ML24227A956

LRA - Requests for Additional Information - Set 1

ML24227A956
Person / Time
Site:	Perry
Issue date:	08/14/2024
From:	Vaughn T NRC/NRR/DNRL/NLRP
To:	Vistra Operations Company
Shared Package
ML24227A955	List: ML24227A956 ML24227A957
References
Download: ML24227A956 (1)

Text

REQUEST FOR ADDITIONAL INFORMATION BY THE OFFICE OF NUCLEAR REACTOR REGULATION PERRY UNIT 1 LICENSE RENEWAL APPLICATION REVIEW (SAFETY)

ENERGY HARBOR NUCLEAR GENERATION LLC PERRY, UNIT 1 DOCKET NO. 05000440 ISSUE DATE: 08/14/2024

SNSB RAI- 10201-R1

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Background===

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

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

Regulatory Basis

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

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

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

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

1 reactor pressure vessel (RPV) fluence predictions by letter dated February 7, 2008

[Reference 4.7- 4].

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

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

Question 2

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

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

NCSG RAI- 10233- R1

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

RAI B.2.8-1

Background:

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

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

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

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

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

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

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

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

Issue:

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

Request:

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

results of previous inspections of uncoated buried stainless steel piping, more details on the

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

RAI B.2.8-2

Background:

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

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

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

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

GALL-LR Report AMP XI.M41, as revised by LR-ISG-2015-01, includes the following recommendations:

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

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

Issue:

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

4 Request:

Provide clarification (including appropriate revisions to LRA Sections B.2.8 and A.1.8) with respect to the qualifications of individuals that will determine (a) whether the extent of coating degradation is significant; and (b) the installation locations of electrical resistance corrosion rate probes and the methods of use. If the qualifications will not be consistent with GALL-LR Report AMP XI.M41, as revised by LR-ISG-2015- 01, state the basis for how the alternative qualification method(s) are appropriate to use.

NCSG RAI-10255- R1

Regulatory Basis:

Section 54.21(a)(3) of Title 10 of the Code of Federal Regulations (10 CFR) requires an applicant to demonstrate that the effects of aging for structures and components will be adequately managed so that the intended function(s) will be maintained consistent with the current licensing basis for the period of extended operation. One of the findings that the U.S.

Nuclear Regulatory Commission (NRC) staff must make to issue a renewed license (10 CFR 54.29(a)) is that actions have been identified and have been or will be taken with respect to managing the effects of aging during the period of extended operation on the functionality of structures, systems and components that have been identified to require review under 10 CFR 54.21, such that there is reasonable assurance that the activities authorized by the renewed license will continue to be conducted in accordance with the current licensing basis. In order to complete its review and enable making a finding under 10 CFR 54.29(a), the staff requires additional information in regard to the matters described in the requests for information.

Background:

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

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

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

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

Issue:

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

While the LRA discusses installation of the non-safety related automatic dewatering pumping system as part of Engineering Changes 22-0026- 001 through 22-0026- 005, it does not discuss

5 what polymer materials the piping and valve bodies are made from. In addition, no discussion was provided as to why these component/material/environment combinations have no applicable aging effects .

Request:

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

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

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

NPHP RAI-10137-R1

RAI 4.3.3-1

Regul ator y Basis:

Pursuant to 10 CFR 54. 21(c), the LRA must include an evaluation of time-limited aging analyses (TLAAs). The applicant must demonstrate that (i) the analyses remain valid for the period of extended operation, (ii) the analyses have been projected to the end of the period of extended operation, or (iii) the effects of aging on the intended function(s) will be adequately managed for the period of extended operation.

Background:

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

Issue:

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

Request:

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

6 RAI 4.3.3-2

Regul ator y Basis

Pursuant to 10 CFR 54. 21(c), the LRA must include an evaluation of time-limited aging analyses (TLAAs). The applicant must demonstrate that (i) the analyses remain valid for the period of extended operation, (ii) the analyses have been projected to the end of the period of extended operation, or (iii) the effects of aging on the intended function(s) will be adequately managed for the period of extended operation.

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Background===

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

Issue

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

In addition, LRA Section 4.3.3 indicates that, after the screening evaluation, the applicant performed more detailed EAF evaluation to remove some conservatisms and determine the re"ned CUFen values for 60 years of operation, as described in LRA Table 4.3-5.

However, the LRA does not clearly describe how the conser vatisms associated with the screening CUFen values were removed to re"ne the 60-year projected CUFen values.

Request

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

2. Clarif y how the conser vatisms associated with the screening CUFen values were removed to re"ne the 60-year projected CUFen.

