Text

License Renewal Application for the Perry Nuclear Power Plant - Responses to Request for Additional Information (RAI - Set 5)
	ML25079A062
Person / Time
Site:	Perry
Issue date:	03/20/2025
From:	Penfield R; Vistra Operations Company
To:	; Office of Nuclear Reactor Regulation, Document Control Desk
References
	L-25-042
	Download: ML25079A062 (1)
	v • d • e

L-25-042 March 20, 2025 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 1 O Center Road Perry, Ohio 44081 10 CFR 54 License Renewal Application for the Perry Nuclear Power Plant - Responses to Request for Additional Information (RAI - Set 5)

REFERENCES:

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

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

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

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

5. Letter L-24-189, from Rod L. Penfield to the Nuclear Regulatory Commission, dated August 7, 2024, submitting the Perry Nuclear Power Plant License Renewal Application Revision 0, Supplement 1 (Non-Proprietary) (ADAMS Accession No. ML24220A270) 6555 SIE:RRA DRIVE IFNING, TEXAS 15039 D 214~812-4600 v1srnACOR P COM

Perry Nuclear Power Plant L-25-042 Page 2 of 4

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

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

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

9. Letter L-24-179, from Rod L. Penfield to the Nuclear Regulatory Commission, dated October 21, 2024, submitting the Perry Nuclear Power Plant License Renewal Application Revision 0, Supplement 5 (ADAMS Accession No. ML24295A352)

10. Letter L-24-243 from Rod L. Penfield to the Nuclear Regulatory Commission, dated November 7, 2024, submitting the Perry Nuclear Power Plant License Renewal Application Revision 0, Supplement 6 (ADAMS Accession No. ML24312A368)

11. Letter L-24-256 from Rod L. Penfield to the Nuclear Regulatory Commission, dated December 19, 2024, submitting the Perry Nuclear Power Plant License Renewal Application Revision 0, Supplement 7 (ADAMS Accession No. ML24354A265)

12. Letter L-25-013 from Rod L. Penfield to the Nuclear Regulatory Commission, dated January 27, 2025, submitting the Perry Nuclear Power Plant License Renewal Application Revision 0, Supplement 8 (ADAMS Accession No. ML25027A327)

13. Letter L-24-207, from Rod L. Penfield to the Nuclear Regulatory Commission, dated September 16, 2024, submitting the License Renewal Application for the Perry Nuclear Power Plant - Response to Request for Additional Information - Set 1 (ADAMS Accession No. ML24260A266)

14. Letter L-24-208, from Rod L. Penfield to the Nuclear Regulatory Commission, dated October 2, 2024, submitting the License Renewal Application for the Perry Nuclear Power Plant -

Response to Request for Additional Information - Set 2 (ADAMS Accession No. ML24276A083)

15. Letter L-24-209, from Rod L. Penfield to the Nuclear Regulatory Commission, dated November 19, 2024, submitting the License Renewal Application for the Perry Nuclear Power Plant - Response to Request for Additional Information - Set 3 (ADAMS Accession No. ML24324A185)

16. Letter L-25-012, from Rod L. Penfield to the Nuclear Regulatory Commission, dated February 5, 2024, submitting the License Renewal Application for the Perry Nuclear Power Plant

- Response to Request for Additional Information - Set 4 (ADAMS Accession No. ML25036A154)

17. Letter L-24-226, from Rod L. Penfield to the Nuclear Regulatory Commission, dated October 31, 2024, submitting the License Renewal Application for the Perry Nuclear Power Plant

- Response to Requests for Confirmatory Information - Set 1 (ADAMS Accession No. ML24305A134) 6555 SIERRA DRIVE IRVING, TEXAS 75039 o 214-812-4600 VISTRACORP COM

Perry Nuclear Power Plant L-25-042 Page 3 of 4

18. Letter L-24-257, from Rod L. Penfield to the Nuclear Regulatory Commission, dated December 4, 2024, submitting the License Renewal Application for the Perry Nuclear Power Plant - Response to Requests for Confirmatory Information - Set 2 (ADAMS Accession No. ML24339A066)

19. Letter L-25-017, from Rod L. Penfield to the Nuclear Regulatory Commission, dated January 30, 2025, submitting the License Renewal Application for the Perry Nuclear Power Plant

- Response to Requests for Confirmatory Information - Set 3 (ADAMS Accession No. ML25030A014)

20. NRC Email from Vaughn Thomas to Rod Penfield - dated February 18, 2025 - Perry LRA-Requests for Additional Information - Set 5 (ADAMS Accession Nos. ML25049A246 and ML25049A247)

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

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

During the Nuclear Regulatory Commission (NRC) staff's aging management audit of the PNPP LRA (Reference 4), the PNPP Staff agreed to supplement the LRA with clarifying information which has led to several LRA supplements (References 5 through 12). In addition, as a result of the NRC's review and audit of the PNPP LRA, the NRC Staff has submitted and the PNPP Staff responded to four sets of Requests for Additional Information (RAls) (References 13 through 16) and three sets of Requests for Confirmatory Information (RCls) (References 17 through 19).

The attachments to this letter provide the responses to address the fifth set of RAls submitted by the NRC Staff on February 18, 2025 (Reference 20). For ease of reference, an index listing the RAI responses and the associated LRA updates is provided.

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.

I declare under penalty of perjury that the foregoing is true and correct. Executed on March 20, 2025.

Rod L. Penfield 6555 SIERRA DRIVE IRVING, TEXAS 75039 o 214-812-4600 VISTRACORP.COM

Perry Nuclear Power Plant L-25-042 Page 4 of 4 Attachments:

PNPP Responses to LRA NRC RAls Set 5 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 VISTRACOR P COM

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachments Index Page 1 of 3 Attachments Index for PNPP Responses to NRC RAI NCSG RAI-10505-R1 Attachment No.

RAI or LRA Update RAI Topic Applicable RAI Inquiry or LRA Section or Table Updated 1

RAI Loss of Material Due to Wear of Fiberglass Piping Question 1 Request 1 2

RAI Automatic Standpipe System Flow Tests Question 2 Request 1 Parts a, b & c 3

RAI Main Drain Tests Question 3, Request 1 4

RAI Suction Screen and Suction Strainer Question 4 Requests 1, 2, 3 & 4 5

RAI Deluge Valve Trip Tests and Pre-Action Valve Trip Tests Question 5 Requests 1, 2 6

RAI Ventilation Filter Unit Plenums Question 6 Requests 1, 2 & 3 7

RAI Mainline Strainers Question 7 Requests 1, 2, 3 & 4 8

RAI Obstruction Investigations Question 8 Request 1 9

RAI Diesel Fire Pump Heat Exchanger Question 9 Request 1 10 LRA Update Response to Question 4 (Suction Screen and Suction Strainer)

Table 3.3.1 - Item 64 Table 3.3.1 - Item 66 11 LRA Update Response to Question 4 (Suction Screen and Suction Strainer) 3.3.2.1.24 Table 3.3.2-24 12 LRA Update Various A.1.21 13 LRA Update Response to Question 4 (Suction Screen and Suction Strainer)

A.1.37

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachments Index Page 2 of 3 Attachment No.

RAI or LRA Update RAI Topic Applicable RAI Inquiry or LRA Section or Table Updated 14 LRA Update Various Table A.3 15 LRA Update Various B.2.21 16 LRA Update Response to Question 4 (Suction Screen and Suction Strainer)

B.2.37 The attachments incorporate the Perry Nuclear Power Plant LRA changes made via the LRA supplements, the annual update and the Request for Additional Information (RAI) responses, which were submitted via the following Vistra correspondence:

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

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

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

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

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

6. LRA Supplement 5 (Vistra Letter L-24-179)

7. LRA Supplement 6 (Vistra Letter L-24-243)

8. LRA Supplement 7 (Vistra Letter L-24-256)

9. LRA Supplement 8 (Vistra Letter L-25-013)

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

11. LRA Response to Request for Additional Information - Set 2 (Vistra Letter L-24-208)

12. LRA Response to Request for Additional Information - Set 3 (Vistra Letter L-24-209)

13. LRA Response to Request for Additional Information - Set 4 (Vistra Letter L-25-012)

In addition to the above supplements, the annual update and the RAI responses, the following letters provided responses to the two sets of Requests for Confirmatory Information (RCIs) received:

1. LRA Response to Requests for Confirmatory Information - Set 1 (Vistra Letter L-24-226)

2. LRA Response to Requests for Confirmatory Information - Set 2 (Vistra Letter L-24-257)

3. LRA Response to Requests for Confirmatory Information - Set 3 (Vistra Letter L-25-017)

Therefore, the LRA updates depicted in the attachments 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 the LRA supplements and the annual update, changes for the attachments are indicated by red, bolded and underlined text for added text and strikethrough for text to be deleted.

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachments Index Page 3 of 3 Note that text editing changes to some of the attachments such as spacing, font consistency changes etc., are not indicated via coloring as these are inconsequential.

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 1 Page 1 of 3 NCSG RAI-10505-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 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.

Question 1 Loss of Material Due to Wear of Fiberglass Piping Background :

As supplemented by letter dated June 27, 2024 (ML24180A010), License Renewal Application (LRA) Table 3.3.2-24 states that change in mechanical properties (cracking, loss of strength),

blistering, and flow blockage for fiberglass piping exposed internally to raw water will be managed by the Fire Water System program. For flow blockage, the aging management review (AMR) item cites plant-specific note 341, which states, 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.

The staff notes that NUREG-2192, Standard Review Plan for Review of Subsequent License Renewal Applications for Nuclear Power Plants (ML17188A158), includes AMR items that address loss of material due to wear of fiberglass exposed to raw water. For example, AMR item 3.3-1, 176 (VII.C1.A-461). Table 2-6 in NUREG-2221, Technical Basis for Changes in the Subsequent License Renewal Guidance Documents NUREG-2191 and NUREG-2192 (ML17362A126), for VII.C1.A-461, indicates that loss of material due to wear from potential abrasive particles in raw water can occur for fiberglass piping.

Issue :

The LRA does not provide a technical basis for why loss of material due to wear is not an applicable aging effect for the fiberglass piping exposed internally to raw water.

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 1 Page 2 of 3 Request :

1. Please provide the technical basis for why loss of material due to wear is not an applicable aging effect for the fiberglass piping exposed internally to raw water.

PNPP Response Request :

1. Please provide the technical basis for why loss of material due to wear is not an applicable aging effect for the fiberglass piping exposed internally to raw water.

The technical bases for why loss of material due to wear is not an applicable aging effect for the fiberglass piping at PNPP is that these piping sections experience stagnant flow conditions more than 98% of the time. The key points to consider are:

1.

License Renewal methodology states that the applicable aging effects should be based upon the conditions that the material experiences the majority of the time and is consistent with the sites operating experience.

2.

The fluid in the Fiberglass pipe is stagnant more than 98% of the time and loss of material due to wear in not applicable for a system that is essentially stagnant.

3.

There is no Operating experience (OE) suggesting loss of material in the fiberglass pipe due to wear is applicable at PNPP. The lack of adverse OE is likely due to the low fluid velocities experienced even during the most onerous periodic test and other incidental uses.

Fluid flow velocities through the fiberglass pipe were determined under the highest flow conditions. This velocity was shown to be less than the speeds necessary to cause loss of material due to wear. Threshold values were determined for the potential aging effect of loss of material due to wear for fiberglass pipe with continuous fluid flow and with abrasive particles. A conservative value used to predict this aging effect is a fluid flow greater than 10 feet per second.

An evaluation of periodic testing since 2013 determined that none of the fiberglass piping at PNPP experienced a fluid velocity greater than 5.8 feet per second. Additional details of the evaluation are as follows.

The fiberglass piping in the fire protection system in scope of license renewal is limited to 3 buried segments of piping in the ring header surrounding the power block and other site buildings and structures. An evaluation of the flow velocities due to testing and other incidental uses, are much less than would be expected to cause this aging effect. The predicted loss of material due to this mechanism requires a continuous water velocity of at least 12 feet per second. As previously addressed, ten (10) feet per second was conservatively chosen for the threshold.

The 12-inch fiberglass pipe segments in the fire protection system mains (supply and ring header), experience stagnant flow for more than 98% of the time. Although continuously pressurized by a small jockey pump, this piping is considered a standby system for aging management evaluations.

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 1 Page 3 of 3 A bounding evaluation of flow rates experienced by fiberglass piping sections occurs during fire pump performance testing. These tests compare the actual pump flow with its vendor pump curve. The pump flow rate data must bound the rated design point for the pump and therefore collects data at high flow rates approaching runout conditions. The pump curve data for each fire pump is collected every 18 months. It takes an estimated 8 hours9.259259e-5 days 0.00222 hours 1.322751e-5 weeks 3.044e-6 months per pump to collect the required data. This time estimate is based upon resources estimated in the work order. The yearly average time is 5.5 hours5.787037e-5 days 0.00139 hours 8.267196e-6 weeks 1.9025e-6 months per pump. The fiberglass pipe experiences fluid flow during these tests 11 hours1.273148e-4 days 0.00306 hours 1.818783e-5 weeks 4.1855e-6 months per year. Using the maximum velocity data collected in periodic tests reviewed from 2013 to 2024, the evaluation determined an average velocity of 5.5 feet per second. PNPP concludes the fiberglass piping will experience an average 5.5 feet per second fluid velocity for 11 hours1.273148e-4 days 0.00306 hours 1.818783e-5 weeks 4.1855e-6 months per year over the period of extended operation. Other velocities are less during the very limited periods of fluid flow conditions.

The threshold velocity for a fluid causing loss of material due to wear was determined assuming sand was the abrasive particle. The raw water supply for the fire water systems is from the Emergency Service Water Pumphouse pump bay containing water from Lake Erie. The primary particles entrained in this water source is silt. Silt, because of its lower weight and density, is less abrasive than sand. Consequently, a higher predicted minimum threshold velocity would be expected for silt to cause the same loss of material.

Therefore, the technical basis for why the loss of material due to wear is not an applicable aging effect is due to the lack of the significant presence of abrasive particles, and the incidences of stagnant flow and low flow velocities for the fiberglass piping installed in the PNPP fire protection system.

Attachments None

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 2 Page 1 of 3 NCSG RAI-10505-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 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.

Question 2 Automatic Standpipe System Flow Tests

Background:

Table 4a in Appendix L of LR-ISG-2012-02, Aging Management of Internal Surfaces, Service Level III and Other Coatings, Atmospheric Storage Tanks, and Corrosion under Insulation, recommends flow tests of automatic standpipe systems in accordance with Section 6.3.1.1 of the 2011 Edition of NFPA 25. Section 6.3.1.1 of the 2011 Edition of NFPA 25 states, [a] flow test shall be conducted every 5 years at the hydraulically most remote hose connections of each zone of an automatic standpipe system to verify the water supply still provides the design pressure at the required flow.

In the letter dated December 19, 2024 (ML24354A265), the second exception in the exception table in LRA Section B.2.21 states that in lieu of flow testing at the hydraulically most remote hose connections of each zone every 5 years as specified in Section 6.3.1.1 of the 2011 Edition of NFPA 25, the applicant will perform main header flow testing in the main headers that supply the standpipe system to verify that the water supply provides the largest demand design flow plus 500 gpm [gallons per minute] for hose streams over the longest route and verifies friction losses are within values used to determine design flow at design pressure based upon the measured discharge pressure and flow of a single fire pump, will partially open hose station supply valves every 3 years to confirm no flow blockage, and will perform main drain tests on 20 percent of standpipes and risers every refueling outage (every 24 months). In addition, the applicant stated that the acceptance criteria for the main drain tests will ensure open flow and no obstructions by verifying valve operability and flow through valve and connections.

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 2 Page 2 of 3 Issue:

The second exception in the exception table in LRA Section B.2.21, as supplemented by letter dated December 19, 2024 (ML24354A265), does not appear to address how many hose stations are flow tested every 3 years, where the hose stations are located (e.g., different buildings), including whether any are considered remote.

Request:

1. In order to determine whether the alternative testing is sufficient in regard to breadth in number and breadth in locations, please address the following:

a. How many hose stations are flow tested every 3 years?

b. Where are the hose stations that are flow tested every 3 years located (e.g.,

different buildings)?

c. Are any of the hose stations that are flow tested every 3 years considered remote?

PNPP Response Request:

1. In order to determine whether the alternative testing is sufficient in regard to breadth in number and breadth in locations, please address the following:

a. How many hose stations are flow tested every 3 years?

b. Where are the hose stations that are flow tested every 3 years located (e.g.,

different buildings)?

The table provided below indicates the hose stations (and / or associated valves) tested in PTI-P54-P0038, Fire Hose Valve Operability Test, Rev 5, and that are within the scope of License Renewal. Every 3 years, this test partially opens each hose station supply valve in the buildings listed in the table below to confirm no flow blockage. All in-scope hose stations are tested under this periodic test instruction.

The buildings containing in-scope hose stations/reels are listed with the number of hoses in each building. Hose stations are installed over a range of plant floors/elevations, with many located at the top level of the buildings.

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 2 Page 3 of 3 Building No. of hose reels/cabinets

& valves tested EW-Emergency Service Water 2

AX-Auxiliary 9

CC - Control Complex 24 IB - Intermediate 24 TB - Turbine 20 OG - Off Gas 4

TP - Turbine Power Complex (U1 Cond Demin Area) 2 AB - Auxiliary Boiler 2

Yard FOPH - Fuel Oil Pumphouse Foam 2

RB - Reactor 12 WT - Waste Treatment 2

CW - Circ Water 2

Total 105 Request:

1. In order to determine whether the alternative testing is sufficient in regard to breadth in number and breadth in locations, please address the following:

c. Are any of the hose stations that are flow tested every 3 years considered remote?

Yes, the testing performed under the fire protection program addresses hose stations throughout the facility, both those in scope and out of scope of license renewal. Because all in-scope hose stations are tested per the approved program, those considered remote are inherently tested.

Attachments None

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 3 Page 1 of 2 NCSG RAI-10505-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 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.

Question 3 Main Drain Tests

Background:

Table 4a in Appendix L of LR-ISG-2012-02 recommends main drain tests for standpipe systems in accordance with Section 13.2.5 of the 2011 Edition of NFPA 25, which specifies annual main drain testing of the standpipe systems. Section 6.3.1.5 of the 2011 Edition of NFPA 25 specifies main drain testing of all standpipe systems with automatic water supplies in accordance with Chapter 13 of the 2011 Edition of NFPA 25.

In the letter dated December 19, 2024 (ML24354A265), the third exception in the exception table in LRA Section B.2.21 states that in lieu of performing annual main drain testing of all standpipe systems, the applicant will perform main drain tests of 20 percent of the standpipe systems every refueling outage (every 24 months). In addition, Enhancement 1, as supplemented by letter dated December 19, 2024 (ML24354A265), states that the Fire Water System program will be enhanced to require main drain testing of 20 percent of standpipe systems every refueling outage. The enhancement also states, [t]hese tests will occur every 10 years throughout the PEO [period of extended operation].

