IR 05000416/2024012

License Renewal Post Approval Phase 2 Inspection Report 05000416/2024012

ML24260A137
Person / Time
Site:	Grand Gulf
Issue date:	09/17/2024
From:	Nick Taylor NRC/RGN-IV/DORS/EB2
To:	Kapellas B Entergy Operations
References
IR 2024012
Download: ML24260A137 (77)

Text

September 17, 2024

SUBJECT:

GRAND GULF - LICENSE RENEWAL POST-APPROVAL PHASE 2 INSPECTION REPORT 05000416/2024012

Dear Brad Kapellas:

On August 15, 2024, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at Grand Gulf and discussed the results of this inspection with Mr. Grant Flynn, General Manager of Plant Operations, and other members of your staff. The results of this inspection are documented in the enclosed report.

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 No. 05000416 License No. NPF-29

Enclosure:

As stated

Inspection Report

Docket Number:

05000416 License Number:

NPF-29 Report Number:

05000416/2024012 Enterprise Identifier:

I-2024-012-0003 Licensee:

Entergy Operations, Inc Facility:

Grand Gulf Location:

Port Gibson, MS Inspection Dates:

July 15 to August 15, 2024 Inspectors:

S. Campbell, Senior Reactor Systems Engineer S. Graves, Senior Reactor Inspector N. Okonkwo, Reactor Inspector G. Pick, Senior Reactor Inspector C. Smith, Senior Reactor Inspector Approved By:

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

SUMMARY

The U.S. Nuclear Regulatory Commission (NRC) continued monitoring the licensees performance by conducting a License Renewal Phase 2 Inspection at Grand Gulf, 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.

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) 2515, Light-Water Reactor Inspection Program - Operations Phase. 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

===71003 - Post-Approval Site Inspection for License Renewal Inspection Procedure 71003, Post-Approval Site Inspection for License Renewal, recommended that the inspection be conducted shortly before the period of extended operation.

The period of extended operation is the additional 20 years beyond the original 40-year licensed term. The period of extended operation for Grand Gulf Nuclear Station will begin after midnight on November 1, 2024.

The inspectors evaluated whether the licensee:

(1) completed actions required to comply with the license renewal license condition and commitments;

(2) implemented the aging management programs that agreed with those approved in the safety evaluation report and described in the safety analysis report;

(3) followed the guidance in Nuclear Energy Institute (NEI) 99-04, Guidelines for Managing NRC Commitment Changes, for changing license renewal commitments and followed the guidance in 10 CFR 50.59 when making changes to the license renewal supplement;

(4) identified, evaluated, and incorporated newly identified structures, systems, and components into their aging management programs; and (5)implemented operating experience review and corrective action programs that account for aging effects.

NUREG-2211, Related to the License Renewal of Grand Gulf Nuclear Station, Unit 1, appendix A, Grand Gulf Nuclear Station, Unit 1 License Renewal Commitments, listed 36 commitments. The inspectors reviewed 35 of the commitments and reviewed the aging management programs. The inspectors closed 34 commitments. The NRC previously closed one commitment in Inspection Report 05000416/2022012 [ML22109A230]. The inspectors reviewed 44 aging management programs.

For each aging management program reviewed, the inspectors reviewed program documents, license renewal documents, the safety analysis report, and the safety evaluation report.

Supporting documents reviewed included implementing procedures, work orders, inspection reports, engineering evaluations, calculations, database entries, and condition reports. The inspectors interviewed program owners and license renewal program personnel.

The inspectors walked down the following areas of the plant to inspect for signs of aging:

• division I, II, and III emergency diesel generators

• fuel oil storage tanks

• fire water storage tanks

• fire water pump house and fire diesel generators

• warehouse and oil storage locations

• condensate storage tank

• various outdoor electrical cable vault manholes

• outdoor fire protection CO2 tank

• refuel floor

• standby gas treatment room

• division I/II HVAC equipment rooms The inspectors determined that the licensee described their aging management programs and commitments in appendix A of their updated final safety analysis report (UFSAR).

The inspectors paraphrased most of the commitments listed in the aging management program reviews. For the actual wording refer to the safety evaluation report and any license basis changes. The inspectors listed specific documents reviewed in the attachment.

Post-Approval Site Inspection for License Renewal===

(1) A.1.1 115 kV Inaccessible Transmission Cable Program and Commitment 1 This new program manages the effects of aging on the 115 kilovolt (kV) inaccessible transmission cable insulation systems This preventive maintenance and testing program monitors inaccessible transmission cables from being exposed to significant moisture. The program performs annual inspections for water accumulation in manholes and inspects manholes for water accumulation after a water event such as flooding and hurricanes. The cables will also be tested every six years to provide an indication of the condition of the cable insulation properties.

Commitment 1 specified:

• Implement the 115 kV Inaccessible Transmission Cable program as described in license renewal application (LRA) section B.1.1 The inspectors reviewed drawings, program documents, license renewal documents, the safety analysis report, and the safety evaluation report. The inspectors walked down the associated manholes and the cable dewatering systems, reviewed the implementing procedures, work orders, inspection reports, engineering evaluations, calculations, and condition reports. The inspectors interviewed program owners and license renewal program personnel.

The inspectors confirmed the licensee completed the required commitments and implemented the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program.

(2) A.1.2 Aboveground Metallic Tanks Program and Commitment 2 This new program manages the effects of aging for loss of material and cracking (both the inside and outside surfaces) of outdoor tanks situated on soil or concrete.

The only component in the scope of this program is the condensate storage tank, 1P11A002.

The program includes preventive measures to mitigate corrosion by protecting the external surfaces of steel components in accordance with standard industry practice including the use of sealant or caulking at the concrete to tank interface of outdoor tanks. The licensee performs external visual surface examinations of uncoated surfaces and of protective paint, coatings, and caulking or sealant, supplemented with physical manipulation of caulking or sealant to monitor degradation. The licensee conducts internal visual and surface examinations (when necessary to detect cracking) as well as measuring the thickness of the tank bottoms to ensure that significant degradation is not occurring and that the component intended function is maintained during the period of extended operation.

Commitment 2 specified:

• Implement the Aboveground Metallic Tanks program as described in LRA section B.1.2.

The inspectors reviewed implementing procedures, work orders, inspection reports, engineering evaluations, calculations, drawings, the license renewal aging management program documents, the safety analysis report, and the safety evaluation report. The inspectors interviewed program owners and license renewal program personnel. The inspectors walked down the exterior of the condensate storage tank. The inspectors identified several issues associated with the program and implementing the commitments, which are documented in observation Condensate Storage Tank Observations in the Inspection Results section of this report.

The inspectors confirmed the licensee completed the required commitments and implemented the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program.

(3) A.1.3 Bolting Integrity Program and Commitment 3 This existing program manages loss of preload, cracking, and loss of material for closure bolting for pressure-retaining components using preventive and inspection activities. The licensee used applicable industry standards and guidance documents to delineate the program. This program interfaces with several other programs.

Commitment 3 specified:

• Ensure procedures prohibit molybdenum disulfide (MoS2) lubricants and specify visually verifying proper gasket compression following assembly.

• Include consideration of the guidance applicable for pressure boundary bolting in NUREG 1339, Electric Power Research Institute (EPRI) NP-5769, and EPRI TR-104213, including replacement bolting.

• Include volumetric examination per American Society of Mechanical Engineers (ASME) Code Section IX, Table IWB-2500-1, Examination Category B-G-1, for high-strength closure bolting.

The inspectors reviewed the aging management program basis document, implementing procedures, documentation of completed inspection activities, corrective action program evaluation of related issues, and closure documents.

The inspectors confirmed the licensee completed the required commitments and implemented the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program.

(4) A.1.4 Boraflex Monitoring Program and Commitment 4 This existing program manages the change in material properties (neutron absorbing capacity) in the Boraflex material affixed to spent fuel racks using silica sampling, areal testing activities, and other monitoring activities. The program requires periodic surveillances of the Boraflex neutron absorbing material every five years using Boron-10 Areal Density Gage for Evaluating Racks (BADGER) testing.

Commitment 4 specified:

• Perform periodic surveillances of the Boraflex neutron absorbing material in the spent fuel pool at least once every 5 years using BADGER testing.

