IR 05000445/2023013

License Renewal Inspection Report 05000445/2023013 and 05000446/2023013

ML24029A077
Person / Time
Site:	Comanche Peak
Issue date:	01/31/2024
From:	Nick Taylor NRC/RGN-IV/DORS/PBB
To:	Peters K Vistra Operations Company
References
IR 2023013
Download: ML24029A077 (54)

Text

January 31, 2024

SUBJECT:

COMANCHE PEAK NUCLEAR POWER PLANT - LICENSE RENEWAL INSPECTION REPORT 05000445/2023013 AND 05000446/2023013

Dear Ken Peters:

On December 19, 2023, a U.S. Nuclear Regulatory Commission (NRC) team completed the onsite portion of an inspection of your application for license renewal for Comanche Peak Nuclear Power Plant. The team discussed the inspection results with Todd Evans and other members of your staff. The results of this inspection are documented in the enclosed report.

The inspection examined activities that supported the application for a renewed license for Comanche Peak Nuclear Power Plant. The inspection addressed your processes for scoping and screening structures, systems, and components (SSCs) to select equipment subject to aging management review. Further, the inspection addressed the development and implementation of aging management programs to support continued plant operation into the period of extended operation. As part of the inspection, the NRC examined procedures and representative records, interviewed personnel, and visually examined accessible portions of various SSCs to verify license renewal boundaries and to observe any effects of equipment aging. The NRC inspection activities constitute one of several inputs into the NRC review process for license renewal applications.

The inspectors concluded that your staff appropriately implemented the scoping and screening of non-safety related SSCs that could affect safety related SSCs as required in 10 CRF 54.4(a)(2). The team concludes that your staff conducted an appropriate review of the materials and environments and established appropriate aging management programs as described in the license renewal application and as supplemented through your responses to requests for additional information from the NRC. The inspectors concluded that your staff maintained the documentation supporting the application in an auditable and retrievable form.

No findings or violations of more than minor significance were identified during this inspection. This letter, its enclosure, and your response (if any) will be made available for public inspection and copying at http://www.nrc.gov/reading-rm/adams.html and at the NRC Public Document Room in accordance with Title 10 of the Code of Federal Regulations 2.390, Public Inspections, Exemptions, Requests for Withholding.

Sincerely, Nicholas H. Taylor, Chief Engineering Branch 2 Division of Operating Reactor Safety Docket Nos. 05000445, 05000446 License Nos. NPF-87, NPF-89

Enclosure:

As stated

Inspection Report

Docket Numbers: 05000445 and 05000446

License Numbers: NPF-87 and NPF-89

Report Numbers: 05000445/2023013 and 05000446/2023013

Licensee: Vistra Operations Company, LLC

Facility: Comanche Peak Nuclear Power Plant

Location: Glen Rose, TX

Inspection Dates: September 11, 2023 to September 29, 2023

Inspectors: S. Makor, Senior Reactor Inspector, Team Lead A. Istar, Civil Engineer A. Johnson, Senior Materials Engineer J. Mejia, Reactor Inspector G. Pick, Senior Reactor Inspector G. Wang, Civil Engineer

Observer: A. Saunders, Reactor Inspector

Approved By: Nicholas H. Taylor, Chief Engineering Branch 2 Division of Operating Reactor Safety

Enclosure

SUMMARY

The U.S. Nuclear Regulatory Commission (NRC) continued monitoring the licensees performance by conducting a License Renewal Inspection at Comanche Peak Nuclear Power Plant, in accordance with the Reactor Oversight Process. The Reactor Oversight Process is the NRCs program for overseeing the safe operation of commercial nuclear power reactors. Refer to https://www.nrc.gov/reactors/operating/oversight.html for more information.

The inspectors performed onsite inspections of the applicant's license renewal activities. The inspectors performed the evaluations in accordance with Manual Chapter 2516, Policy and Guidance for the License Renewal Inspection Programs, and Inspection Procedure 71002,

License Renewal Inspection. The inspectors did not identify any findings as defined in NRC Manual Chapter 0612.

The inspectors concluded the applicant adequately performed screening and scoping of non-safety related structures, systems, and components as required in 10 CFR 54.4(a)(2). The inspectors concluded that the applicant conducted an appropriate review of the materials and environments, and established appropriate aging management programs as described in the license renewal application and as supplemented through responses to requests for additional information from the NRC. The inspectors concluded that the applicant provided the documentation that supported the application and inspection process in an auditable and retrievable form.

Based on the samples reviewed by the inspectors, the inspection results support a conclusion of reasonable assurance that actions have been identified and have been or will be taken to manage the effects of aging in the structures, systems, and components identified in your application, and that the intended functions of these structures, systems, and components should be maintained in the period of extended operation.

List of Findings and Violations

No findings or violations of more than minor significance were identified.

Additional Tracking Items

None.

INSPECTION SCOPES

Inspections were conducted using the appropriate portions of the inspection procedures (IPs) in effect at the beginning of the inspection unless otherwise noted. Currently approved IPs with their attached revision histories are located on the public website at http://www.nrc.gov/reading-rm/doc-collections/insp-manual/inspection-procedure/index.html. Samples were declared complete when the IP requirements most appropriate to the inspection activity were met consistent with Inspection Manual Chapter (IMC) 2516, Policy and Guidance for the License Renewal Inspection Program. The inspectors reviewed selected procedures and records, observed activities, and interviewed personnel to assess licensee performance and compliance with Commission rules and regulations, license conditions, site procedures, and standards.

OTHER ACTIVITIES

- TEMPORARY INSTRUCTIONS, INFREQUENT AND ABNORMAL

===71002 - License Renewal Inspection

This inspection was performed to evaluate the thoroughness and accuracy of the applicant's scoping and screening of non-safety related structures, systems, and components (SSC), as required in 10 CFR 54.4(a)(2). Also, the inspectors evaluated whether aging management programs (AMP) will be capable of managing identified aging effects in an appropriate manner.

In order to evaluate scoping activities, the inspectors selected a number of SSCs for review to evaluate whether the methodology used by the applicant appropriately addressed the non-safety related systems affecting the safety functions of a structure, system, or component within the scope of license renewal.

The inspectors selected 25 of the 43 AMPs to verify the adequacy of the applicants guidance, implementation activities, and documentation. The inspectors evaluated the programs to determine whether the applicant would appropriately manage the effects of aging and to verify that the applicant would maintain the safety functions of the SSCs during the period of extended operation (PEO).

The inspectors evaluated the applicants review and consideration of industry and plant-specific operating experience related to aging effects.

The inspectors reviewed supporting documentation and interviewed applicant personnel to confirm the accuracy of the license renewal application conclusions. For a sample of plant structures and systems, the inspectors walked down accessible portions of the systems to observe aging effects, which included the material condition of the SSCs.

License Renewal Inspection===

(1) The inspectors evaluated the aging management and commitments described below and walked down selected areas of the facility while performing this license renewal inspection.

B2.3.2 Water Chemistry AMP The water chemistry AMP is an existing mitigation AMP that manages the effects of aging related to cracking, loss of material, and reduction of heat transfer in components exposed to an environment of reactor coolant, treated water, steam, and treated borated water through periodic monitoring and control of water chemistry. The program provides corrosion control for the reactor vessel and reactor vessel internals, reactor coolant system, engineered safety features systems, steam generator internals and balance of plant components. The program is a mitigation program that relies on chemical additions to both the primary and secondary systems in accordance with industry guidelines. The program includes specifications and limits for chemical species, impurities and additives, sampling and analysis frequencies, and corrective actions for control of water chemistries.

The applicant provided a review of industry and plant specific operating experience related to aging effects for the water chemistry AMP in the AMP basis document. The supplied operating experience was reviewed, and interviews were conducted with applicant personnel to confirm the accuracy of the AMP conclusion. For a sample of plant structures and systems covered by the water chemistry AMP, accessible portions of the system were walked down to observe aging effects, which included the material condition of the SSCs. No new aging effects other than those described by the generic aging lessons learned (GALL) report were noted in the operating experience review or the walkdown.

The closed cooling water plant specific guidelines were found to incorrectly list the control and alert limits for the closed cooling water systems covered within the document; however, this was an administrative error that did not affect actual chemistry limits in the covered systems, since the chemistry limits used for controlling the closed cooling water systems are contained in procedure CHM-100, Chemistry Specifications, which was verified to contain the correct limits and the document used to verify the limits. The limits in the closed cooling water plant specific guideline will be corrected and TR-2023-006699 was issued on September 26, 2023, to track the issue to resolution.

A gap analysis performed in 2021 identified that chemistry trend notes in NuclearIQ were not being logged with enough detail to track the performance history of primary system chemistry. The updated NuclearIQ system with new detailed chemistry trend notes was demonstrated for the NRC staff on September 27, 2023.

The applicant identified an enhancement needed to ensure consistency with the GALL report. The enhancement included revising strategic plans to include evidence of aging effects as items to be evaluated, the cause identified, and the condition corrected.

The applicant also identified an exception to the GALL report. Specifically, the Electric Power Research Institute (EPRI) 3002010645 PWR Secondary Water Chemistry Guidelines, Revision 8 and EPRI 3002000505 PWR Primary Water Chemistry Guidelines, Revision 7 are used instead of previous revisions of these same documents. The newer revisions of these documents have been endorsed by NUREG-2191 GALL-SLR and SLR-ISG-2021-02-MECHANICAL, which updated the Water Chemistry AMP for subsequent license renewal.

The applicant committed to implementing the enhancement and exception no later than six months prior to entering the PEO or no later than the last refueling outage prior to the PEO. The inspectors identified no concerns with the enhancement or the exception.

The inspectors concluded that the water chemistry AMP as proposed provides reasonable assurance that the effects of aging will be managed, consistent with the license basis in the PEO.

B2.3.3 Reactor Head Closure Stud Bolting and Commitment 5 The reactor head closure stud bolting AMP manages the aging effects of cracking due to stress corrosion cracking (SCC) or intergranular stress corrosion cracking (IGSCC) and loss of material due to wear or corrosion for reactor vessel closure stud bolting. The program includes periodic visual and volumetric examinations of reactor vessel flange stud hole threads, reactor head closure studs, nuts, and washers. The examinations are conducted in accordance with American Society of Mechanical Engineers (ASME)Section XI, Subsection IWB, Table IWB 2500-1, Examination Categories, Examination Category BG-1, Pressure Retaining Bolting Greater Than 2 in. (50 mm) in Diameter. The program includes preventive measures as recommended in Regulatory Guide 1.65, Materials and Inspections for Reactor Vessel Closure Studs,

(a) avoiding the use of metal-plating to prevent degradation due to corrosion or hydrogen embrittlement,

(b) using manganese phosphate or other acceptable surface treatments,

(c) use stable lubricants, and using bolting material for closure studs that has an actual measured yield strength less than 150 ksi.

Comanche Peak no longer uses Plasmabond as a surface treatment for the head studs and HydraNuts and washers as part of the head stud closure bolting. Both units use the original design nuts and washers.

The applicant identified an exception to the GALL Report, Element 2, Preventive Measures. NUREG-1801 recommends using bolting material that has an actual measured yield strength of less than 150 ksi. The applicant indicated that there is existing bolting material, reactor head closure stud nuts and washers, in service and spares in stock that have actual measured yield strength greater than 150 ksi.

NUREG-2191 allows for existing bolting material to have an ultimate tensile strength of 170 ksi and existing bolting material meets the 170 ksi tensile strength limit.

Commitment 5 specified that the applicant would continue the existing reactor head closure stud bolting aging management program during the PEO, including enhancements to assure the maximum yield strength of replacement reactor head closure stud bolting material purchased in the future is limited to a measured yield strength of <150 ksi and explicitly prohibit the use of lubricants not meeting RG 1.65 guidance. The program is scheduled to be implemented no later than 6 months prior to the PEO, or no later than the last refueling outage prior to entering the PEO. The inspectors identified no concerns with the exception or these enhancements.

The inspectors reviewed the aging management evaluation report, implementing procedures, corrective action documents, and operating experience. The inspectors also reviewed completed inspection records, engineering design analysis documents and interviewed plant staff. The inspectors inspected several studs and nuts for the Unit 1 and Unit 2 reactor vessels during the 1RF23 and 2RF20 refueling outages.

The inspectors concluded that the reactor head closure stud bolting AMP as proposed provides reasonable assurances that the effects of aging will be managed, consistent with the license basis in the PEO.

B2.3.5 Cracking of Nickel-Alloy Components and Loss of Material Due to Boric Acid-Induced Corrosion in Reactor Coolant Pressure Boundary Components (PWRs Only)and Commitment 7 The induced corrosion in reactor coolant pressure boundary components AMP manages the effects of aging due to primary water stress corrosion cracking (PWSCC) of nickel-alloy based components and associated welds, as well as loss of material due to boric acid-induced corrosion in susceptible components in the vicinity of nickel-alloy reactor coolant pressure boundary components. The program monitors conditions through periodic bare-metal visual and volumetric examinations of nickel alloy-based components, associated welds, and components in the vicinity of nickel alloy-based reactor coolant pressure boundary components that are susceptible to loss of material due to boric acid-induced corrosion, such as reactor pressure vessel components, pressurizer components, and reactor coolant system pressure boundary piping and welds. The program also includes inspection requirements for reactor pressure vessel upper heads and steam generator drain stubs. Element 2 of the GALL does not include preventive or mitigating measures, however, maintaining high water purity reduces susceptibility to PWSCC. The program maintains water purity through the water chemistry AMP. The applicant has taken discretion to implement preventive actions to mitigate PWSCC through Alloy 600 mitigation strategies and implemented where applicable.

Commitment 7 specified continue the existing cracking of nickel-alloy components and loss of material due to boric acid-induced corrosion in reactor coolant pressure boundary aging management program during the PEO and complete the implementation no later than 6 months prior the PEO, or no later than the last refueling outage prior to entering the PEO.

The inspectors interviewed plant staff and responsible licensing staff on the mechanical stress improvement process (MSIP) partially completed on the reactor pressure vessel (RPV) hot and cold leg nozzle dissimilar metal welds for Unit 2. The stress mitigation was not completed for all eight welds as the tooling had failed during the process. The inspectors questioned the staff on the long-term fatigue aspect affecting the welds that only received a partial MSIP. Two welds are mitigated by MSIP and the one weld that achieved a partial squeeze is not fully mitigated by MSIP and will be monitored through periodic inspection. The fatigue aspect will be monitored by the Fatigue Monitoring aging management program. The remaining welds not mitigated will be monitored through periodic inspection.