Issue:

Given that the main drain tests will be performed every refueling outage, it is unclear what tests will occur every 10 years throughout the PEO as indicated in Enhancement 1, as supplemented by letter dated December 19, 2024 (ML24354A265).

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 3 Page 2 of 2 Request:

1. Please clarify what tests associated with the main drain testing will occur every 10 years throughout the PEO?

PNPP Response Request:

1. Please clarify what tests associated with the main drain testing will occur every 10 years throughout the PEO?

The basis for the exception regarding Section 6.3.1.5 of NFPA 25-2011 states Main drain tests on 20 percent of the standpipes and risers every 24 months provide adequate information to determine if the condition of fire water piping is maintained consistent with design basis.

The enhancement under Standpipe and Hose Systems is referring to these tests. It states:

Program documentation will be revised, or new test instructions developed to add main drains testing of the in-scope water-based standpipes including those associated with automatic water suppression systems. Program documentation will require testing of 20% of the necessary standpipe systems every refueling outage/cycle. These tests will occur every 10 years and throughout the PEO.

The intent of the last sentence in the above paragraph is to ensure that all main drains will be tested within each 10-year period. Each 20% collection of tests will not repeat main drain tests already tested within the previous 4 collections. Hence, every 10 years, all (5 x 20% =100%) of the main drains in scope of License Renewal will be tested. Testing 20% of the drains every refueling outage/cycle provides sufficient data to identify adverse trends in the internal condition of standpipes.

Attachments None

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 4 Page 1 of 5 NCSG RAI-10505-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 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.

Question 4 Suction Screen and Suction Strainer Table 4a in Appendix L of LR-ISG-2012-02 recommends fire pump suction screen inspections in accordance with Section 8.3.3.7 of the 2011 Edition of NFPA 25, which states, After the waterflow portions of the annual test or fire protection system activations, the suction screens shall be inspected and cleared of any debris or obstructions. In the letter dated December 19, 2024 (ML24354A265), the fourth exception in the exception table in LRA Section B.2.21 states,

[d]ue to the design of the supply inlet and filtering of water from the lake to the Emergency Service Water Pumphouse Suction Bay, PNPP does not require monitoring of the suction screens on the fire pumps after the waterflow portions of the periodic tests, fire protection system activations nor during periods of unusual water supply conditions such as floods. The applicant described the design of the supply inlet, which includes traveling screens that are monitored for differential level and the high level difference is alarmed in the control room. The applicant stated that the alternative aging management activities for the traveling screens are managed by the Open-Cycle Cooling Water System program. The applicant noted that there is a basket type fire pump suction strainer and blockage of the strainer is unlikely given that the upstream traveling screen mesh size is smaller. The applicant also stated that there is no plant-specific operating experience related to flow blockage of the fire pump suction strainer.

The staff notes that LRA Table 3.3.2-22 cites AMR item 3.3.1-40 for managing loss of material of the stainless steel traveling screens by the Open-Cycle Cooling Water System program.

During the audit of the Fire Water System program, the applicant described the Open-Cycle Cooling Water System programs periodic traveling screen inspections and described inspections when the screen wash system is not functional.

In addition, the staff notes that LRA Table 3.3.2-24 cites AMR item 3.3.1-64 for managing loss of material of the copper alloy less than 15 percent zinc pump casing (suction strainer element) by the Fire Water System program. As supplemented by letter dated June 27, 2024

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 4 Page 2 of 5 (ML24180A010), the AMR item cites plant-specific note 342 that states, 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. The staff notes that it is appropriate to manage the effects of aging of the fire pump suction strainer because Item 68 in Table 2.1-5 of Revision 2 of NUREG-1800 indicates that strainers meet 10 CFR 54.21(a)(1)(i).

Issue :

The LRA does not appear to describe the Open-Cycle Cooling Water System programs periodic traveling screen inspections. The staff notes that the traveling screens could become damaged or corrode over time, which could allow debris to pass-through and reach the fire pump suction strainer. Therefore, a description of inspections that could provide insight into whether the traveling screens are allowing debris to pass-through is requested.

The LRA does not appear to address how the Fire Water System program will manage loss of material of the fire pump suction strainer, including the frequency of the aging management activities.

The LRA does not appear to address plant-specific operating experience related to flow blockage and loss of material of the traveling screens, or loss of material of the fire pump suction strainer.

Request:

Please address the following:

1. Provide the description of the Open-Cycle Cooling Water System programs periodic traveling screen inspections, including frequency.

2. Describe the aging management activities to manage loss of material of the fire pump suction strainer under the Fire Water System program, including the frequency of the aging management activities. In addition, discuss whether the aging management activities are capable of verifying flow blockage is being adequately managed.

3. Discuss any plant-specific operating experience related to flow blockage and loss of material of the traveling screens.

4. Discuss any plant-specific operating experience related to loss of material of the fire pump suction strainer.

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 4 Page 3 of 5 PNPP Response Request:

Please address the following:

1. Provide the description of the Open-Cycle Cooling Water System programs periodic traveling screen inspections, including frequency.

2. Describe the aging management activities to manage loss of material of the fire pump suction strainer under the Fire Water System program, including the frequency of the aging management activities. In addition, discuss whether the aging management activities are capable of verifying flow blockage is being adequately managed.

The Open Cycle Cooling Water System program will manage Loss of Material and flow blockage for the ESW traveling screens and the Diesel Driven and Electric Motor Driven Fire Protection Pumps inlet columns and inlet strainers. Diving activities inspect these components in the Emergency Service Water (ESW) Pumphouse suction bay below the water level. The dive operations primarily support Open Cycle Cooling Water Components and include Fire Water Pump inspections during inspection of other component in the ESW pump bay. A review of dive operation inspection reports from 2011 through 2024 revealed that inspections are effective in identifying accumulation of silt in the pumpbay and forebay, general inspection of ESW Traveling Water Screens, ESW pumps, screen wash pumps, Fire Pumps and other hardware.

See response to Question 4 subparts 3 and 4 below for further detail. Based upon the above, the Fire Water System program will be replaced with Open Cycle Cooling Water System program for the applicable component types in LRA Table 3.3.2-24, Fire Water System, and the Open Cycle Cooling Water AMP will include an enhancement to ensure program documentation reflects inspection of the fire water pumps.

The response to TRP-027-08 provided information on the 26-week periodic traveling screen inspections performed by plant personnel in the ESW Pumphouse. Response to an earlier inspection discussed the method of mussel control in the raw water system.

The maintenance plan instructions for the 26-week inspections include the following steps:

1. INSPECT screen sections for damage/wear of basket mesh and basket ends

2. INSPECT chain links for indications of wear

3. INSPECT nozzles for proper spray pattern (even distribution, free flow, (approximately) 1/2" overlap between nozzles)

4. BLOWDOWN the filter regulator

5. INSPECT debris trough for deterioration or blockage

6. DOCUMENT inspection results in the Work in Progress Log As the mesh and attached baskets move, the debris accumulated in the baskets are dumped in the debris trough. If plant personnel find degradation of the mesh or blockage in the debris trough or mesh, such a condition would be reported in the work in progress log and entered into the Corrective Action Program.

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 4 Page 4 of 5 The method of mussel control for raw water systems is cited in a site periodic procedure and includes chemical treatment that is injected at one of the intake structures in Lake Erie. For the ESW system, the chemical treatment would flow through the traveling screen baskets. It is evident that mussels killed upstream of the traveling screens would accumulate in the traveling screen baskets, requiring periodic cleaning/removal of debris. Any mussels that were growing in a traveling screen basket would be expected to be killed by the chemical treatment and removed as part of the overall treatment process. Annual diving inspections have effectively ensured the intake and discharge structures continue to control mussel contamination within acceptable limits. This minimizes the challenges stemming from biofouling.

ESW pumphouse traveling screens are referenced in the LRA description of the Open Cycle Cooling Water (OCCW) program as screens. The OCCW aging management program does not discuss the active function of the traveling screens to clear blockage. The PNPP main control room includes level differential transmitter indications and alarms that continuously monitor ESW screen conditions. The level switches start the screen wash pumps in different speeds. PNPP operations and maintenance staff periodically test the screen wash system. The purpose of these tests is to ensure the system can perform its system level function when called upon. The action of clearing blockage is an active function of the sprays and traveling baskets (rakes). These periodic tests of the active function are part of the existing program. Further, this testing demonstrates that the maintenance of the intended functions for the system piping (pressure boundary) and for the spray nozzles (directing flow) has adequate force and provides adequate coverage to clear blockage of the mesh and screens. The OCCW aging management program activities also include dive operations that inspect for loss of material of the stainless steel mesh traveling screens.

LRA Updates to OCCW program Although routinely performed, program documentation does not explicitly address Fire Pump inlet strainers as other hardware in the ESW Pumphouse Pumpbay. As such, PNPP will revise documentation for Emergency Service Water System Monitoring Program. The proposed LRA enhancements are as follows.

In LRA Appendix A, Section A.1.37 (under enhancements that will be implemented no later than six months prior to the period of extended operation), and in Item 37 of Table A.3, additional items will be provided to explicitly identify external portions of submerged components in the ESWPH (ESW pumps, ESW screenwash pumps, motor and diesel-driven fire water pumps).

Corresponding changes will also be made in LRA Appendix B, Section B.2.37.

Additionally, LRA Table 3.3.2-24 will be changed to assign the Open Cycle Cooling Water program to manage loss of material for the electric motor driven and diesel driven Pump casing (Suction strainer element), Pump casing (Suction bell) and Pump casing (Column).

These LRA changes are provided in Attachments 11, 13, 14 and 16 to this letter.

Request:

Please address the following:

3. Discuss any plant-specific operating experience related to flow blockage and

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 4 Page 5 of 5 loss of material of the traveling screens.

4. Discuss any plant-specific operating experience related to loss of material of the fire pump suction strainer.

PNPP has an Emergency Service Water System Monitoring Program that provides the requirements for an inspection program in compliance with Perry UFSAR Table 1.8-1, which documents compliance with RG 1.127, to conduct periodic surveillance of the structural, hydraulic, and foundation conditions of underwater tunnels and certain water-control structures of the ESW System.

A review of the dive reports from 2011 through 2024 reveals that among other water control structure inspections, dive operations inspect the ESW traveling water screens, support structures, and basket attachments, as well as the Diesel Driven and Electric Motor Driven Fire Protection Pumps inlet columns, supports, and inlet strainers. No degradation of stainless steel ESW Traveling Water screens, or copper alloy fire pump inlet strainers has been reported. Steel components associated with the traveling screen baskets (rakes) are described as having some level of deterioration but acceptable in the most recent dive report. Although part of the inspection activities, no debris or blockage has been reported during dive operations conducted since 2011 through 2024. Recent photos and video obtained during dive operations show that the fire pump inlet strainers and traveling water screen mesh are clear with no loss of material.

A review of operating experience for fire pump inlet strainers was conducted. Only one relevant finding in a 2011 Condition Report describes an inspection of the motor driven fire pump inlet strainer during regularly scheduled dive inspections. Dive inspections of ESW Traveling water screens occurred during the following periods: 3/2011, 8/2015, 10/2016, 9/2017, 9/2018, 12/2019, 10/2020, 12/2021-3/2022, and 4/2024. In all cases the ESW Traveling water screens were intact and clear of debris. Fire Water System Pumps were inspected in 11/2012 (only the Electric Motor Driven Fire Pump), and on 10/2020, and 4/2024. The fire pump inspections revealed that all hardware was present, and the pump inlet strainers were clear of debris and sediment buildup.

LRA Changes to OCCW program In LRA Appendix B, Section B.2.37, in the paragraph describing annual diving inspection operating experience, changes will be made to provide additional information/results of these inspections.

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

Attachments Attachments 10, 11, 13, 14 and 16 to this letter.

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 5 Page 1 of 4 NCSG RAI-10505-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 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.

Question 5 Deluge Valve Trip Tests and Pre-Action Valve Trip Tests

Background:

Table 4a in Appendix L of LR-ISG-2012-02 recommends that each deluge valve be trip tested at full flow annually in accordance with Section 13.4.3.2.2 of the 2011 Edition of NFPA 25. In the letter dated December 19, 2024 (ML24354A265), the sixth exception in the exception table in LRA Section B.2.21 states that in lieu of annually trip testing at full flow each deluge valve, the applicant will trip test at full flow open spray deluge valves every refueling outage in accordance with Section 13.4.3.2.2.3 of the 2011 Edition of NFPA 25, trip test with the supply isolation valves closed dry pipe pre-action systems with closed sprinkler heads and ventilation filter deluge spray systems with open sprays every 18 months, and the spray system protecting the Hydrogen Seal Oil System will be full flow tested every 5 years and trip tested with the supply isolation valve closed annually. The applicant stated that Any valve that fails to open is considered a failure and entered into the corrective action program to evaluate and take required corrective actions.

The staff notes that the seventh exception in the exception table in LRA Section B.2.21, as supplemented by letter dated December 19, 2024 (ML24354A265), states that the Ventilation Filter Unit Plenums cannot be tested with water and have no provisions to be tested with air.

Table 4a in Appendix L of LR-ISG-2012-02 recommends that pre-action systems be trip tested with the control valve in the full-open position every 3 years in accordance with Section 13.4.3.2.3 of the 2011 Edition of NFPA 25.

In the letter dated December 19, 2024 (ML24354A265), the eighth exception in the exception table in LRA Section B.2.21 states that in lieu of trip testing the pre-action valve with a fully open control valve every 3 years as specified in Section 13.4.3.2.3 of the 2011 Edition of NFPA 25, the applicant will trip test the pre-action valve with the isolation valves (equivalent to the control

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 5 Page 2 of 4 valve) closed every 18 months. The applicant stated that To ensure these systems will perform the intended function throughout the PEO, PNPP proposes trip testing and inspections that ensure the downstream piping is free of matter that might plug system sprinklers if the system were actuated, and goes on to discuss Enhancement 4 related to augmented inspections for piping segments that cannot be drained or piping segments that allow water to collect.

Issue :

The LRA does not address whether the Hydrogen Seal Oil System has provisions to be tested with air in accordance with Section 13.4.3.2.2.5 (A) of the 2011 Edition of NFPA 25. The LRA is unclear whether the inspections that ensure the downstream piping is free of matter that might plug system sprinklers if the system were actuated only refers to the augmented inspections for piping segments that cannot be drained or piping segments that allow water to collect, or whether it also includes internal visual inspections in accordance with Section 14.2 of the 2011 Edition of NFPA 25 (i.e., internal visual inspections every 5 years by removing a sprinkler head from the most remote branch line from the source of water or using the inspector's test valve (Section 14.2.1.5 of the 2011 Edition of NFPA 25)). The staff notes that Question 9 is related to Section 14.2 of the 2011 Edition of NFPA 25. In addition, the LRA is unclear whether downstream piping associated with the spray system protecting the Hydrogen Seal Oil System will also be inspected in accordance with Section 14.2 of the 2011 Edition of NFPA 25.

Request:

Please address the following:

1. Does the Hydrogen Seal Oil System have provisions to be tested with air in accordance with Section 13.4.3.2.2.5 (A) of the 2011 Edition of NFPA 25? If this system has provisions to be tested with air, what is the technical basis for not testing with air?

2. Will the downstream piping associated with both the dry pipe pre-action systems with closed sprinkler heads and the spray system protecting the Hydrogen Seal Oil System be visually inspected internally in accordance with Section 14.2 of the 2011 Edition of NFPA 25?

PNPP Response Request:

Please address the following:

1. Does the Hydrogen Seal Oil System have provisions to be tested with air in accordance with Section 13.4.3.2.2.5 (A) of the 2011 Edition of NFPA 25? If this system has provisions to be tested with air, what is the technical basis for not testing with air?

There are no provisions for air testing the spray system protecting the Hydrogen Seal Oil System. Regardless, the Hydrogen Seal Oil System suppression system is an open-nozzle system that is periodically flow tested under the current fire protection program. Periodic air testing would not provide different information than is obtained during flow testing.

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 5 Page 3 of 4

2. Will the downstream piping associated with both the dry pipe pre-action systems with closed sprinkler heads and the spray system protecting the Hydrogen Seal Oil System be visually inspected internally in accordance with Section 14.2 of the 2011 Edition of NFPA 25?

For clarity this question is being divided into 2 parts:

Response to Part 1:

Will the downstream piping associated with the dry pipe pre-action systems with closed sprinkler heads be visually inspected internally in accordance with Section 14.2 of the 2011 Edition of NFPA 25?

No, the dry pipe pre-action sprinkler piping will not be inspected periodically as discussed in NFPA 25 Section 14.2.1. However, prior to the PEO, the dry pipe pre-action systems in-scope of license renewal will be inspected per NFPA 25 Section 14.2.1 and as noted in Enhancement 4.

The inspection method will include those listed in NFPA 25 Section 14.2.1 by opening a flushing connection at the end of one main and by removing a sprinkler toward the end of one branch line for the purpose of inspecting for the presence of foreign organic and inorganic material. Per Enhancement 4, the areas where water may collect and not be drained will also be inspected.

Subsequent inspections will be based upon actuations of the system. Per Enhancement 4, after the inspections prior to the PEO, the program activities will monitor pre-action system actuations with the control valves fully open. If an actuation occurs, the inspections per NFPA 25 Section 14.2.1 and Enhancement 4 will be performed prior to resetting the system. Hence, the initial conditions will be restored and ensure that no water remains in the system and the piping is free of foreign organic and inorganic material.

The Main Turbine Bearing Pre-action system is an in-scope system that is disassembled at the bearing housing more frequently than every 5 years due to periodic maintenance during refueling outages. Water, organic or inorganic materials, or corrosion products within the system would be apparent to maintenance personnel at the time of disassembly. These unexpected conditions would warrant further investigation and remedial actions per the Corrective Action Program. Consequently, this scope has previously met and continues to meet the intent of Obstruction Investigation.

See Attachments 12, 14 and 15 for the LRA changes to Enhancement 4 to clarify the text and ensure PNPPs intent is captured (perform NFPA 25 Section 14.2.1 inspections on a post-actuation basis). This edit also promotes consistency with Appendix A and Appendix B of the PNPP LRA.

Response to Part 2:

Will the downstream piping associated with the spray system protecting the Hydrogen Seal Oil System be visually inspected internally in accordance with Section 14.2 of the 2011 Edition of NFPA 25?

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 5 Page 4 of 4 No, PNPP does not propose to periodically inspect the piping downstream of the Hydrogen Seal Oil System deluge valve per NFPA 25 Section 14.2. However, PNPP will perform an internal inspection based upon condition found during periodic testing. The inspection activities would be commensurate with the observed condition as prescribed in the codes explanatory material (specifically the Annex A content for Section 14.3.1 which states, in part, The type of obstruction investigation should be appropriately selected based on the observed condition.).