• RACKLIFE analysis, or an equivalent methodology, will continue to be performed each cycle. Compare the RACKLIFE predicted silica to the plant measured silica to determine if adjustments to the RACKLIFE loss coefficient are merited and project the next RACKLIFE analysis date to ensure Region I storage locations will not need to be reclassified as Region II.

The inspectors interviewed the system owner, reviewed the aging management program basis document, implementing procedures, completed inspection activities, corrective action from operating experiences, program evaluation of related issues, and commitment closure documents. The inspectors reviewed the baseline BADGER reports for determining the density of the neutron-absorbing materials in the spent fuel pool and found no issues. The inspectors reviewed the procedure 20-S-03-410, Fuel Services Vendor Procedure Northeast Technology Corp. Badger Assembly and Testing Procedures for testing and procedure 17-S-02-300 Fuel and Core Component Movement Control for monitoring and analysis of the Boraflex panels.

The licensee initiated license basis document change request (LBDCR) 2020-074 to eliminate BADGER testing for the racks in the upper containment pool since the licensee does not store fuel assemblies in these racks during normal operation and their use is limited to short durations during refueling outages. The inspectors confirmed that the licensee performed RACKLIFE calculations for the storage racks in the upper containment pool. The LBDCR added an allowance in the second enhancement to use a method equivalent to the RACKLIFE analysis in assessing Boraflex performance. The proposed monitoring/evaluation methodology change makes the license renewal commitments consistent with monitoring/methodology described in UFSAR section 9.1.2.3.2.1. The inspectors did not identify any issues with these changes.

The inspectors confirmed the licensee completed the required commitments and implemented the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program.

(5) A.1.5 Buried Piping and Tanks Inspection Program and Commitment 5 This existing program manages loss of material for the external surfaces of buried and underground piping and tanks composed of any material through preventive, mitigative, and inspection activities. Preventive and mitigative actions include selection of component materials, external coatings for corrosion control, backfill quality control and the application of cathodic protection.

Cathodic protection is used for additional protection of buried piping and tanks. The cathodic protection system is monitored and trended annually in accordance with the national association of corrosion engineers (NACE) standards SP-0169, Control of External Corrosion on Underground or Submerged Metallic Piping Systems, and RP-0285, Standard Recommended Practice Corrosion Control of Underground Storage Tank Systems by Cathodic Protection. Inspection activities include non-destructive evaluation of pipe or tank wall thickness, and visual inspection of the exterior, as permitted by opportunistic or directed excavations.

Commitment 5 specified:

• Ensure to implement the program consistent with LR-ISG-2015-01, Changes to Buried and Underground Piping and Tank Recommendations.

• Perform soil testing at two locations near the stainless-steel condensate storage system piping. Measured parameters will include soil resistivity, bacteria, pH, moisture, chlorides and redox potential. If the soil is corrosive, then the number of inspections will be increased from one to two prior to and during the period of extended operation.

• Perform the diesel fuel oil storage tank, 1P81A001, ultrasonic examination no later than 2 years after entering the period of extended operation instead of 5 years prior as originally committed. This inspection coincides with an already scheduled preventive maintenance internal visual inspection of diesel fuel oil storage tank interior.

The inspectors reviewed procedures, work orders, engineering reports, and the license renewal implementing document. The inspectors interviewed license renewal project personnel and corporate program engineers. The inspectors confirmed that the licensee had established requirements in procedure EN-DC-343, Underground Piping and Tanks Inspection and Monitoring Program, and procedure SEP-UIP-GGN, Underground Components Inspection Plan, to implement the guidance of LR-ISG-2015-01, as required by bullet 1. For their baseline inspections prior to entering the period of extended operation, the inspectors verified that the licensee implemented their baseline inspection activities in accordance with LR-ISG-2015-01, category F, because they did not have reliable cathodic protection in place. The licensee had performed the appropriate number of inspections for each system with buried piping.

From review of cathodic protection reports, the inspectors questioned whether the licensee connected the service water piping to the rest of the cathodic protection system across an isolating flange. The report indicated that the piping continued to have cathodic protection but recommend the modification as a good practice. The licensee had not implemented a connection across the isolating flange. The licensee-initiated condition report CR-GGN-2024-04397 so that engineering would provide a formal analysis of this condition.

The inspectors determined that the license upgraded the cathodic protection system to better protect their buried piping and to meet the conditions described in LR-ISG-2015-01 to meet category C, which only requires one inspection of each buried piping system every 10 years. The modifications and refurbishment included installation of six

(6) deep anode ground beds (2009), rectifier reconfiguration to allow more current output, replacement of a faulty deep anode ground bed (2021),and installation of two

(2) new impressed current cathodic protection (ICCP)rectifiers and deep anode ground beds (2023). The inspectors determined two significant insights from the 2024 annual survey identified that

(1) two rectifiers with higher-than-normal resistance indicating that their ground beds were depleting and

(2) readings near the exterior of the standby service water basins did not meet the

-850 mV instant off polarization criteria indicating additional cathodic protection may be needed. The licensee indicated that the vendor would provide recommendations for how best to evaluate and protect, if needed, the service water piping located 40 feet below the surface. The readings to date have been taken at the surface and the buildings as well as the piping can impact the accuracy of the readings.

The inspectors verified that the licensee performed soil testing at two locations near the stainless-steel condensate piping for soil resistivity, bacteria, pH, moisture, chlorides and redox potential, as described in bullet 2. The test results indicated non-corrosive soil; consequently, the licensee only had to excavate one stainless steel pipe sample during the 10-years prior to the period of extended operation and during each 10-year period. The inspectors determined that the licensee used the excavation from July 2013 that fell slightly more than 11 years (slightly outside the 10 years) prior to the period of extended operation. Because of the non-corrosive soil conditions and the fact that the piping had been in the soil for over 30 years without any negative impact the inspectors had no concerns with this being the credited sample.

The licensee elected to perform the ultrasonic examination of the Division III diesel fuel oil storage tank 1P81A001 within 2 years after entering the period of extended operation instead of within 5 years prior, as specified in bullet 3. The licensee used LBDCR 2022-086 to reflect this change in the UFSAR. The licensee did this to align the inspection with a scheduled preventive maintenance 5001959501 that required a visual inspection, which prevented the need to drain the tank twice in a relatively short time. The inspectors had no concerns with the justification because the tank exterior is coated with coal tar epoxy, the cathodic protection for this tank has had 100 percent availability for the last 10 years, and the completed examination of tank found no corrosion with poorer performing cathodic protection. The licensee initiated condition report CR-GGN-2024-04402 to ensure the required inspection of the diesel fuel oil storage tank will occur no later than November 1, 2026.

The inspectors confirmed the licensee completed the required commitments and implemented the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program.

(6) A.1.6 BWR CRD Return Line Nozzle Program and Commitment 32 This existing program manages cracking of control rod drive return line nozzle components using preventive, mitigative, and in-service inspection activities. The control rod drive return line has been cut and capped.

Commitment 32 specified:

• Enhance the BWR CRD Return Line Nozzle program to inspect the inconel end cap to carbon steel safe end dissimilar metal weld once prior to the period of extended operation and every 10 years thereafter.

The inspectors reviewed the aging management program basis document, implementing procedures, documentation of completed testing activities, and corrective action program evaluation of related issues.

The inspectors confirmed the licensee completed the required commitments and implemented the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program.

(7) A.1.7 BWR Feedwater Nozzle Program This existing program manages cracking of the feedwater nozzles using inspection activities. This program augments the in-service inspections performed under 10 CFR 50.55a(g) and ASME Code Section XI that require periodic inspection of critical regions of the feedwater nozzles. This program ensures that the nozzle components maintain their function through the end of the period of extended operation. The licensee volumetrically examines the inner radii and nozzle bore of the six feedwater nozzles in accordance with ASME Code,Section XI, Examination Category B-D.

The inspectors reviewed the aging management program basis document, implementing procedures, documentation of completed testing activities, and corrective action program evaluation of related issues.