The inspectors reviewed the aging management evaluation report, implementing procedures, corrective action documents, and operating experience. The inspectors also reviewed the reactor coolant system (RCS) materials management plan and interviewed responsible applicant staff. The inspectors observed nondestructive examinations of various nickel-alloy components and performed boric acid walkdowns of Unit 1 and Unit 2 systems during the 1RF23 and 2RF20 refueling outages.

The inspectors concluded that the cracking of nickel-alloy components and loss of material due to boric acid-induced corrosion in reactor coolant pressure boundary components AMP as proposed provides reasonable assurances that the effects of aging will be managed, consistent with the license basis in the PEO.

B2.3.7 PWR Vessel Internals and Commitment 9 The PWR vessel internals AMP is a new program that manages the effects of aging due to various forms of cracking, including SCC, irradiation-assisted stress corrosion cracking (IASCC), primary water stress corrosion cracking (PWSCC), and cracking due to fatigue/cyclic loading, loss of material induced by wear, loss of fracture toughness due to thermal aging and neutron irradiation embrittlement, change in dimension due to void swelling or distortion, and loss of preload due to thermal and irradiation-enhanced stress relaxation and creep. The program applies the guidance of EPRI Technical Report, MRP-227, revision 1-A, Materials Reliability Program:

Pressurized Water Reactor Internals Inspection and Evaluation Guidelines for inspecting and evaluating vessel internals to procedure EPG-710, Reactor Vessel Internals Aging Management Program Plan. The program will include periodic examinations and other inspections scheduled in accordance with ASME Code,Section XI. The reactor internals program plan also includes inspection of thermal sleeve flange wear, guide card wear and baffle former bolts.

Commitment 9 implements the new PWR vessel internals aging management program during the PEO and completes the implementation no later than 6 months prior the PEO, or no later than the last refueling outage prior to entering the PEO.

The inspectors reviewed the aging management evaluation report, corrective action documents, and operating experience. The inspectors also reviewed work orders, the implementing program plan and schedule of reactor internals examination activities prior to entering and during the PEO. The inspectors performed limited inspection of various internal components by remote cameras when the reactor vessel heads were removed for Unit 1 and Unit 2 during the 1RF23 and 2RF20 refueling outages.

The inspectors concluded that the PWR vessels internals AMP as proposed provides reasonable assurances that the effects of aging will be managed, consistent with the license basis in the PEO.

B2.3.8 Flow Accelerated Corrosion and Commitment 10 This program manages loss of material caused by flow accelerated corrosion (wall thinning) and flow erosion. The applicant implemented the objectives of the program by:

(1) determining systems susceptible to flow accelerated corrosion;

(2) conducting appropriate analyses to predict wall thinning;

(3) performing wall thickness measurements based on wall thinning predictions and operating experience; and

(4) evaluating measurement results to determine the remaining service life, and the need for replacement or repair of components. The program applied to carbon steel piping and valve bodies containing two-phase and single-phase fluids and followed guidance consistent with EPRI NSAC-202L, Recommendations for an Effective Flow Accelerated Corrosion Program, Revision 4.

Commitment 10 specified:

1. The program will be enhanced to Include erosion mechanisms such as cavitation, flashing, droplet impingement, or solid particle impingement for the components that contain raw water, treated water (including borated water), or steam.

2. The program will be enhanced to address erosion as an aging mechanism for all components that are susceptible to erosion wall thinning mechanisms such as cavitation, flashing, droplet impingement, or solid particle impingement.

This will include guidelines for measuring wall thickness due to erosion.

3. The program will be enhanced to ensure that identification of locations susceptible to erosion are based on the extent of condition reviews from corrective actions in response to plant specific and industry operating experience. Components may be treated in a manner like susceptible-not-modeled lines discussed in NSAC-202L-R4. Additionally, include guidance from EPRI 1011231 Recommendations for Controlling Cavitation, Flashing, Liquid Droplet Impingement, and Solid Particle Erosion in Nuclear Power Plant Piping Systems, for identifying potential damage locations and EPRI TR-112657, Revised Risk-Informed Inservice Inspection Evaluation Procedure, and/or NUREG/CR-6031, Cavitation Guide for Control Valves, guidance for cavitation erosion.

4. The program will be enhanced to include trending of wall thickness measurements at locations susceptible to erosion mechanisms to adjust the monitoring frequency and to predict the remaining service life of the component for scheduling repairs or replacements. Inspection results will be evaluated to determine if assumptions in the extent of condition review remain valid. If degradation is associated with infrequent operational alignments, such as surveillances or pump starts/stops, then trending activities may consider the number or duration of these occurrences. The program will be enhanced to consider periodic wall thickness measurements of replacement components, which would continue until the effectiveness of corrective actions has been confirmed.

5. Procedures will be enhanced to ensure that updates to plant predictive models are controlled and independently reviewed by a second qualified flow accelerated corrosion engineer, consistent with NSAC-202L recommendations.

6. The program will be enhanced to update corrective action guidance for erosion issues to consider adjusting operating parameters or changing component designs to eliminate the cause of erosion mechanisms as part of long-term corrective actions and verify the effectiveness of these corrective actions. Continue periodic monitoring activities for any components (susceptible to erosion) replaced with an alternate material, since a material that is completely erosion resistant is not currently available.

As described in the above enhancements the applicant will be formally implementing the guidance contained in License Renewal-ISG-2012-001, Wall Thinning Due to Erosion Mechanisms, to address erosion mechanisms described in industry operating experience if they do not want to change out the components.

The inspectors reviewed the completed flow accelerated corrosion inspection reports for each unit, interviewed the program owner and reviewed the implementation of the CHECKWORKs and usage of the FAC Manager program. In addition to performing the trending and inspections of piping erosion in accordance the flow accelerated corrosion program, the inspectors reviewed how the applicant used the program to manage wall thinning of the above-ground portion of the standby service water piping.

The inspectors reviewed how the applicant had incorporated the operating experience described in EPRI 1011231 because the erosion phenomenon could affect current operation of the plant. The inspectors determined that the applicant had not processed the 2004 report as industry information nor any of the updated reports in 2007, 2010, 2015, and 2018. The applicant had identified the need to review updated EPRI Technical Report, "Recommendations for an Effective Program Against Erosive Attack. Revision 1" against their current flow accelerated corrosion program and practices in TR-2023-000461, action 17. The inspectors determined that the applicant had reviewed their auxiliary feedwater system piping because the system engineer suspected cavitation had caused erosion in a valve. Although the applicant missed several opportunities to evaluate and implement changes to their program based on industry experience, the inspectors determined that the applicant had initiated actions to consider other erosion mechanisms and to address changes to their program based on the most recent EPRI Report on other erosion mechanisms.

The inspectors concluded that the flow accelerated corrosion AMP as proposed provides reasonable assurances that the effects of aging will be managed, consistent with the license basis in the PEO.

B.2.3.11 Open-Cycle Cooling Water System This program is an existing preventive, mitigative, condition monitoring, and performance monitoring AMP that manages loss of material, flow blockage, and reduction of heat transfer in components in nuclear safety related and non-safety related raw water systems. This AMP manages components constructed of various materials including steel, stainless steel, copper alloy, and nickel-alloy. System and component intended functions are maintained by testing, visual inspections, nondestructive examination, and biocide and chemical treatment. The applicant has plant specific procedures that provide instructions and controls for chemical and biocide injection.

This AMP includes the station service water system at Comanche Peak. The station service water system is supplied from the safe shutdown impoundment that serves as the ultimate heat sink and is an enclosed body of water formed from a cove of the Squaw Creek Reservoir. The in-scope heat exchangers that use service water are the component cooling water heat exchangers, diesel generator jacket water heat exchangers, safety injection pump lube oil coolers, centrifugal charging pump lube oil coolers, containment spray pump bearing coolers, and service water pump motor bearing coolers.

The component cooling water heat exchangers are tested in accordance with industry guidelines. The centrifugal charging pump lube oil coolers, the containment spray pump bearing coolers, and the safety injection lube oil coolers are not tested and instead temperatures are recorded during surveillance runs of associated pumps. The diesel generator jacket water heat exchangers do not undergo thermal performance testing due to measurement limitations on this heat exchanger from jacket water temperature stratification and mixing at the outlet end; diesel generator intercooler water temperature is monitored instead. Trends are analyzed and for heat exchangers that are not heat transfer tested, inspections and cleanings are performed on a periodic basis. Periodic flushing is performed on stagnant pipe segments that were evaluated and determined to require periodic flushing. Service water piping is inspected every refueling outage per the corrosion monitoring program.

The applicant has plant specific guideline documents that specify the chemicals added, monitoring frequency, parameter limits, and action level limits. The program implements the guidance recommended in industry standards.

The applicant provided a review of industry and plant specific operating experience related to aging effects in the AMP basis document. The supplied operating experience was reviewed, and interviews were conducted with applicant personnel to confirm the accuracy of the AMP conclusion. For a sample of plant structures and systems covered by this AMP, accessible portions of the systems were walked down to observe aging effects, which included the material condition of the SSCs. No new aging effects other than those described by the GALL report were noted in the operating experience review or the walkdown.

A walkdown of the service water intake structure building was completed and no concerns were noted. Recordings of the temperature trending data worksheets for the safety injection lube oil coolers were reviewed. The diesel generator intercooler water temperature trending data was reviewed by sampling a diesel generator slow start log. Vendor reports of coupon testing for 316 stainless steel, copper-nickel, and mild steel coupons were reviewed from 2017-2018, 2020, and 2022.

The applicant identified enhancements needed to ensure consistency with the GALL report, as modified by LR-ISG-2013-01 and LR-ISG-2012-02. Specifically, the enhancements include:

• Revising implementing documents to ensure that if corrosion buildup or fouling is noted, the impact on the heat transfer capability of the system is evaluated.

• Revising implementing documents to ensure that evidence of corrosion in these systems is evaluated for its potential impact on the integrity of the piping. For relevant indications, inspections or nondestructive testing is used to determine the extent of biofouling, the condition of the surface coating, the magnitude of localized pitting, and the amount of microbiologically influenced corrosion (MIC), if applicable.

• Revising implementing documents to ensure evaluations are performed for test or inspection results that do not satisfy established acceptance criteria, and a CR is initiated to document the concern in accordance with plant administrative procedures.

The applicant committed to implementing the enhancements no later than six months prior to entering the PEO or no later than the last refueling outage prior to the PEO.

The inspectors identified no concerns with these enhancements.

The inspectors concluded that the open-cycle cooling water system AMP as proposed provides reasonable assurance that the effects of aging will be managed, consistent with the license basis in the PEO.

B2.3.12 Closed Treated Water Systems This program is an existing mitigative and condition monitoring AMP that manages loss of material, cracking, and reduction of heat transfer in components via chemical treatment and monitoring of water chemistry in the following closed cooling water systems: turbine plant cooling water (TPCW), component cooling water (CCW),ventilation chilled water systems (both safety and non-safety), and diesel generator jacket water. The program parameters include:

(a) water treatment, including the use of corrosion inhibitors, which also act as a biocide, to modify the chemical composition of the water such that the effects of corrosion and microbiological activity are minimized;

(b) chemical testing of the water so that the water treatment program maintains the water chemistry within acceptable guidelines; and

(c) inspections to determine the presence or extent of corrosion and/or cracking. The applicant has plant specific guideline documents that specify the chemicals added, monitoring frequency, parameter limits, and action level limits. The program implements the guidance recommended in industry standards.

The applicant provided a review of industry and plant specific operating experience related to aging effects for the closed treated water systems AMP in the AMP basis document. The supplied operating experience was reviewed, and interviews were conducted with applicant personnel. For a sample of plant structures and systems covered by this AMP, accessible portions of the systems were walked down to observe aging effects, which included the material condition of the SSCs. No new aging effects other than those described by the GALL report were noted in the operating experience review or the walkdown.

Walkdowns of the CCW pump room and CCW heat exchanger room were completed, and both rooms were in excellent material condition. A walkdown of portions of the TPCW system in the Unit 1 turbine building was completed and locations where leaks in undersized welds had been repaired were observed. Two leaks that had yet to be repaired but which were documented by open work orders were also observed. The applicant provided a document and drawings that summarized the history of the undersized weld issue in the TPCW system. The license renewal drawings related to the TPCW system were reviewed to verify proper scoping of systems and components required by 10 CFR 54.4(a)(1), (a)(2), and (a)(3), including a walk down of TPCW system boundaries in the control building. The applicant also provided chemistry logs of the TPCW system from 2005-2023 that documented regular sampling for biological activity, which had been a program weakness prior to 2004.

The applicant identified enhancements needed to ensure consistency with the GALL report. Specifically, the enhancements include:

• Updating implementing documents or creating new documents to include visual inspection of surfaces exposed to the closed treated water environment for evidence of loss of material, cracking, or fouling whenever the system boundary is opened. At a minimum, in each 10-year period during the PEO, a representative sample (20% of the population, up to a maximum of 25 components) of piping and components will be inspected using techniques capable of detecting loss of material, cracking, and fouling, as appropriate.

The representative sample will be selected based on likelihood of corrosion or cracking. Inspections will be conducted in accordance with applicable ASME Code requirements. If there are no ASME Code requirements, inspections will be conducted in accordance with the EPRI Closed Cooling Water Chemistry Guideline. Guidance will be included to report and evaluate any detectable loss of material, cracking, or fouling associated with the surfaces exposed to the closed treated water (closed cooling water) environment per the Comanche Peak Nuclear Power Plant (CPNPP) Corrective Action Program.

Components will meet system design requirements, such as minimum wall thickness. If visual examination identifies adverse conditions, additional examinations, including ultrasonic testing, are conducted. Inspection results will be trended so that the progression of any corrosion or cracking can be evaluated and predicted.

• Performing additional inspection on the TPCW system, based on plant specific operating experience that shows a loss of material due to recurring internal corrosion (RIC) has been identified as an aging effect in the TPCW system at some weld locations. Implementing documents will be updated or new documents created to perform volumetric inspection of welds located within in-scope carbon steel TPCW piping (located within the control building and auxiliary building) to address RIC. At a minimum, in each 10-year period during the PEO, a representative sample (20% of the population, up to a maximum of 25 welds) of in scope TPCW welds will be inspected using techniques capable of detecting loss of material. Inspection results which indicate a reduction in wall thickness greater than 50 percent or below minimum wall thickness values will be entered into the corrective action program for evaluation.