PNPP notes that NFPA 25 Section 14.2 applies to sprinkler systems and does not apply to open spray deluge systems. The dry pipe pre-action systems with closed sprinkler heads are distinctly different than the fixed, open spray system protecting the Hydrogen Seal Oil System.

PNPP does not consider fixed open pipe deluge system sprays equivalent to dry or wet pipe sprinkler systems with closed sprinkler heads. The Hydrogen Seal Oil system is tested with control valve full open every 5 years and later drained. Additionally, its upstream strainer is flushed prior to resetting the system and the deluge valve is tripped tested annually with the control valve closed to ensure it operates.

In NFPA 25 Section 14.2 Internal Inspection of Piping, paragraph 14.2.1 states:

Except as discussed in 14.2.1.1 (use of alternative nondestructive examination methods) and 14.2.1.4 (non-metallic pipe exception) an inspection of piping and branch line conditions shall be conducted every 5 years by opening a flushing connection at the end of one main and by removing a sprinkler toward the end of one branch line for the purpose of inspecting for the presence of foreign organic and inorganic material. (parenthetical text in italics was added for context).

As noted above, PNPP conducts full flow Hydrogen Seal Oil system spray testing every 5 years.

Thus, this open spray system is confirmed to be free from blockages and ensures the sprays operate as designed. Internal inspection every 5 years would be unnecessary and would provide no new information that is not already learned from the full flow spray testing. The hydrogen seal oil system is an indoor, open nozzle system and not likely to contain biological fouling. It is drained after use and is not subject to temperature variations causing internal condensation. Therefore, it is unlikely to accumulate corrosion products capable of blocking the open stray nozzles. Historically, the absence of plugging or even partially plugging of these nozzles is noted in the justification for the exception to NFPA 25 Section 13.4.3.2.2.

The Hydrogen Seal Oil system is subject to Section 14.3 of NFPA 25. See Enhancement 1 under Obstruction Investigation. If a spray nozzle(s) in the Hydrogen Seal Oil system was to be partially blocked, then it would indicate there is a discharge of obstructive material.

Consequently, Condition 2 under NFPA 25 Section 14.3.1, requires an obstruction investigation.

It states that an obstruction investigation shall be conducted for system or yard main piping wherever the discharge of obstructive material during routine water tests is identified.

Attachments Attachments 12, 14 and 15

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 6 Page 1 of 4 NCSG RAI-10505-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 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.

Question 6 Ventilation Filter Unit Plenums

Background:

Table 4a in Appendix L of LR-ISG-2012-02 recommends water discharge patterns from open spray nozzles or sprinklers be observed in accordance with Section 13.4.3.2.2.5 of the 2011 Edition of NFPA 25 to ensure plugged nozzles dont impede the spray patterns, nozzles are positioned correctly, and obstructions dont prevent discharge patterns wetting the required surfaces. The staff notes that Section 13.4.3.4.4.5 (A) of the 2011 Edition of NFPA 25 states,

[w]here the nature of the protected property is such that water cannot be discharged, the nozzles or open sprinklers shall be inspected for correct orientation and the system tested with air to ensure that the nozzles are not obstructed.

In the letter dated December 19, 2024 (ML24354A265), the seventh exception in the exception table in LRA Section B.2.21 states that the Ventilation Filter Unit Plenums cannot be tested with water and have no provisions to be tested with air. Therefore, in lieu of observing the water discharge patterns of the Ventilation Filter Unit Plenums, the applicant will visually inspect the charcoal filter plenum spray header/nozzle each time the charcoal is changed to ensure no debris that would obstruct the spray nozzles.

Issue :

The LRA does not appear to indicate the frequency of changing the charcoal. In addition, the LRA does not appear to describe the visual inspections of the charcoal filter plenum spray header/nozzle when the charcoal is changed.

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 6 Page 2 of 4 The LRA does not appear to address plant-specific operating experience related to the charcoal filter plenum spray headers/nozzles.

Request:

Please address the following:

1. On what frequency is the charcoal changed?

2. Describe the visual inspections of the charcoal filter plenum spray header/nozzle that will be performed when the charcoal is changed.

3. Discuss plant-specific operating experience related to the charcoal filter plenum spray headers/nozzles.

PNPP Response Request:

Please address the following:

1. On what frequency is the charcoal changed?

There is no standard replacement frequency for any of the charcoal filters. Charcoal filters are inspected and tested periodically and replaced on condition established by specific effectiveness acceptance criteria. Certain activities, such as painting, may result in consumption of the charcoal bed and affect its efficiency.

Over the past 20 years the number of charcoal replacements and associated spray nozzle and header inspections are:

M14 - Containment Vessel and Drywell Exhaust Plenum 2011 (B spray header) 2015 (A spray header)

M15 - Annulus Exhaust Gas Treatment Plenum (2 spray headers none inspected.

None (A spray header)

None (B spray header)

M21 - Controlled Access and Mechanical Equipment Area Ventilation 2005 & 2015 (A spray header) 2008 & 2015 (B spray header)

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 6 Page 3 of 4 M26 - Control Room Emergency Recirculation Plenum 2009 (A spray header)

None (B spray header)

M31 - Radwaste Building Exhaust Plenum 2013 (A spray header) 2006 & 2015 (B spray header)

M36 - Off Gas Building Exhaust Plenum 2016, 2020, 2022 (A spray header) 2003, 2020, & 2023 (B spray header)

M38 - Auxiliary Building Exhaust Plenum 2005, 2011, 2013, 2021 (spray header)

M40 - Fuel Handling Area Exhaust Plenum 2006 & 2020 (A spray header)

None (B spray header) 2012 & 2020 (C spray header)

Request:

2. Describe the visual inspections of the charcoal filter plenum spray header/nozzle that will be performed when the charcoal is changed.

The inspection activity listed in Charcoal Filter Bed Spray Nozzle Visual Inspection periodic inspection procedure is as follows:

1. Visually inspect each spray nozzle and verify no obstructions are present and the nozzles are not damaged or clogged.

2. Visually inspect the header within the bed and verify the piping is intact with no signs of distortion or damage.

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 6 Page 4 of 4 The corresponding acceptance criteria are:

1. Each spray nozzle shall be free of obstructions and show no signs of damage.

2. Each header within the filter bed shall not be damaged or distorted.

Request:

3. Discuss plant-specific operating experience related to the charcoal filter plenum spray headers/nozzles.

The periodic test in the fire protection program used to perform Charcoal Filter Bed Spray Nozzle Visual Inspection contains the acceptance criteria listed in response to Request 2, above.

A review of these inspections for ventilation systems over the past 20 years was conducted.

Inspection work orders containing the results of this inspection were found for 7 of 10 systems containing one or more charcoal spray headers. Two of the three systems with no inspection work orders over this time period are not within the scope of License Renewal. Only the Annulus Exhaust Gas Treatment Plenum A and B spray systems have not been inspected at least once in the last 20 years. The lack of inspections in the Annulus Exhaust Gas Treatment Plenum A and B spray systems is reasonable as the charcoal beds would not be exposed to volatile contaminants that might deplete the charcoal efficiency.

The seven in-scope systems inspected represent a total of 14 plenums with charcoal beds, 12 of which were inspected over the review period. Over the past 20 years there have been none that failed the acceptance criteria. These results are sufficient to identify any adverse trend if one existed. Hence, the previous results can be extrapolated to the four plenums not inspected over this 20 year period. Two of these four plenums are in systems that had one or more plenums inspected. The other two plenums are in the Annulus Exhaust Gas Treatment system, which had no inspections. Therefore, operating experience supports the conclusion that none of the charcoal bed fixed spray nozzles are blocked, and the external surfaces of the spray headers are in good condition. Because of the similarity between the internal and external air environments, PNPP concludes that the external surface condition bounds the conditions of the internal surfaces of the spray header.

The above results are reasonable considering the configuration of the spray headers. They are typically pointing downward thereby minimizing the potential for plugging from foreign material intrusion. Also, being downstream of high efficiency particulate filters mitigates the potential for biological fouling. Finally, the air environment entering the charcoal beds is typically filtered and dehumidified minimizing the potential for loss of material of the carbon steel header and copper alloy spray nozzles.

Attachments None

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 7 Page 1 of 5 NCSG RAI-10505-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 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.

Question 7 Mainline Strainers

Background:

Table 4a in Appendix L of LR-ISG-2012-02 recommends water spray fixed system strainer inspections be performed every refueling outage and after each system actuation. The staff notes that Table XI.M27-1 in NUREG-2191, Volume 2, recommends water spray fixed system strainer inspections be performed after each system actuation, not every refueling outage because absent flow in the system, an inspection would not provide an effective indicator of system flow blockage as discussed in Table 2-29 of NUREG-2221 (ML17362A126). Section 10.2.1.7 of the 2011 Edition of NFPA 25 specifies removal and inspection for damaged and corroded parts of the water spray fixed system strainers every 5 years.

In the letter dated December 19, 2024 (ML24354A265), the ninth exception in the exception table in LRA Section B.2.21 states that in lieu of removing and inspecting the water spray fixed system strainers every 5 years as specified in Section 10.2.1.7 of the 2011 Edition of NFPA 25, the applicant will inspect mainline supply strainers for damage including corrosion and flow blockage from organic and inorganic debris in water spray fixed nozzle systems in scope of License Renewal every 10 years. The applicant stated that adverse findings are entered into the corrective action program for evaluation. In addition, the applicant stated that internal operating experience demonstrates that the current frequency of inspection is adequate to support fixed water system sprays. The staff notes that Enhancement 1 in LRA Section B.2.21, as supplemented by letter dated December 19, 2024 (ML24354A265), is related to this exception.

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 7 Page 2 of 5 Issue :

The LRA does not appear to address whether the water spray fixed system strainers will be inspected whenever the system has been actuated consistent with Table 4a in Appendix L of LR-ISG-2012-02. While the applicant stated, internal operating experience demonstrates that the current frequency of inspection is adequate to support fixed water system sprays, it is not clear whether this statement addresses both damaged and corroded parts and flow blockage of the water spray fixed system strainers. In addition, it is not clear if current frequency indicates the mainline strainers are currently inspected on a 10-year frequency.

The LRA does not provide a technical basis for inspecting the mainline supply strainers on a 10-year frequency. Specifically, sufficient details are not provided related to the process used to determine the 10-year frequency or alternative testing (number, location, frequency) that would provide insights into whether the mainline supply strainers are blocked or are damaged or corroded.

Request:

Please address the following:

1. Will the water spray fixed system strainers be inspected whenever the system has been actuated consistent with Table 4a in Appendix L of LR-ISG-2012-02? If not, provide a technical basis for not inspecting the water spray fixed system strainers whenever the system has been actuated, or discuss revising the ninth exception and Enhancement 1 to specify inspection after each system actuation.

2. Discuss whether the statement related to internal operating experience addresses both damaged and corroded parts and flow blockage of the water spray fixed system strainers.

3. Discuss whether the current frequency statement means the mainline strainers are currently inspected on a 10-year frequency.

4. Provide a technical basis for inspecting the mainline supply strainers on a 10-year frequency that includes a description of the process followed to determine the 10-year frequency and a description of alternative testing (number, location, and frequency of alternative inspections/tests) that provides insight into whether the mainline supply strainers are damaged, have corroded parts, or are blocked prior to the next mainline supply strainer inspection. Alternatively, revise the LRA to inspect the mainline supply strainers on a 5-year frequency consistent with Section 10.2.1.7 of the 2011 Edition of NFPA 25.

PNPP Response Request:

Please address the following:

1. Will the water spray fixed system strainers be inspected whenever the system has been actuated consistent with Table 4a in Appendix L of LR-ISG-2012-02? If not, provide a technical basis for not inspecting the water spray fixed system

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 7 Page 3 of 5 strainers whenever the system has been actuated, or discuss revising the ninth exception and Enhancement 1 to specify inspection after each system actuation.

PNPP notes that the Code provisions, related to fixed spray system strainers, of Sections 10.1 and 10.2 of NFPA 25-2011 address multiple types of system strainers (i.e., mainline strainers and individual nozzle strainers). PNPP water spray fixed suppression systems are provided with mainline strainers, but do not have individual nozzle strainers. PNPP further notes that the Code requirements invoking strainer inspections after each system actuation are limited to individual nozzle strainers (Code Section 10.2.7.2). Review of LR ISG-2012-02 and NUREG-2191, as cited above in the Background section of this RAI, do not invoke requirements for mainline strainer inspections beyond those provided in the NFPA Code. The following discussion describes PNPP practices relative to mainline strainers, and the basis for not invoking additional requirements beyond those specified in NFPA 25-2011, LR-ISG 2012-02 and NUREG-2191.

Mainline strainers are not disassembled, and the internals of the associated mainline strainers are not inspected whenever water spray fixed systems are actuated. The potential for flow blockage is addressed whenever water spray fixed systems are actuated, as evidenced by flow through the mainline strainers and downstream spray nozzles. Fire water system operating procedures contain steps to reset systems after actuations that include flushing the strainers; this post-actuation flushing meets the requirements of NFPA 25-2011, Section 10.2.7.1. Strainer flushing includes cycling the strainers two turns while confirming backwash flow, consistent with strainer manufacturer recommendations. Personnel are stationed at the building drain to observe drain flow, confirming effective strainer backwash. Additionally, the periodic full flow tests conducted every two years include steps to flush the strainers as part of the system restoration.

Ten-year periodic internal inspection of each main line strainer in the scope of license renewal is conducted under the existing maintenance program. The strainers are inspected for biological and other fouling/blockage and for satisfactory internal condition. Inspections address structural integrity and corrosion. The strainer parts are cleaned prior to reassembly. Post maintenance testing ensures no leakage and acceptable functioning of the strainers backwash capability which includes freedom of movement of the strainer handwheel.

Operating experience reviewed since 2003 revealed no blockages in any main line strainers in the scope of license renewal. Some were considered dirty but acceptable, and no zebra mussels were found. All flow conditions were considered acceptable and all internal, as found conditions (corrosion) and integrity were considered satisfactory. However, in one instance in 2024, the hydrogen seal oil mainline strainer was replaced. The stem was found bent and one of its strainers was starting to separate. Although the strainer could be operated, plant personnel conservatively decided to replace the strainer.

Several strainers failed the initial post maintenance test after reassembly due to handwheel issues. The typical cause of difficult or no movement of the handwheels was due to packing gland, and in some cases, follower issues. One handwheel was found frozen on disassembly.

All handwheels were left functional prior to close-out of the work orders.

In the response to part 4 of this question, the periodic inspection frequency will be changed from every 10 years to every 5 years in compliance with the NFPA 25-2011, Section 10.2.1.7. The 10-year inspections have shown no blockages. The historical 20-year review of work orders

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 7 Page 4 of 5 demonstrates the effectiveness of flushing the strainers after every actuation, which occurs periodically in conjunction with the fixed spray testing activities (NFPA 25-2011, Section 10.2.7.1). Consequently, there does not appear to be any compelling reason to invoke requirements beyond that of NFPA 25 by inspecting the system mainline strainers after every actuation, especially considering the change in inspection frequency to every 5 years to align with NFPA 25-2011, Section 10.2.1.7.

This result follows, and is consistent with, the justification to the exception for inspecting the fire pump inlet strainer after every actuation. This justification describes the basis for the low level of debris due to the configuration of the intake structure and the fine mesh in the traveling screens.

Due to the lower level of debris, flushing the mainline strainers is adequate to ensure the strainers do not become blocked. Further, there were no records of finding zebra mussels in the screens during the 10-year inspections.

Based upon the evidence in the 20 years of acceptable strainer inspections at PNPP, the increased inspection frequency (response to part 4 of this question), and effectiveness of current practices, internal inspections of mainline strainers after every actuation is not warranted.

2. Discuss whether the statement related to internal operating experience addresses both damaged and corroded parts and flow blockage of the water spray fixed system strainers.

The internal operating experience addresses both damaged and corroded parts and flow blockage from inorganic and organic materials in water spray fixed system mainline strainers.

See response to Question 7, Request 1, above for additional details.

3. Discuss whether the current frequency statement means the mainline strainers are currently inspected on a 10-year frequency.

The statement current frequency for inspection is 10 years. However, other activities complement the 10-year frequency. The frequency of inspection should consider the collective activities of periodic (2-year) spray flow testing, conduct of mainline strainer manipulation, and backwash/flushing following each spray actuation.

4. Provide a technical basis for inspecting the mainline supply strainers on a 10-year frequency that includes a description of the process followed to determine the 10-year frequency and a description of alternative testing (number, location, and frequency of alternative inspections/tests) that provides insight into whether the mainline supply strainers are damaged, have corroded parts, or are blocked prior to the next mainline supply strainer inspection. Alternatively, revise the LRA to inspect the mainline supply strainers on a 5-year frequency consistent with Section 10.2.1.7 of the 2011 Edition of NFPA 25.

The LRA will be revised to inspect the mainline strainers on a 5-year frequency consistent with Section 10.2.1.7 of the 2011 Edition of NFPA 25.

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 7 Page 5 of 5 LRA changes associated with this RAI response are provided in the associated attachments identified below.

Attachments Attachments 12, 14 and 15 to this letter

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 8 Page 1 of 2 NCSG RAI-10505-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 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.

Question 8 Obstruction Investigations

Background:

Table 4a in Appendix L of LR-ISG-2012-02 recommends an obstruction investigation in accordance with Sections 14.2 and 14.3 of the 2011 Edition of NFPA 25. Section 14.2 of the 2011 Edition of NFPA specifies inspection of piping and branch lines every 5 years by opening a flushing connection at the end of one main and by removing a sprinkler toward the end of one branch line. In the letter dated December 19, 2024 (ML24354A265), Enhancement 1 in LRA Section B.2.21 (Commitment No. 21.1 in LRA Table A.3) defines existing enhancements as the inspection scope established in other program elements or elsewhere in this program element and states that Section 14.2 of the 2011 Edition of NFPA 25 does not apply to existing enhancements.

Issue :

Enhancement 1 is unclear on what inspection scope established in other program elements or elsewhere in this program element that Section 14.2 of the 2011 Edition of NFPA 25 would not apply.

Request:

1. Please identify the specific instances where Section 14.2 of the 2011 Edition of NFPA 25 would not apply to existing enhancements (inspection scope established in other program elements or elsewhere in this program element).

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 8 Page 2 of 2 PNPP Response Request:

1. Please identify the specific instances where Section 14.2 of the 2011 Edition of NFPA 25 would not apply to existing enhancements (inspection scope established in other program elements or elsewhere in this program element).