The inspectors determined that LBDCR 2021-081 revised the requirement to perform the periodic examinations of critical regions specified in calculation NE-523-A71-0594, Alternate BWR Feedwater Nozzle Inspection Requirements, revision 1 with the requirements of ASME Code Section XI. The licensee made this change because 10 CFR 50.55a(g) requires performing the periodic inspection of critical regions of the feedwater nozzles using ASME Code Section XI. The inspectors determined that NUREG-2191, Generic Aging Lessons Learned for Subsequent License Renewal (GALL-SLR) Report, specified using ASME Code Section XI. The inspectors identified no concerns with this change.

The inspectors confirmed the licensee completed the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program.

(8) A.1.8 BWR Penetrations Program and Commitment 33 This existing program manages cracking caused by cyclic loading or stress corrosion cracking (SCC) and intergranular SSC (IGSCC) of instrument penetrations, control rod drive and in core instrument housing penetrations, and core plate differential pressure/standby liquid control penetrations. The licensee performed inspections in accordance with the guidelines of the Boiling Water Reactor Vessel Internals Program (BWRVIP)-49-A, Instrument Penetration Inspection and Flaw Evaluation Guidelines, for the instrument penetrations, BWRVIP-47-A, BWR Lower Plenum Inspection and Flaw Evaluation Guidelines, for the control rod drive and in core instrument housing penetrations, and BWRVIP-27-A, BWR Standby Liquid Control System / Core Plate Delta-P Inspection and Flaw Evaluation Guidelines, for the core plate delta P/standby liquid control penetrations. The guidelines of BWRVIP-49-A, BWRVIP-47-A, and BWRVIP-27-A provide information on the type of penetrations, evaluate their susceptibility and consequences of failure, and define the inspection strategy to assure safe operation.

Commitment 33 specified:

• Enhance the BWR Penetrations program implementing procedure to clarify the guidelines of BWRVIP-47-A will be applied without exceptions.

The inspectors reviewed the aging management program basis document, implementing procedures, completed reactor vessel in-service inspection work documentation, and commitment closure documents.

The inspectors confirmed the licensee completed the required commitments and implemented the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program.

(9) A.1.9 BWR Stress Corrosion Cracking Program This existing program manages IGSCC in 4 inch or larger nominal diameter piping and piping welds in accordance with BWRVIP-75-A, Technical Basis for Revisions to Generic Letter 88-01, NRC Position on Intergranular Stress Corrosion Cracking (IGSCC) in BWR Austenitic Stainless-Steel Piping, Inspection Schedules, and the risk-informed in-service inspection program. The program includes preventive measures including the mechanical stress improvement process to minimize stress corrosion cracking.

The inspectors reviewed the aging management program basis document, implementing procedures, and documentation of completed program activities and held discussions with site personnel and fleet program owners. Piping welds include category A, B, C, and E in accordance with the recommendations in BWRVIP-75-A.

The licensee inspects category A welds under the provisions of the risk-informed in-service inspection program approved on June 30, 2010. During the period of extended operation, the licensee will inspect at least 10 percent of the category A welds during each in-service inspection interval. The licensee will inspect the category B, C, and E welds in accordance with BWRVIP-75-A and GL 88-01.

The inspectors confirmed the licensee implemented the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program.

(10) A.1.10 BWR Vessel ID Attachment Welds Program This existing program manages cracking in structural welds for reactor vessel internal integral attachments using inspection and flaw evaluation. The program provides for mitigation of cracking of reactor vessel internal components through control of reactor water chemistry as described in the Water Chemistry Control - BWR Program (UFSAR section A.1.43) and condition monitoring through in-vessel examinations of the reactor vessel internal attachment welds. The program uses inspections, scheduling, acceptance criteria, and flaw evaluation in conformance with BWRVIP guidelines, including BWRVIP-48-A, Vessel ID Attachment Weld Inspection and Flaw Evaluation Guidelines.

The inspectors reviewed the aging management program basis document, implementing procedures, and documentation of completed program activities and held discussions with site personnel and fleet program owners.

The inspectors confirmed the licensee implemented the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program.

(11) A.1.11 BWR Vessel Internals Program and Commitment 6 This existing program manages cracking, loss of material, and reduction of fracture toughness for vessel internal components using inspection and flaw evaluation. This program

(1) determines the susceptibility of cast austenitic stainless-steel components,

(2) accounts for the synergistic effect of thermal aging and neutron irradiation, and

(3) implements a supplemental examination program, as necessary.

The program, implemented through station procedures using applicable industry standards and staff-approved BWRVIP documents provides for mitigation of cracking loss of material and reduction of fracture toughness of reactor vessel internal components through control of reactor water chemistry as described in the Water Chemistry Control - BWR Program (section A.1.43) and condition monitoring through in-vessel examinations of the reactor vessel internal components. The program uses inspections, scheduling, acceptance criteria, and flaw evaluation in conformance with BWRVIP guidelines.

Commitment 6 specified:

• Evaluate the susceptibility to neutron or thermal embrittlement for the specific reactor vessel internal components composed of CASS, X-750 alloy, precipitation-hardened martensitic stainless steel, and martensitic stainless steel.

• Inspect susceptible components determined to be limiting from the standpoint of thermal aging susceptibility, neutron fluence, and cracking susceptibility. The inspection technique must be capable of detecting the critical flaw size with adequate margin. Determine the critical flaw size based on the service loading and service-degraded material properties. Complete the initial inspection either prior to or within 5 years after entering the period of extended operation. If the initial inspection detects cracking, justify the reinspection frequency based on fracture toughness properties appropriate for the condition of the component. The initial inspection includes 100 percent of the accessible, susceptible component population, excluding components that may be in compression during normal operations.

The inspectors reviewed the aging management program basis document, implementing procedures, and documentation of completed program activities, including several in-vessel visual inspection reports from refueling outages 23 and 24.

The inspectors confirmed the licensee completed the required commitments and implemented the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program.

(12) A.1.12 Compressed Air Monitoring Program and Commitment 7 This existing program manages loss of material in compressed air systems by monitoring air samples for moisture and contaminants and by inspecting internal surfaces within compressed air systems.

Commitment 7 specified:

• Consider the guidance of ASME OM-S/G-1998, Part 17; American National Standards Institute (ANSI)/ISA-S7.0.01-1996; EPRI NP-7079; and EPRI TR-108147 when specifying the limits for air system contaminants.

• Revise procedures to include opportunistic visual inspections to evaluate accessible component internal surfaces downstream of system air dryers.

The inspectors reviewed the aging management program basis document, implementing procedures, documentation of completed program activities, and held discussions with site personnel and fleet program owners. Specifically, the inspectors verified the dew point data, particulates data for air samples, trends, and discussed the program with the system engineers.

The inspectors reviewed LBDCR 2021-085 that revised the program description to specify opportunistic inspections on components downstream of system air dryers.

The inspectors evaluated this change and did not identify any concerns with the change. Specifically, the inspectors confirmed this change aligned with the guidance in NUREG-2191.

The inspectors reviewed procedure SEP-GGN-AMP-01, GGNS Opportunistic Inspections for Aging Management Programs, and confirmed the licensee had developed the compressed air monitoring opportunistic inspections. However, the inspectors noted that the licensee had drafted but not completed the work control and maintenance procedures change requests for the opportunistic inspections (procedure EN-MA-106, Planning, and procedure EN-MA-101, Conduct of Maintenance, respectively) at the time of the inspection. Despite the lack of work control procedure enhancements, the inspectors concluded the licensee had implemented the program commitments because the licensee completed the overall program procedure for opportunistic inspections and drafted the changes to the implementing procedures.

The inspectors confirmed the enhancements to the program and commitment 7 were implemented prior to the period of extended operation, with the exception as noted above. The inspectors confirmed the licensee implemented the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program.

(13) A.1.13 Containment Inservice Inspection - IWE This existing program manages cracking, loss of material, loss of sealing, loss of preload, and loss of leak tightness of containment by performing a general visual examination that assesses the condition of the containment steel liner and detects evidence of degradation. This examination is credited with meeting the requirements of the applicable edition of the ASME Boiler and Pressure Vessel Code Section XI, Subsection IE Examination Category E-A. The licensee performs IWE inspections to identify and manage any containment liner aging effects that could result in loss of intended function.