The applicant also identified an exception to the GALL report, since the program will follow EPRI 3002000590, Closed Cooling Water Chemistry Guidelines, Revision 2 instead of EPRI Report 1007820, Closed Cooling Water Chemistry Guidelines, Revision 1. The differences between the two reports are only applicable to chromate-based treatment programs and because Comanche Peak does not use such based treatment programs in the closed treated water system AMP.

The applicant committed to implementing the enhancements and exception no later than six months prior to entering the PEO or no later than the last refueling outage prior to the PEO. The inspectors identified no concerns with these enhancements or the exception.

The inspectors concluded that the closed treated water AMP as proposed provides reasonable assurance that the effects of aging will be managed, consistent with the license basis in the PEO.

B.2.3.13 Inspection of Overhead Heavy Load and Light Load (Related to Refueling)

Handling Systems The inspection of overhead heavy load and light load (related to refueling) handling systems AMP is an existing condition monitoring program. The governing plant procedures are DBD-ME-006, Control of Heavy Loads at Nuclear Plants, MDA-308, Rev. 10, Requirements for Load Handling Personnel, and MDA-402, Rev. 13, Control of Load Handling Equipment. The plant procedures are based on the ASME B30 series standards by performing visual inspections prior-to-use of cranes/hoists to manage loose and/or missing bolts/nuts and loss of material due to corrosion and wear of structural components.

The applicant provided a review of industry and plant specific operating experience related to aging effects for this AMP. The inspectors reviewed the AMP basis document, implementing procedures, operating experience, drawings, and the license renewal application (LRA). In addition, the inspectors interviewed the program personnel and performed walkdowns on a sample of Spent Fuel Pool Crane and Diesel Generator Room Electric Chain Hoists to observe the general conditions. No significant concerns were identified during the walkdown.

The applicant identified two enhancements needed to ensure consistency with the GALL report. Specifically, the enhancements include:

• Elements 3 Parameters Monitored or Inspected, and 6, Acceptance Criteria, The CPNPP procedures will be enhanced to specifically inspect for visual indications of loss of material due to corrosion and wear. Any visual indication of loss of material due to corrosion or wear and any visual signs of loss of bolting preload will be evaluated according to ASME/ANSI B30.2 or ASME B30.16.

The inspectors concluded that the inspection of overhead heavy load and light load (related to refueling) handling systems AMP as proposed provides reasonable assurances that the effects of aging will be managed, consistent with the license basis in the PEO.

B.2.3.14 Compressed Air Monitoring The compressed air monitoring program is an existing condition and performance monitoring AMP that manages the loss of material of components in the instrument air system by periodically monitoring the system air for moisture and contaminants, and by inspecting internal surfaces of select compressed air system components. The applicant maintains their air system quality in accordance with manufacturer recommendations and industry guidelines.

The applicant provided a review of industry and plant specific operating experience related to aging effects for the compressed air monitoring AMP in the AMP basis document. The supplied operating experience was reviewed, and interviews were conducted with applicant personnel to confirm the accuracy of the AMP conclusion.

For a sample of plant structures and systems covered by this AMP, accessible portions of the systems were walked down to observe aging effects, which included the material condition of the SSCs. No new aging effects other than those described by the GALL report were noted in the operating experience review or the walkdown.

A walkdown of the component cooling water trim cooler associated with TR-2021-008393 was performed and the history of leakage associated with the trim cooler was discussed with the license renewal lead. There were a few drops of water on the floor near one end of the cooler, but there was no active leakage seen during the walkdown. A work order had been opened to correct the leak, but the work has not yet been performed because the cooler is associated with instrument air, and the applicant was waiting for an opportunity to take the system offline.

Commitment 19289, which commits Comanche Peak to performing quarterly air sampling, was reviewed. The preventive maintenance coordinator linked the commitment to the quarterly preventative maintenance in a controlled database that automatically provides inspection requirements on schedule to system engineers.

The applicant identified enhancements needed to ensure consistency with the GALL report. Specifically, the enhancements include:

• Procedures performing periodic internal inspections will be enhanced to specifically inspect components for signs of corrosion and abnormal corrosion products. Visual inspection results will be compared to previous inspection results to ascertain if adverse long-term trends exist. Signs of corrosion will be evaluated.

• Procedures performing air quality analysis will be enhanced to describe review of analysis results and comparison of previous results.

• Procedures will be enhanced to trend dewpoint temperature readings.

• Air sampling procedures will be enhanced to describe the corrective actions taken if air samples are unsatisfactory.

The applicant committed to implementing the enhancements no later than six months prior to entering the PEO or no later than the last refueling outage prior to the PEO.

The inspectors identified no concerns with these enhancements.

The inspectors concluded that the compressed air monitoring AMP as proposed provides reasonable assurance that the effects of aging will be managed, consistent with the license basis in the PEO.

B.2.3.16 Fire Water System and Commitment 10 The fire water system AMP is an existing program with enhancements that are intended to be consistent with the program described in NUREG-1801,Section XI.M27, Fire Water System. This program focuses on managing loss of material due to corrosion, MIC, or biofouling of steel components in fire protection systems exposed to water, which include sprinklers, nozzles, valve bodies, fire pump casings, hydrants, hose stations, fire water storage tanks, fire service mains, and standpipes.

Additionally, fire protection systems that are normally drained, such as dry-pipe type systems are also included within the scope of the applicants program. Fire hoses and gaskets are excluded from this program, as they are managed under the applicants system and structure scoping report (LUM00020-REPT-001 Scoping Rev. 1). The aging effects of coatings/linings for the internal surfaces of the fire water storage tanks are also managed within this applicants program.

The inspectors reviewed the applicants aging management program basis document, testing procedures for air and water flush testing, visual inspections, and electric and diesel driven fire pump operability tests, operating experience, condition reports, relevant information notices, code compliance review, site program documents, and associated work orders. Based on operating experience and previously stated documents, there were no new additional aging effects other than those described by the GALL report.

The program is implemented using inspection and monitoring activities, which include flush testing, internal and external inspection, and replacement of sprinkler heads.

Many enhancements, except for strainers for water-spray systems, to the applicants program will revise or create procedures that are in accordance with the National Fire Protection Association Standard (NFPA) 25, 2011 Edition. Procedures involving flush testing are enhanced to ensure that the strainers are fully flushed, as noted in previous requests for additional information.

The applicant will be taking one exception to air or water flush testing for their deluge systems in their containment pre-access filtration system charcoal filter units and primary plant ventilation engineered safety feature filter units. The reason for this exception is that the filter units cannot be tested with water, as the filter media will be compromised, and there are no alternate provisions for air flow testing as described in NFPA 25. In lieu of not being able to air or water flow test these deluge systems, the applicant will be enhancing the program by creating a new implementing document or revising an existing implementing document to perform external and internal visual inspections. External visual inspections, to check that spray spargers are not obstructed, will be inspected every refuel cycle. Internal visual inspections will be performed every five years on each unit.

The inspectors concluded that the fire water system AMP as proposed provides reasonable assurances that the effects of aging will be managed, consistent with the license basis in the PEO.

B.2.3.17 Fuel Oil Chemistry The fuel oil chemistry AMP is an existing program with the principal objective of minimizing the introduction and presence of contaminants in the plant fuel oil systems that could cause degradation of components in systems that contain fuel oil as well as identify, trend, and correct fuel oil system tank degradation.

The emergency diesel generator (EDG) diesel fuel oil storage tanks are drained, cleaned, visually inspected, and ultrasonically inspected on a 20-year frequency per site preventative maintenance (PM) activities. The applicant noted one exception to inspect and clean PM every 20 years instead of 10-year frequency recommended by NUREG-1801, Rev 2. Prior inspections have a positive trend where all four tanks have been found to be in acceptable condition. Additionally, this exception was reviewed and approved by NRC staff in association with buried tanks.

The second exception is to the NUREG-1801, Rev. 2 recommendation for periodic multilevel sampling to provide assurance that fuel oil contaminants ate below unacceptable levels. The guidance notes that if the tank design features do not allow for multilevel sampling, a sample methodology that includes a representative sample from the lowest point in the tank is allowed. The applicant originally obtained multi-level samples and conservatively performed an assessment that compared multi-level sampling to a single, lower-level sample. The analysis determined that no statistically significant difference existed between the sample methods and the NUREG-1801, Rev. 2 guidance allows for a representative sample from the lowest point in the tank as an acceptable method. The inspectors identified no concerns with the enhancements and exceptions for the Fuel Oil Chemistry AMP.

The inspectors reviewed the aging management evaluation report, implementing procedures, corrective action documents, work orders, and operating experience. The inspectors also sampled historical exam data and interviewed responsible applicant staff. From this review, the inspector noted that the current program includes the EDG storage tank and will add day tanks and the diesel driven fuel tank to enhance the program and the applicant was confident that they would be able to monitor using the same clean and inspect UT technique.

The inspectors concluded that the fuel oil chemistry AMP as proposed provides reasonable assurances that the effects of aging will be managed, consistent with the license basis in the PEO.

B.2.3.18 Reactor Vessel Surveillance and Commitment 20 This program manages loss of fracture toughness for reactor vessels caused by neutron irradiated embrittlement. The program includes periodic withdrawal of surveillance capsules containing reactor vessel material specimens (i.e., beltline metal and weld materials) and dosimetry from the reactor vessel. The data from specimen testing validate embrittlement projections, performed using NRC Regulatory Guide 1.99, Radiation Embrittlement of Reactor Vessel Materials, Revision 2, which demonstrate compliance with 10 CFR Part 50, Appendix G requirements and 10 CFR 50.61 limits (i.e., upper shelf energy, pressure temperature (PT) limit curves, and pressurized thermal shock). The data validates the neutron fluence projection for the reactor vessel and determine operating restrictions.

Commitment 20 specified:

1. A capsule in each unit will be reinserted prior to 36 effective full power years (EFPY) to achieve at least a vessel equivalent fluence of 80 EFPY.

2. For Unit 1, Capsule Z will be reinserted and then withdrawn and tested at the outage nearest to but following an additional 9 EFPY of operation. If Capsule Z is not available for reinsertion, Capsule W or V can be reinserted for an additional 13 EFPY of operation.

3. For Unit 2, Capsule Z will be reinserted and then withdrawn and tested at the outage nearest to but following an additional 8 EFPY of operation. If Capsule Z is not available for reinsertion, Capsule Y or V can be reinserted for an additional 14 EFPY of operation.

4. The capsule withdrawal schedule will be documented in the pressure temperature limits report (PTLR) and note that changes require NRC approval per 10 CFR 50, Appendix H.

5. The program documents will be modified to require that all pulled and tested specimens will be retained unless the NRC has approved the discard of the pulled and tested samples.

6. The program documents will be modified to establish operating restrictions to ensure that the plant is operated within the material aging OE, i.e., the cold leg temperature during normal operation will be limited to 525°F (minimum) to 590°F (maximum).

7. The program documents will be modified to require an update to the PTLR consistent with the surveillance test results after submittal of the surveillance test result consistent with 10CFR50 Appendix H.

The inspectors identified no concerns with the enhancements.

The inspectors determined that the applicant had tested three of the capsules from each unit as required under their original 40-year licenses. The applicant had removed the untested capsules (Unit 1 Capsules V, W, and Z, and Unit 2 Capsules V, Y, and Z) and placed them in the spent fuel pool (SFP). The inspectors reviewed the engineering change that installed ex-vessel neutron dosimetry in each unit to verify fast neutron exposure distributions met predicted values within the reactor vessel wall in accordance with Regulatory Guide 1.190, Calculational and Dosimetry Methods for Determining Pressure Vessel Neutron Fluence. The applicant believed that their analysis of record based on the capsule analysis for each unit would enable the plant to operate for 60 years. However, the applicant determined that actual unit performance while operating will result in them achieving the EFPY documented in their analysis of record before operating for 60 years.

Letter LTR-SDA-20-069, Update of the Comanche Peak Units 1 and 2 Pressure and Temperature Limit Report Based on the Most Recent Reactor Vessel Surveillance Capsule Test Reports, Revision 0 submitted the PTLR update for the capsule analysis in September 2006 for Unit 1 and September 2010 for Unit 2.

The inspectors questioned the applicant on what procedure provided the direction needed to implement their reactor vessel surveillance program tasks (e.g., upper shelf energy, adjusted reference temperature, and the pressure temperature limits).

Specifically, what procedural requirements would drive the applicant to update the PTLR prior to exceeding 36 EFPY or prevent them from inadvertently operating past 36 EFPY. Because the applicant could not identify a mechanism to ensure this would occur, the applicant initiated Incident Report 2023-006718 to identify the corrective actions required to address this deficiency. The applicant has four operating cycles for Unit 1 and six operating cycles before they exceed 36 EFPY.

The inspectors concluded that the reactor surveillance AMP as proposed provides reasonable assurance that the effects of aging will be managed, consistent with the license basis in the PEO.

B.2.3.20 Selective Leaching Inspection The selective leaching inspection AMP is a new program that is in progress and is a process that involves the preferential removal of one of the alloying elements from the material, which leads to the enrichment of the remaining alloying elements.

The program is a condition monitoring program and contains no preventive actions but will monitor by using visual inspections to identify differences in color, porosity, or general abnormal surface conditions of materials within the scope of the program.

The program will include a one-time inspection that will perform visual or destructive inspections of a sample susceptible to selective leaching to determine and demonstrate the absence of this aging effect or to implement an aging management program if a loss of material has occurred.

Currently, the AMP basis will require that selective leaching is not present and that material/environment susceptible to selective leaching has been determined. The scoping for this program identified 12 systems containing component types that will be managed by this program and materials susceptible to selective leaching.

The three materials susceptible to selective leaching scoped are aluminum bronze-copper allow containing greater than 8% aluminum, cast iron including cement-lines and ductile iron, and copper alloy containing greater than 15% zinc.

Because this is a new program, the inspectors were only able to review the AMP basis document describing the implementation strategy.

The inspectors concluded that the selective leaching inspection AMP as proposed provides reasonable assurance that the effects of aging will be managed, consistent with the license basis in the PEO.