PNPP notes that Section 14.2 of NFPA 25-2011 applies to sprinkler systems (i.e., wet-pipe, pre-action) based on the specific language utilized in Section 14.2 and the accompanying annex material of the Code. As such, the requirements of Section 14.2 of NFPA 25-2011 would not apply to other portions of the water-based fire protection system such as open nozzle deluge systems, or standpipe and hose systems, which are addressed by separate requirements and programmatic enhancements. Similarly, sprinkler heads are not subject to Section 14.2 but are addressed under separate requirements such as the new sprinkler head testing program and expanded periodic inspection scope and criteria.

With respect to portions of the water-based fire protection system which are subject to Section 14.2 requirements, the text cited in the Background and Issue refers to Item 21.4 of LRA Table A.3 (inspections of piping that is normally dry but periodically subjected to flow). This enhancement specifically addresses in-scope pre-action systems. As this enhancement specifically addresses augmented internal inspections, and subsequent system actuation monitoring, the requirements of Section 14.2 need not be applied on a periodic basis.

Item 21.4 of LRA Table A.3 requires the piping to be inspected following any system actuation.

Following initial inspections, and without a system actuation, there is no method of introduction of foreign organic or inorganic material. Consequently, this existing enhancement would take precedence and Section 14.2 would not apply, as outlined in the obstruction investigation enhancement text cited above.

Attachments None

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 9 Page 1 of 3 NCSG RAI-10505-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 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.

Question 9 Diesel Fire Pump Heat Exchanger

Background:

As supplemented by letter dated June 27, 2024 (ML24180A010), license renewal application (LRA) Table 3.3.2-24 includes aging management review items for the diesel fire pump heat exchanger tubes, noting intended functions of both pressure boundary and heat transfer with loss of material, reduction of heat transfer, and flow blockage as the aging effects requiring management. The table shows these aging effects as being managed by the Fire Water System aging management program (AMP). LRA Section B.1.4, Operating Experience, notes that Perry will continue the existing operating experience program to manage aging management program effectiveness, consistent with LR-ISG-2011-05, Ongoing Review of Operating Experience. This section also states, If there is an indication that the effects of aging are not being adequately managed, then that will be documented in the corrective action process to either enhance the AMPs or develop and implement new AMPs, as appropriate.

Perry condition report CR-2024-08405 documents a high temperature alarm on the diesel driven fire pump on October 25, 2024. The diesel fire pump (DFP) was emergency shut down per the alarm response. The condition report notes that the engines heat exchanger was highly fouled and was not providing adequate heat removal from the engine. Troubleshooting activities noted that the heat exchanger was fouled with sediment and high amounts of tube blockage. The CRs organizational effectiveness investigation notes that the cause of the failure was age-related degradation/fouling and identified a lack of maintenance on the heat exchanger. The CRs maintenance rule evaluation notes that the degraded heat exchanger caused a functional failure of the diesel driven fire pump. The CRs aging management evaluation states The issues identified in the CR are known aging mechanisms, and as stated in the CR, the heat exchanger on the DFP is to be replaced every 14 years as an enhancement to the Fire Water System program. As such, no further actions are required.

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 9 Page 2 of 3 Issue :

Aging management review items in LRA Table 3.3.2-24, associated with the diesel driven fire pump heat exchanger tubes, identify loss of material, reduction of heat transfer, and flow blockage as the aging effects requiring management through the Fire Water System AMP.

Although the LRA includes an enhancement to replace the DFP heat exchanger on a 14-year frequency, this periodic replacement fundamentally only addresses the loss of material aging effect for the pressure boundary intended function. Previous industry operating experience had identified diesel engine heat exchanger tube leaks, which another site said they could only address through periodic replacement because they could not inspect the diesel engines heat exchanger tubes for wall thinning. While a new DFP heat exchanger will initially address the reduction of heat transfer aging effect (because it is a new unfouled heat exchanger), the staff notes that Perrys raw water heat exchanger for the high pressure core spray pump (part of the Generic Letter 89-13 program) experienced a 75 percent loss of heat transfer margin over a period of approximately 8.2 years. (Reference information discussed in CR-2022-00950 and CR-2022-01183 cited in RAI-10183-R1.)

Because the activities prescribed by the Fire Water System AMP allowed a functional failure of the diesel fire pump to occur, due to a reduction of heat transfer by the engines heat exchanger, the current activities apparently did not adequately manage the applicable effects of aging. Because the aging management evaluation did not specifically address the reduction of heat transfer due to fouling, which has also occurred in other raw water heat exchangers at Perry, it is not clear that the effects of aging will be adequately managed by only replacing the DFP heat exchanger every 14 years. Although not directly applicable to the DFP heat exchanger, the staff notes that heat exchangers managed by the Generic Letter 89-13 program are either tested or inspected/cleaned on at least a 5-year frequency.

Request:

1. Because the activities currently prescribed by the Fire Water System AMP apparently allowed a functional failure of the diesel fire pump to occur, either describe enhancements to the Fire Water System AMP to ensure that reduction of heat transfer will be adequately managed during the period of extended operation (consistent with the guidance in LRA Section B.1.4), or provide information to demonstrate that reduction of heat transfer due to fouling (as seen by other raw water heat exchangers at Perry) will be adequately managed through the 14-year periodic replacement of the DFP heat exchanger.

PNPP Response Request:

1. Because the activities currently prescribed by the Fire Water System AMP apparently allowed a functional failure of the diesel fire pump to occur, either describe enhancements to the Fire Water System AMP to ensure that reduction of heat transfer will be adequately managed during the period of extended operation (consistent with the guidance in LRA Section B.1.4), or provide information to demonstrate that reduction of heat transfer due to fouling (as

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 9 Page 3 of 3 seen by other raw water heat exchangers at Perry) will be adequately managed through the 14-year periodic replacement of the DFP heat exchanger.

PNPP Response As a result of the event documented in Condition Report (CR) 2024-08405, PNPP agrees that additional enhancement is needed to ensure protection against heat transfer reduction. PNPP will inspect for fouling of the heat exchanger tubes (interior and exterior) on the Diesel Driven Fire Pump every 3 cycles (6 years) and remediate any adverse conditions, for example, by performing cleaning or replacement. This enhancement to the fire water program will be included in LRA Table A.3, as provided in Attachment 14 of this letter. This frequency aligns with the current six-year maintenance evolution required by the approved Fire Protection Program and is judged to be reasonable given site operating experience.

Prior to 10/25/2024, a review of work history and condition reports for the diesel driven fire pump since 2007 reflected no history of fouling or maintenance that involved the engine water cooler/heat exchanger. That history provides some indication of low susceptibility of the diesel driven fire pump water cooler to fouling.

Following the 10/25/2024 event, on 11/6/2024, the heat exchangers tube bundle was replaced.

The replacement was initiated instead of cleaning the heat exchanger tubes that were fouled with an internal layer of silt reducing heat transfer and making it difficult to control temperature.

The extent of fouling and compact nature of the tubes/bundle made replacement the preferred option. An existing license renewal commitment to replace the heat exchanger every 14 years addresses managing loss of material in the tubes. Consequently, this heat exchanger will be replaced 14 years from this in-service date.

Based on this response, Appendix A and Appendix B will be revised to include additional enhancement text associated with the 6-year heat exchanger inspection described above.

Appendix B will also be updated to reflect this recent site operating experience.

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

Attachments Attachments 12, 14 and 15 to this letter.

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 10 Page 1 of 3 0

LRA Section: Table 3.3.1 LRA Page Number(s): Page 3.3-103 and 3.3-104

References:

NCSG RAI-10505-R1 Description of Change: PNPP LRA Table 3.3.1 is revised based on the response to NCSG RAI-10505-R1, Question 4 (Attachment 4 of this letter). Changes are made to the Discussion text as shown on the following page.

PNPP LRA Table 3.3.1 Items 64 and 66, Page 3.3-103 and 3.3-104, as modified by Supplement 2, Vistra Letter L-24-020, is revised as follows: (next page)

Note: Only the affected table row is presented on the following page. No other changes are made to PNPP LRA Table 3.3.1.

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 10 Page 2 of 3

Table 3.3.1 Summary of Aging Management Evaluations for the Auxiliary Systems Item Number Component Aging Effect/Mechanism Aging Management Programs Further Evaluation Recommended Discussion 3.3.1-64 (LR-ISG-2012-02)

Steel, Copper alloy Piping, piping components, and piping elements exposed to Raw water Loss of material due to general, pitting, crevice, and microbiologically-influenced corrosion; fouling that leads to corrosion; flow blockage due to fouling Chapter XI.M27, "Fire Water System" No Consistent with NUREG-1801 (as modified by LR-ISG-2012-02) with the following clarifications and with some program exceptions. The Fire Water System program will manage loss of material and flow blockage in steel and copper alloy components exposed to raw water in the Fire Protection system. Steel is used here in the broad category of carbon steel, alloy steel, cast iron, gray cast iron, malleable iron, and high-strength low-alloy, steel.

All are vulnerable to loss of material and flow blockage due to the various aging mechanisms cited under this table 1 item number. In addition, fire pump steel bolting in the Fire Protection system that is submerged in raw water is aligned to this row but will be managed for loss of material under the Bolting Integrity program. The Open Cycle Cooling Water System program will manage loss of material and flow blockage for the external surfaces of submerged, steel, electric Motor Driven and Diesel Driven Fire Pump column and column suction bell and copper alloy, suction strainer element.

See Appendix B Section B.2.7 for the Bolting Integrity program and

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 10 Page 3 of 3

Table 3.3.1 Summary of Aging Management Evaluations for the Auxiliary Systems Item Number Component Aging Effect/Mechanism Aging Management Programs Further Evaluation Recommended Discussion B.2.21 for Fire Water System program exceptions to NUREG-1801.

3.3.1-66 (LR-ISG-2012-02)

Stainless steel Piping, piping components, and piping elements exposed to Raw water Loss of material due to pitting and crevice corrosion; fouling that leads to corrosion; flow blockage due to fouling Chapter XI.M27, "Fire Water System" No Consistent with NUREG-1801 (as modified by LR-ISG-2012-02) with the following clarifications and some program exceptions. The Fire Water System program will manage loss of material of stainless steel piping components exposed to raw water in the Fire Protection system. In addition, Open Cycle Cooling Water System program will manage loss of material in stainless steel Pump casing (Suction strainer element).

See Appendix B Section B.2.21 for Fire Water System program exceptions to NUREG-1801.

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 11 Page 1 of 4 1

LRA Section: 3.3.2.1.24 and Table 3.3.2-24 LRA Page Number(s): Pages 3.3-30 through 3.3-32 and 3.3-303 through 3.3-305

References:

NCSG RAI-10505-R1 Description of Change: PNPP LRA Section 3.3.2.1.24 and Table 3.3.2-24 are revised based on the response to NCSG RAI-10505-R1, Question 4 (Attachment 4 of this letter). Changes are made to the assigned aging management program as shown on the following pages.

PNPP LRA Section 3.3.2.1.24, Pages 3.3-30 through 3.3.2-32, as modified by Supplement 4, Vistra Letter L-24-200, and accompanying Table 3.3.2-24, are revised as follows: (next page)

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 11 Page 2 of 4 3.3.2.1.24 Fire Protection Materials Fire Protection system components are constructed of the following materials:

Aluminum Copper alloy <15% Zn Copper alloy >15% Zn Fiberglass Glass Gray cast iron Gray cast iron with internal coating/lining Polymers Stainless steel Steel Environments Fire Protection system components are exposed to the following environments:

Air - indoor, uncontrolled Air - outdoor Closed-cycle cooling water Condensation Diesel exhaust Fuel oil Gas Lubricating oil Raw water Soil Aging Effects Requiring Management The following aging effects associated with the Fire Protection system require management:

Change in mechanical properties (cracking, loss of strength), Blistering Cracking Cumulative fatigue damage

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 11 Page 3 of 4 Flow blockage Loss of coating or lining integrity Loss of material Loss of preload Reduction of heat transfer Aging Management Programs The following aging management programs manage the effects of aging on Fire Protection system components:

Bolting Integrity (B.2.7)

Buried and Underground Piping and Tanks (B.2.8)

Closed Treated Water Systems (B.2.15)

External Surfaces Monitoring of Mechanical Components (B.2.18)

Fire Protection (B.2.20)

Fire Water System (B.2.21)

Fuel Oil Chemistry (B.2.23)

Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components (B.2.25)

Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks (B.2.27)

Lubricating Oil Analysis (B.2.28)

Plant-Specific Periodic Inspections for Selective Leaching (B.2.45)

One-Time Inspection (B.2.35)

Open Cycle Cooling Water System (B.2.37)

Selective Leaching (B.2.42)

TLAA

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 11 Page 4 of 4 PNPP LRA Table 3.3.2-24, Pages 3.3-303 through 3.3-305, as modified by Supplement 4, Vistra Letter L-24-200, is revised as follows:

Note: Only the affected table rows are presented on the following page. No other changes are made to PNPP LRA Table 3.3.2-24.

Table 3.3.2 Fire Protection System Row Component Type Intended Function Material Environment Aging Effect Requiring Management Aging Management Program NUREG-1801 Item Table 1 Item Notes 101 Pump casing (Column)

Pressure boundary Steel Raw water (Ext)

Loss of material Open Cycle Cooling Water System Fire Water System VII.G.A-33 (LR-ISG-2012-02) 3.3.1-64 E B 111 Pump casing (Suction bell)

Pressure boundary Gray cast iron with internal coating/lining Raw water (Ext)

Loss of material Open Cycle Cooling Water System Fire Water System VII.G.A-33 (LR-ISG-2012-02) 3.3.1-64 E B 115 Pump casing (Suction strainer element)

Filtration Copper alloy

<15% Zn Raw water (Ext)

Loss of material Open Cycle Cooling Water System Fire Water System VII.G.AP-197 (LR-ISG-2012-

02) 3.3.1-64 E B, 342 116 Pump casing (Suction strainer element)

Filtration Stainless steel Raw water (Ext)

Loss of material Open Cycle Cooling Water System Fire Water System VII.G.A-55 (LR-ISG-2012-02) 3.3.1-66 E B, 330

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 12 Page 1 of 6 2

LRA Section: Section A.1.21 LRA Page Number(s): Pages A-23 through A-25

References:

RAI Set 3 response in Attachment 12 (Vistra Letter L-24-209), and Supplement 2 in Attachment 44 (Vistra Letter L-24-020), Supplement 7 in Attachment 14 (Vistra Letter L 256), NCSG RAI-10505-R1 and the response to Questions 5, 7 and 9 of this letter (Attachments 5, 7 and 9).

Description of Change: PNPP LRA Section A.1.21 is revised based upon the responses to NCSG RAI-10505-R1, Questions 5, 7 and 9 (Attachments 5, 7, and 9 of this letter) and two self-identified clarifications added to Enhancement 1, bullet 1, under Sprinkler Systems and Enhancement 4.ii.3.

PNPP Section A.1.21, Pages A-23 through A-25, as modified by Supplement 7 (Vistra Letter L-24-256) is revised as follows:

A.1.21 Fire Water System Program The Fire Water System Program (a sub-program of the overall Fire Protection Program) is an existing condition monitoring program that applies to the fire water supply and water-based suppression systems, which include sprinklers, nozzles, fittings, valve bodies, fire pump casings and heat exchanger, hydrants, hose stations, standpipes, a pressure maintenance tank, various retarding chambers (tank), Foam Liquid Storage Tank (component types Tank), and aboveground, buried and underground piping and components. The PNPP Firewater System does not have a fire water storage tank. The program conducts tests and inspections in accordance with applicable National Fire Protection Association (NFPA) codes and standards. These codes and standards will have enhanced flow testing and visual inspections performed in accordance with the 2011 Edition of NFPA 25 as described below.

The Fire Water System Program manages:

loss of material due to general, crevice, pitting corrosion, MIC, macrofouling leading to corrosion and recurring corrosion; flow blockage due to fouling; reduction in heat transfer (for the diesel driven fire pump engine); and, change in mechanical properties (cracking, loss of strength) and blistering of ASTM D-2996 fiberglass reinforced epoxy piping.

This program manages the aging effects using flow testing and visual inspections.

Reduction in heat transfer will be managed by periodic replacement of the cooling coil and through periodic visual inspections for fouling. In addition to NFPA codes and standards, those portions of the system that are (a) normally dry but periodically subject

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 12 Page 2 of 6 to flow (e.g., dry-pipe or pre-action sprinkler systems) and (b) cannot be drained or allow water to collect, are subjected to augmented testing or inspections prior to the PEO.

During the PEO, pre-action sprinklers will be monitored, and for those that actuate, similar inspections will be performed to ensure collected water in pipe segments is again removed. The program also performs augmented inspections to address loss of material due to recurring corrosion by performing periodic, non-intrusive pipe thickness measurement in above ground or underground, wetted, metallic fire protection piping.

The water-based fire protection system is normally maintained at required operating pressure and is monitored such that loss of system pressure is immediately detected and corrective actions initiated.

Sprinklers are replaced or a representative sample of sprinklers from one or more sample areas is tested to ensure that signs of degradation, such as corrosion, are detected in a timely manner and prior to exceeding the service life limits specified in the 2011 Edition of NFPA 25.

For the buried piping, visual inspections of the piping interior surfaces will be performed whenever the piping internal surface is made accessible due to maintenance and repair activities. Where above-grade and underground or buried piping environments and material are similar, the above-grade will be extrapolated to evaluate the condition of the underground or buried piping.

The program will be enhanced as follows:

1. The program will include inspections and testing consistent with Appendix L, Table 4a, Fire Water System Inspection and Testing Recommendations, of License Renewal Interim Staff Guidance LR-ISG-2012-02. Specific enhancements below must be considered in light of the program exceptions.

Sprinkler Systems:

Program documents will be enhanced to require visual inspection of all in-scope sprinklers in addition to those that are directly protecting safe shutdown equipment as specified in the Fire Protection Functional Specifications. The functional specifications in the Fire Protection Program describe inspecting sprinklers in fire areas containing safe shutdown equipment on an 18-month frequency. This frequency is applied for these additional sprinklers consistent with the currently required inspection of sprinklers in fire areas containing safe shutdown equipment. Where sprinklers are inaccessible during power operation, the frequency will be per each cycle (two years) instead of 18 months.

Program periodic inspection criteria will be revised to require sprinklers to be free of corrosion, foreign materials, and paint and installed in the correct orientation to meet Section 5.2.1.1.1 criteria.

Program instructions will be enhanced to require inoperable sprinklers to be replaced. The criteria used to determine the impact on sprinkler operability include: when showing signs of (1) leakage (any), (2) severe corrosion, (3)

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 12 Page 3 of 6 physical damage, (4) loss of fluid in the glass bulb heat responsive element, (5) severe loading (e.g., with dust), or (6) painting unless painted by the sprinkler manufacturer; or (7) any sprinkler installed incorrectly. Additionally, Annex A of NFPA 25 regarding cleaning of dust loaded sprinklers will be adapted.

