have been prepared for the reactor vessel beltline materials and bound the projected EFPY value for 60-years of operation.

Therefore, the neutron fluence analysis has been projected to the end of the period of extended operation.

Disposition: 10 CFR 54.21(c)(1)(ii)

The neutron fluence analysis has been projected to the end of the period of extended operation.