B.2.3.22 External Surfaces Monitoring of Mechanical Components The external surfaces monitoring of mechanical components program is an existing condition monitoring AMP that manages the effects of aging related to loss of material, cracking, and change in material properties of metallic, elastomeric, and polymeric materials through periodic inspections and walkdowns that monitor for material degradation and leakage, including integrity of coatings, insulation degradation, and loss of material.

The applicant provided a review of industry and plant specific operating experience related to aging effects for this AMP in the AMP basis document. The supplied operating experience was reviewed, and interviews were conducted with applicant personnel to confirm the accuracy of the AMP conclusion. For a sample of plant structures and systems covered by this AMP, accessible portions of the systems were walked down to observe aging effects, which included the material condition of the SSCs. No new aging effects other than those described by the GALL report were noted in the operating experience review or the walkdown.

The firewater pumphouse and service water intake structure building were walked down; no concerns were noted. The basis document for the safety and non-safety related chilled water system insulation requirements were reviewed, including the associated drawings and a calculation sheet.

The applicant identified enhancements needed to ensure consistency with the GALL report. The enhancements included:

• The program will be enhanced to include elastomeric and polymeric components in the scope of the program.

• The program will be enhanced to include outdoor insulated components and indoor insulated components exposed to condensation in the scope of the program to monitor for degraded conditions under insulation.

• The program will be enhanced to clarify that below grade components that are accessible during normal operations or refueling outages for which access is not restricted are managed by this program.

• The program will be enhanced to allow external examinations to be credited to manage the aging effects of the internal surfaces of components when external conditions are representative of internal conditions.

• The program will be enhanced to include monitoring for discoloration, surface cracking, crazing, scuffing, dimensional change and hardening for polymeric and elastomeric components as well as exposure of internal reinforcement for reinforced elastomers.

• The program will be enhanced to include monitoring metallic components for loss of material due to material wastage; leakage; worn, flaking or oxide coated surfaces; and corrective coating degradation; as well as corrosion stains on thermal insulation.

• The program will be enhanced to include examples of components inspected, such as piping, piping components, ducting, polymeric components, insulation jacketing.

• The program will be enhanced to inspect unit coolers for reduction of heat transfer. The inspection will consist of the heat transfer surfaces of unit coolers that are exposed to external condensation and are credited with a heat transfer function.

• The program will be enhanced to ensure the inspections of surfaces readily visible during plant operations and refueling outages are performed once per refueling cycle. Surfaces that are not readily visible during plant operations and refueling outages are inspected when they are made accessible and at such intervals that would ensure the components intended functions are maintained.

• The program will be enhanced, when non-ASME Code inspections and tests are required, to ensure inspections follow site procedures that include inspection parameters for items such as lighting, distance, offset, surface coverage, and presence of protective coatings.

• The program will be enhanced to include inspection for elastomeric and polymeric components through a combination of visual inspection and manual or physical manipulation of the material. Visual inspections will cover 100 percent of accessible component surfaces. Manual or physical manipulation of flexible polymeric material includes touching, pressing on, flexing, bending, or otherwise manually interacting with the material in order to reveal changes in material properties, such as hardness, and to make the visual examination process more effective in identifying aging effects such as cracking. The sample size for manipulation will be at least 10 percent of available surface area. The inspection parameters for elastomers and polymers shall include the following:

o Surface cracking, crazing, scuffing, and dimensional change (e.g.,

ballooning and necking)o Loss of thickness o Discoloration (evidence of a potential change in material properties that could be indicative of polymeric degradation)o Exposure of internal reinforcement for reinforced elastomers, and o Hardening as evidenced by a loss of suppleness during manipulation where the component and material are appropriate for manipulation.

• The program will be enhanced to include inspecting insulated components in an outdoor environment or in an indoor environment that may be exposed to condensation, once every 10 years during the PEO. The population and sample sizes used for inspections will be determined based on the material type and environment combination. A minimum of 20 percent of the in-scope piping length, or 20 percent of the surface area for components whose configuration does not conform to a 1-foot axial length determination (e.g.,

valve, accumulator, tank) will be inspected after the insulation is removed.

Alternatively, any combination of a minimum of twenty-five 1-foot axial length sections and components from each material type is inspected, with a maximum of 25 inspections required for each material environment in each population.

• The program will be enhanced to include the following alternatives to removing insulation after the initial inspection:

o Subsequent inspections may consist of examination of the exterior surface of the insulation with sufficient acuity to detect indications of damage to the jacketing or protective outer layer (if the protective outer layer is waterproof) of the insulation when the results of the initial inspections meet the following criteria:

No loss of material due to general, pitting, or crevice corrosion beyond that which could have been present during initial construction is observed during the first set of inspections, and No evidence of SCC is observed during the first set of inspections.

o If:

(a) the external visual inspections of the insulation reveal damage to the exterior surface of the insulation or jacketing,

(b) there is evidence of water intrusion through the insulation (e.g., water seepage through insulation seams/joints), or

(c) the protective outer layer (where jacketing is not installed) is not waterproof, then periodic inspections under the insulation should continue as conducted for the initial inspection.

• Removal of tightly adhering insulation that is impermeable to moisture is not required unless there is evidence of damage to the moisture barrier. If the moisture barrier is intact, the likelihood of corrosion under insulation (CUI) is low for tightly adhering insulation. Tightly adhering insulation is a separate population from the remainder of insulation installed on in-scope components.

The entire population of in-scope piping that has tightly adhering insulation is visually inspected for damage to the moisture barrier with the same frequency as for other types of insulation inspections. These inspections are not credited towards the inspection quantities for other types of insulation.

• The program will be enhanced to require selection of bounding or lead components most susceptible to CUI in an outdoor environment or in an indoor environment that may be exposed to condensation. This could be due to time in service, severity of operating conditions (e.g., amount of time that condensate would be present on the external surfaces of the component), and lowest design margin for inspection under insulation.

• The program will be enhanced to include the following acceptance criteria:

o For metallic surfaces, any indications of degradation are evaluated.

o For stainless steel surfaces, a clean, shiny surface is expected, and any deviation is evaluated.

o For flexible polymers, a uniform surface texture and uniform color with no dimension change is expected and any deviation is evaluated.

o For flexible materials, changes in physical properties (e.g., the hardness, flexibility, physical dimensions, and color. of the material are unchanged from when the material was new) are evaluated.

o For rigid polymers, surface changes affecting performance, such as erosion, cracking, crazing, and chalking, are evaluated.

The applicant committed to implementing the enhancements no later than six months prior to entering the PEO or no later than the last refueling outage prior to the PEO.

The inspectors identified no concerns with these enhancements.

The inspectors concluded that the external surfaces monitoring of mechanical components AMP as proposed provides reasonable assurance that the effects of aging will be managed, consistent with the license basis in the PEO.

B.2.3.23 Flux Thimble Tube Inspection (XI.M37) and Commitment 25 The program manages the effects of aging for loss of material due to wear. The program uses the nondestructive examination methodology of eddy current testing to determine flux thimble tube wall thickness and to predict wear rates for the early identification of potential flux thimble tube failures. Inspection of all flux thimble tubes are periodically performed on each unit, with a frequency of every other outage. The results are evaluated and trended to determine if corrective actions are required or if the inspection frequency needs to be adjusted to ensure the pressure boundary is maintained. Corrective actions include repositioning, isolating, or replacing the tube.

Commitment 25 specified continue the existing flux thimble tube Inspection aging management program during the PEO and complete the implementation no later than 6 months prior the PEO, or no later than the last refueling outage prior to entering the PEO.

The inspectors reviewed the aging management evaluation report, implementing procedures, corrective action documents, work orders, and operating experience. The inspectors also reviewed historical exam data and interviewed responsible applicant staff. The inspectors performed a walkdown of the flux thimble tube room for boric acid and observed eddy current testing of the flux thimble tubes for Unit 1 during the 1RF23 refueling outage.

The inspectors concluded that the flux thimble tube inspection AMP as proposed provides reasonable assurances that the effects of aging will be managed, consistent with the license basis in the PEO.

B.2.3.25 Lubricating Oil Analysis This is an existing mitigative and condition monitoring program that manages the loss of material and reduction of heat transfer in components exposed to lubricating oil and is credited for license renewal. The program maintains oil system contaminants within acceptable limits and the principal objective is to provide reasonable assurance that the oil environment in mechanical systems is maintained to the required quality to prevent or mitigate age-related degradation of components with the scope of the AMP.

The program checks for water and a particle count to detect evidence of contamination by moisture or excessive corrosion by sampling for water, particle count and other parameters. lubricating oil analysis AMP is consistent without exception to NUREG-1801.

The inspectors reviewed the aging management evaluation report, implementing procedures, corrective action documents, work orders, and operating experience. The inspectors also sampled historical exam data and interviewed responsible applicant staff. From this review, the inspector noted that there would be no additional lubricating inspections completed prior to the PEOs and that the applicant had plans to revise the procedures and/or the preventative maintenance procedures to clarify that phase-separated water in any amount is not acceptable for any component within the license renewal scope.

The inspectors concluded that the lubricating oil analysis AMP as proposed provides reasonable assurances that the effects of aging will be managed, consistent with the license basis in the PEO.

B.2.3.26 Monitoring of Neutron-Absorbing Materials Other than BORAFLEX and Commitment 28 The program manages the effects of aging on neutron-absorbing components/materials used in spent fuel racks. The program employs neutron absorber surveillance coupons of BORAL material, stored in each spent fuel pool that are tested using visual examination, dimensional measurements (length, width, and thickness), neutron attenuation, and weight and specific gravity. The program examines changes in dimensional measurements to determine if loss of material has occurred, and changes in weight and specific gravity to determine if changes in neutron-absorbing capabilities has occurred via a decrease in boron areal density.

Inspection and testing of at least one coupon are performed periodically, not to exceed once every 10 years. Acceptance criteria for neutron attenuation and dimensional measurements are established as indicators of potential degradation and adverse trends in the condition of the BORAL material. Correction actions are taken prior to challenging the 5 percent sub-criticality margin of the spent fuel pool criticality analysis. Results not meeting the established acceptance criteria are entered into the corrective action program for resolution.

Commitment 28 specified continuing the existing monitoring of neutron-absorbing materials other than Boraflex aging management program during the PEO, including an enhancement to ensure the required corrective action to address failed acceptance criteria includes a comparison of current and future predicted parameters to the assumptions of the spent fuel pool criticality analysis. The program is scheduled to be implemented no later than 6 months prior the PEO, or no later than the last refueling outage prior to entering the PEO.

The inspectors identified no concerns with the enhancement. The inspectors reviewed the aging management evaluation report, implementing procedures, corrective action documents, examination reports, and operating experience.

The inspectors concluded that the monitoring of neutron-absorbing materials Other than BORAFLEX AMP as proposed provides reasonable assurances that the effects of aging will be managed, consistent with the license basis in the PEO.

B.2.3.27 Buried and Underground Piping and Tanks and Commitment 29 This program manages loss of coating integrity, and loss of material on external surfaces of buried and underground piping and tanks. The program includes inspections of the internal surfaces of the diesel fuel oil storage tanks. The applicant included all in-scope underground piping and components of carbon steel, cast iron, and cement-lined ductile iron. This program included the following systems: standby service water, emergency diesel generator (fuel oil), including the fuel oil storage tanks, and fire protection systems.

The applicant identified that they manage aging through preventive and mitigative actions (i.e., coatings, backfill quality, and cathodic protection). The number of inspections will be based on the effectiveness of the preventive and mitigative actions. Specifically, the inspections for each 10-year inspection period, commencing 10 years prior to the PEO, is based on the guidance provide in LR-ISG-2015-01, Changes to Buried and Underground Piping and Tank Recommendations, Table XI.M41-2 (adjusted for a 2-unit plant site), Inspection of Buried and Underground Piping and Tanks. For steel components, the acceptance criteria for the effectiveness of the cathodic protection are less than or equal to -850 mV. Wall thickness is determined by a nondestructive examination technique such as ultrasonic testing.

The applicant took an exception to this program to inspect the diesel generator fuel oil storage tanks every 20 years instead of 10 years. The tanks will be inspected no later than the first 10 years after entering the PEO. The inspectors confirmed that the current wall thickness would be acceptable until the next scheduled inspection and identified no concerns with the exception.

Commitment 29 specified the following,

1. Revise procedures to manage loss of material due to corrosion of piping system bolting within the scope of this program.

2. Revise cathodic protection procedures to implement the requirements of National Association of Corrosion Engineers (NACE) SP0169-2007 or NACE RP0285-2002.

3. Ensure pit depth gages or calipers used for measuring wall thickness have been demonstrated to be effective for the material, environment, and conditions (e.g., remote methods) during the examination, and they are capable of quantifying general wall thickness and the depth of pits.

4. Perform inspections of buried and underground piping and tanks within the fire

protection, SSW, and emergency diesel generator and auxiliary systems in accordance with LR-ISG-2015-01 Table XI.M41-2 for steel. The inspections will be distributed evenly among the units. Since CPNPP is a two-unit site, the inspection quantities are 50% greater than LR-ISG-2015-01 Table XI.M41-2 and are rounded up to the nearest whole inspection.

5. When the inspections for a given material type is based on percentage of

length and results in an inspection quantity of less than 10 feet, then 10 feet of piping is inspected. If the entire run of piping of that material type is less than 10 feet in total length, then the entire run of piping is inspected.

6. Ensure a minimum of 25% of the internal surface of the diesel generator fuel

oil storage tank, including the upper and lower portion of the tank and tank end bells, is inspected volumetrically.

7. With respect to cathodic protection, use an acceptance criterion equal to or

more negative than -850 mV instant off for all in-scope buried components.

Trend potential difference and current measurements to identify changes in the effectiveness of the cathodic protection system and/or coatings. Ensure the critical potential limit does not exceed -1200 mV.

8. Trend the main fire pump activity and, for small leaks, the fire water storage

tank level indicator alarms and associated makeup from the treated water system (or similar parameter) to identify concerns with buried fire water yard loop header leakage.

9. Ensure type and extent of coating degradation is evaluated by evaluators who:

(a) possess 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."

10.Where loss of material is identified, the measured wall thickness is projected to the end of the PEO such that minimum wall thickness requirements are maintained.

11.Revise acceptance criteria to ensure there is no evidence that backfill caused damage to the respective component coatings or the surface of the component (if not coated), and changes in fire pump activity (or similar parameter) that cannot be attributed to causes other than leakage from buried piping are not occurring.