The program will be enhanced to perform representative sprinkler head sampling (laboratory field service testing) or replacement of sprinkler heads within the scope of license renewal prior to exceeding the in-service (installed) limits specified in the 2011 Edition of NFPA 25. In the case of testing, requirements are selected in accordance with the 2011 Edition of NFPA 25 and repeated at the specified intervals. Testing is continued through the period of extended operation, or until there are no untested sprinkler heads that will exceed the service limits through the remainder of the period of extended operation.

Standpipe and Hose Systems Program documentation will be revised, or new test instructions developed to add main drains testing of the in-scope water-based standpipes including those associated with automatic water suppression systems. Program documentation will require testing of 20% of the necessary standpipe systems every refueling outage/cycle. These tests will occur every 10 years and throughout the PEO.

Private Fire Service Mains Program documentation will be revised to acknowledge compliance per Section 7.3.1.3 of NFPA 25, where underground piping supplies individual fire sprinkler, standpipe, water spray, or foam-water sprinkler systems and there are no means to conduct full flow tests, tests generating the maximum available flows shall be permitted. (Note: PNPP does not have a foam water sprinkler system.)

Program documentation will be revised to require that flow tests shall be made at flows representative of those expected during a fire, for the purpose of comparing the friction loss characteristics of the pipe with those expected for the particular type of pipe involved, with due consideration given to the age of the pipe and to the results of previous flow tests. Any flow test results that indicate deterioration of available waterflow and pressure shall be investigated to the complete satisfaction of the authority having jurisdiction to ensure that the required flow and pressure are available for fire protection.

Program documentation will be revised to include a 60-minute hydrant drainage limit requirement during testing to meet Section 7.3.2.4, NFPA 25. A note will be added to include words to the effect that due to the Plant Foundation Underdrain system, groundwater level around the nuclear island does not normally reach the level of the relevant hydrants. PNPP monitors ground water level. However, if water level were to be too high or other conditions exist to prevent drainage, the hydrant drain shall be plugged and water in the barrel shall be pumped out.

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 12 Page 4 of 6 Relevant test instructions will be revised to include a statement that dry barrel hydrants that are located in areas subject to freezing weather and that have plugged drains shall be identified clearly as needing pumping after operation.

Valves and System Wide Testing See enhancement for Main Drain Testing under Standpipe and Hose Systems above.

Main Drains Testing shall require identification and correction of the cause of any 10% reduction in full flow pressure.

Water Spray Fixed Systems PNPP Fire Protection Program documentation will be revised to require the removal, inspection for damaged and corroded parts, and cleaning of mainline strainers in water spray fixed nozzle systems in scope of License Renewal every 10 years 5 years consistent with Section 10.2.1.7 of NFPA 25, 2011 Edition.

Adverse findings will be entered into the corrective action program for evaluation for increased frequency of inspection and trending.

In addition to flush activities currently associated with periodic flow testing, PNPP Fire Protection Program documentation will be revised to ensure that mainline strainers are flushed after each actuation of an associated water spray fixed system.

Foam Water Systems PNPP Fire Protection Program documentation will be revised to require that the foam liquid storage tank shall be drained of foam liquid and flushed every 10 years.

Obstruction Investigation New PNPP Fire Protection Program documentation will be added to meet the requirements of NFPA 25, 2011 Edition, Section 14.2, Internal Inspection of Piping and Section 14.3 Obstruction Investigation and Prevention. Inspection scope established in other program elements or elsewhere in this program element, collectively referred to as existing enhancements, shall remain in effect.

Where overlap or conflicts exist between existing enhancements and this enhancement: a) the existing enhancements shall take precedence, b) Section 14.2 requirements shall not apply to existing enhancements, and c) Section 14.3 guidance shall continue to apply to all inspection activities.

2. As an enhancement to detect aging effects of internal surfaces of buried piping, a portion of the aboveground inspection locations will be selected where above-grade and underground or buried piping environments and material are similar, the above-grade will be extrapolated to evaluate the condition of the underground or buried piping.

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 12 Page 5 of 6

3. The program will be enhanced to require that when visual inspections are used to detect loss of material in the piping within the scope of license renewal, the inspection technique is capable of detecting surface irregularities that could indicate wall loss to below nominal pipe wall thickness due to corrosion and corrosion product deposition. Where such irregularities are detected, follow-up volumetric wall thickness examinations will be performed.

4. Enhancement i. below was implemented and identified piping configurations causing piping not to drain, hence Enhancement ii. is applicable at PNPP.

i.

Prior to the period of extended operation, all accessible dry pre-action, sprinkler, horizontal pipe configurations (including fittings and pipe components) within the scope of License Renewal were walked down to provide reasonable assurance that the as-built, flow path piping system may be drained without areas that will allow water to accumulate and potentially contain corrosion products that could block the installed sprinklers. For those portions that are inaccessible, as-built drawings were used to identify such configurations.

ii.

The program will be enhanced to include augmented testing and inspections beyond those of Table 4a for portions of water-based fire protection system components within the scope of license renewal that are (a) normally dry but periodically subjected to flow (e.g., dry-pipe or pre-action sprinkler system components) and (b) cannot be drained or allow water to collect. The augmented inspections and activities are:

1. Within 5 years prior to the PEO, inspect 100% of the subject piping segment locations for trapped water and any condition such as organic and inorganic materials that might cause blockage of the sprinkler heads if the system were actuated. Any segments found to be wet or contain significant corrosion or organic matter will be cleaned and minimum wall thickness determined for the worst areas of wall loss. Results will be entered into the Corrective Action Program (CAP) for disposition and correction, as required.

2. After the completion of these inspections, monitor and record all actuations of the dry sprinkler systems within the scope of License Renewal, and

3. For any system that actuates, ensure baseline conditions are established as noted in part 1 above prior to putting the dry sprinkler system back in service:, that the affected system piping segments that are the subject of this issue will be inspected and any pooling water eliminated; and the actuated system will be inspected per NFPA 25-2011 Section 14.2.1 by opening a flushing connection at the end of one main and by removing a sprinkler toward the end of one branch line for the purpose of inspecting for the presence of foreign organic and inorganic material.

5. Fire protection procedures will be revised, or new procedures developed to require

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 12 Page 6 of 6 periodic replacement of the coolant heat exchanger tube bundle on the Diesel Driven Fire Pump Engine during the period of extended operation at a frequency of every 14 years. The program will also require internal visual inspection of the heat exchanger shell and channel for loss of material, and inspection for internal tube fouling every 3 cycles (6 years) with remediation of adverse conditions (for example by performing cleaning or replacement of affected components).

in conjunction with tube bundle replacement.

6. The program will provide that if the presence of sufficient foreign organic or inorganic material to obstruct pipe or sprinklers is detected during pipe inspections, the material will be removed and its source will be determined and corrected.

7. The program will be augmented to perform periodic (initially, every other cycle, i.e., 4 year intervals), nonintrusive pipe thickness measurement in above ground or underground (not buried), wetted, metallic Fire Water system piping. Each 4 year sample will include at least three locations for a total of 100 feet of piping.

Locations selected will be based upon system susceptibility to corrosion, evidence of performance degradation during system flow testing or periodic flushes or prior wall thickness measurements. The method used will attempt to detect localized degradation in pipe wall thickness, e.g., Low Frequency Electromagnetic Technique (LFET), or equivalent. The idea is to use the method as a screening tool to identify "spots of interest" which are then followed up with ultrasonic (UT) testing or Phased Array Testing (PAUT) on the spots of interest. Additionally, proximity to Safety Related or high risk equipment will be favored locations when given equivalent susceptibility or evidentiary factors. Significant finding shall be entered into the Corrective Action Program for remediation and additional corrective actions. Significant findings will be any wall thickness less than min wall or localized minimum wall thickness more than 50% less when compared to its surroundings.

8. The program will be augmented for subsequent or existing leaks not yet repaired, when practical, to determine or confirm the corrosion mechanism(s) causing the leaks. The results will be processed through the Corrective Action Program to determine further actions and adjustments to the period of augmented inspections.

Unless otherwise noted, these Fire Water System Program enhancements described above will be implemented no later than 6 months prior to the extended period of operation.

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 13 Page 1 of 2 3

LRA Section: Appendix A, A.1.37 LRA Page Number(s): A-36

References:

NCSG RAI-10505-R1 Description of Change: The OCCW Program description is revised to add new programmatic enhancements as a result of the responses to NCSG RAI-10505-R1, Question 4 (Attachment 4 of this letter). Specifically, enhancements are added to expand the scope of the OCCW Program to perform aging management of submerged portions of ESW and Fire Water Pumps.

PNPP LRA, Appendix A, Section A.1.37, Page A-36 is revised as follows:

A.1.37 OPEN-CYCLE COOLING WATER SYSTEM PROGRAM The open-cycle cooling water (OOCW) systems program is an existing program that manages material loss due to micro-or macro-organisms and various corrosion mechanisms to ensure effective transfer of heat from safety-related structures, systems and components (SSCs) to the ultimate heat sink (UHS). At PNPP, raw water for heat transfer to safety-related SSCs is accomplished with the emergency service water (ESW) system. The program relies on the implementation of the recommendations of NRC Generic Letter (GL) 89-13 to ensure that the effects of aging on the OCCW systems will be managed for the period of extended operation. Other components are also managed under OCCW based on exposure to a raw water environment and the aging management review. In accordance with the guidance of GL 89-13, the OCCW program manages aging effects by using a combination of preventive, condition, and performance monitoring activities. These include (a) surveillance and control techniques to manage aging effects caused by biofouling, corrosion, erosion, protective coating failures, and silting in the OCCW system or structures and components serviced by the OCCW system; (b) inspection of critical components for signs of corrosion, erosion, and biofouling; and (c) testing of the heat transfer capability of heat exchangers that remove heat from components important to safety.

Loss of material due to recurring internal corrosion has been identified for the Emergency Service Water (ESW) System. Loss of material due to recurring internal corrosion and erosion is managed by augmented inspections utilizing the XI.M17 Flow Accelerated Corrosion program. The XI.S7, RG 1.127, Inspection of Water Control Structures Associated with Nuclear Power Plants aging management program is credited with silt removal from the from the multi-port intake structure through the ESW pumphouse, including intake and alternate intake tunnels, associated tunnel riser shafts, discharge tunnel, and discharge structure. AMP XI.M41, Buried and Underground Piping and Tanks, manages aging effects for underground ESW piping. These activities are not managed by this program.

Enhancements

1. The implementing procedures for heat exchanger thermal performance testing will be enhanced to require each heat exchanger thermal performance periodic test

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 13 Page 2 of 2 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.

2. The OCCW program documentation will be revised as follows:

Include periodic maintenance inspections of the external portions of components submerged in the emergency service water pump bay:

Emergency Service Water pump casings for loss of material; Emergency Service Water screen wash pump casings for loss of material; Emergency Service Water traveling screens for loss of material and flow blockage; Motor driven fire pump casing and its suction strainer for loss of material and flow blockage; Diesel driven fire pump casing and its suction strainer for loss of material and flow blockage.

The minimum frequency of these inspections is once every operating cycle.

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

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 14 Page 1 of 12 4

LRA Section: Appendix A. Table A.3 LRA Page Number(s): Pages A-67 through A-70 and A-73

References:

NCSG RAI-10505-R1 Description of Change: PNPP LRA Table A.3 is revised based on the response to NCSG RAI-10505-R1. Enhancements have been revised in this table for Item 21, the XI.M27 aging management program, and additional enhancements added for Item 37, the XI.M20 aging management programs, consistent with the changes made to LRA Sections A.1.21, A.1.37, B.2.21 and B.2.37 (Attachments 12, 13, 15 and 16 of this letter).

PNPP LRA Table A.3, Pages A-67 through A-70 (XI.M27), as modified by Supplement 2 Vistra Letter L-24-20 and Supplement 7, Vistra Letter L-24-256, and Page A-73 (XI.M20), as modified by Supplement 5, L-24-179, is revised as follows: (next page)

Note: Only the affected table rows are presented on the following pages. No other changes are made to PNPP LRA Table A.3.

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 14 Page 2 of 12

Item No.

AMP Commitment Implementation Schedule Related LRA Sections 21 XI.M27 Complete the following enhancements to the existing Fire Water System Program:

The program will include inspections and testing consistent with Appendix L, Table 4a, Fire Water System Inspection and Testing Recommendations, of License Renewal Interim Staff Guidance LR-ISG-2012-02. Specific enhancements below must be considered in light of the program exceptions.

Sprinkler Systems:

Program documents will be enhanced to require visual inspection of all in-scope sprinklers in addition to those that are directly protecting safe shutdown equipment as specified in the Fire Protection Functional Specifications. The functional specifications in the Fire Protection Program describe inspecting sprinklers in fire areas containing safe shutdown equipment on an 18-month frequency. This frequency is applied for these additional sprinklers consistent with the currently required inspection of sprinklers in fire areas containing safe shutdown equipment. Where sprinklers are inaccessible during power operation, the frequency will be per each cycle (two years) instead of 18 months.

Program periodic inspection criteria will be revised to require sprinklers to be free of corrosion, foreign materials, and paint and installed in the correct orientation to meet May 8, 2026 A.1.21 B.2.21

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 14 Page 3 of 12

Item No.

AMP Commitment Implementation Schedule Related LRA Sections Section 5.2.1.1.1 criteria.

Program instructions will be enhanced to require inoperable sprinklers to be replaced. The criteria used to determine the impact on sprinkler operability include: when showing signs of (1) leakage (any), (2) severe corrosion, (3) physical damage, (4) loss of fluid in the glass bulb heat responsive element, (5) severe loading (e.g., with dust), or (6) painting unless painted by the sprinkler manufacturer; or (7) any sprinkler installed incorrectly. Additionally, Annex A of NFPA 25 regarding cleaning of dust loaded sprinklers will be adapted.

The program will be enhanced to perform representative sprinkler head sampling (laboratory field service testing) or replacement of sprinkler heads within the scope of license renewal prior to exceeding the in-service (installed) limits specified in the 2011 Edition of NFPA 25. In the case of testing, requirements are selected in accordance with the 2011 Edition of NFPA 25 and repeated at the specified intervals. Testing is continued through the period of extended operation, or until there are no untested sprinkler heads that will exceed the service limits through the remainder of the period of extended operation.

Standpipe and Hose Systems Program documentation will be revised, or new test instructions developed to add main drains testing of the in-scope water-based standpipes including

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 14 Page 4 of 12

Item No.

AMP Commitment Implementation Schedule Related LRA Sections those associated with automatic water suppression systems. Program documentation will require testing of 20% of the necessary standpipe systems every refueling outage/cycle. These tests will occur every 10 years and throughout the PEO.

Private Fire Service Mains Program documentation will be revised to acknowledge compliance per Section 7.3.1.3. of NFPA 25, where underground piping supplies individual fire sprinkler, standpipe, water spray, or foam-water sprinkler systems and there are no means to conduct full flow tests, tests generating the maximum available flows shall be permitted. (Note: PNPP does not have a foam water sprinkler system.)

Program documentation will be revised to require that flow tests shall be made at flows representative of those expected during a fire, for the purpose of comparing the friction loss characteristics of the pipe with those expected for the particular type of pipe involved, with due consideration given to the age of the pipe and to the results of previous flow tests. Any flow test results that indicate deterioration of available waterflow and pressure shall be investigated to the complete satisfaction of the authority having jurisdiction to ensure that the required flow and pressure are available for fire protection.

Program documentation will be revised to include a 60-minute hydrant drainage limit requirement

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 14 Page 5 of 12

Item No.

AMP Commitment Implementation Schedule Related LRA Sections during testing to meet Section 7.3.2.4, NFPA 25. A note will be added to include words to the effect that due to the Plant Foundation Underdrain system, groundwater level around the nuclear island does not normally reach the level of the relevant hydrants. PNPP monitors ground water level. However, if water level were to be too high or other conditions exist to prevent drainage, the hydrant drain shall be plugged and water in the barrel shall be pumped out.

Relevant test instructions will be revised to include a statement that dry barrel hydrants that are located in areas subject to freezing weather and that have plugged drains shall be identified clearly as needing pumping after operation.

Valves and System Wide Testing See enhancement for Main Drain Testing under Standpipe and Hose Systems above.

Main Drains Testing shall require identification and correction of the cause of any 10% reduction in full flow pressure.

Water Spray Fixed Systems PNPP Fire Protection Program documentation will be revised to require the removal, inspection for damaged and corroded parts, and cleaning of mainline strainers in water spray fixed nozzle systems in scope of License Renewal every 10 years 5 years consistent with Section 10.2.1.7 of NFPA

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 14 Page 6 of 12

Item No.

AMP Commitment Implementation Schedule Related LRA Sections 25, 2011 Edition. Adverse findings will be entered into the Corrective Action Program for evaluation for increased frequency of inspection and trending.

In addition to flush activities currently associated with periodic flow testing, PNPP Fire Protection Program documentation will be revised to ensure that mainline strainers are flushed after each actuation of an associated water spray fixed system.

Foam Water Systems PNPP Fire Protection Program documentation will be revised to require that the foam liquid storage tank shall be drained of foam liquid and flushed every 10 years.

Obstruction Investigation New PNPP Fire Protection Program documentation will be added to meet the requirements of NFPA 25, 2011 Edition, Section 14.2, Internal Inspection of Piping and Section 14.3 Obstruction Investigation and Prevention. Inspection scope established in other program elements or elsewhere in this program element, collectively referred to as existing enhancements, shall remain in effect. Where overlap or conflicts exist between existing enhancements and this enhancement: a) the existing enhancements shall take precedence, b) Section 14.2 requirements shall not apply to existing enhancements, and c) Section

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 14 Page 7 of 12

Item No.

AMP Commitment Implementation Schedule Related LRA Sections 14.3 guidance shall continue to apply to all inspection activities.

2. As an enhancement to detect aging effects of internal surfaces of buried piping, a portion of the aboveground inspection locations will be selected where above-grade and underground or buried piping environments and material are similar, the above-grade can be extrapolated to evaluate the condition of the underground or buried piping.

3. The program will be enhanced to require that when visual inspections are used to detect loss of material in the piping within the scope of license renewal, the inspection technique is capable of detecting surface irregularities that could indicate wall loss to below nominal pipe wall thickness due to corrosion and corrosion product deposition. Where such irregularities are detected, follow-up volumetric wall thickness examinations will be performed.

4. Enhancement i. below was implemented and identified piping configurations causing piping not to drain, hence Enhancement ii. is applicable at PNPP.

i.

Prior to the period of extended operation, all accessible dry pre-action, sprinkler, horizontal pipe configurations (including fittings and pipe components) within the scope of License Renewal were walked down to provide reasonable assurance that the as-built, flow path piping system may be drained without areas that will allow water to accumulate and

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 14 Page 8 of 12

Item No.