The licensee augments this program using existing plant procedures to ensure that the selection of bolting material installation torque or tension and the use of lubricants and sealants remain appropriate for the intended purpose. These procedures reference guidance contained in EPRI TR-104213, NUREG-1339 and EPRI NP-5769 to ensure proper specification of bolting material, lubricant, and installation torque.

The inspectors reviewed the aging management program basis document, implementing procedures, documentation of completed inspection activities, corrective action program evaluation of related issues, and closure documents. The inspectors concluded that the licensee appropriately implemented procedures for the required inspection activities and that the licensee adequately implemented this program.

The licensee modified the UFSAR supplement section A.1.13, using LBDCR 2021-038, to remove the reference to the specific ASME Code edition because the applicable code year and addenda are dictated by the regulations of 10 CFR 50.55a. The licensee implemented the change to achieve consistency with the in-service inspection plan for the fourth interval. The inspectors had no concerns with this change.

The inspectors confirmed the licensee implemented the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program.

(14) A.1.14 Containment Inservice Inspection - IWL Program This existing program manages the aging of the overall condition of the containment concrete and detect evidence of degradation that may affect structural integrity or leak tightness. This examination is credited with meeting the examination requirements of the applicable edition of the ASME Boiler and Pressure Vessel Code Section XI, Subsection IWL Examination Category L-A, item numbers L1.11, L1.12. The program section for ASME Section XI Class CC and Class MC components is developed in accordance with 10 CFR 50.55a using the ASME Boiler and Pressure Vessel Code,Section XI except where specific written alternatives from Code requirements have been requested by Entergy and granted by the NRC.

The inspectors reviewed the aging management program basis document, implementing procedures, documentation of completed inspection activities, corrective action program evaluation of related issues, and commitment closure documents.

The licensee modified the UFSAR supplement section A.1.14, using LBDCR 2021-002, to remove the reference to examination category L2.30, Anchorage Hardware and Surrounding Concrete. The licensee made this change because the exam category applies to reactor buildings having unbonded post tensioning systems, and the licensee does not employ a post tensioning system.

The change also removed the reference to the specific ASME Code edition because the applicable code year and addenda are dictated by the regulations of 10 CFR 50.55a. The licensee implemented the change to achieve consistency with the in-service inspection plan for the fourth interval. The change also removed the last sentence of the program description referring to relief requests because it was no longer applicable. The inspectors had no concerns with this change.

The inspectors confirmed the licensee implemented the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program.

(15) A.1.15 Containment Leak Rate Program This existing program monitors leakage rates through the containment pressure boundary, including the penetrations and access openings, to detect degradation of the containment pressure boundary. Containment leak rate tests assure that leakage through the primary containment as well as systems and components penetrating primary containment do not exceed allowable leakage limits specified in the technical specifications. These components include containment isolation valves/flanges and containment penetrations.

The inspectors reviewed the aging management program basis document, implementing procedures, documentation of completed testing activities, and corrective action program evaluation of related issues.

The inspectors determined that LBDCR 2022-031 revised UFSAR section A.1.15 text to read Types A, B and C leakage rate testing will be implemented in accordance with the criteria set forth in NEI 94-01, Industry Guideline for Implementing PerformanceBased Option of 10 CFR Part 50, appendix J, revision 3-A and ANSI/ANS 56.8-2002. The inspectors identified no concerns since this had removed the reference to RG 1.163, Performance-Based Containment Leak-Test Program, which referred to NEI 94-01 and ANSI/ANS 56.8.

The inspectors confirmed the licensee implemented the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program.

(16) A.1.16 Diesel Fuel Monitoring Program and Commitment 8 This existing program manages loss of material and fouling in piping and components exposed to an environment of diesel fuel oil by verifying the quality of fuel oil and controlling fuel oil contamination as well as periodic draining, cleaning, and inspection of tanks. The licensee delineates the program using applicable industry standards and chemistry guidance documents. Acceptance criteria for fuel oil quality parameters are specified in the licensee's technical specifications to ensure that adequate diesel fuel quality is maintained to prevent plugging of filters, fouling of injectors, and corrosion of diesel fuel systems.

Commitment 8 specified:

Enhance the Diesel Fuel Monitoring program for the fire water pump diesel fuel oil tanks (SP64A002A/B), the diesel fuel oil day tanks for Divisions I, II, and III, and the diesel fuel oil drip tanks for Divisions I and II to:

• Perform ten-year periodic cleaning and internal inspection once during the 10-year period prior to the period of extended operation and at succeeding 10-year intervals.

• Volumetrically exam affected areas of the diesel fuel tanks if evidence of degradation is observed during visual inspection. This enhancement is applicable to the inspections performed during the 10-year period prior to the period of extended operation and at succeeding 10-year intervals.

The inspectors reviewed the aging management program basis document, implementing procedures, documentation of completed program activities, and held discussions with site personnel and fleet program owners. Specifically, the inspectors verified the fuel quality chemistry analyses for new diesel fuel, diesel tank inspection results, trends, walkdown the accessible portions of the diesel generator and their associated tanks and discussed the program with the system engineers.

The inspectors confirmed the licensee completed the required commitments and implemented the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program.

(17) A.1.17 Environmental Qualification (EQ) of Electric Components Program This existing program manages the effects of thermal, radiation, and cyclic aging using evaluations based on 10 CFR 50.49(f) qualification methods.

The inspectors reviewed the aging management program basis document, implementing procedures, documentation of completed program activities, and held discussions with site personnel and fleet program owners. The inspectors verified that procedure EN-DC-164, Environmental Qualification (EQ) Program, specified aging management as applicable to Grand Gulf. The inspectors verified that the licensee had replaced all components as required before the period of extended operation. The inspectors verified the licensee established a replacement schedule for components before the end of 60-years. The inspectors reviewed select component plant qualification evaluations and did not identify any concerns. The inspectors determined the licensee appropriately used the corrective action program to disposition their results.

The inspectors confirmed the licensee implemented the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program.

(18) A.1.18 External Surfaces Monitoring Program and Commitment 9 This existing program manages aging effects through visual inspection of external surfaces for evidence of loss of material, cracking and change in material properties.

Physical manipulation is used to detect hardening or loss of strength for elastomers and polymers.

Commitment 9 specified:

• Include instructions for evaluating flexible polymeric components by manual or physical manipulation of at least 10 percent of available surface area.

• Clearly identify underground components in program documents.

• Inspecting all in-scope underground components during each 5-year period, beginning 10 years prior to entering the period of extended operation.

• Revise implementing procedures to specify the following for insulated components:

a.

Conduct representative inspections during each 10-year period.

b.

Remove insulation to visually inspect the surface of a representative sample of indoor components exposed to condensation. Include a minimum of 20 percent of the piping length for each material type (e.g.,

steel, stainless-steel, copper alloy, aluminum), or for components other than piping (e.g., valve, accumulator), inspect 20 percent of the surface area. Alternatively, remove insulation and perform a minimum of 25 inspections that can be a combination of 1-ft axial length sections and individual components for each material type.

c.

Select locations based on the likelihood of corrosion under insulation (e.g., components experiencing alternate wetting and drying or those that operate for long periods below the dew point). Subsequent inspections can be limited to an examination of the exterior surface of the insulation for indications of damage to the jacketing or protective outer layer of the insulation, if the following conditions are verified in the initial inspection:

(1) No loss of material caused by general. pitting or crevice corrosion and

(2) No evidence of cracking.

d.

For damage to the exterior surface of the insulation or there is evidence of water intrusion through the insulation, periodic inspections under the insulation will continue as described above. Do not remove tightly adhering insulation impermeable to moisture unless damage identified on the moisture barrier. Tightly adhering insulation is considered a separate population from the remainder of insulation installed on in-scope components. The entire population of in-scope accessible piping component surfaces that have tightly adhering insulation will be visually inspected for damage to the moisture barrier at the same frequency as inspections of other types of insulation. These inspections will not be credited toward the inspection quantities for other types of insulation.

The inspectors reviewed the aging management program basis document, implementing procedures, and documentation of completed program activities and inspection results. The inspectors identified several issues related to this aging management program and described the details in observation Walkdown Observations in the Inspection Results section of this report.

The inspectors confirmed the licensee completed the required commitments and implemented the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program.