12.Revise procedures to conduct an extent of condition evaluation when damage to a coating has been evaluated as significant and the damage was caused by nonconforming backfill to determine the extent of degraded backfill in the vicinity of the observed damage.

13.Revise procedures to state unacceptable cathodic protection survey results are entered into the plant corrective action program.

14.When using the option of monitoring the activity of a main fire pump or fire water storage tank level indicator alarms (and associated makeup from the treated water system) instead of inspecting buried fire water system piping, a flow test or system leak rate test is conducted by the end of the next refueling outage or as directed by the current licensing basis, whichever is shorter, when unexplained changes in main fire pump activity, fire water storage tank level indicator alarms, (or equivalent equipment or parameter) are observed.

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

16. Where the coatings, backfill, or the condition of exposed piping does not meet acceptance criteria, the degraded condition is repaired, or the affected component is replaced. In addition, where the depth or extent of degradation of the base metal could have resulted in a loss of pressure boundary function when the loss of material is extrapolated to the end of the PEO, an expansion of sample size is conducted. The number of inspections within the affected piping categories are doubled or increased by 5, whichever is smaller. If the acceptance criteria are not met in any of the expanded samples, an analysis shall be conducted to determine the extent of condition and extent of cause.

The timing of the additional examinations is based on the severity of the degradation identified and is commensurate with the consequences of a leak or loss of function.

However, in all cases, the expanded sample inspection is completed within the 10-year interval in which the original inspection was conducted or, if identified in the latter half of the current 10-year interval, within 4 years after the end of the 10-year interval. These additional inspections conducted during the four years following the end of an inspection interval cannot also be credited towards the number of inspections in Table XI.M41-2 for the following 10-year interval. The number of inspections may be limited by the extent of piping or tanks subject to the observed degradation mechanism.

The expansion of sample inspections may be halted in a piping system or portion of system that will be replaced within the 10-year interval in which the inspections were conducted or, if identified in the latter half of the current 10-year interval, within 4 years after the end of the 10-year interval. The inspectors identified no concerns with the enhancements.

The inspectors determined that procedure EPG-9.03, Underground Piping and Tank Program, Revision 5 implemented the NEI 09-14, Guideline for The Management of Underground Piping and Tank Integrity, Revision 1, requirements had not been updated to include the license renewal aging management program enhancements.

The applicant had not inspected any sections of the in-scope buried piping. The inspectors determined that the applicant had not begun any implementation of the enhancements needed to ensure that the program meets the GALL report.

The applicant had modified their cathodic protection system in 2013 and was taking actions to ensure that they increased the system availability above 85 percent so that they met the minimum inspection requirements required by LR-ISG-2015-01, Table XI.M41-2. The inspectors sampled the bimonthly and annual cathodic preventive maintenance tasks. The data for the last three annual surveillances had exceeded 85 percent and the applicant expects that the average will be greater than 85 percent as required within 5 years before entering the PEO.

The applicant had last performed an area potential earth current (APEC) survey of the buried metallic structures in 2017. The applicant plans to perform this survey in 2027 as a 10-year preventive maintenance task before transitioning to a 5-year frequency. The APEC survey described that the upgraded cathodic protection system had sufficient capacity to enable the applicant to meet the -850 mV criterion required by LR-ISG-2015-01. The applicant determined that soil conditions result in anode ground bed dry-out that affects the cathodic protection readings. To compensate the applicant implemented a recurring monthly preventative maintenance task to pour water into the cathodic protection wells that has been effective in addressing the dry-out issues and resulted in more consistent cathodic protection readings.

The inspectors determined that the fire water storage tank has tank level alarms, and the applicant can monitor for makeup to the tank from the treated water system.

The inspectors concluded that the buried and underground piping and tanks AMP as proposed provides reasonable assurances that the effects of aging will be managed, consistent with the license basis in the PEO.

B2.3.28 Internal Coatings/Linings for In-Scope Piping, Piping Components, Heat Exchangers, and Tanks The internal coatings/linings for in-scope piping, piping components, heat exchangers, and tanks AMP is an existing condition monitoring AMP that manages degradation related to loss of material and loss of coating/lining integrity through periodic visual inspections of the internal surfaces of in-scope components. These components are exposed to raw water, treated water, and air, which can lead to loss of material or coating/lining, or lead to downstream effects, such as reduction in flow, pressure, or heat transfer then coatings/linings become debris.

The applicant provided a review of industry and plant specific operating experience related to aging effects for the internal coatings/linings for in-scope piping, piping components, heat exchangers, and tanks AMP in the AMP basis document. The supplied operating experience was reviewed, and interviews were conducted with applicant personnel to confirm the accuracy of the AMP conclusion. For a sample of plant structures and systems covered by this AMP, accessible portions of the systems were walked down to observe aging effects, which included the material condition of the SSCs. No new aging effects other than those described by the GALL report were noted in the operating experience review or the walkdown.

Walk downs of the safety injection pump lube oil cooler and reservoir room and the diesel generator room for Unit 2 were performed. It was confirmed that the reservoir is part of the lube oil skid assembly and located in the floor of the room, below the pump, cooler, and filter, which are mounted on the top of the reservoir, thereby limiting physical access to the reservoir. Access to the emergency diesel generator intercooler via access covers and piping removal was confirmed to be sufficient to allow internal inspection of the coating on the interior of the intercooler.

The applicant identified enhancements needed to ensure consistency with the GALL report, as modified by LR-ISG-2013-01. The enhancements included:

• Include the following internal coatings/linings in the scope of the AMP:

o Emergency diesel generator intercoolers o Fire protection cement-lined piping o Internally coated four inch service water piping within the service water intake structure (SWIS)

• Perform visual inspections capable of identifying flaking, peeling, delamination, and spalling.

• Perform baseline inspections of coatings/linings in the 10-year period prior to the PEO for the:

o Emergency diesel generator intercoolers o Internally coated four inch service water piping within the SWIS

• Perform subsequent inspections based on an evaluation of the effect of a coating/lining failure on the in-scope components intended function, potential problems identified during prior inspections, and known service life history.

Subsequent inspection intervals are established by a coating specialist qualified in accordance with an ASTM International standard endorsed in RG 1.54. Inspection intervals should not exceed those in LR-ISG-2013-01 Table 4a, Inspection Intervals for Internal Coatings/Linings for Tanks, Piping, Piping Components, and Heat Exchangers.

• Perform inspections of all accessible internally coated surfaces of in-scope heat exchangers.

• Establish qualifications for cementitious coatings/linings inspectors to have a minimum of 5 years of experience inspecting or testing concrete structures or cementitious coatings/linings, or a degree in the civil/structural discipline and a minimum of 1 year of experience.

• Perform opportunistic inspections of the cement lining applied to the internal surface of buried fire protection piping.

• Perform a pre-inspection review of the previous two inspections, when available that includes reviewing the results of inspections and any subsequent repair activities.

• Prepare post-inspection reports, by a coatings specialist, to include: a list and location of all areas evidencing deterioration, a prioritization of the repair areas into areas that must be repaired before returning the system to service and areas where repair can be postponed to the next refueling outage, and where possible, photographic documentation indexed to inspection locations. When corrosion of the base material is the only issue related to coating/lining degradation of the component and external wall thickness measurements are used in lieu of internal visual inspections of the coating/lining, the corrosion rate of the base metal is trended.

• Include the following acceptance criteria:

o Indications of peeling and delamination are not acceptable.

o Blisters, cracking, flaking, and rusting are evaluated by a coatings specialist qualified in accordance with an ASTM International standard endorsed in RG 1.54. Blisters should be limited to a few intact small blisters that are completely surrounded by sound coating/lining bonded to the substrate. Blister size and frequency should not be increasing between inspections.

o Minor cracking and spalling of cementitious coatings/linings is acceptable provided there is no evidence that the coating/lining is debonding from the base material.

o As applicable, wall thickness measurements, projected to the next inspection, meet design minimum wall requirements.

• Revise corrective actions to include the following:

o As an alternative to repair/replacement, coatings exhibiting indications of peeling and delamination may be returned to service if:

(a) physical testing is conducted to ensure that the remaining coating is tightly bonded to the base metal;

(b) the potential for further degradation of the coating is minimized, (i.e., any loose coating is removed, the edge of the remaining coating is feathered);

(c) adhesion testing using ASTM International standards endorsed in RG 1.54 is conducted at a minimum of 3 sample points adjacent to the defective area;

(d) an evaluation is conducted of the potential impact on the system, including degraded performance of downstream components due to flow blockage and loss of material of the coated component; and (e)follow-up visual inspections of the degraded coating are conducted within 2 years from detection of the degraded condition, with a re-inspection within an additional 2 years, or until the degraded coating is repaired or replaced.

o If coatings/linings are credited for corrosion prevention (e.g., corrosion allowance in design calculations is zero, the preventive actions program element credited the coating/lining) and the base metal has been exposed or it is beneath a blister, the components base material in the vicinity of the degraded coating/lining will be examined to determine if the minimum wall thickness is met and will be met until the next inspection.

o If a blister is not repaired, physical testing may be conducted to ensure that the blister is surrounded by sound coating/lining bonded to the surface. Physical testing consists of adhesion testing using ASTM International standards endorsed in RG 1.54. An alternative means of determining that the remaining coating/lining is tightly bonded to the base metal may be conducted such as lightly tapping the coating/lining. Acceptance of a blister to remain in service should be based both on the potential effects of flow blockage and degradation of the base material beneath the blister.

The applicant also identified four exceptions to the GALL report, which are described below:

• Exception to Element 1, Scope of Program - The applicant included the environment of air within the scope of the AMP since the EDG combustion air subsystem contains an internally coated component that requires aging management. The NRC staff performed a walkdown of an emergency diesel generator and confirmed that there was sufficient access to perform an internal inspection of the combustion air subsystem by removing access covers and piping.

• Exception to Element 3, Parameters Monitored or Inspected and Element 4, Detection of Aging Effects - The applicant took an exception to baseline and on-going periodic inspections to detect coating degradation, along with physical testing to determine extent of coating damage, of the Safety Injection Pump Lube Oil Cooler Reservoirs, due to physical limitations. The Safety Injection Pump Lube Oil Reservoirs are internally lined and Comanche Peak samples the lubricating oil quarterly, including cleaning and inspecting an oil filter as part of the lubricating oil sampling activities. The NRC staff walked down a Safety Injection Pump Lube Oil room and confirmed the physical limitation.

• Exception to Element 4, Detection of Aging Effects - The applicant took an exception to the baseline and subsequent coating/lining inspections that commence in the 10-year period prior to the PEO. The Internal Coatings AMP will perform periodic flow testing, as well as opportunistic inspections, of the cement lining applied to the internal surface of buried fire protection piping, based on the guidance in SLR-ISG-2021-02-MECHANICAL. This ISG also requires continuous monitoring of system pressure monitoring through a main control room alarm, which the applicant has committed to perform, and a review of operating experience that finds no evidence of leaks due to age-related degradation of internal coatings (cement lining) used in the buried in-scope fire water system components, which the NRC staff confirmed. This alternative is supported by SLR-ISG-2021-02-MECHANICAL, and the applicant has met the requirements of the ISG.

• Exception to Element 7, Corrective Actions - The applicant took an exception to performing adhesion testing of coatings/linings to determine if the remaining coating/lining is tightly adhered to the base metal. As discussed in GALL Report AMP XI.M42, this is an acceptable alternative when adhesion testing is not possible due to physical constraints. The applicant stated that they intend to use this exception regardless of physical constraints, since the ASTM international standards endorsed in RG 1.54 are destructive to the coating/lining. These adhesion testing methods are based on using tape tests (ASTM D 3359-09), portable adhesion testers (ASTM D 4541-09), or a knife (ASTM D 6677-07), and there is no potential for a blister to remain in service after any of these adhesion testing methods. Lightly tapping the coating/lining is an appropriate alternative for testing blisters in a nondestructive manner and determining whether the coating/lining is tightly bonded to the base metal.

The applicant committed to implementing the enhancements and exceptions no later than six months prior to entering the PEO or no later than the last refueling outage prior to the PEO. The inspectors identified no concerns with these enhancements or exceptions.

The inspectors concluded that the internal coatings/linings for in-scope piping components, heat exchangers, and tanks AMP as proposed provides reasonable assurance that the effects of aging will be managed, consistent with the license basis in the PEO.

B.2.3.32 10 CFR Part 50, Appendix J The 10 CFR Part 50, appendix j AMP is an existing performance monitoring program and does not include preventive measures. The governing plant procedures are STA-743, 10CFR50 Appendix J Containment Leakage Rate Testing Program, Revision 2 and TSP-743, 10CFR50 Appendix J Option B Test Intervals and Administrative Limits, Revision 0. The Type A, Containment Integrated Leakage Rate Testing (ILRT), for Units 1 and 2 is implemented in accordance with Option B of 10 CFR 50 Appendix J as required by Technical Specification. The program further includes the Local Leak Rate Tests (LLRT) of Types B and C tests and pre-test visual inspections.

The applicant provided a review of industry and plant specific operating experience related to the 10 CFR Part 50, Appendix J AMP. The inspectors reviewed LR AMP basis document, implementing procedures, operating experience, drawings, licensing amendment request for extension of containment leakage rate testing frequency, design change notice and the LRA, and interviews were conducted with applicant personnel to confirm the accuracy of the AMP conclusion. In addition, the inspectors performed walkdowns on the external of Unit 1 and 2 containment buildings to observe the general conditions, which included the current material condition of the containment structures that also included the cut-out cylindrical section of Unit 1 containment for the steam generator replacement. No significant concerns were identified during the walkdown.

The applicant did not identify any enhancements for this AMP, which is consistent with NUREG-1801, AMP XI.S4. Further, the applicant stated that no additional 10 CFR Part 50, Appendix J inspections are required prior to PEO.

The inspectors concluded that the 10 CFR Part 50, appendix j AMP as proposed provides reasonable assurance that the effects of aging will be managed, consistent with the license basis in the PEO.