AMP Commitment Implementation Schedule Related LRA Sections potentially contain corrosion products that could block the installed sprinklers. For those portions that are inaccessible, as-built drawings were used to identify such configurations.

ii.

The program will be enhanced to include augmented testing and inspections beyond those of Table 4a for portions of water-based fire protection system components within the scope of license renewal that are (a) normally dry but periodically subjected to flow (e.g., dry-pipe or pre-action sprinkler system components) and (b) cannot be drained or allow water to collect. The augmented inspections and activities are:

1. Within 5 years prior to the PEO, inspect 100% of the subject piping segment locations for trapped water and any condition such as organic and inorganic materials that might cause blockage of the sprinkler heads if the system were actuated.

Any segments found to be wet or contain significant corrosion or organic matter will be cleaned and minimum wall thickness determined for the worst areas of wall loss.

Results will be entered into the Corrective Action Program (CAP) for disposition and correction, as required.

2. After the completion of these inspections, monitor and record all actuations of the dry sprinkler systems within the scope of License Renewal, and

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 14 Page 9 of 12

Item No.

AMP Commitment Implementation Schedule Related LRA Sections

3. For any system that actuates, ensure baseline conditions are established as noted in part 1 above prior to putting the dry sprinkler system back in service:, that the affected system piping segments that are the subject of this issue will be inspected and any pooling water eliminated; and the actuated system will be inspected per NFPA 25-2011 Section 14.2.1 by opening a flushing connection at the end of one main and by removing a sprinkler toward the end of one branch line for the purpose of inspecting for the presence of foreign organic and inorganic material.

5. Fire protection procedures will be revised, or new procedures developed to require periodic replacement of the coolant heat exchanger tube bundle on the Diesel Driven Fire Pump Engine during the period of extended operation at a frequency of every 14 years. The program will also require internal visual inspection of the heat exchanger shell and channel for loss of material, and inspection for internal tube fouling every 3 cycles (6 years) with remediation of adverse conditions (for example by performing cleaning or replacement of affected components). in conjunction with tube bundle replacement.

6. The program will provide that if the presence of sufficient foreign organic or inorganic material to obstruct pipe or sprinklers is detected during pipe

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 14 Page 10 of 12

Item No.

AMP Commitment Implementation Schedule Related LRA Sections inspections, the material will be removed, and its source will be determined and corrected.

7. The program will be augmented to perform periodic (initially, every other cycle, i.e., 4 year intervals),

nonintrusive pipe thickness measurement in above ground or underground (not buried), wetted, metallic Fire Water system piping. Each 4 year sample will include at least three locations for a total of 100 feet of piping. Locations selected will be based upon system susceptibility to corrosion, evidence of performance degradation during system flow testing or periodic flushes or prior wall thickness measurements. The method used will attempt to detect localized degradation in pipe wall thickness, e.g., Low Frequency Electromagnetic Technique (LFET), or equivalent. The idea is to use the method as a screening tool to identify "spots of interest" which are then followed up with ultrasonic (UT) testing or Phased Array Testing (PAUT) on the spots of interest. Additionally, proximity to Safety Related or high risk equipment will be favored locations when given equivalent susceptibility or evidentiary factors. Significant finding shall be entered into the Corrective Action Program for remediation and additional corrective actions. Significant findings will be any wall thickness less than min wall or localized minimum wall thickness more than 50% less when compared to its surroundings.

8. The program will be augmented for subsequent or existing leaks not yet repaired, when practical, to

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 14 Page 11 of 12

Item No.

AMP Commitment Implementation Schedule Related LRA Sections determine or confirm the corrosion mechanism(s) causing the leaks. The results will be processed through the Corrective Action Program to determine further actions and adjustments to the period of augmented inspections.

37 XI.M20 Complete the following enhancement to the existing Open Cycle Cooling Water System Program:

1. 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.

2. The OCCW System program documentation will be revised as follows:

May 8, 2026 A.1.37 B.2.37

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 14 Page 12 of 12

Item No.

AMP Commitment Implementation Schedule Related LRA Sections Include periodic maintenance inspections of the external portions of components submerged in the Emergency Service Water pump bay:

Emergency Service Water pump casings for loss of material; Emergency Service Water screen wash pump casings for loss of material; Emergency Service Water traveling screens for loss of material and flow blockage; Motor driven fire pump casing and its suction strainer for loss of material and flow blockage; Diesel driven fire pump casing and its suction strainer for loss of material and flow blockage.

The minimum frequency of these inspections is once every operating cycle.

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 15 Page 1 of 19 5

LRA Section: Section B.2.21 LRA Page Number(s): Pages B-69 through B-74

References:

NCSG RAI-10505-R1 (Questions 5, 7, and 9), Supplement 7 in Attachment 19 (Vistra Letter L-24-256)

Description of Change: PNPP LRA Sections B.2.21 is revised based upon the responses to NCSG RAI-10505-R1, Questions 5, 7, and 9 (Attachments 5, 7, and 9 of this letter). Two applicant-initiated clarifications are also provided to ensure the intent of programmatic enhancements are consistent throughout the program description. The clarification in the fourth enhancement under ii.3 was generated due to the response to Question 5.

PNPP Section B.2.21, Pages B-69 through B-74, as modified by Supplement 7 (Vistra Letter L-24-256) is revised as follows:

B.2.21 Fire Water System Program The Fire Water System Program (a sub-program of the overall Fire Protection Program) is an existing condition monitoring program that applies to the fire water supply and water-based suppression systems, which include sprinklers, nozzles, fittings, valve bodies, fire pump casings and heat exchanger, hydrants, hose stations, standpipes, a pressure maintenance tank, various retarding chambers (tank), Foam Liquid Storage Tank (component types Tank), and aboveground, buried and underground piping and components. The PNPP Firewater System does not have a fire water storage tank. The program conducts tests and inspections in accordance with applicable National Fire Protection Association (NFPA) codes and standards. These codes and standards will have enhanced flow testing and visual inspections performed in accordance with the 2011 Edition of NFPA 25 as described below.

The Fire Water System Program manages:

loss of material due to general, crevice, pitting corrosion, MIC, macrofouling leading to corrosion and recurring corrosion; flow blockage due to fouling; reduction in heat transfer (for the diesel driven fire pump engine); and, change in mechanical properties (cracking, loss of strength) and blistering of ASTM D-2996 fiberglass reinforced epoxy piping.

This program manages the aging effects using flow testing and visual inspections.

Reduction in heat transfer will be managed by periodic replacement of the cooling coil and through periodic visual inspections for fouling. In addition to NFPA codes and standards, those portions of the system that are (a) normally dry but periodically subject to flow (e.g., dry-pipe or pre-action sprinkler systems) and (b) cannot be drained or allow water to collect, are subjected to augmented testing or inspections prior to the PEO.

During the PEO, pre-action sprinklers will be monitored, and for those that actuate,

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 15 Page 2 of 19 similar inspections will be performed to ensure collected water in pipe segments is again removed. The program also performs augmented inspections to address loss of material due to recurring corrosion by performing periodic, non-intrusive pipe thickness measurement in above ground or underground, wetted, metallic fire protection piping.

The water-based fire protection system is normally maintained at required operating pressure and is monitored such that loss of system pressure is immediately detected and corrective actions initiated.

Sprinklers are replaced or a representative sample of sprinklers from one or more sample areas is tested to ensure that signs of degradation, such as corrosion, are detected in a timely manner and prior to exceeding the service life limits specified in the 2011 Edition of NFPA 25.

For the buried piping, visual inspections of the piping interior surfaces will be performed whenever the piping internal surface is made accessible due to maintenance and repair activities. Where above-grade and underground or buried piping environments and material are similar, the above-grade will be extrapolated to evaluate the condition of the underground or buried piping.

Consistent with NUREG-1801, other aging management programs are relied upon to manage aging effects in the Fire water system and are not considered exceptions.

NUREG-1801 Consistency The Fire Water System Program is an existing PNPP program that, with enhancement, will be consistent with the 10 elements of an effective aging management program as described in NUREG-1801,Section XI.M27, Fire Water System as revised by LR-ISG-2012-02 and LR-ISG-2013-01, with the following exceptions.

Exceptions to NUREG-1801:

The Fire Water System program has the following exceptions[1]:

Exception to NFPA Section Basis for the Exceptions Sprinkler Systems 5.2.1.1 Sprinklers shall be inspected from the floor level annually.

In lieu of annual inspections, PNPP will retain the current licensing basis inspection frequency. PNPP performs the sprinkler inspections once every 18 months, unless the inspection is in a high radiation area, in which case the inspection is As indicated in Note 5 to Table 4a of LR-ISG-2012-02, access for some inspections is feasible only during refueling outages, which are scheduled every 24 months. All sprinkler systems protecting safe shutdown equipment are in scope of license renewal; other sprinkler systems are also in scope as delineated on the scoping drawings.

Inspections currently conducted in areas with safe shutdown equipment every 18 months have been satisfactory and demonstrate that more frequent inspections would not result in

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 15 Page 3 of 19 Exception to NFPA Section Basis for the Exceptions performed every refueling cycle (24 month cycle).

any different conclusion. A search of internal OE has shown very few CRs regarding obstructions and none are age related conditions but are latent or design issues.

Standpipe and Hose Systems 6.3.1.1 A flow test shall be conducted every 5 years at the hydraulically most remote hose connections of each zone of an automatic standpipe system to verify the water supply still provides the design pressure at the required flow.

In lieu of adopting this code paragraph as a new requirement, PNPP will retain the current licensing basis testing requirements which demonstrate adequacy of the water supply.

Every 3 years, PNPP performs main header flow testing in the main headers that supply the standpipe system to verify that the water supply provides the largest demand design flow plus 500 gpm for hose streams over the longest route and verifies friction losses are within values used to determine design flow at design pressure based upon the measured discharge pressure and flow of a single fire pump. PNPP also performs fire pump full flow tests on an 18-month frequency.

To flow test the hydraulically most remote hose connection of the automatic standpipe system in a manner that would provide sufficient information to verify design pressure and flow would generate a large quantity of liquid that is potentially radwaste and could create a risk of wetting components critical to normal and shut down operations.

By not performing additional flow testing, the potential for creating radwaste and increasing operational risk is reduced.

Every 3 years, PNPP partially opens hose station supply valves and confirms no flow blockage for the hoses listed in the Fire Protection Functional Specifications.

PNPP will perform main drain tests on 20 percent of the license renewal in-scope standpipes and risers requiring fire suppression functionality each refueling outage/cycle. Acceptance criteria will consist of ensuring an open flow path by verifying valve operability and flow through valve and connections with no indication of obstruction or undue restriction of water flow.

Section 6.3.1 has been revised in the 2014 Edition of NFPA 25 to indicate this testing provision is only applicable to Class I and Class III standpipe systems. PNPP interior hose stations are designed for Class II service.

6.3.1.5 A main drain test shall be performed on all standpipe systems with automatic water supplies in accordance with the requirements of Chapter 13.

As indicated by the Note 5 in Appendix D, Table 4a of LR-ISG-2012-02, access for some inspections is feasible only during refueling outages, which are scheduled every 24 months. The number of tests to be conducted every 24 months was found to exceed the

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 15 Page 4 of 19 Exception to NFPA Section Basis for the Exceptions In lieu of adopting this code paragraph, PNPP will adopt a sample-based testing program for main drain tests. By reference to Chapter 13 (Paragraph 13.2.5),

Paragraph 6.3.1.5 invokes an annual frequency for the main drain tests.

The sample-based approach will include 20% of the in-scope systems, tested on 24-month intervals.

number of recommended tests or inspections (i.e., 25) in several sampling-based AMPs (e.g.,

XI.M38). This number of tests supports the decision that the exception still allows the plant to establish a trend if major flow blockage is occurring which is the stated purpose of this testing per the Annex A material provided in Section A.13.2.5. Main drain tests on 20 percent of the standpipes and risers every 24 months provide adequate information to determine if the condition of fire water piping is maintained consistent with design basis. Furthermore, current testing of hose stations for flow blockage every 3 years and program requirements to verify valve positions as listed below provides reasonable assurance that a trend of flow blockage would be established if it were occurring.

Valve position verification:

Existing FP program includes valve position verification which addresses, in part, the considerations of a main drain test as explained in Annex A of the Code.

Fire Pumps 8.3.3.7 Suction Screens. After the waterflow portions of the annual test or fire protection system activations, the suction screens shall be inspected and cleared of any debris or obstructions.

From Annex A: A.8.3.3.7 During periods of unusual water supply conditions such as floods, inspection should be on a daily basis.

In lieu of adopting this requirement from the Code, PNPP will credit the inherent design features provided by the plant intake structure and ESW Pumphouse physical arrangement. Due to the design of Requiring inspection of the fire pump suction screens in the Emergency Service Water Pumphouse Suction Bay would require diving activities at least every nine months given frequency of fire pump full flow tests. This is unnecessary given the design of the upstream inlet pipe configuration taking suction from the lake, Emergency Service Water Pumphouse traveling screens, smaller mesh size, and alternative aging management activities for the traveling screens. The aging effects of the traveling screens is managed by the Open-Cycle Cooling Water System Program.

The design of the ESW system pump forebay incorporates traveling screens for removing submerged debris that may have entered through the intake structure. The water inlet

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 15 Page 5 of 19 Exception to NFPA Section Basis for the Exceptions the supply inlet and filtering of water from the lake to the Emergency Service Water Pumphouse Suction Bay, PNPP does not require monitoring of the suction screens on the fire pumps after the waterflow portions of the periodic tests, fire protection system activations nor during periods of unusual water supply conditions such as floods.

is located more than one quarter mile offshore and submerged more than 15 feet below the surface of the lake. In order for debris to enter the ESW Pumphouse forebay, the debris would have to be submerged to the elevation of the intake structure, travel approximately 100 feet vertically downward, travel approximately 3,000 feet horizontally, and then rise vertically approximately 100 feet to the ESW Pumphouse forebay. Also, the intake system is designed for an approach velocity of 0.5 fps which diminishes the uptake of debris. These features are intended to prevent any significant amount of debris from entering the ESW Pumphouse forebay and clogging the travelling screens.

Water entering the suction bay travels passed a basket mesh opening of 0.375 inch in the traveling screens. If differential level from forebay to suction bay across the traveling screens exceeds 6 inches, the ESW Screen Wash pumps start, and the traveling screens start in slow speed. If the ESW Traveling Screen difference in level exceeds 10 inches, the screen shifts to fast speed. Control room alarms are provided based upon exceeding the high level difference across the traveling screens. The physical size and mesh size of the ESW traveling screens are intended for the ESW pump operation and therefore it is highly unlikely any significant level difference would be expected when a fire pump is operating alone.

The fire pump inlet strainer is a basket type suction strainer with a free area of at least four times the area of the suction connection and openings of such size to restrict the passage of a 1/2-inch sphere.

Since the traveling screens mesh size is smaller than the inlet strainer of the fire pumps, any debris entering from the lake would pass through the pump and therefore

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 15 Page 6 of 19 Exception to NFPA Section Basis for the Exceptions blockage of the inlet strainer is highly unlikely.

A search of internal condition reports in the corrective action database did not find any instances of flow blockage in fire pump suction strainers.

Valves and System-Wide Testing 13.2.5* Main Drain Test. A main drain test shall be conducted annually at each water-based fire protection system riser to determine whether there has been a change in the condition of the water supply piping and control valves. (See also 13.3.3.4.)

13.3.3.4 A main drain test shall be conducted any time the control valve is closed and reopened at system riser.

The enhancement associated with Standpipe and Hose Systems will add main drains testing to 20% of in scope water-based standpipe systems including those supplying automatic water suppression systems every refueling outage /

operating cycle (24 months) rather than all standpipe systems annually, as required by Chapter 13 of NFPA

25.

The addition of main drain tests in enhancements under to the PNPP Fire Water Program provides compliance with this section of NFPA 25 in meeting main drains test requirement. The exception is in the number of tests and to perform them annually. See the basis for exception under 6.3.1.5.

13.4.3.2.2* Each deluge valve shall be trip tested annually at full flow in warm weather and in accordance with the manufacturers instructions.

From Annex A: A.13.4.3.2.2 *Pre-action and deluge valves in areas subject to freezing should be trip tested in the spring to allow time before the onset of cold weather for all water that has entered the system Regarding the annual testing requirement, it should be noted that the corresponding table in NUREG-2191 Volume 2, Table XI.M27-1 contains Note 10, Where NFPA 25 or this table cite annual testing or inspections, testing and inspections can be conducted on a refueling outage interval if plant-specific OE has shown no loss of intended function of the in-scope systems due to aging effects being managed for the specific component (e.g., loss of material, flow blockage due to fouling).

Furthermore, as noted, NFPA 25 section

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 15 Page 7 of 19 Exception to NFPA Section Basis for the Exceptions or condensation to drain to low points or back to the valve.

In lieu of the above requirement, PNPP will continue to utilize the current licensing basis testing frequencies.

PNPP conducts trip tests on open spray deluge valves in the scope of license renewal with full flow during shutdowns for refueling in accordance with 13.4.3.2.2.3. Other Deluge valve subsystems falling under sections 13.4.3.2.2.2 are tested with the supply isolation valves closed (equivalent to control valves per Chapter 3 of NFPA 25) every 18 months. These systems include dry piping pre-action systems with closed sprinkler heads and ventilation filter deluge spray systems with open sprays. In the latter cases damage to equipment would occur if conducted at full or partial flow. The use of this exception is discussed below within this section and pre-action deluge valve testing is discussed below under Section 13.4.3.2.3 and 13.3.2.4.

For testing meeting the conditions under Section 13.4.3.2.2.2, PNPP trip testing of deluge valves with the isolation valve closed traps water pressure between the isolation valve and trip valve prior to actuation.

The trapped pressure causes the valve to pop open when tripped.

Any valve that fails to open is considered a failure and entered into the corrective action program to evaluate and take required corrective actions.

13.4.3.2.2.3 permits waiting when testing is possible without risking equipment damage and plant transients due to energized electrical components. Although partial blockage occurs in outdoor open spray deluge testing of transformers, the spray patterns have been found acceptable. Each time partial blockage is identified the blockages are cleared. Thus, plant specific OE supports continued testing at a frequency of each refueling outage.

Hydrogen Seal Oil deluge valve open spray system:

PNPP proposes to maintain the 5-year interval for full flow testing of the Hydrogen Seal Oil deluge system. Hydrogen Seal Oil spray nozzle and piping are located completely with an enclosed structure, i.e., the Turbine Building. Since the piping and nozzles are indoors, these nozzles are not subject to freezing, outdoor cycles, moisture, nor biological intrusion. This makes plugging of nozzles unlikely. During the full flow test every 5 years, water flow is captured and processed within the liquid radwaste systems.