(19) A.1.19 Fatigue Monitoring Program and Commitment 10 This existing program monitors the number of pressure and temperature transient cycles and periodically compares this cycle count with the design limits for cycle counts to ensure that the fatigue sensitive components remain within their allowable design. Monitoring the cycle count ensures that pressure and thermal cycles are maintained within their design limits and tracked to identify abnormal trends toward their design limits. The Fatigue Monitoring Program monitors the number of transient cycles that are considered in the fatigue analyses for all fatigue usage locations.

Commitment 10 specified:

• Monitor and track all critical thermal and pressure transients for all components that have been identified to have a fatigue time limited aging analysis.

• Review the high energy line break analyses and the corresponding tracking of associated cumulative usage factors to ensure the program adequately manages fatigue usage for these locations.

The inspectors reviewed the aging management program basis document, implementing procedures, documentation of completed program activities, and held discussions with site personnel and fleet program owners. Specifically, the inspectors reviewed the engineering changes and environmentally assisted fatigue calculations, discussed the program with the system engineers, and confirmed cycle counts, transients, and cumulative usage factors were below the threshold requirements.

The inspectors reviewed the following UFSAR changes:

• LBDCR 2021-072 revised the UFSAR section A.1.19 language from explicit cycle counting and cycle counting methods. The licensee incorporated the methods into a new set of calculations for environmentally assisted fatigue that made cycle-based and stress-based fatigue monitoring unnecessary.

• LBDCR 2021-084 implemented editorial changes such as typos, omissions, and references to request for information sent by the licensee to NRC staff.

This existing program ensures that fatigue usage remains within allowable limits by

(a) tracking the number of critical thermal and pressure transients for selected components,

(b) verifying that the severity of monitored transients are bounded by the design transient definitions for which they are classified, and

(c) assessing the impact of the reactor coolant environment on a set of sample critical components for an assumed plant operation of 60 years.

The licensee uses manual transient cycle logging techniques and fatigue monitoring software together to ensure cumulative usage factors do not exceed design limits. In addition to providing cycle counting information, the fatigue monitoring software determines cycle-based fatigue and stress-based fatigue based on actual transients incurred. Cycle-based fatigue monitoring utilizes cycle counts that have occurred and design basis fatigue calculations to calculate usage for a specific location and make projections of future fatigue usage. Stress-based fatigue monitoring calculates stress and fatigue based on actual stress loadings. The combination of cycle counting, cycle-based fatigue monitoring, and stress-based fatigue monitoring ensures that the licensee will maintain cumulative usage factors within allowable limits.

The inspectors reviewed engineering change EC-94963, where the station generated stress calculation MC-Q1B13-23003. This calculation evaluated components for environmentally assisted fatigue, reviewed high energy line break analyses, and provided guidance for the required transient cycles to track. This calculation utilizes the FatiguePro computer software. These calculations and methods were incorporated into procedure GGNS-MS-40, ASME Class 1 Components Fatigue Cycle Counting.

The inspectors confirmed the licensee completed the required commitments and implemented the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program.

(20) A.1.20 Fire Protection Program and Commitment 11 This existing program manages loss of material for fire-rated barriers including fire doors, fire dampers and the clean agents (a term used to encompass CO2, Halon 1301, Novec 1230, or similar fire suppression agent) suppression system.

The program manages

(1) concrete cracking, spalling, and loss of material for fire barrier concrete curbs, manways, hatches, manhole covers, hatch covers, roof slabs and increased hardness, shrinkage, and loss of strength of fire barrier penetration seals; and

(2) aging effects for clean agent fire suppression systems through periodic visual inspection and testing. The program credits

(1) visual inspections of fire barrier penetration seals, fire dampers, and structural fire barriers (walls, ceilings and floors) to ensure they can perform their intended functions; and

(2) visual inspections and functional tests of fire-rated doors, the Halon system, and the CO2 tank daily during the period of extended operation.

Commitment 11 Specified:

Enhance the Fire Protection program to require visual inspections at least once every fuel cycle of:

• The clean agent/CO2 fire suppression system for signs of corrosion.

• fire damper framing to check for signs of degradation.

• concrete curbs, manways, hatches, manhole covers, hatch covers, and roof slabs to confirm that aging effects are not occurring.

• the exterior of the CO2 tank to examine for signs of corrosion.

The inspectors reviewed implementing procedures, aging management program basis document, work orders, surveillances, inspections, and test results. The inspectors walked down fire protection equipment and discussed the fire protection program details with the program owner. The inspectors identified an issue related to this aging management program and described the details in observation Walkdown Observations, in the Inspection Results section of this report.

The inspectors determined that the licensee had replaced the existing fire detection and suppression subsystem equipment with modern equivalent equipment using engineering change (EC) 79268. The engineering change installed new equipment including storage containers with a clean agent extinguishing media (i.e.,

Novec 1230) to replace the Halon, releasing solenoids (i.e., discharge valves),discharge piping nozzles, multi-zone fire control panels, addressable smoke and thermal detectors, and fire bells. The licensee developed LBDCR 2019-044 to reflect these changes in their UFSAR, technical requirements manual, and their fire protection program. The inspectors identified no concerns with these changes.

The inspectors confirmed the licensee completed the required commitments and implemented the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program.

(21) A.1.21 Fire Water System Program and Commitment 12 This existing program manages loss of material, loss of coating integrity, and fouling for components in fire water systems using preventive, inspection, and monitoring activities, including periodic full-flow flush tests, system performance testing, and testing or replacement of sprinkler heads. The program includes acceptance criteria for the water-based fire protection system to maintain required pressure, and the licensee enhanced the acceptance criteria to verify no unacceptable degradation.

Components within the scope of the program include sprinkler heads, nozzles, fittings, valve bodies, fire pump casings, yard hydrants (D010, D012, and D013),hose stations, fire water storage tanks including internal coatings, fire service mains, and standpipes. The program scope also includes breather vents, heat exchanger bonnets and tubes, strainer and strainer housing, and vortex breakers. The internal surfaces of water-based fire protection system piping that are normally drained, such as dry-pipe sprinkler system piping, are also included within the scope of the program. Additionally, the deluge systems for ESF-11 and ESF-21 transformers, the radwaste building oil separator sprinkler system, and the manual deluge system for charcoal filter systems in safety-related structures are included within the scope of the program.

Commitment 12 specified:

Enhance the Fire Water System program as follows to revise program procedures to:

• Include visual inspection of spray and sprinkler system internals.

• Include inspecting sprinklers in the overhead for signs of corrosion.

• Specify that corrosion beyond a normal oxide layer will be entered into the corrective action program with follow-up volumetric wall thickness examinations.

• Include periodic inspection of hose reels for degradation.

• Inspect the strainers upstream of the deluge valves every three years.

• Inspect the charcoal filter fire water piping discharge openings when replacing charcoal.

• Periodically open a connection at a main and remove a branch line component for pre-action and dry pipe systems to perform a visual inspection.

• Perform a flow blockage evaluation if during main drain testing, the flowing pressure drops more than 10 percent from the normal flowing pressure.

• Perform air flow testing to ensure no obstructions downstream of the deluge valves for the listed filter units each refueling cycle.

• Require internal inspections at the end of one fire main and the end of one branch line as specified every five years. During each five-year internal inspection period, select samples such that internal inspections are performed on all the wet pipe sprinkler systems in the auxiliary and control buildings every 15 years and in the fire pump house every 10 years. If deficiencies are identified in a building wet pipe system, expand the number of inspections to include all the wet pipe sprinkler systems in the identified building.

• Inspect the emergency diesel generator enclosures fire suppression piping to ensure that the piping does not collect water. In the event areas collect water, perform the following tests and inspections in 5-year intervals to ensure that flow blockage has not occurred:

(a) Visually inspect 100 percent of the internal surface of the affected piping segments; and

(b) Volumetrically examine 20 percent of the length of piping segments that allow water to collect in 5-year intervals. Select different piping in each interval. Use inspection data to identify the type of corrosion. If the results of a 100 percent internal visual inspection are acceptable without subsequent wetting, no further tests or inspections are necessary

• Test or replace sprinkler heads in accordance with NFPA-25. For any failed sprinkler test, replace other sprinklers of the same type that failed.