B.2.3.33 Masonry Wall The masonry wall AMP is an existing condition monitoring program and does not include specific preventative measures. The masonry wall AMP is executed through the Structures Monitoring AMP following the principal objective of detecting aging and age-related degradation of masonry walls in the scope of LR. Therefore, the governing plant procedure for the Masonry Wall AMP is STI-744.09, Comanche Peak Nuclear Power Plant Station Administration Manual, Structural Monitoring Inspection Guide, Revision 0. Further, masonry walls that perform a fire barrier intended function are also managed by the Fire Protection AMP (XI.M26), and its governing procedure is STA-722, Comanche Peak Nuclear Power Plant Station Instruction Manual, Fire Protection Program, Revision 8. The masonry walls in the program are inspected by qualified personnel. These personnel inspect the structures and components using the guidance specified by industry standards. The applicant inspects the masonry walls at least once every 5 years to ensure there is no loss of intended function.

The applicant provided a review of industry and plant specific operating experience related to aging effects for the masonry wall AMP. The inspectors reviewed LR AMP basis document, implementing procedures, operating experience, drawings and the LRA and interviews were conducted with applicant personnel to confirm the accuracy of the AMP conclusion. In addition, the inspectors interviewed the program manager and performed walkdowns on a sample of accessible portions of the masonry walls (fixed and removable) to observe the general conditions. No significant concerns were identified during the walkdown.

The applicant identified two enhancements needed to ensure consistency with the GALL Report. Specifically, the enhancements include:

• Elements 1, Scope of Program, and 4, Detection of Aging Effects, to include the bricks and mortar near the diesel generator exhaust silence/muffler and relief valve for each diesel with a baseline inspection prior to entering the PEO.

• Element 4, Detection of Aging Effects, to qualify of the inspector and reviewer for masonry walls and other structural components to match current ACI 349.3R requirements through the Structures Monitoring AMP.

The team identified no concerns with these enhancements. The applicant committed to implementing the enhancements no later than six months prior to entering the PEO or no later than the last refueling outage prior to the PEO.

The inspectors concluded that the masonry wall AMP, as described in the LRA with the proposed enhancements, provides reasonable assurances that the effects of aging will be managed, consistent with the license basis in the PEO.

B.2.3.34 Structures Monitoring The structures monitoring AMP is an existing aging management program based on the requirements of 10 CFR 50.65 and NRC RG 1.160. The program consists primarily of periodic visual inspections of plant structures and components for evidence of deterioration or degradation. The governing plant procedure for the AMP is STI-744.09, Comanche Peak Nuclear Power Plant Station Instruction Manual, Structural Monitoring Inspection Guide, Revision 0.

For concrete structures, the program manages the aging effects of loss of material, cracking, increase in porosity and permeability, loss of foundation strength, and reduction in concrete anchor capacity due to local concrete degradation. For the steel structures and components, the program manages the aging effects of loss of material due to corrosion, loose bolts, missing or loose nuts, cracking of concrete around the anchor bolts, and other conditions indicative of loss of preload. The program also includes aging management for elastomers in Structural Isolation Gap elements and the component supports commodity group in addition to periodic sampling and testing of groundwater to assess the impact of any changes in its chemistry on below grade concrete structures.

The structures and components in the program are inspected by qualified personnel.

These personnel inspect the structures and components using the guidance specified by industry standards. The applicant inspects the structures and components at least once every 5 years to ensure there is no loss of intended function except the sampled component supports identified above.

For this program, the applicant identified seventeen enhancements to the scope of program, preventive actions, parameters monitored or inspected, detection of aging effects, and acceptance criteria program elements for ensuring consistency with the GALL-LR Report and committed to implementing the enhancements no later than six months prior to entering the PEO or no later than the last refueling outage prior to the PEO. The inspectors reviewed these enhancements and identified no concerns.

The inspectors concluded that the structures monitoring AMP, as described in the LRA with the proposed enhancements, provides reasonable assurance that the aging effects will be managed, consistent with the license basis in the PEO.

Additional details regarding the inspectors observations during review of the structures monitoring program are included in the Inspection Results section of this report.

B.2.3.35 Inspection of Water-Control Structures Associated with Nuclear Power Plants The inspection of water-control structures associated with nuclear power plants AMP is an existing aging management program and is implemented as part of the structures monitoring AMP. The program is a condition monitoring program that addresses age-related deterioration, degradation due to environmental conditions, and the effects of natural phenomena that may affect water-control structures. The governing plant procedure for the AMP is STI-744.09, Comanche Peak Nuclear Power Plant Station Instruction Manual, Structural Monitoring Inspection Guide, Revision 0. The supporting plant procedure for the AMP is PPT-SX-7517, Comanche Peak Steam Electrical Station Unit Common Testing Manual, Safe Shutdown Impoundment Inspection, Revision 2.

For the concrete structures, the program manages the aging effects of cracking, movements (e.g., settlement, heaving, deflection), conditions at junctions with abutments and embankments, loss of material, increase in porosity and permeability, seepage, and leakage. For the earthen embankment structures, the program manages the aging effects of settlement, depressions, sink holes, slope stability, seepage, proper functioning of drainage systems, and degradation of slope protection features.

For the steel structures and components, the program manages the aging effects of loss of material due to corrosion, loose bolts, missing or loose nuts, cracking of concrete around the anchor bolts, and other conditions indicative of loss of preload.

For the service water intake channel, discharge canal and equalization canal, the program manages the aging effects of erosion or degradations.

The applicant provided a review of industry and plant specific operating experience related to aging effects for the inspection of water-control structures associated with nuclear power plants AMP. The inspectors reviewed LR AMP basis document, implementing procedures, operating experience, dam inspection report, drawings, and the LRA. In addition, the inspectors performed walkdowns on the service water intake structure and discharge canal to observe aging effects, which included the material condition of the structures and components. No significant concerns were identified during the walkdown.

The inspectors interviewed the program manager and found that Freese and Nichols, Inc performs the inspection of dam annually and always sends the diver to inspect the dam on the safe shutdown impoundment (SSI) side.

The structures and components in the program are inspected by qualified personnel.

These personnel inspect the structures and components using the guidance specified by industry standards. The applicant inspects the structures and components at least once every 5 years to ensure there is no loss of intended function.

The applicant identified seven enhancements to the preventive actions, parameters monitored or inspected, detection of aging effects, and monitoring and trending program elements for ensuring consistency with the GALL-LR Report and committed to implementing the enhancements no later than six months prior to entering the PEO or no later than the last refueling outage prior to the PEO. The inspectors reviewed these enhancements and had no concerns.

The inspectors concluded that the water-control structures associated with nuclear power plants AMP, as described in the LRA with the proposed enhancements provides reasonable assurance that the effects of aging will be managed, consistent with the license basis in the PEO.

B.2.3.37 Insulation Material for Electrical Cables and Connections Not Subject to 10CFR50.49 EQ Requirements This program manages the effects of adverse localized environments (ALE) on the insulation of non-environmentally qualified accessible electrical cables. An ALE results when environmental conditions (e.g., temperature, radiation, or moisture)could damage the electrical cable insulation and connectors. The aging effects include embrittlement, discoloration, cracking, melting, swelling, or surface contamination that could indicate electrical insulation degradation. ALEs will be evaluated using an integrated approach that includes

(1) a review of plant specific and industry operating experience,

(2) a review of environmental qualification zone maps, and

(3) conversations with plant personnel cognizant of specific area and room environmental conditions.

Commitment 39 specified the implementation of the new insulation material for electrical cables and connections not subject to 10 CFR 50.49 environmental qualification (EQ) requirements aging management program no later than 6 months prior to each unit entering the PEO or no later than the last refueling outage prior to the PEO.

The inspectors determined that procedure EPG-9.05, Cable Reliability Program, Revision 5, prescribes activities to address the potential aging issues involved with medium (<35 KV) and low voltage (<1000 V) power cables. From interviews with license renewal project personnel, the inspectors determined that they plan to use a vendor to inspect the areas of the plant to identify ALE that may impact non-environmentally qualified electrical cables.

The inspectors determined that the applicant had developed a cable aging management program in response to industry operating experience and initiatives.

Procedure EPG-9.05, Cable Aging Management Program, dated July 18, 2011, prescribed actions to address cable insulation degradation for safety related cables throughout the plant as documented in Commitment 4473432. Condition Report 2013-005325 documents actions taken by the applicant to address cable reliability, aging, and monitoring. The applicant developed a cable health aging management program walkdown procedure to look for ALE in both units. The applicant walked down the Unit 1 containment during 1RF17 and the Unit 2 containment during 2RF14. The inspectors identified no concerns with these initiatives.

The inspectors concluded that the insulation material for electrical cables and connections not subject to 10CFR50.49 EQ requirements AMP as proposed provides reasonable assurances that the effects of aging will be managed, consistent with the license basis in the PEO.

B.2.3.38 Insulation Material for Electrical Cables and Connections Not Subject to 10CFR5049 EQ Requirements Used in Instrumentation Circuits and Commitment 40 This program manages the effects of aging on non-environmentally qualified cables and connections used in high-voltage, low-level current signal applications that are sensitive to reduction in electrical insulation resistance. The applicant can use either of two methods to determine the aging effects for the cables and connections. In the first method, the license can review the calibration results and instrument circuit performance. In the second method, the applicant can test the cables by removing the cables from the circuit. The applicant will perform an engineering evaluation to identify the test frequency.

Commitment 40 specified the implementation of the new Insulation Material for Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits aging management program no later than 6 months prior to each unit entering the PEO or no later than the last refueling outage prior to the PEO.

The inspectors determined that the applicant included six components (three for each unit) that related to the containment particulate, gaseous, and iodine radiation monitors. The inspectors determined that the applicant had not decided whether they would use the testing method or the evaluation of test results method to assess whether cable degradation had occurred.

The inspectors questioned why the applicant had not identified the nuclear instrumentation cables as in scope. Since the applicant had included these cables and the main steam line instrument cables in their environmental qualification program, the inspectors confirmed that the applicants environmental qualification reports for the components and had established a qualified life for each of the instruments not included in this program.

The inspectors concluded that the Insulation Material for Electrical Cables and Connections Not Subject to 10CFR5049 EQ Requirements Used in Instrumentation Circuits AMP as proposed provides reasonable assurances that the effects of aging will be managed, consistent with the license basis in the PEO.

B.2.3.39 Inaccessible Power Cables Not Subject to 10 CFR50.49 EQ Requirements and Commitment 41 This program manages the effects of reduced insulation resistance on inaccessible underground (e.g., in conduit, duct bank, or direct buried) power cables (greater than or equal to 400V) not subject to environmental qualification requirements. The program manages the cables exposed to significant moisture. Significant moisture is any periodic exposures to moisture that last more than a few days (e.g., cable wetting or submergence in water). The cables included in this program provide power to the 6.9 kV standby service water pumps for each unit. Further, the applicant will include the cables to their fire water pumps in the scope of this program.

The inspection will include direct observation or indication that cables are not wetted or submerged, that cables/splices and cable support structures are intact, and, if installed, that dewatering/drainage systems (i.e., sump pumps) and associated alarms operate properly. The program includes testing prior to the PEO to confirm no insulation deterioration had occurred with subsequent tests performed at least every 6 years. The specific type of test performed will be determined prior to the initial test and is to be a proven test for detecting deterioration of the insulation system due to wetting or submergence,

Commitment 41 specified the implementation of the new inaccessible power cables not subject to 10 CFR 50.49 EQ requirements aging management program no later than 6 months prior to each unit entering the PEO or no later than the last refueling outage prior to the PEO.

The inspectors determined that the applicant had not established a formal program or procedure to manage the effects of aging for their standby service water pump cables. The applicant conducts quarterly inspections in accordance with preventive maintenance activities, and after rain events, of the cable vaults containing the in-scope cables. The inspectors determined that the applicant had been conducting these activities since 2010 in response to Generic Letter 2007-01, Inaccessible or Underground Power Cable Failures That Disable Accident Mitigation Systems or Cause Plant Transients. The inspectors determined that Condition Report 2012-006260 evaluated actions to address industry information, which documented reactor scrams because of cables in cable vaults becoming wetted.

The applicant described that their current practices to monitor for the presence of water involve significant time and labor because it requires lifting each of the eight 2400-lb cable vault covers to visually inspect for the presence of water.

Consequently, the applicant initiated a preliminary design study to evaluate establishing a level monitoring system in the cable vaults that alarms and a method to remove any water without lifting the manhole covers.

Procedure EPG-9.05 provided guidance for inspecting and testing the cables routed in cable vaults to ensure that the cable insulation had not deteriorated. The guidance had not been upgraded to include the aging effects being evaluated by license renewal. The applicant had completed one tan-delta diagnostic test for each of the cables and were performing a second set of tan-delta tests. The applicant scheduled the testing every 10 years and used procedure MSE-G0-1217, Tan Delta Insulation Resistance Testing, to perform the testing. The completed tan-delta tests confirmed that no cable insulation degradation had occurred. The inspectors identified no concerns with these initiatives.

The inspectors concluded that the inaccessible power cables not subject to 10 CFR50.49 EQ requirements AMP as proposed provides reasonable assurances that the effects of aging will be managed, consistent with the license basis in the PEO.

B.2.3.40 Metal Enclosed Bus and Commitment 42 This program manages the effects on the internal components of metal enclosed buses related to reduced insulation resistance as evidenced by cracking, corrosion, excessive dust buildup or embrittlement or ohmic heating as evidenced by cracking, chipping, melting, discoloration, or swelling, respectively. The program samples 20 percent up to a maximum of 25 accessible bolted bus connections to confirm they are not experiencing increased resistance. Further, this program inspects external accessible gaskets, boots, sealants for hardening or loss of strength. The visual inspections will be completed prior to the PEO and every 5 years thereafter.

Commitment 42 specified implement the new metal enclosed bus AMP no later than 6 months prior to each unit entering the PEO or no later than the last refueling outage prior to the PEO.

The inspectors determined that the applicant had installed spare transformers for each unit to ensure offsite power sources remain available without causing forced shutdown upon failure of one of the existing offsite power transformers. The applicant installed non-segregated metal enclosed buses to transfer power from transformer XST2 to transformer XST2A and from the XST2A transformer to the safety related buses. The applicant had not inspected the buses at the time of this inspection. The inspections will need to be completed by August 31, 2026, which includes the grace period without being delinquent. The applicant described that they would inspect the non-segregated buses using the same procedures that they used to inspect their isophase buses because they had similar components and configurations. The inspectors reviewed the isophase bus inspection activities and identified no issues.