Due to having only 8 nozzles it is estimated that at least 500 gallons of radwaste would be generated. The Hydrogen Seal Oil deluge valve trip test is conducted at a frequency of every 12 months. To further support this exception, the history of Hydrogen Seal Oil full flow spray testing since 2007 through 2021 there has been no identified plugged or partially plugged nozzles. In contrast and to further support this exception, the difference between indoor Hydrogen Seal Oil testing and outdoor testing of open spray nozzles is illustrated as follows. In 2019, a condition report was written documenting 97 examples of outdoor, open spray nozzles found to have some level of partially plugging in a four-year period from 2016 thru 2019. The affected nozzles were found to have an acceptable spray pattern and were subsequent cleaned.

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 15 Page 8 of 19 Exception to NFPA Section Basis for the Exceptions Considering the above, the exception is not with the method of trip testing every 18 months but with the requirement for annual testing.

Further, full flow testing of the spray subsystem protecting Hydrogen Seal Oil system equipment are conducted every 5 years and trip tests with the supply isolation valve closed (equivalent control valve closed) are conducted annually.

NFPA 25, 13.4.3.2.2.2 states: Where the nature of the protected property is such that water cannot be discharged for test purposes, the trip test shall be conducted in a manner that does not necessitate discharge in the protected area. The PNPP deluge valves associated with spray systems protecting ventilation filter / charcoal plenums are trip tested with isolation valves closed as described above to protect the equipment that would be damaged by water spray. Additionally, these tests verify that the ventilation plenum drain valves open upon activation of the spray system. PNPP deluge valves with spray systems protecting ventilation filter /

charcoal plenums are discussed further in the exception for 13.4.3.2.2.5 below.

NFPA 25, 13.4.3.2.2.3, where the nature of the protected property is such that water cannot be discharged unless protected equipment is shut down (e.g.,

energized electrical equipment), a full flow system test shall be As noted above, over the past 17 years no instances of plugging of indoor Hydrogen Seal Oil open spray nozzles were noted in the work order notes and a search of OE found no condition reports regarding plugging of the HSO nozzles.

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 15 Page 9 of 19 Exception to NFPA Section Basis for the Exceptions conducted at the next scheduled shutdown.

Deluge water open spray systems protecting ventilation filter plenums and closed sprinkler head pre-action systems that protect sensitive equipment in the cable spreading rooms and main turbine bearings meet this requirement. An exception for these pre-action systems is discussed further under 13.4.3.2.3 and 13.4.3.2.4 13.4.3.2.2.5 The water discharge patterns from all of the open spray nozzles or sprinklers shall be observed to ensure that patterns are not impeded by plugged nozzles, that nozzles are correctly positioned, and that obstructions do not prevent discharge patterns from wetting surfaces to be protected.

13.4.3.2.2.5 (A) Where the nature of the protected property is such that water cannot be discharged, the nozzles or open sprinklers shall be inspected for correct orientation and the system tested with air to ensure that the nozzles are not obstructed.

In lieu of the above, PNPP will continue to utilize the testing approved in the plants CLB.

Ventilation filter unit plenums in scope cannot be tested with water and have no provisions to perform an air test to verify that the spray openings are not obstructed.

Ventilation filter unit plenums in scope cannot be tested with water and have no provisions to perform an air test to verify that the spray openings are not obstructed. The Fire Protection Program Functional Specifications requires that each charcoal filter plenum spray header/nozzle is visually inspected each time the charcoal is changed.

This activity will ensure that there are no debris locally that would obstruct the spray nozzles if the spray system were actuated.

13.4.3.2.3 Except for pre-action systems covered by 13.4.3.2.5, every 3 years the pre-action valve shall be trip tested with the control valve fully open.

Pre-action system:

Trip testing the pre-action valves with the control valve fully open would allow fire water to enter the normally dry portion of the system in the case of dry pipe systems which

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 15 Page 10 of 19 Exception to NFPA Section Basis for the Exceptions 13.4.3.2.4 During those years when full flow testing in accordance with 13.4.3.2.3 is not required, the pre-action valve shall be trip tested with the control valve partially open.

In lieu of the above requirements from the Code, PNPP will continue to utilize the testing frequency and scope prescribed in the plants current license basis. PNPP pre-action systems are tested with the isolation valves closed (Equivalent to control valve per NFPA 25 definitions Chapter 3) every 18 months.

The method of trip testing of the pre-action deluge valves is the same as the method discussed for the deluge valves serving open spray systems and is not repeated here.

The pre-action system testing falls under allowances described in paragraph 13.4.3.2.2.2 and are not considered exceptions, but for clarity, the basis for exception expands upon this.

is trying to be avoided. In addition, there is a potential for wetting equipment critical to normal and shut down operations if one of the closed sprinkler heads actuate.

PNPP proposes to maintain the current testing intervals on the basis that PNPP has demonstrated adequate performance and that adopting a more frequent testing regimen is not expected to improve system performance or availability but adds to the risk.

Furthermore, The corresponding table in NUREG-2191 Volume 2, Table XI.M27-1 contains Note 10 Where NFPA 25 or this table cite annual testing or inspections, testing and inspections can be conducted on a refueling outage interval if plant-specific OE has shown no loss of intended function of the in-scope systems due to aging effects being managed for the specific component (e.g., loss of material, flow blockage due to fouling).

PNPP meets this condition by testing at the current frequency.

To ensure these systems will perform the intended function throughout the PEO, PNPP proposes trip testing and inspections that ensure the downstream piping is free of matter that might plug system sprinklers if the system were actuated. As noted in enhancement ii, augmented inspections of portions of water-based fire protection system components within the scope of license renewal that are (a) normally dry but periodically subjected to flow (e.g., dry-pipe or pre-action sprinkler system components) and (b) cannot be drained or allow water to collect, three (3) activities will be performed.

These activities provide a baseline for ensuring that the piping does not contain inorganic or organic materials that could plug downstream sprinklers upon a system actuation. Further, they include continual monitoring of the system for actuation, and if actuated, restores the piping to the baseline condition before restoring the system to

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 15 Page 11 of 19 Exception to NFPA Section Basis for the Exceptions service. Collectively this enhancement ensures the piping system is clear and the new enhancement for performing main drains testing ensures the in-scope systems can perform its intended function throughout the PEO. The in-scope pre-action sprinkler systems are the Unit 1 and 2 Cable Spreading Divisions 1 and 2 systems and the Unit 1 Main Turbine Driven Pump Bearings Pre-action systems. The downstream piping in the Unit 1 Main Turbine Driven Pump Bearings Pre-action systems is dismantled periodically during refueling outages in conjunction with main turbine maintenance. In essence, if corrosion or inorganic materials would be discovered this condition would be entered into the Corrective Action Program to evaluate and take corrective actions.

Water Spray Fixed Systems 10.2.1.7 Mainline strainers shall be removed and inspected every 5 years for damaged and corroded parts.

In lieu of the above five-year requirement, PNPP will perform this activity on a ten-year frequency.

PNPP Fire Protection Program inspects mainline supply strainers for damage including corrosion and flow blockage from organic and inorganic debris in water spray fixed nozzle systems in scope of License Renewal every 10 years. Adverse findings are entered into the corrective action program for evaluation for increased frequency of inspection and for trending.

PNPP internal operating experience demonstrates that the current frequency of inspection is adequate to support fixed water system sprays. Except for testing the Hydrogen Seal Oil fixed water spray systems every 5 years, the other spray systems in scope of License Renewal are tested every refueling cycle.

10.2.7* Strainers.

10.2.7.1 Mainline strainers (basket or screen) shall be flushed until clear after each operation or flow test.

Strainer flush lines are connected to the floor drain system piping and discharge cannot be viewed directly. However, flush water can be viewed through sight glass provided in the flush connection. Floor drains are susceptible to backing up when subjected to high in-flow rates. The testing recommends that personnel

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 15 Page 12 of 19 Exception to NFPA Section Basis for the Exceptions From Annex A: A.10.2.7 *Mainline strainers should be removed and inspected for damaged and corroded parts every 5 years.

Due to system design limitations, PNPP will not explicitly confirm the flushed until clear portion of this requirement.

PNPP full flow tests of each fixed open spray system includes steps to flush the associated main line strainer after flow testing of all associated fixed spray system tests are completed. These tests are performed every refueling outage.

Guidance is provided to limit flush water flowrate to prevent backup of floor drains. During flush operation, the strainer handwheel is rotated a full 2 turns. Flush water can be viewed through sight glass provided in the flush connection. Due to limitations on ability to confirm flush water is clear, flush water clarity is not included in guidance.

See enhancement 1, under Water Spray Fixed Systems, 1st Bullet, inspection of mainline strainers will meet requirements of NFPA 25-2011 Section 10.2.1.7. See response to exception in 10.2.1.7 above.

be staged on each floor between the flushing elevation and the sump pit elevation to monitor for backup. Water back-up out of the floor drains shall be treated as potentially contaminated. Guidance encourages limiting flush time to as minimal as possible.

Nevertheless, strainers are cycled two turns during flush operation to ensure debris removal.

Operating experience has demonstrated that these activities have been successful in maintaining strainers without having any significant blockage. Consequently, due to system design limitations, PNPP will not explicitly confirm the flushed until clear portion of this requirement but has presented a successful alternative.

Notes:

1.

Exceptions are not taken when the equipment discussed in the requirement does not exist at PNPP.

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 15 Page 13 of 19 Enhancements:

Unless otherwise noted, the following enhancements will be implemented in the identified program elements no later than six months prior to the period of extended operation.

The program will be enhanced to include inspections and testing consistent with Appendix L, Table 4a, Fire Water System Inspection and Testing Recommendations, of License Renewal Interim Staff Guidance LR-ISG-2012-02. Specific enhancements in the table below must be considered in light of the program exceptions.

Sprinkler Systems:

Program documents will be enhanced to require visual inspection of all in-scope sprinklers in addition to those that are directly protecting safe shutdown equipment as specified in the Fire Protection Functional Specifications. The functional specifications in the Fire Protection Program describe inspecting sprinklers in fire areas containing safe shutdown equipment on an 18-month frequency. This frequency is applied for these additional sprinklers consistent with the currently required inspection of sprinklers in fire areas containing safe shutdown equipment. Where sprinklers are inaccessible during power operations, the frequency will be per each cycle (two years) instead of 18 months.

Program periodic inspection criteria will be revised to require sprinklers to be free of corrosion, foreign materials, and paint and installed in the correct orientation to meet Section 5.2.1.1.1 criteria.

Program instructions will be enhanced to require inoperable sprinklers to be replaced. The criteria used to determine the impact on sprinkler operability include: when showing signs of (1) leakage (any), (2) severe corrosion, (3) physical damage, (4) loss of fluid in the glass bulb heat responsive element, (5) severe loading (e.g., with dust), or (6) painting unless painted by the sprinkler manufacturer; or (7) any sprinkler installed incorrectly. Additionally, Annex A of NFPA 25 regarding cleaning of dust loaded sprinklers will be adapted.

The program will be enhanced to perform representative sprinkler head sampling (laboratory field service testing) or replacement of sprinkler heads within the scope of license renewal prior to exceeding the in-service (installed) limits specified in the 2011 Edition of NFPA 25. In the case of testing, requirements are selected in accordance with the 2011 Edition of NFPA 25 and repeated at the specified intervals. Testing is continued through the period of extended operation, or until there are no untested sprinkler heads that will exceed the service limits through the remainder of the period of extended operation.

Standpipe and Hose Systems

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 15 Page 14 of 19 Program documentation will be revised, or new test instructions developed to add main drains testing of the in-scope water-based standpipes including those associated with automatic water suppression systems.

Program documentation will require testing of 20% of the necessary standpipe systems every refueling outage/cycle. These tests will occur every 10 years and throughout the PEO.

Private Fire Service Mains Program documentation will be revised to acknowledge compliance per Section 7.3.1.3 of NFPA 25, where underground piping supplies individual fire sprinkler, standpipe, water spray, or foam-water sprinkler systems and there are no means to conduct full flow tests, tests generating the maximum available flows shall be permitted. (Note: PNPP does not have a foam water sprinkler system.)

Program documentation will be revised to require that flow tests shall be made at flows representative of those expected during a fire, for the purpose of comparing the friction loss characteristics of the pipe with those expected for the particular type of pipe involved, with due consideration given to the age of the pipe and to the results of previous flow tests. Any flow test results that indicate deterioration of available waterflow and pressure shall be investigated to the complete satisfaction of the authority having jurisdiction to ensure that the required flow and pressure are available for fire protection.

Program documentation will be revised to include a 60-minute hydrant drainage limit requirement during testing to meet Section 7.3.2.4, NFPA 25.

A note will be added to include words to the effect that due to the Plant Foundation Underdrain system, groundwater level around the nuclear island does not normally reach the level of the relevant hydrants. PNPP monitors ground water level. However, if water level were to be too high or other conditions exist to prevent drainage, the hydrant drain shall be plugged and water in the barrel shall be pumped out.

Relevant test instructions will be revised to include a statement that dry barrel hydrants that are located in areas subject to freezing weather and that have plugged drains shall be identified clearly as needing pumping after operation.

Valves and System Wide Testing See enhancement for Main Drain Testing under Standpipe and Hose Systems above.

Main Drains Testing shall require identification and correction of the cause of any 10% reduction in full flow pressure.

Water Spray Fixed Systems

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 15 Page 15 of 19 PNPP Fire Protection Program documentation will be revised to require the removal, inspection for damaged and corroded parts, and cleaning of mainline strainers in water spray fixed nozzle systems in scope of License Renewal every 10 years 5 years consistent with Section 10.2.1.7 of NFPA 25, 2011 Edition. Adverse findings will be entered into the Corrective Action Program for evaluation for increased frequency of inspection and trending.

In addition to flush activities currently associated with periodic flow testing, PNPP Fire Protection Program documentation will be revised to ensure that mainline strainers are flushed after each actuation of an associated water spray fixed system.

Foam Water Systems PNPP Fire Protection Program documentation will be revised to require that the foam liquid storage tank shall be drained of foam liquid and flushed every 10 years.

Obstruction Investigation New PNPP Fire Protection Program documentation will be added to meet the requirements of NFPA 25, 2011 Edition, Section 14.2, Internal Inspection of Piping and Section 14.3 Obstruction Investigation and Prevention. Inspection scope established in other program elements or elsewhere in this program element, collectively referred to as existing enhancements, shall remain in effect. Where overlap or conflicts exist between existing enhancements and this enhancement: a) the existing enhancements shall take precedence, b) Section 14.2 requirements shall not apply to existing enhancements, and c) Section 14.3 guidance shall continue to apply to all inspection activities.

Program Element Affected: Detection of Aging Effects (Element 4)

As an enhancement to detect aging effects of internal surfaces of buried piping, a portion of the aboveground inspection locations will be selected where above-grade and underground or buried piping environments and material are similar, the above-grade will be extrapolated to evaluate the condition of the underground or buried piping.

Program Elements Affected: Parameters Monitored (Element 3) and Detection of Aging Effects (Element 4)

The program will be enhanced to require that when visual inspections are used to detect loss of material in the piping within the scope of license renewal, the inspection technique is capable of detecting surface irregularities that could indicate wall loss to below nominal pipe wall thickness due to corrosion and corrosion product deposition.

Where such irregularities are detected, follow-up volumetric wall thickness examinations

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 15 Page 16 of 19 will be performed. Program Elements Affected: Parameters Monitored (Element 3) and Detection of Aging Effects (Element 4)

Enhancement i. below was implemented and identified piping configurations causing piping not to drain, hence Enhancement ii. is applicable at PNPP.

i)

Prior to the period of extended operation, all accessible dry pre-action, sprinkler, horizontal pipe configurations (including fittings and pipe components) within the scope of License Renewal were walked down to provide reasonable assurance that the as-built, flow path piping system may be drained without areas that will allow water to accumulate and potentially contain corrosion products that could block the installed sprinklers. For those portions that are inaccessible, as-built drawings were used to identify such configurations:

ii)

The program will be enhanced to include augmented testing and inspections beyond those of Table 4a for portions of water-based fire protection system components within the scope of license renewal that are (a) normally dry but periodically subjected to flow (e.g., dry-pipe or pre-action sprinkler system components) and (b) cannot be drained or allow water to collect. The augmented inspections and activities are:

1. Within 5 years prior to the PEO, inspect 100% of the subject piping segment locations for trapped water and any condition such as organic and inorganic materials that might cause blockage of the sprinkler heads if the system were actuated. Any segments found to be wet or contain significant corrosion or organic matter will be cleaned and minimum wall thickness determined for the worst areas of wall loss. Results will be entered into the Corrective Action Program (CAP) for disposition and correction, as required.

2. After the completion of these inspections, monitor and record all actuations of the dry sprinkler systems within the scope of License Renewal, and

3. For any system that actuates, ensure baseline conditions are established as noted in part 1 above prior to putting the dry sprinkler system back in service:, that the affected system piping segments that are the subject of this issue will be inspected and any pooling water eliminated; and the actuated system will be inspected per NFPA 25-2011 Section 14.2.1 by opening a flushing connection at the end of one main and by removing a sprinkler toward the end of one branch line for the purpose of inspecting for the presence of foreign organic and inorganic material. Program Elements Affected: Parameters Monitored (Element 3), Detection of Aging Effects (Element 4), and Operating Experience (Element 10)

Fire protection procedures will be revised, or new procedures developed to require periodic replacement of the coolant heat exchanger tube bundle on the Diesel Driven Fire Pump Engine during the period of extended operation at a frequency of every 14 years. The program will also require internal visual inspection of the heat exchanger shell and channel for loss of material, and inspection for internal tube fouling every

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 15 Page 17 of 19 3 cycles (6 years) with remediation of adverse conditions (for example by performing cleaning or replacement of affected components). in conjunction with tube bundle replacement. Program Element Affected: Detection of Aging Effects (Element 4)

The program will be enhanced to provide that if the presence of sufficient foreign organic or inorganic material to obstruct pipe or sprinklers is detected during pipe inspections, the material will be removed and its source will be determined and corrected. Program Elements Affected: Acceptance Criteria (Element 6)

The program will be augmented to perform periodic (initially, every other cycle, i.e., 4 year intervals), nonintrusive pipe thickness measurement in above ground or underground (not buried), wetted, metallic Fire Water system piping. Each 4 year sample will include at least three locations for a total of 100 feet of piping. Locations selected will be based upon system susceptibility to corrosion, evidence of performance degradation during system flow testing or periodic flushes or prior wall thickness measurements. The method used will attempt to detect localized degradation in pipe wall thickness, e.g., Low Frequency Electromagnetic Technique (LFET), or equivalent. The idea is to use the method as a screening tool to identify "spots of interest" which are then followed up with ultrasonic (UT) testing or Phased Array Testing (PAUT) on the spots of interest. Additionally, proximity to Safety Related or high risk equipment will be favored locations when given equivalent susceptibility or evidentiary factors.