NCSG RAI-10183- R1

Regul ator y Basis

Title 10 of the Code of Federal Regulations section 54.21(a)(3) requires the applicant to demonstrate that the effects of aging for structures and components will be adequately

7 managed so that the intended function will be maintained consistent with the current licensing basis (CLB) for the period of extended operation. As described in the NUREG-1800, Standard Review Plan [SRP] for Review of License Renewal [LR] Applications for Nuclear Power Plants, SRP-LR, an applicant may demonstrate compliance with 10 CFR 54.21(a)(3) by referencing the NUREG-1801, Generic A ging Lessons Learned License Renewal (GALL) Report when evaluation of the matter in the GALL Report applies to the plant.

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Background===

Condition Report (CR) CR-2019- 10233, dated December 9, 2019, 2019 Triennial Heat Sink Inspection: Roll Up CR, documented issues and problems found during the 2019 triennial heat sink inspection, which was performed in December 2019. Perr y s open cycle cooling water system program is implemented through procedure NOP-ER-2006, Rev 6, Service Water Reliability Management Program. As noted in CR-2019- 10233, NOP-ER-2006 was revised in S eptember of 2019 to incorporate tighter handoffs between maintenance procedures and to clearly delineate responsibilities between System Engineers, Site Managers, and the Fleet Engineering Program Manager. After identif ying program de"ciencies in advance of the triennial heat sink inspection and revising NOP-ER-2006 in S eptember 2019, the applicant incorporated a system trending improvement plan (ATL-2022-0277) in March of 2022. During the audit in December 2023, the staff reviewed CR -

2022-01183, dated Februar y 16, 2022, Rollup CR for a Gap Identi"ed in Strategic Mechanical Engineering Performance, which documented that performance testing on the A emergency closed cooling water heat exchanger failed to meet the acceptance criteria in December of 2021 and that the issue would be resolved under CR-2022-02280, dated March 16, 2022. In addition, CR-2022- 01183 also documented that heat exchanger system trending was not performed for multiple years on the Division I and III diesel generator jacket water heat exchangers and on the Division I and II residual heat removal heat exchange rs.

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

The approach delineated in NOP-ER-2006 implements the monitoring and trending portion of aging management programs delineated in SRP-LR section A .1.2.3.5, which states, This includes an evaluation of the results against the acceptance criteria and a prediction regarding the rate of degradation in order to con"rm that timing of the next

8 scheduled inspection will occur before a loss of [structure or component] SC-intended function.

The documentation described in NOP-ER-2006 (regarding an acknowledgement of the acceptability of the test frequency based upon review of previous test results), was not found in the evaluation of the test data for the Division III emergency diesel generator (EDG) jacket water heat exchanger, which was documented in CR-2022-00950, dated Februar y 8, 2022, Triennial Ultimate Heat Sink Self -Assessment: Division III Diesel Generator Jacket Water Heat Exchanger Performance Degradation.

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

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

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

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

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

In response to a breakout question about CR-2022- 03813, asked by the NRC staff in December 2023, the applicant responded by stating that, The Condition Report was initiated by engineering based on the initial inspection of the heat exchanger. After further analysis of the debris, the zebra mussels initially thought to be inside the Division III

9 Emergency Diesel Generator Jacket Water Heat Exchanger as identi"ed in CR-2022-003813 were later determined to be predominately metallic corrosion debris from the carbon steel piping (ref NOP-ER-2006 Attachment 1 - Heat Exchanger Visual Inspection Checklist as completed by the system engineer). As such, an infestation of live zebra mussels did not occur.

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

The documentation in CR-2022-03813 indicated that the Division III E DG jacket water heat exchanger would be cleaned, and performance testing would be performed following maintenance. However, it did not indicate whether the degraded condition of the heat exchanger provided acceptable heat transfer capability, to demonstrate that the aging management program was taking corrective actions prior to unacceptable heat exchanger performance. This heat exchanger was tested in October 2014 and June 2019. Based on the NRC staffs calculated rate of degradation from these previous tests (i.e., trending), the heat exchanger would not meet its acceptance criteria sometime in December 2021. The data evaluation for the 2019 test does not include any statement about the acceptability of the test frequency (i.e., a prediction of the degradation rate to con"rm that the next scheduled inspection will occur before a loss of intended function).

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

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

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

However, contrar y to the statement above that none of these events fell below performance acceptance criteria, the graph on page 7 of 34 in CR-2022 -01183 shows that

10 emergency closed cooling (ECC) A heat exchanger did not pass acceptance criteria during the latest performance test, on S eptember 21, 2021. S ection 4. 2.2.2.f of NOP-ER-2006, Implementation notes that the heat transfer capability of heat exchangers are veri"ed by periodic testing, and states, A post maintenance heat transfer test shall be conducted following corrective action to a heat exchanger that failed a heat transfer test.