The inspectors concluded that the metal enclosed bus AMP as proposed provides reasonable assurances that the effects of aging will be managed, consistent with the license basis in the PEO.

INSPECTION RESULTS

Observation: Structures Monitoring Program B.2.3.34

The applicant provided a review of industry and plant-specific operating experience related to aging effects for the structures monitoring AMP. The inspectors reviewed the basis document, implementing procedures, operating experience, drawings, and the license renewal application. In addition, the inspectors interviewed the program manager and performed walkdowns on a sample of accessible portions of the structures and components to observe aging effects, which included the material condition of the structures and components.

The inspectors identified that sampled component supports are inspected on the interval of 10 years, which is not consistent with GALL-LR Report recommendations. The applicant proposed to change the inspection frequency of component supports to a 5-year interval and plans to provide an enhancement to the Structures Monitoring AMP for ensuring the consistency with GALL-LR Report recommendations.

The inspectors identified calcium leaching on the HVAC intake on the west wall of the Auxiliary Building, which was not identified by the applicant. The applicant created Action No.

IR-2023-006455, dated September 14, 2023, and proposed including this operating experience in the application.

During plant walkdowns of the spent fuel pool liner leak collection system, the inspectors observed no flow of borated water or boric acid deposits in the collection tray from the tell-tale tubing for the spent fuel pool but did review pictures showing boric acid deposits on the bottom of the spent fuel pool concrete slab. The boric acid deposit may have resulted from the leakage of spent fuel pool borated water through the thickness of the spent fuel pool concrete slab. This is a new aging effect that is not described by the GALL-LR Report. The LRA did address how this aging effect will be adequately managed during the PEO.

Following the IP71002 inspection, the NRC staff held multiple follow-up discussions with the applicant regarding the operating experience and its impacts to the Structures Monitoring AMP. The applicant submitted LRA Annual Update 1 (ML23290A273) on October 17, 2023, and LRA Supplement 3 (ML2334A0A191) on December 6, 2023, to add 11 more enhancements to the structures monitoring AMP to address the operating experience. The NRC staff conducted a public meeting (ML24019A034) on January 4, 2024, with the applicant to discuss comments and questions the staff had related to the added enhancements described in LRA Supplement 3.

The inspectors concluded that continued implementation of the structures monitoring AMP, as described in the LRA with the proposed enhancements, provide reasonable assurance the aging effects will be managed, consistent with the license basis, for the PEO.

EXIT MEETINGS AND DEBRIEFS

The inspectors verified no proprietary information was retained or documented in this report.

• On December 19, 2023, the inspectors presented the license renewal inspection results to Todd Evans and other members of the licensee staff.

DOCUMENTS REVIEWED

Inspection Type Designation Description or Title Revision or

Procedure Date

71002 Calculations CS-CA-0000-5157 ESF Thermal Insulation Requirements For CT, SI, CS, RHR 2

and CCW Systems

Corrective Action CR-2002-001473, 2007-002677, 2010-003195, 2012-000529,

Documents 2012-004563, 2012-006075, 2012-006603, 2012-010503,

2013-000912, 2013-002005, 2013-003039, 2014-003630,

2014-009603, 2014-013753, 2015-002780, 2015-002781,

2016-006634, 2017-005198, 2017-007536, 2018-008747,

20-003291, 2021-007061, 2022-004262

TR-2016-006155, 2017-003596, 2018-004483, 2018-008037,

2019-001452, 2019-005992, 2020-001247, 2020-002735,

20-002889, 2020-003153, 2020-003443, 2020-006263.

20-006878, 2021-005441, 2022-000897

Drawings 2323-E1-0002 Transformers XST1, XST1A, XST2 and XST2A Cable Block 0

Diagram

23-E1-1009 Yard Electrical Ductbank, Manhole & Handhole Sections & 17

Details, Sheet 2

23-E1-1020 Yard Main Grounding Plan 11

23-MI-0512-01 Containment Liner Leak Chase Piping 4

23-MI-0512-02 Containment Liner Leak Chase Piping 4

23-MI-0512-02 Containment Liner Leak Chase Piping 4

23-MI-0512-03 Containment Liner Leak Chase Piping 4

23-S-0108 Site Preparation Plan Sheet 1 4

23-S-0114 Site Preparation Sections & Details Sheet 1 3

23-S-1107 Service Water Intake Structure Plans & Details 9

23-S-1117 Service Water Discharge - Stilling Basin Structure 2

23-S-1118 Service Water Discharge Spillway Structure 4

23-S1-0315 Refueling Water Storage Tank 4

23-S1-0316 Condensate Storage Tank 3

23-S1-0317 Reactor Make Up Water Storage Tank 3

23-S2-0315 Refueling Water Storage Tank 3

23-S2-0317 Reactor Make Up Water Storage Tank 3

6469E23 Comanche Peak Unit 2 Ex-Vessel Neutron Dosimetry 0

Inspection Type Designation Description or Title Revision or

Procedure Date

Installation

6469E24 Comanche Peak Unit 2 Ex-Vessel Neutron Dosimetry 1

Installation

6469E25 Comanche Peak Unit 1 and 2 Neutron Dosimetry Chain 2

Assembly

DDVEN 10773-Upper Vessel Machining 3

21-005

DDVEN 11773-Stud, Nut, and Washer 0

179-001

E1-1705, sheet 6 Startup Transformers XST2 and XST2A 15kV Power Cable 3

Tray - Cable Tray Support Location Plan Turbine BLDG Unit

and X-Yard

Figure 2.5.4 - 28A Service Water Intake Channel Cut & Fill 3/31/1980

Final Safety Comanche Peak NPP Final Safety Analysis Report Units 1 7/13/2020

Analysis Report and 2 - Plot Plan

Units 1 and 2

Figure 1.2-1

Final Safety Start-UP/Station Service/Unit Aux Transformer Cable Bus

Analysis Report Connection to 6.9 kV Switchgear

Units 1 and 2

Figure 8.2-11

ID1-0232 ESF Piping Thermal Insulation Containment Spray System CP-1

ID1-0255 ESF Piping Thermal Insulation CVCS Charging and Positive CP-1

Displacement Pump Trains

ID1-0263 ESF Piping Thermal Insulation Safety Injection System CP-1

ID2-0232 ESF Piping Thermal Insulation Containment Spray System CP-1

LR-STRUCT-01 Comanche Peak NPP Final Safe Analysis Report, Units 1 3

and 2, Plot Plan

M1-0212-B-LR Flow Diagram Turbine Plant Cooling Water System 0

M1-0234-LR Flow Diagram Station Service Water System 1

M1-0261-LR Flow Diagram Safety Injection System Sheet 0

Sheet 1 of 5

M1-0262-LR Flow Diagram Safety Injection System Sheet 0

Sheet 2 of 5

Inspection Type Designation Description or Title Revision or

Procedure Date

M1-0263-A-LR Flow Diagram Safety Injection System Sheet 0

Sheet 4 of 5

M1-0263-B-LR Flow Diagram Safety Injection System Sheet 0

Sheet 5 of 5

M1-0263-LR Flow Diagram Safety Injection System Sheet 0

Sheet 3 of 5

M2-0212-B-LR Flow Diagram Turbine Plant Cooling Water System 0

M2-0215-B-LR Flow Diagram Lube Oil Piping and Instrument Diagram 0

M2-0215-C-LR Flow Diagram Lube Oil Piping and Instrument Diagram 0

SK-0024-12-General Layout for New Cathodic Protection System 3

000027-01-03

Engineering DMA-2007-Install hydraulically actuated self tensioning nuts (Hydranuts) 6/17/2009

Changes 002677-02 as an alternate to the conventional stud nuts used at CPNPP

Unit 2 for reactor closure head stud tensioning.

FDA-2004-Installation of Transformer XST2A 1

003620-01-06

FDA-2005-Unit 1 Steam Generators and Reactor Vessel Head 2

000658-01-02 Replacement Project Containment Alternate Access

FDA-2007-Prepare design documents to support the use of the Nova 9/10/2009

2677-01-00 HydraNut system as an alternative means of tensioning the

Unit-1 reactor head studs.

FDA-2007-Prepare design documents to support the use of the Nova 5/13/2009

2677-02-00 HydraNut system as an alternative means of tensioning the

Unit-2 reactor head closure nuts.

FDA-2012-Install Cathodic Protection System 0

000027-01-05

Engineering PQE 611-1 Four-Section Power Range Neutron Detector Assembly 5/4/2023

Evaluations

Miscellaneous CPNPP XI.E3 Aging Management Program Manhole White 2/8/2022

Paper

FAC Manager - Web Edition, Software Quality Assurance 5/21/2019

Plan

RCS Materials Management, ISI and Reactor Internals 10

Strategic Plan

Inspection Type Designation Description or Title Revision or

Procedure Date

EDG 1-01 Slow Start Log 9/18/2023

Unit 1 TPCW chemistry logs 2005-2023 9/27/2023

Unit 2 TPCW chemistry logs 2005-2023 9/27/2023

FAC Strategic Plan 0

TPCW Weld Status 0

11-2235-TR-001 Flow Accelerated Corrosion Program System Susceptibility 0

Evaluation and Susceptible Not Modeled Line Review

1400419.401.R0 2017 APEC Re-Survey - Comanche Peak Nuclear Power 0

Plant

20-0113-TR-001 Flow Accelerated Corrosion Program - System Susceptibility 1

Evaluation (SSE) Comanche Peak Nuclear Power Plant, Unit

20-0113-TR-002 Flow Accelerated Corrosion Program - Susceptible Non-1

Modeled (SNM) Comanche Peak Nuclear Power Plant, Unit

20-0113-TR-003 Flow Accelerated Corrosion Program - Color Coded Flow 1

Diagrams Comanche Peak Nuclear Power Plant Unit 1

20-0113-TR-004 Flow Accelerated Corrosion Program - System Susceptibility 0

Evaluation (SSE) Comanche Peak Nuclear Power Plant, Unit

20-0113-TR-005 Flow Accelerated Corrosion Program - Susceptible Non- 0

Modeled (SNM) Comanche Peak Nuclear Power Plant, Unit

20-0113-TR-006 Flow Accelerated Corrosion Program - Color Coded Flow 0

Diagrams Comanche Peak Nuclear Power Plant Unit 2

23-SS-16B CPNPP Units 1 and 2, Specification of Structural 14

Steel/Miscellaneous Steel

59SC-2007-Activity Tracker: FDA-2007-002677-01-00 will allow the use 8/13/2009

2677-02 of HydraNuts as an option to standard existing nuts for the

reactor head

closure bolting hardware.

CP-201000067 Soil Analysis for Comanche Peak Nuclear Power Plant 1

(CPNPP)

CPES-S-1062G CPNPP Units 1 and 2, Specification of Fastener Substitution 5

Inspection Type Designation Description or Title Revision or

Procedure Date

and Heli-Coil Specification

CPNPP-SSD Nalco Water Report 9/1/2022

22 September 1

DBD-CS-068 CPNPP Units 1 and 2 Design Basis Document, Non-ASME 6

Pipe Stress Analysis and Support Design

DBD-CS-085 CPNPP Units 1 and 2, Seismic Category I and II Structural 10

Steel

DBD-CS-088 CPNPP Units 1 and 2 Design Basis Document, Pipe Whip 7

Gap Restraints and Analysis

DBD-CS-096 CPNPP Units 1 and 2 Design Basis Document, Safe 14

Shutdown Impoundment/Dam

DBD-ME-028 CPNPP Units 1 and 2 Design Basis Document, Classification 27

of Structures, Systems and Components

DBD-ME-250 CPNPP Units 1 and 2 Reactor Coolant System 66

DCN 003510, 003517, 005188, 007239, 010551

DCVDI MED-Evaluation of Stuck Reactor Vessel Closure Stud Comanche 2/11/1992

PCE-11320 Peak Unit 1

Design Change Insulation of fire bricks to protect the built-up roof on the Unit 0

Notice (DCN): 1 site, near the DG Exhaust Silencers.