Significant findings shall be entered into the Corrective Action Program for remediation and additional corrective actions. Significant findings will be any wall thickness less than min wall or localized minimum wall thickness more than 50% less when compared to its surroundings. Program Elements Affected: Parameters Monitored (Element 3),

Detection of Aging Effects (Element 4), and Acceptance Criteria (Element 6)

The program will be augmented for subsequent or existing leaks not yet repaired, when practical, to determine or confirm the corrosion mechanism(s) causing the leaks. The results will be processed through the Corrective Action Program to determine further actions and adjustments to the period of augmented inspections. Program Elements Affected: Preventive Actions (Element 2)

Operating Experience The following operating experience examples provide objective evidence that the Fire Water System 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 Fire Water System program is a subsystem in the XI.M26, Fire Protection Program.

Operating experience related to programmatic issues in the Fire Water System Program are addressed in the XI.M26, Fire Protection Program. Two instances of procedure weaknesses were also Identified and addressed during audits from outside agencies.

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 15 Page 18 of 19 Between 2013 and January 31, 2023, there were thirty-five (35) condition reports (CR) identified in the site OE that are considered age related. Eighty percent (28 CRs) were associated with leaks in piping. Of the 28 CRs, 12 CRs are characterized as above ground pin hole leaks. Seven 7 CRs are from buried pipe and 9 CRs of the remaining above ground leaks ranged from 10 dpm to a separated 6 pipe. Six (6) of the 35 age related CRs were associated with flow blockage and one of these 6 CRs involved a recent investigation of multiple occurrences. Finally, one CR involved a severely eroded jockey pump casing.

The PNPP OE reviewed covers a longer time span than the 10 years cited above. The observed OE events have been consistent through the monitored time period. The Fire Water System Program including the Corrective Action Program has shown to be consistent at identifying, repairing and/or replacing degrading equipment. More importantly, these examples demonstrate that this condition monitoring program will continue to be effective at maintaining the intended functions through the period of extended operation.

LR-ISG-2012-02 has been issued which addresses instances of recurring internal corrosion. A review of the PNPP operating experience determined that recurring internal corrosion has been experienced in the Fire Protection System with a frequency that is consistent with the thresholds discussed in LR-ISG-2012-02. The steel Fire Protection System piping is subjected to localized pitting; however, the pitting is not indicative of a gross degradation of the system. The localized pitting is due to the use of untreated lake water.

There have been numerous instances where one or more transformer deluge spray nozzles have had either partial or full obstructions due to scaling deposits. Transformer deluge systems are not required to protect safe shutdown components as noted in Section 2.1.2 above. Blockage affected the designed spray pattern, but the restricted nozzles were still capable of performing their fire suppression ability in a transformer fire. The blocked nozzles were cleaned. Regular water flow tests are performed to flush out the rust and scaling in the system.

Operating experience shows that issues are addressed quickly via the Corrective Action Program and work scheduled based upon significance.

External Industry OE were reviewed for applicability to the XI.M27 program. No new aging effects were identified. NUREG-2191 (GALL-SLR) has identified ductile iron as being susceptible to selective leaching and be managed under the Selective Leaching AMP XI.M33. Ductile iron components in the Fire Water system are included with components labeled as gray cast iron in the aging management review tables and are assigned the same aging effects. Additionally, the internal OE is consistent with the industry OE identified as applicable by the SME. The NUREG-1801 program is based upon industry OE and the applicable industry standards meant to address these concerns. Since the PNPP AMP is consistent with the NUREG-1801 program as modified by the applicable ISG and Subsequent LR program information, it is reasonable to conclude the PNPP condition monitoring and performance monitoring program is capable of management of the identified aging effects.

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 15 Page 19 of 19 In November, 2024, during the performance of periodic testing, a high water temperature alarm was received for the diesel driven fire pump engine. The local panel alarmed, and an incidental amount of engine coolant discharged from the engine cooler cap. In response to the event, the engine was secured before completion of the test. Upon inspection and disassembly three adverse conditions were identified: Local temperature indication for the engine was degraded, the engine water pump belt was broken, and the raw water side of the engine cooler was significantly fouled with silt. Of these issues, only loss of heat transfer due to heat exchanger fouling is subject to aging management. Although raw water cooled, the diesel driven fire pump engine cooler is considered an integral part of the diesel driven fire pump engine, and is age managed under the fire water aging management program. Based on this November 2024 site event, an additional enhancement has been added to the fire water program for periodic inspection (six year frequency) of the diesel driven fire pump heat exchanger.

IN 2013-06, Corrosion in Fire Protection Piping due to Air and Water Interaction, included operating experience from PNPP, Unit 1. IN 2013-06 is also identified in Volume 2 of NUREG-2191. Corrosion was identified internal to the galvanized steel piping in one of the dry, pre-action sprinkler systems. Corrosion was identified as a cause of flow blockage at other Nuclear Plants. The cause of the corrosion was incomplete drainage of a pre-action sprinkler piping, which violates the code of record, NFPA-13 Edition 1972.

The corrective actions in a 2012 Condition Report addressed the required modification and evaluations related to the relevant industry OE.

Based on the preceding, there are no locations identified that are normally dry but periodically wetted and cannot be drained or allow water to collect. However, there were no documented extent of condition reviews identified in dry piping within the scope of license renewal. Enhancement (i) in this section was modified to address this concern. A 2024 condition report documents the results of the walkdown indicating the areas that will allow water to accumulate after the system is drained using the piping drain valves.

Conclusion The Fire Water System Program has been effective at managing aging effects. The continued implementation of the program, with enhancements, provides reasonable assurance that the effects of aging will be managed such that applicable components will continue to perform their intended functions consistent with the current licensing basis through the period of extended operation.

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 16 Page 1 of 6 6

LRA Section: Appendix B, Section B.2.37 LRA Page Number(s): B-103 through B-107

References:

NCSG RAI-10505-R1 Description of Change: The OCCW Program description is revised to add new programmatic enhancements as a result of the responses to NCSG RAI-10505-R1, Question 4 (Attachment 4 of this letter). Specifically, enhancements are added to expand the scope of the OCCW Program to perform aging management of submerged portions of ESW and Fire Water Pumps. Changes to the referenced operating experience is also provided, related to the expanded programmatic scope.

PNPP LRA, Appendix B, Section B.2.37, Page B-103 through B-107 are revised as follows:

B.2.37 OPEN-CYCLE COOLING WATER SYSTEM PROGRAM Program Description The open-cycle cooling water (OCCW) systems program is an existing program that manages material loss due to micro-or macro-organisms and various corrosion mechanisms to ensure effective transfer of heat from safety-related structures, systems and components (SSCs) to the ultimate heat sink (UHS). At PNPP, raw water for heat transfer to safety related SSCs is accomplished with the emergency service water (ESW) system. The program relies on the implementation of the recommendations of the Nuclear Regulatory Commission (NRC) Generic Letter (GL) 89-13 to ensure that the effects of aging on the OCCW systems will be managed for the period of extended operation. In accordance with the guidance of GL 89-13, other components are also managed under OCCW based on exposure to a raw water environment and the aging management review. The OCCW program manages aging affects by using a combination of preventive, condition, and performance monitoring activities. These actions include (a) surveillance and control techniques to manage aging effects caused by biofouling, corrosion, erosion, protective coating failures, and silting in the OCCW system or structures and components serviced by the OCCW system; (b) inspection of critical components for signs of corrosion, erosion, and biofouling; and (c) testing of the heat transfer capability of heat exchangers that remove heat from components important to safety. AMP XI.M17, Flow-Accelerated Corrosion, manages the aging effects caused by pipe and piping component wall thinning.

AMP XI.M21A, Closed Treated Water Systems, manages closed cooling water systems.

Loss of material due to recurring internal corrosion has been identified for the Emergency Service Water (ESW) system. Loss of material due to recurring internal corrosion and erosion is managed by augmented inspections utilizing the XI.M17, Flow Accelerated Corrosion program. The XI.S7 RG 1.127, Inspection of Water Control Structures Associated with Nuclear Power Plant aging management program is credited with silt removal from the multi-port intake structure through the ESW pumphouse, including intake and alternate intake tunnels, associate tunnel riser shafts, discharge tunnel, and discharge structure.

AMP XI.M21A, Closed Treated Water Systems, manages closed cooling water systems. AMP

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 16 Page 2 of 6 XI.M41, Buried and Underground Piping and Tanks, manages aging effects for underground ESW piping. These activities are not managed by this program.

ESW system components are unlined. The recommendations of LR-ISG-2013-01 to include recommendations of LR-ISG-2013-01 section XI.M42, Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks do not apply.

The program will be continued for the period of extended operation.

NUREG-1801 Consistency The open-cycle cooling water (OCCW) systems program is an existing PNPP program that, with enhancement, will be consistent with the 10 elements of an effective aging management program as described in NUREG-1801,Section XI.M20, Open-Cycle Cooling Water and additional guidance in LRISG-2012-02.

Exceptions to NUREG-1801 None Enhancements The program will be enhanced as follows:

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: Program Element Affected: Monitoring and Trending (Element 5)

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.

The OCCW program documentation will be revised as follows:

Include periodic maintenance inspections of the external portions of components submerged in the emergency service water pump bay:

Emergency Service Water pump casings for loss of material; Emergency Service Water screen wash pump casings for loss of material; Emergency Service Water traveling screens for loss of material and flow blockage; Motor driven fire pump casing and its suction strainer for loss of material and flow blockage;

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 16 Page 3 of 6 Diesel driven fire pump casing and its suction strainer for loss of material and flow blockage.

The minimum frequency of these inspections is once every operating cycle.

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

Operating Experience The following operating experience examples provide objective evidence that the Open-Cycle Cooling Water Systems Program will be effective in ensuring that component intended functions are maintained consistent with the current licensing basis during the period of extended operation.

A review of plant specific PNPP operating experience since 2013, was conducted through a search of plant corrective action program documents identified condition reports (CRs) potentially identifying operating experience related to the OCCW aging management program. The review shows the guidance of NRC GL 89-13 has been effective in managing aging effects due to biofouling, corrosion, erosion, protective coating failures, and silting in structures and components serviced by OCCW systems. The PNPP corrective action program identified more recent adverse trends regarding thermal performance monitoring of GL 89-13 heat exchangers. An enhancement to this aging management program, combined with actions from the corrective action program, are expected to ensure the effectiveness of GL 89-13 heat exchanger thermal performance monitoring going forward.

Annual diving inspections have effectively ensured the intake and discharge structures continue to control mussel contamination within acceptable limits. No evidence of Asian clams has been identified. There have been no documented instances of mussel infestation in ESW system piping or safety-related heat exchangers served by the system. The lack of documented instances indicates that the existing program has been effective in managing aging effects due to biofouling and silting in structures and components serviced by OCCW systems.

PNPP has an Emergency Service Water System Monitoring Program that provides the requirements for an inspection program in compliance with Perry USAR Table 1.8-1 Commitment to RG 1.127 to conduct periodic surveillance of the structural, hydraulic, and foundation conditions of underwater tunnels and certain water-control structures of the ESW System.

A review of the associated dive reports from 2011 through 2024 reveals that among other water control structure inspections, dive operations inspect the ESW traveling water screens, support structures, and basket attachments and the Diesel Driven and Electric Motor Driven Fire Protection Pumps inlet columns, supports, and inlet strainers.

No degradation of stainless steel ESW Traveling Water screens, or copper alloy Fire pump inlet strainers has been reported. Steel components associate with the traveling screen baskets (rakes) are described as having some level of deterioration but acceptable. Although part of the inspection activities, no debris or blockage has been reported during dive operations conducted since 2011 through 2024. Recent photos

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 16 Page 4 of 6 and video during dive operation show that the Fire Pump inlet strainers and Traveling Water Screen mesh are clear with no loss of material.

Periodic heat exchanger performance tests ensure the effective transfer of heat from safety-related structures, systems and components (SSCs) to the ultimate heat sink (UHS).

No unacceptable performance has been documented.

In April 2013, a Condition Report (CR) documented that the ECC B heat exchanger divider plate was found to have a wall thickness that appeared to be less than allowable. Extent of condition found the ECC A heat exchanger acceptable. An engineering review of calculations and divider plate condition concluded there was some wall thinning that was acceptable for the period leading to the next scheduled inspection.

A January 2022 CR identified a degrading trend in the Div 1 RHR B train heat exchanger (HX) thermal performance. The margin between calculated HX performance and acceptance criteria was identified as slim. Subsequent analysis of another segment of test data from the same performance test identified additional performance margin. A subsequent performance test for the same heat exchanger in June 2022 indicated adequate thermal performance.

A separate CR written in January 2022 identifying a degrading trend on the RHR A train heat exchangers thermal performance. A heat exchanger thermal performance test was subsequently scheduled and performed in November 2022 that indicated adequate heat exchanger thermal performance, still with low margin. A work order was scheduled to clean the RHR A train heat exchangers that was completed in April 2023 restoring margin.

A February 2022 CR identified a degrading trend in the Div 3 EDG jacket water HX.

The margin between calculated HX performance and acceptance criteria was identified as slim. The HX was cleaned in May 2022 and subsequent thermal performance testing results were acceptable.

In February 2022, a rollup CR was initiated to document that four separate Generic Letter 89-13 heat exchangers were exhibiting degrading thermal performance trends but neither a CR or a maintenance notification was initiated at the time of the testing to document the condition. The rollup CR identified recent CRs that captured those issues. Significantly, the rollup CR extent of condition review included statements that were found to be inaccurate, such that a new CR was initiated in September 2024 to have the statements corrected.

A March 2022 CR identified the Emergency Closed Cooling (ECC) A HX test conditions, when projected to design basis conditions, the test acceptance criteria could not be met. Review found there was insufficient heat load to obtain valid test results. Several related human performance errors were identified with the test and documented in a subsequent CR. The HX performance test was reperformed in June 2022. Analysis of the June test results resulted in a third CR. Excess conservatism had been included in the performance acceptance criteria (additional heat load and tube plugging margin). When the excess conservatism was removed, the test results

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 16 Page 5 of 6 were considered acceptable, but with low margin. The HX was cleaned in the following year to restore margin.

A May 2022 CR identified a degrading trend in the Div 3 EDG jacket water HX was found unsatisfactory when opened and inspected. A reddish-brown substance, initially identified as zebra mussel shells but later determined to be carbon steel corrosion products, had 72 tubes more than 50% blocked. The tubes and waterbox were cleaned and cleared.

In March 2023 two CRs documented that fouling in RHR heat exchangers was observed during cleaning, demonstrating that, while fouling occurs, site practices are effective at identifying and controlling the fouling before unacceptable heat exchanger performance occurs.

In November, 2024 during the performance of periodic testing, a high water temperature alarm was received for the diesel driven fire pump engine. The local panel alarmed and an incidental amount of engine coolant discharged from the engine cooler cap. In response to the event, the engine was secured before completion of the test.

Upon inspection and disassembly three adverse conditions were identified: Local temperature indication for the engine was degraded, the engine water pump belt was broken, and the raw water side of the engine cooler was significantly fouled with silt.

Although raw water cooled, the diesel driven fire pump engine cooler is considered an integral part of the diesel driven fire pump engine, and is age managed under the fire water aging management program. Additionally, raw water cooled heat exchanger fouling from silt deposits is already monitored by the open cycle cooling water program.

AMP XI.M17, Flow-Accelerated Corrosion, manages the aging effects caused by pipe and piping component wall thinning and corrosion. This includes identification of internal erosion and corrosion of valve bodies, piping, piping components and piping elements. A review of the OE potentially related to the XI.M20 OCCW aging management program and of the OE potentially related to the XI.M17 program was conducted. Operating experience with the applicable principal aging mechanisms are identified below.

Through wall leaks - aging mechanism internal corrosion Through wall, or pinhole, leaks are usually the result of corrosion over time, at unpredictable locations in a piping system. No evidence of recurring leaks in a single location have been found, though a very few occasions have noted an increased leak rate at a known leak location prior to repair. None of the leaks resulted in loss of system function. Numerous instances have been documented of pipe leaks or blockage due to corrosion between 2013 and 2022 related to XI.M20 or XI.M17.

In August 2017 a CR documents that a leak was identified in ESW piping near ECC heat exchanger B. An evaluation determined the leak was a pinhole leak rather than cracking. The extent of the leak did not affect operability. A clamp was applied to contain the leak until repairs could be accomplished. Another leak in the vicinity prompted an extent of condition evaluation which found the other areas to be

Perry Nuclear Power Plant Responses to LRA NRC RAIs Set 5 L-25-042 Attachment 16 Page 6 of 6 satisfactory. This section of pipe was removed and eliminated by design in Refuel Outage (RFO) 17 so it could not happen again, and the same piece in the A loop was eliminated in RFO 18.

The XI.M17 walkdown process is effective in identifying leaks and the management and repair of those leaks have demonstrated the program will be effective throughout the period of extended operation. The XI.M20 program does not need to be enhanced for this aging effect.

Wall thinning - aging mechanism internal erosion.

Wall thinning occurs as a result of erosion by corrosion products suspended in the fluid, high velocity or high pressure flow. Thinning occurs most often at points where the piping system turns or where piping opens into a waterbox of some kind, impacting a localized surface within the waterbox. Numerous instances have been documented of wall thinning or flange or valve seat leaks due to erosion from 2013 through 2021.

In April 2018 a CR documented that a through-wall pipe leak was discovered on ESW 'A' piping at the outlet of the RHR 'A' heat exchangers. The leak was identified between valves 1P45F550A (RHR A/C HX'S ESW OUTLET) and 1P45F0068A (RHR A HX'S ESW OUTLET VALVE) on 20" piping beneath piping insulation. The leak did not affect operability.

In July 2018 a CR documented that a UT examination as part of the FAC program extent of condition evaluation for a condition report found localized wall thinning.

While the amount of wall thinning was acceptable, a 30-day UT monitoring plan was instituted to determine the rate of thinning. Replacement of the elbow occurred in the next refueling outage.

The XI.M17 ultrasonic examination process is effective in identifying wall thinning and management or repair of the condition to ensure no loss of function. These actions have demonstrated the program will be effective throughout the period of extended operation. The XI.M20 program does not need to be enhanced for this aging effect.

Other aging mechanisms, such as external corrosion, have been isolated instances that were identified in system walkdowns and tracked or repaired using the corrective action program.

The XI.M20 program, in conjunction with the XI.M17 and XI.M41 programs have been effective in managing aging effects due to biofouling, corrosion, erosion, protective coating failures, and silting in structures and components serviced by OCCW systems.

Conclusion The Open-Cycle Cooling Water System program 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 during the period of extended operation.

L-25-042, License Renewal Application for the Perry Nuclear Power Plant - Responses to Request for Additional Information (RAI - Set 5)

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L-25-042, License Renewal Application for the Perry Nuclear Power Plant - Responses to Request for Additional Information (RAI - Set 5)

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