• Ensure flow for not less than one minute when hydrant valves are flow tested.

• Inspect the interior of the fire water tanks at the frequency specified by NFPA 25, section 9.2.6.1.2:

(a) Testing for possible voids beneath the tank;

(b) Inspection of the vortex breaker; and

(c) Review coating inspection results with personnel qualified in accordance with Regulatory Guide (RG)1.54, Service Level I, II, and III Protective Coatings Applied to Nuclear Power Plants, revision 3.

• If tank inspections, including the bottom, show any signs of pitting, corrosion, or coating failure then perform the following testing specified by NFPA-25, section 9.2.:

(a) Adhesion testing endorsed by RG 1.54;

(b) Take dry film thickness measurements at random locations;

(c) Perform spot wet-sponge tests to detect pinholes, cracks, or other compromises in the coating;

(d) Use nondestructive ultrasonic readings to evaluate the wall thickness where evidence of pitting or corrosion identified; and

(e) Use ultrasonic testing of the tank bottom where evidence of pitting or corrosion exists.

• Return the fire water tank to service after identifying coating deficiencies after ensuring the coating has only a few intact blisters surrounded by coating bonded to the substrate as determined by a qualified coating specialist or perform the following actions:

(a) Remove blistering not surrounded by coating bonded to the substrate;

(b) Remove any delaminated or peeled coating;

(c) Verify exposed underlying coating is securely bonded to the substrate by an adhesion test;

(d) Feather the outermost coating and determine it to be securely bonded by an adhesion test;

(e) Perform an ultrasonic testing where pitting or corrosion exists to verify minimum wall thickness requirements;

(f) Evaluate to ensure downstream flow blockage is not a concern, and

(g) Perform follow up inspection every two years until the coating is repaired, replaced, or removed.

• Review at least two previous coating inspection result reports prior to inspecting. Coating inspection reports list the locations that had coating degradation including, where possible, photographs indexed to the location, and a prioritization of areas into those that must be repaired before returning the system to service and those that can be postponed to later inspection or repair.

• Specify no debris observed (i.e., no corrosion that could obstruct flow or clog downstream components) for flow testing, main drain testing, or internal inspections.

• Include the following acceptance criteria for loss of coating integrity:

(a) Indications of peeling and delamination are not acceptable;

(b) Blisters, cracking, flaking, and rusting are evaluated by a coating specialist qualified in accordance with RG 1.54. Blister size and frequency should not be increasing between inspections;

(c) Minor cracking and spalling of cementitious coatings/linings is acceptable provided no evidence exists of coating debonding from the base material;

(d) As applicable, wall thickness measurements, projected to the next inspection, meet design minimum wall requirements; and

(e) Adhesion testing results, when conducted, meet or exceed the degree of adhesion recommended in plant specific design requirements specific to the coating/lining and substrate.

• Specify replacing any sprinkler that shows signs of leakage or corrosion.

• Require an obstruction evaluation if any signs of abnormal corrosion or blockage are identified during tests or inspections. Determine and correct its source and enter the condition into the corrective action program. The evaluation should consider all system components and branch lines, and the performance of a complete flushing program by qualified personnel.

• Ensure coatings that do not meet the acceptance criteria will be repaired or replaced.

• Establish monthly jockey pump monitoring in accordance with LR-ISG-2015-01 and full-flow testing every 4 years as alternative to direct visual inspection.

The inspectors reviewed the aging management program basis documents, implementing procedures, completed work orders and surveillances satisfying the testing and examination requirements for the program, plant operating experience, and corrective action documents. The inspectors interviewed plant personnel and walked down a sample of fire water system equipment, including: the fire pumps and jockey pump, fire water storage tanks, yard hydrants, and associated piping and valves. The inspectors also reviewed the results of an excavation of a segment of fire water piping that had leaked. The inspectors determined that the licensee had included fire water components susceptible to selective leaching in that program.

The licensee implemented the following UFSAR supplement changes:

• LBDCR 2022-045:

(1) required coating inspector qualifications consistent with LR-ISG-2013-01, Aging Management of Loss of Coating or Lining Integrity for Internal Coatings/Linings on In Scope Piping, Piping Components, Heat Exchangers and Tanks,

(2) established jockey pump monitoring as an alternative to direct visual inspections of below-grade fire protection piping coatings inspections, and

(3) deleted the requirement to perform an obstruction evaluation for the dry pipe fire suppression system associated with the auxiliary building railroad access because this system is not within the scope of license renewal.

• LBDCR 2023-0001: clarified the commitment related to visual inspection of charcoal filter deluge distribution piping.

• LBDCR 2023-0046: deleted a commitment related to inspection of pre-action system piping because of operating experience and follow-up corrective actions.

The inspectors verified that the licensee had included the enhancements specified in commitment 12 in their implementing procedures. The inspectors determined that the licensee performed the required testing to determine internal coating integrity and determined that the licensee inspected the bottom of the fire water storage tanks to confirm the presence of no voids. An inspection performed in 2023 under work order 52971020 did not document any concern with the tank internal coatings.

The licensee scheduled the next internal inspection under preventive maintenance task 54005929 with a due date of April 26, 2028. The inspectors identified a material deficiency during walk down of the fire water storage tank that is documented in the in observation Walkdown Observations, in the Inspection Results section of this report.

The inspectors determined that the licensee started planning for the 50-year sprinkler testing and/or replacement but had not finalized their plans. The licensee committed to perform sprinkler testing or replacement in accordance with NFPA 25, 2011 Edition, Section 5.3.1. This standard requires, in part, for sprinklers in service for 50 years, they shall be replaced or representative samples from one or more sample areas shall be tested, and the testing process will repeat periodically through the life of the facility. The licensee tracked implementation of this commitment with condition report CR-GGN-2024-04529. The inspectors had no concerns with this approach.

The inspectors reviewed the results of a recent license renewal inspection that had identified unacceptable levels of internal flow blockage in the dry pipe pre-action sprinkler systems servicing the emergency diesel generator enclosures. The inspectors discussed the issues and corrective actions taken with site and corporate staff. The licensee replaced the degraded branch line piping in these areas and the inspectors reviewed the work orders documenting the replacements. The inspectors determined that the emergency diesel generator room pre-action fire water piping systems were the only dry pipe systems within scope of license renewal.

The inspectors confirmed the licensee completed the required commitments and implemented the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program.

(22) A.1.22 Flow-Accelerated Corrosion Program (FAC) and Commitments 13 and 36 This existing program manages loss of material caused by wall thinning for piping and components subject to flow accelerated corrosion. This program includes conducting appropriate analysis and baseline inspections, determining the extent of thinning, performing follow-up inspections, and taking corrective actions as necessary. The program also manages the effects of aging caused by other wall-thinning mechanisms (erosion) that may be identified through industry or plant-specific operating experience. The program follows guidelines in NSAC-202L, Recommendations for an Effective Flow Accelerated Corrosion Program.

Commitment 13 specified:

• Enhance the Flow-Accelerated Corrosion program to specify monitoring downstream components closely to mitigate any increased wear when replacing susceptible upstream components with resistant materials, such as high chromium material.

Commitment 36 specified:

• Revise program documentation to specify that components subject to wall thinning mechanisms other than flow-accelerated corrosion, which are replaced with alternate materials (e.g. replacing a carbon steel pipe with stainless steel) shall continue to be periodically monitored at a frequency commensurate with their post-replacement wear rate and operating time.

The inspectors reviewed the aging management program basis document, implementing procedures, documentation of completed program activities, and held discussions with site personnel and fleet program owners. The inspectors concluded the implementing procedures appropriately implemented the programs, and the licensee implemented the program in accordance with the procedures. After discussion with the inspectors, the licensee determined that the wording of procedure EN-DC-315, Flow Accelerated Corrosion Program, step 7.5.1 could potentially cause confusion, especially for an inexperienced staff. The licensee initiated condition report CR-GGN-2024-04455 to recommend revision of the procedure step 7.5.1.

The inspectors confirmed the licensee completed the required commitments and implemented the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program.