13341

FIR-P2-3120 Containment Building Hose Stations Air Flow and Deluge 6

Valve 2-HV-4075D Test

HI-2002436 Criticality Safety Analysis of Holtec Spent Fuel Racks for 9

Comanche Peak

HI-2135720 Comanche Peak Boral Surveillance Coupon Report 1

HI-2156882 Comanche Peak Boral Surveillance Coupon Report 1

HI-2188305 Comanche Peak Boral Surveillance Coupon Report 0

HPP-2303-1 Test Procedure for Comanche Peak Spent Fuel Pool 0

Neutron Absorbing Materials Surveillance Program

LTR-REA-20-115-Plant-Specific Assessment of the MRP-227, Revision 1-A 0

NP Fuel Design and Fuel Management Limitations for

Comanche Peak Unit 1 and Unit 2

LTR-SDA-20-069 Update of the Comanche Peak Units 1 and 2 Pressure and 0

Temperature Limit Report Based

Inspection Type Designation Description or Title Revision or

Procedure Date

on the Most Recent Reactor Vessel Surveillance Capsule

Test Reports

LTR-SDA-21-084 Comanche Peak Unit 2 Reactor Vessel Hot Leg and Cold 1

Leg Dissimilar Metal Welds PWSCC Operability Based on

MSIP Application and Inspections per Code Case N-770-5

LTR-SDA-21-084 Comanche Peak Unit 2 Reactor Vessel Hot Leg and Cold 1

Leg Dissimilar Metal Welds PWSCC Operability Based on

MSIP Application and Inspections per Code Case N-770-5

LUM00020-REPT-Comanche Peak Nuclear Power Plant Units 1 and 2 License 1

001 Renewal System and Structure Scoping Results

LUM00020-REPT-General Aging Considerations 0

2

LUM00020-REPT-Non-Nuclear Safety Related Systems Affecting Nuclear 1

030 Safety Related Systems

LUM00020-REPT-Comanche Peak Nuclear Power Plant Units 1 And 2 License 1

2 Renewal Screening and Aging Management Review Report

for the Concrete Containment Building

LUM00020-REPT-Screening and Aging Management Review Report for the 0

033 Structural Bulk Commodities

LUM00020-REPT-CPNPP Units 1 and 2 License Renewal Screening and 0

033 Aging Management Review Report for the Structural Bulk

Commodities

LUM00020-REPT-Comanche Peak Units 1 And 2 License Renewal Aging 1

035 Management Review - Electrical and I&C Commodities,

- Scoping of Impedance Sensitive Circuits

LUM00020-REPT-Water Chemistry AMP Basis Document 1

040

LUM00020-REPT-Reactor Head Closure Stud Bolting AMP Basis Document 1

041

LUM00020-REPT-Nickel Alloy AMP Basis Document 2

043

LUM00020-REPT-PWR Vessel Internals AMP Basis Document 1

044

LUM00020-REPT-Flow Accelerated Corrosion AMP Basis Document 1

Inspection Type Designation Description or Title Revision or

Procedure Date

045

LUM00020-REPT-Open Cycle Cooling Water Systems AMP Basis Document 1

048

LUM00020-REPT-Closed Treated Water System AMP Basis Document 0

049

LUM00020-REPT-Comanche Peak Nuclear Power Plant Units 1 And 2 License 1

050 Renewal Inspection Of Overhead Heavy Load And Light

Load (Related To Refueling) Handling Systems AMP Basis

Document

LUM00020-REPT-Compressed Air Monitoring AMP 1

051

LUM00020-REPT-Fire Water System Aging Management Program Basis 1

050 Document

LUM00020-REPT-Fuel Oil Chemistry AMP Basis Document 1

055

LUM00020-REPT-External Surfaces Monitoring of Mechanical Components 1

059 AMP Basis Document

LUM00020-REPT-Flux Thimble Tube AMP Basis Document 1

060

LUM00020-REPT-Monitoring of Neutron-Absorbing Materials Other Than 0

063 Boraflex AMP Basis Document

LUM00020-REPT-Internal Coatings-Linings for In Scope Piping, Piping 0

065 Components, Heat Exchangers, and Tanks

LUM00020-REPT-Comanche Peak Nuclear Power Plant Units 1 And 2 License 1

069 Renewal 10 Cfr Part 50, Appendix J AMP Basis Document

LUM00020-REPT-Comanche Peak Nuclear Power Plant Units 1 And 2 License 1

070 Renewal Masonry Walls AMP Basis Document

LUM00020-REPT-Comanche Peak Nuclear Power Plant Units 1 And 2 License 1

071 Renewal Structures Monitoring AMP Basis Document

LUM00020-REPT-Comanche Peak Nuclear Power Plant Units 1 And 2 License 0

2 Renewal Regulatory Guide (Rg) 1.127, Inspection Of Water-

Control Structures Associated With Nuclear Power Plants

AMP Basis Document

LUM00020-REPT-Insulation Material for Electrical Cables and Connections Not 1

Inspection Type Designation Description or Title Revision or

Procedure Date

074 Subject To 10 CFR 50.49 Environmental Qualification

Requirements AMP Basis Document

LUM00020-REPT-Insulation Material for Electrical Cables and Connections Not 0

075 Subject To 10 CFR 50.49 Environmental Qualification

Requirements Used in Instrumentation Circuits AMP Basis

Document

LUM00020-REPT-Metal Enclosed Bus AMP Basis Document 0

077

MDA-402-1 Documented Prior-To-Use Inspection of Cranes and Hoists 11

(excluding mobiles)

NUC-211-1 BORAL Coupon Documentation Form 1

NUC-211-1-Comanche Peak Boral Surveillance Coupon Report 10/16/2018

101618

NUC-211-2 BORAL Coupon Visible Degradation Trending 0

OER-2017-BWR Reactor Water Cleanup System Pipe Wall Thinning 9/21/2017

000119

OWI-104-27 Nuclear Equipment Operator Diesel Generator 1-01 20

Operating Log

PA-SEE-1685 Comanche Peak Thimble Tube History

PM 326652 WEC Seal Table Activities: Unit 1

PM 329397 WEC Seal Table Activities: Unit 2

PM 339606 Instrument Air Sampling Analysis 7/1/2021

PM 339607 Instrument Air Sampling Analysis 7/1/2021

PM 349506 Perform Seal Table Eddy Current Test: Unit 1

PM 349507 Perform Seal Table Eddy Current Test: Unit 2

PM 351416 Perform volumetric (UT)

PM 351417 Perform volumetric (UT)

PM 351418 Measure for thermal sleeve flange wear

PM 351419 Measure for thermal sleeve flange wear

PM 351420 Perform inspections for control rod guide tube assembly

guide card

PM 351421 Perform inspections for control rod guide tube assembly

guide card

PWROG-15105-PA-MSC-1288 PWR RV Internals Cold-Work Assessment 0

Inspection Type Designation Description or Title Revision or

Procedure Date

NP

Section 5.5.16 Technical Specification for Comanche Peak NPP, Units 1

"Containment and 2.

Leakage Rate

Test Program," of

Technical

Specification for

Comanche Peak

NPP, Units 1 and

2.

SIR-02-144 Comanche Peak Steam Electric Station Life Cycle 0

Management of Buried Piping

STI-422.03 Att. Performance Gap Analysis that identified insufficient detail 6/28/2021

8.D being provided in comments of primary chemistry trends.

TB-16-4 Fuel Alignment Pin Malcomized Surface Degradation 0

TCX-PP000-CN-Comanche Peak Unit 2 Operability Assessment of the 0

PX-000002 Reactor Coolant Piping and Support System due to the

MSIP Tool Failures

TCX-PP000-TR-Reactor Coolant Loop (RCL) Piping and Support System 0

PX-000001 Operability Assessment due to impact of the MSIP Tool

Failure at Comanche Peak Unit 2 by Westinghouse

TER-09-0210-85 NFPA Code Verification NFPA 13-1978 and 1985 Sprinkler 0

Systems in Unit 1 and Common Safety-Related Areas

TPSTA_STA - Fire Protection Systems/Equipment Requirements 5

23_5_PCN_0006

TPFIR_FIR-307 Inspection of Sprinkler Systems 4

TPFIR_FIR-PX-Electric Driven Fire Protection Pump CPX-FPAPFP-04 5

3801_5 Operability Test

TPFIR_FIR-PX-Diesel Driven Fire Protection Pump CPX-FPAPFP-06 5

3803_5 Operability Test

TS Technical Specifications for Comanche Peak Nuclear Power 157

Plants Units 1 and 2, Section 5.5.16, "Containment Leak

Test Program"

TX04912 Safe Shutdown Impoundment (SSI) Dam 2022 Inspection August 2022

Inspection Type Designation Description or Title Revision or

Procedure Date

Report

TXX-15001 LAR 14-002, Extension of Containment Leakage Test 1/28/2015

Frequency."

TXX-15001 LAR 14-002 Extension of Containment Leakage Test 1/28/2015

Frequency

U2 ISI Program Unit 2 - Third Interval ASME Section XI Inservice Inspection 2

Plan Program Plan

VDRT-5953371 2020 SSI Dam Inspection Report 9/30/2020

VDRT-6034538 NRC Dam Safety Inspection Report 2021 3/17/2022

VDRT-6034728 2022 SSI Dam Inspection Report 6/29/2022

WCAP-10527-P Technical Justification for Eliminating Large Primary Loop 3

Pipe Rupture as the Structural Design Basis for the

Comanche Peak Units 1 and 2 for the License Renewal

Program (60 Years)

WCAP-16346-NP Comanche Peak Units 1 and 2 Heatup and Cooldown Limit 0

Curves for Normal Operation

WCAP-16610-NP Analysis of Capsule X from the TXU Energy Company 0

Comanche Peak Unit 1 Reactor Vessel Radiation

Surveillance Program

WCAP-17629-NP Analysis of Capsule W from the Comanche Peak Unit No. 2 0

Reactor Vessel Radiation Surveillance Program

WCAP-18630-NP Comanche Peak Units 1 and 2 Time-Limited Aging Analysis 0

on Reactor Vessel Integrity

WCAP-9475 Texas Utilities Comanche Peak Unit No. 1 Reactor Vessel 0

Radiation Surveillance Program

NDE Reports 1RF20 Inservice Inspection Report at the Comanche Peak Nuclear 5/13/2019

Power Plant Unit 1

2RF17 Inservice Inspection Report at the Comanche Peak Nuclear 12/29/2018

Power Plant Unit 2

Procedures CPNPP DM Weld Visual Examination 6

Open Cooling Water Plant Specific Guidelines 4

Closed Cooling Water Plant Specific Guidelines 7

Cable Reliability Program Strategic Plan 2

170.01 Instructions for Implementing the Software Quality 1

Inspection Type Designation Description or Title Revision or

Procedure Date

Assurance Program

3002000590 EPRI Closed Cooling Water Chemistry Guideline 2

CDF #18424 Corrosion Monitoring Program Commitment for SSWS 3/25/2020

Piping (GL 89-13)

CHM-100 Chemistry Specifications 4

CHM-101 Chemistry Administrative Control 29

CHM-140 Water Treatment 3

CHM-150 Closed Cooling Water Systems 4

COP-313A Chemistry Operating Procedures Manual - Turbine Plant 5

Cooling Water

COP-501 Station Service Water 12

COP-502B Chemistry Operating Procedures Manual - Component 7

Cooling Water

COP-520 Instrument Air Sampling 0

DBD-CS-081 General Structural Design Criteria 13

DBD-ME-218 Design Basis Document Instrument Air System 24

DBD-SC-073 Concrete Containment Structure 7

EPG-703 Inservice Inspection Program 4

EPG-710 Reactor Vessel Internals Aging Management Program 0

EPG-731 ASME Section XI Repair/Replacement Activities 6

EPG-731 ASME Sec XI Repair/Replacement Activities 6

EPG-756 Nondestructive Examination Program 6

EPG-9.02 CPNPP Alloy 600 Management Program 3

EPG-9.03 Underground Pipe and Tank Program 5

EPG-9.04 Flow Accelerated Corrosion Program 3

EPG-9.05 Cable Reliability Program 5

EPG-9.08 Reactor Vessel Closure Head Visual Examination 3

INC-7096 COT & CCAL - CON

T. PIG CHS 1-RE-5502/5503/5566, 2-5

RE-5502/5503/5566

MDA-308 CPNPP Maintenance Department Administration Manual, 10

Requirements for Load Handling Personnel

MDA-308 REQUIREMENTS FOR LOAD HANDLING PERSONNE 10

MDA-402 CPNPP Maintenance Department Administrative Manual, 13

Inspection Type Designation Description or Title Revision or

Procedure Date

Control of Load Handling Equipment

MDA-402-1 Documented Prior-To-Use Inspection of Cranes and Hoists 11

(excluding mobiles)

MDA-404 Materials Control 10

MRS-GEN-1180 Generic Flux Thimble Tube Eddy Current Inspection Field 3

Service Procedure (FTEC)

MRS-GEN-1304 Generic Flux Thimble Eddy Current (FTEC) Field Procedure 7

Using the Corestar System 8.1

MRS-SSP-1151-Flux Thimble Tube Replacement for Comanche Peak Unit 1 4

TBX/TCX & 2

MRS-SSP-2077-BMI Flux Thimble Tube Repositioning, Capping, and High 3

TBX/TCX Pressure Seal Inspection at Comanche Peak Units 1 and 2

MSE-G0-1217 Tan Delta Cable Insulation Resistance Testing 2

MSE-G0-4201 Megger Testing of Power Cables, Motors, and Generators 9

MSE-P0-1327 Bi-Monthly Cathodic Protection Inspection 7

MSE-P0-1328 Cathodic Protection Annual Survey 4

MSE-P0-6004 Isophase Bus Cleaning and Inspection 4

MSG-0103 Installation, Modification and Removal of Sway Struts and 0

Snubbers

MSG-1006 Fabrication of Structural & Embedded Steel and Erection of 0

Structural Steel

MSG-1006 Fabrication of Structural & Embedded Steel and Erection of 0

Structural Steel

MSG-1008 Pipe Supports Adjustments and Verifications 0

MSM-C1-9901 Reactor Vessel Head Removal and Installation (Unit 1) 7

MSM-C1-9901 Reactor Vessel Head Removal and Installation (Unit 1) 8

MSM-C2-9901 Reactor Vessel Head Removal and Installation (Unit 2) 10

MSM-G0-0210 Constant and Variable Spring Pipe Support Maintenance

MSM-P0-3713 Diesel Generator Fuel Oil Storage Tank Cleaning 0

MSM-P0-7336 Instrument Air Dryer Maintenance 2

MSM-P0-9714 Reactor Vessel Test Capsule Removal 2

NUC-211 SFP Storage Limitations for Reactivity Control 7

PPT-SX-7517 Safe Shutdown Impoundment Inspection 2

Inspection Type Designation Description or Title Revision or

Procedure Date

RFO-210 Reactor Vessel and Upper Internals FOSAR (Foreign Object 6

Search and Retrieval) Activities

SOP-501A Station Service Water System 21

SOP-501B Station Service Water System 12

SOP-509B Instrument Air Systems 15

STA*421 Control of Issue Reports 21

STA-170 Nuclear Software Quality Assurance Program 7

STA-422 Corrective Action Program 34

STA-502 Routine Reporting 16

STA-677 Preventive Maintenance Program 0

STA-722 Fire Protection Program 8

STA-730 Corrosion Monitoring Program 5

STA-730 Corrosion Monitoring Program 5

STA-730 Corrosion Monitoring Program 5

STA-733 Steam Generator Reliability Program 14

STA-734 Service Water System Fouling Monitoring Program 5

STA-734 Service Water System Fouling Monitoring Program 5

STA-737 Boric Acid Corrosion Detection and Evaluation 8

STA-743 10CFR50 Appendix J Containment Leakage Rate Testing 2

Program

STA-753 Control of Site Excavation 6

STI-677.01 Database Change Processing 0

STI-744.09 Structural Monitoring Inspection Guide 0

TSP-743 10CFR50 Appendix J Option B Test Intervals and 0

Administrative Limits

Work Orders 5098314 Perform cross functional walkdown Safeguard Building, Unit 1/18/2017

1, TRN A

292289 U2 TB 803 Mezzanine Floor - CR-2015-000452: rework 5/23/2017

loose grout and patch

5992133 Penetration/Adapter Mod# Type MIII Ser# NA, Unit 2 11/9/2021

WO-210909861, 4153009, 4270009, 4683892, 4683895,

25008, 5172648, 5258047, 5668060, 5669174, 5692640,

5713401, 5743564, 5863837. 5935024, 5954250, 5979742,

Inspection Type Designation Description or Title Revision or

Procedure Date

5998393, 6008163, 6008209, 6014217, 6038611

51