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

On pages 20 - 22 of 34 in CR-2022-01183, identi"cation of a degrading trend is discussed, and it is noted that, One outlying point is abnormal, two is a correlation, and three make a trend. The graphs on pages 5 and 6 of 34 in CR-2022-01183 show the tre nding of the heat transfer coefficient for the residual heat removal (RHR) A and Division I jacket water heat exchangers, respectively. While both graphs only show a correlation of decreasing performance between two data points, both graphs also show an extension of the time between performance tests, such that had the original testing frequency been maintained, a degraded trend (i.e., three points) would have been identi"ed. Also, on page 30 of 34 in CR-2022-01183, the extent of condition discussion s tates that the ECC A heat exchanger did not meet the acceptance criteria, due to a negative step change in performance but was not found to have a declining trend.

Issue: It appears to the NRC staff that the de"nition of a degrading trend, One outlying point is abnormal, two is a correlation, and three make a trend is inappropriate for monitoring heat exchanger performance, which typically shows a decreasing trend over time, in between heat exchanger cleanings. The de"nition Perr y is using appears to a have been adopted from a statistical process control de"nition commonly used in manufacturing, which typically includes a measured parameter mean, standard deviation, and upper and lower control limits.

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

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

The Standard Review Plan, NUREG-1800, Rev. 2, section A .1.2.3 A ging Management Program [AMP] Elements also contains a description of Element 10, Operating Experience, and states, in part,

The operating experience of AMPs that are existing programs, including past corrective actions resulting in program enhancements or additional programs, should be considered.

A past failure would not necessarily invalidate an AMP because the feedback from operating experience should have resulted in appropriate program enhancements or new programs. This information can show where an existing program has succeeded and where it has failed (if at all) in intercepting aging degradation in a timely manner. This information should provide objective evidence to support the conclusion that the effects of aging will be managed adequately so that the structure- and component intended function(s) will be maintained during the period of extended operation.

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

Issue: The information in the LRA was not complete and accurate as required by 10 CFR 54.13. The statements in the LRA regarding heat exchanger performance tests were incomplete because they did not include all the relevant operating experience documented by the applicant in their corrective action program and the statement that No unacceptable performance has been documented was inaccurate since unacceptable performance was documented, as shown above in CR-2022- 1183, CR-2022-02280, CR -

2022-03813, and CR -2022-05199.

Requests

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

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

3. State the basis for why changes to the de"nition of a degraded trend, such that negative step changes to the heat exchanger performance that result in not meeting

12 performance acceptance criteria will no longer be misclassi"ed as not also being in a degraded trend, are not warranted.

SCPB RAI- 10192-R1 Regulation

Screening is governed by Title 10 of the Code of Federal Regulations (10 CFR) section 54.21(a).

Issue

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

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

UFSAR Appendix 9A .4.13.1 reads in part:

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

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

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

Components located below elevation 660 of the offgas building are designed to satisf y system space requirements and to satisf y the requirements for Safety Class 3 and S eismic Categor y I items.

LRA section 2.3.3.35, MCC [Motor Control Center] Switchgear and Miscellaneous Electrical Area HVAC [Heating, Ventilation, and Air-Conditioning], and Batter y Room Exhaust (M23 & M24), subsection System Functions (and scoping criteria, if intended function) contains the intended function:

Prevent the accumulation of combustible gas in the batter y rooms. [10 CFR 54.4(a)(1), (a)(3) - FP ["re protection))

13 LRA section 2.3.3.35, subsection References, License Renewal Drawings: 912-0609 displays as being subject to aging m anagement review (AMR) for both supply and exhaust ventilation duct/registers to/from the Unit 1 divisional DC [direct curre nt] s witchgear room(s) and b atter y room(s) [coordinates F-4 & F -8] to prevent the buildup of Hydrogen within the batter y ro om s.

In contrast, LRA s ection 2.3.3.41, subsection, System Functions (and scoping criteria, if intended function) does not contain an intended function that parallels LRA s ection 2.3.3.35 system intended function; that is:

Prevent the accumulation of combustible gas in the Offg as Building. [10 CFR 54.4(a)(1), (a)(3) - FP]

LRA section 2.3.3.41, subsection References, License Renewal Drawings: 912-06 22 displays as NOT being subject to AMR for the supply ventilation duct / registe rs from the turbine building cooling and ventilation system at all three elevations of the o ffgas building.

In addition, LRA s ection 2.3.3.63, Turbine Building Ventilation (M35), s u b s e c t i o n , System Functions (and scoping criteria, if intended function) does not contain an intended function that parallels LRA s ection 2.3.3.35 system intended function. Speci"cally:

Prevent the accumulation of combustible gas in the Offg as Building. [10 CFR 54.4(a)(1), (a)(3) - FP]

Request

The N RC staff requests that the licensee:

1. justif y the discrepancy noted above. More speci"cally, how combustible gas threats are mitigated in the o ffgas building versus how these same threats are mitigated in the Unit 1 divisional DC switchgear room(s) and b atter y room(s) of the Units 1 and 2 control complex buildings.

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

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

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