(23) A.1.24 Inservice Inspection - IWF Program and Commitment 14 This existing program manages aging effects for ASME Class 1, 2, 3 piping and component supports as required by ASME Section XI, subsection IWF and other requirements specified in 10CFR50.55a with approved NRC alternatives and relief requests. The program inspects a sampling of piping supports and 100 percent of component supports other than piping as specified in Table IWF-2500-1. The program uses nondestructive examination techniques to detect and characterize component degradation.

Commitment 14 specified:

• Address inspections of accessible sliding surfaces.

• Clarify monitored or inspected parameters include corrosion; deformation; misalignment of supports; missing, detached, or loosened support items; improper clearances of guides and stops; and improper hot or cold settings of spring supports, and constant load supports.

• Include monitoring structural bolting in accordance with ASTM requirements and monitoring anchor bolts for loss of material, loose or missing nuts, loss of preload, and cracking around the anchor bolts. Perform volumetric examination comparable to that of ASME Code Section XI, Table IW8-2500-1, Examination Category 8-G-1 for high-strength structural bolting to detect cracking in addition to the VT-3 examination.

The inspectors reviewed the aging management program basis document, implementing procedures, and documentation of completed program activities and inspection results and held discussions with plant staff.

The licensee revised the UFSAR with LBDCR 2023-014 to remove provisions for high strength bolting, because they are not present on subsection IWF supports at the station. The inspectors reviewed this change and identified no concerns. The licensee indicated that high-strength structural bolting susceptible to stress corrosion cracking will be monitored.

The inspectors confirmed the licensee completed the required commitments and implemented the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program.

(24) A.1.25 Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program and Commitment 15 This existing program manages loss of material and loss of preload for bolting for all cranes, bridges, trolley and hoist structural components, fuel handling equipment and applicable rails within the scope of license renewal. This includes visual inspection of structural components and structural bolts for loss of materials caused by corrosion of structural members and bolting, loss of materials caused by wear of rails, and loss of preload for bolted connections.

Commitment 15 specified:

• Include monitoring of rails in the rail system for the aging effect wear, and structural connections/bolting for loose or missing bolts, nuts, pins, or rivets.

Additionally, clarify the program to visually inspect structural components and structural bolts for loss of material and structural bolting for loss of preload caused by self-loosening.

• State that any significant loss of material for structural components and structural bolts, and significant wear of rails in the rail system, is evaluated according to applicable industry standards in the B30 series.

The inspectors reviewed the aging management program basis document, implementing procedures, nondestructive evaluation reports, crane inspection reports, completed work orders, and commitment closure documents. The inspectors verified procedures for implementing the inspections and enhancements of the program commitment. The procedures included the appropriate materials and followed the appropriate ASME B30 series standard.

The inspectors confirmed the licensee completed the required commitments and implemented the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program.

(25) A.1.26 Internal Surfaces in Miscellaneous Piping and Ducting Components Program and Commitment 16 This new program manages the effects of aging using opportunistic visual inspections of the internal surfaces of metallic piping, piping components, ducting, elastomeric components, and other components during periodic surveillances or maintenance activities when the surfaces are accessible.

The licensee will perform an assessment of opportunistic inspections to ensure a representative sample, in each 10-year period during the PEO, for each material-environment-aging effect combination. The licensee will complete directed inspections to complete a 20 percent sample with a maximum of 25 inspections for each material-environment-aging effect combination during the 10-year period under review. Where practical, inspections shall be conducted at locations that are most susceptible to the effects of aging because of time in service, severity of operating conditions (e.g., low or stagnant flow), and lowest design margin. An inspection conducted of a material in a more severe environment may be credited as an inspection of the same material in a less severe environment.

For metallic components visual inspection will be used to detect loss of material and fouling. For elastomeric and plastic components, visual inspections will be used to detect cracking and change in material properties. Visual examinations of elastomeric components are accompanied by physical manipulation or pressurization (i.e., the component is sufficiently pressurized to expand the surface of the material in such a way that cracks or crazing are evident) such that changes in material properties are readily observable. The sample area subject to manipulation of flexible elastomeric components is at least 10 percent of the available surface area.

Commitment 16 specified:

• Implement the Internal Surfaces in Miscellaneous Piping and Ducting Components program as described in LRA section B.1.26.

The inspectors reviewed the aging management program basis document, implementing procedures, and held discussions with site personnel and fleet program owners. The inspectors reviewed LBDCR 2021-084, which corrected various editorial changes such as typos, omissions, and references to request for information letters sent by the licensee to NRC staff.

The inspectors reviewed procedure SEP-GGN-AMP-01, GGNS Opportunistic Inspections for Aging Management Programs, and confirmed the licensee developed opportunistic inspections for internal surfaces in miscellaneous piping and ducting components. However, the inspectors noted that the licensee had drafted but not completed the work control and maintenance procedures change requests for the opportunistic inspections (procedure EN-MA-106, Planning, and procedure EN-MA-101, Conduct of Maintenance, respectively) at the time of the inspection. Despite the lack of work control procedure enhancements, the inspectors concluded the licensee implemented the program commitments because the licensee completed the overall program procedure for opportunistic inspections and drafted the changes to the implementing procedures.

The inspectors concluded that the licensee appropriately implemented the program and that the licensee had established appropriate implementing procedures for inspection activities. The inspectors confirmed the enhancements to the program and commitment 16 were implemented prior to the period of extended operation.

However, because this is a new program and inspections will begin during the period of extended operation, there were no examination results for the inspectors to review.

The inspectors confirmed the licensee completed the required commitments and implemented the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program.

(26) A.1.27 Masonry Wall Program and Commitment 17 This existing program manages aging effects for each masonry wall within the scope of license renewal. The program includes visual inspection of masonry walls including 10 CFR 50.48-required masonry walls, radiation-shielding masonry walls, and masonry walls with the potential to affect safety-related components. Structural steel components of masonry walls are managed by the structures monitoring program. Masonry walls are visually examined at a frequency selected to ensure there is no loss of intended function between inspections.

Commitment 17 specified:

Enhance the Masonry Wall program to clarify that:

• Parameters monitored or inspected will include monitoring gaps between the supports and masonry walls that could potentially affect wall qualification and

• Detection of aging effects requires masonry walls to be inspected every 5 years unless technical justification is provided to extend the inspection to a period not to exceed 10 years.

The inspectors interviewed engineering personnel, reviewed license renewal implementing documents, drawing, implementing procedures, and industry standards. The inspectors confirmed that procedure EN-DC-150, Condition Monitoring of Maintenance Rule Structures, revision 18, section 7.1.6.b implemented the requirements to inspect masonry walls at 5-year intervals (first bullet) and section 7.2.3 specified the requirement to identify nonconforming conditions, including gaps, do not invalidate the qualification basis or function of the wall (second bullet).

The inspectors confirmed the licensee completed the required commitments and implemented the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program.

(27) A.1.28 Non-EQ Cable Connections Program and Commitment 18 This new one-time program provides reasonable assurance that the intended functions of the metallic parts of electrical cable connections remain consistent with the current licensing basis through the period of extended operation. Cable connections evaluated are those connections susceptible to age-related degradation resulting in increased resistance of connection caused by thermal cycling, ohmic heating, electrical transients, vibration, chemical contamination, corrosion, or oxidation that are not subject to the environmental qualification requirements.

The factors considered for sample selection were application (medium and low voltage, defined as < 35 kV), circuit loading (high loading), connection type, and location (high temperature, high humidity, vibration, etc.). Inspection methods included thermography, contact resistance testing, as well as other quantitative test methods implemented without removing the connection insulation. The sample included various voltages and current in multiple plant locations.

Commitment 18 specified:

• Implement the Non-EQ Cable Connections program as described in LRA section B.1.28.

The inspectors reviewed the aging management program basis document, implementing procedures, documentation of completed inspection activities, corrective action program evaluation of related issues, and commitment closure documents. The inspectors determined that the licensee established implementing procedures that appropriately conducted the required inspections and had adequately implemented this program and associated commitment 18.

Based on the review of the procedures, records and discussion with licensee personnel, the inspectors did not identify any findings or violation of more than minor significance for this aging management program.

(28) A.1.29 Non-EQ Inaccessible Power Cables (400 V to 35 kV) Program and Commitment 19 This existing program managed the aging effects on inaccessible power (400 V to 35kV) cable systems. The program currently includes periodic actions to prevent inaccessible cables from being exposed to significant moisture and testing of the cables at least every six years to provide an indication of the condition of the cable insulation properties. The program included an allowance for adjusting the test frequencies based on test results and operating experience. The specific type of test performed is a proven test for detecting deterioration of the cable insulation. The program also includes inspections for water accumulation in manholes at least once every year (annually).

Commitment 19 specified:

Enhance the Non-EQ Inaccessible Power Cables (400 V to 35 kV) program to include:

• Low-voltage (400V to 2kV) power cables.

• Direct observation that cables are not wetted or submerged, that cables/splices and cable support structures are intact, and that dewatering/drainage systems (i.e., sump pumps) and associated alarms if applicable operate properly.

• Condition-based inspections of manholes that are not automatically dewatered by sump pumps following periods of heavy rain or potentially high-water table conditions, as indicated by river level.

The inspectors reviewed the aging management program basis documents, implementing procedures, completed work orders and surveillances satisfying the testing and examination requirements for the program, plant operating experience, and corrective action documents. The inspectors interviewed plant personnel and had several discussions about the changes to the original commitments.

The inspectors reviewed the following UFSAR changes:

• LBDCR 2023-027 removed the commitment UFSAR description to perform event-driven inspections of manholes not automatically dewatered by a sump pump.

• LBDCR 2024-0004 revised UFSAR section A.1.29 to allow adjusting the frequency for the cable insulation testing when justified based on evaluation of test results and operating experience.

The inspectors questioned the removal of the condition-based inspections of manholes not automatically dewatered and determined this inspection applied to one manhole (SP45MH13) in the scope of license renewal. The inspectors determined from review of the site manhole and trench details that this manhole floor was approximately 20 feet higher than the next closest manhole. Because the manholes directly communicated, water in the highest elevation manhole would gravity drain and cascade to the lower manholes. The site had an annual preventive maintenance task that inspected this manhole, and the licensee explained, if the lower manhole flooded, they would inspect the higher manhole as routine. The inspectors identified no concerns with this change.

The inspectors questioned removing the six-year frequency for cable testing and replacing with an option to justify extending the inspection period because the licensee had not defined a periodicity. The inspectors identified that the Detection of Aging Effects section in the NUREG 1801, Generic Aging Lessons Learned (GALL)

Report, section XI.E3 stated, in part, that for power cables exposed to significant moisture, cable testing should occur at least once every 6 years to provide multiple data points during a 20-year period, which can be used to characterize the degradation rate. The program provided allowances for test frequencies to be adjusted based on test results (including trending of degradation where applicable)and operating experience. Discussions with the licensee noted that the site had not experienced any failures of the license-renewal related inaccessible power cables, and they had installed cables with jacketing designed for use in wet locations and in underground duct installations. The licensee agreed to revise the UFSAR using an LBDCR and establish an eight-year frequency for periodic inspections, when extending the GALL recommended six-year frequency based on no historic failures for the cable population, the quality and type of cable jacketing. The licensee planned to align cable insulation testing with the associated electrical equipment train outages that typically occur every 4 years. The licensee-initiated condition report CR-GGN-2024-04404. The inspectors identified no concerns with this change.

The inspectors confirmed the licensee completed the required commitments and implemented the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program.

(29) A.1.30 Non-EQ Instrumentation Circuits Test Review Program and Commitment 20 This new monitoring program manages the aging of the cables in the neutron monitoring and process radiation monitoring systems. The program assures the intended functions of sensitive, high-voltage, low-signal cables exposed to adverse localized environments caused by heat, radiation and moisture can be maintained consistent with the current licensing basis through the period of extended operation.

Sensitive instrumentation circuit cables and connections are included in the instrumentation loop calibration at the normal calibration frequency, which provides sufficient indication of the need for corrective actions based on acceptance criteria related to instrumentation loop performance. The review of calibration results will be performed once every ten years, with the first review completed before the period of extended operation.

For sensitive instrumentation circuit cables that are disconnected during instrument calibrations, testing using a proven method for detecting deterioration for the insulation (such as insulation resistance tests or time domain reflectometry) will occur at least once every ten years, with the first review completed before the period of extended operation.

Commitment 20 specified:

• Implement the Non-EQ Instrumentation Circuits Test Review program as described in LRA section B.1.30.

The inspectors reviewed the aging management program basis document, implementing procedures, documentation of completed inspection activities, corrective action program evaluation of related issues, and commitment closure documents.

The inspectors confirmed the licensee completed the required commitments and implemented the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program.

(30) A.1.31 Non-EQ Insulated Cables and Connections Program and Commitment 21 This new program manages the effects of aging of insulated cables and connections exposed to adverse localized environments caused by heat, radiation and moisture and to ensure their function can be maintained consistent with the current licensing basis through the period of extended operation. A representative sample will be visually inspected for cable and connection jacket surface anomalies such as embrittlement, discoloration, cracking, melting, swelling, or surface contamination.

The program sample consists of all accessible cables and connections in localized adverse environments, and the sample is selected to represent, with reasonable assurance, all cables and connections in the adverse localized environment. This program will perform the visual inspections at least once every ten years, with the first inspection completed prior to the period of extended operation.

Commitment 21 specified:

• Implement the Non-EQ Insulated Cables and Connections program as described in LRA section B.1.31.

The inspectors reviewed the aging management program basis document, implementing procedures, documentation of completed inspection activities, corrective action program evaluation of related issues, and commitment closure documents.

The inspectors confirmed the licensee completed the required commitments and implemented the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program.

(31) A.1.32 Oil Analysis Program and Commitment 22 This existing program ensures that loss of material and reduction of heat transfer are not occurring by maintaining the quality of lubricating oil. The licensee uses analysis and periodic sampling to detect evidence of abnormal wear rates, moisture contamination, excessive corrosion, and oil degradation. The program ensures that contaminants (primarily water and particulates) remain within acceptable limits.

Commitment 22 specified:

• Enhance the Oil Analysis program to provide a formalized analysis technique for particulate counting.

The inspectors reviewed the aging management program basis document, implementing procedures, completed program activities, and held discussions with the site program owner, fleet program owner, and system engineer. Specifically, the inspectors verified the dew point data, particulates data for oil samples, and trends.

The licensee removed the commitments to evaluate liquids in the generator oil and generator primary water system using LBDCR 2021-003. The licensee made this change because they reviewed liquids as part of a leak detection system, and the alarm response procedure requires action to immediately drain any liquids collected in that system. Because the licensee already monitors the oil in the generator seal oil system and actions taken to drain water, the inspectors did not identify any concerns with this change.

The inspectors verified procedure SEP-LUB-GGN-002, GGN Oil Analysis Program, section 6.4, included the formal analysis for particulate counting, as specified as ISO 4406 or ISO 11171, and sent to a vendor on the qualified supplier list or performed by the licensee.

The inspectors confirmed the licensee completed the required commitments and implemented the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program.

(32) A.1.33 One-Time Inspection Program and Commitment 23 This new program verifies that aging management programs are effective and associated inspection methods can confirm that aging effects are insignificant.

Commitment 23 specified:

• Implement the One-Time Inspection Program as described in LRA section B.1.33 The licensee had not completed their one-time inspection samples at the time of this onsite inspection; therefore, the inspectors will review this program in a future inspection.

This program and associated commitment remain open.

(33) A.1.34 One-Time Inspection - Small-Bore Piping Program and Commitment 24 This new one-time program manages cracking of ASME Code Class 1 piping less than four inches nominal pipe size (NPS 4) and greater than or equal to one-inch nominal pipe size (NPS 1). This program included ultrasonic testing examinations conducted in accordance with ASME Section XI with acceptance criteria from paragraph IWB-3000 for butt welds, with at least 25 butt welds included in the examination population. The program also included volumetric examination of socket welds to identify potential cracking. The licensee selected eight small-bore Class 1 socket welds for examination, which represented 10 percent of the population. The licensee used the ASME Code edition consistent with the provisions of 10 CFR 50.55a during the 10-year period prior to the period of extended operation (fourth interval).

Commitment 24 specified:

• Implement the One-Time Inspection - Small Bore Piping program as described in LRA section B.1.34.

The inspectors reviewed the aging management program basis document, implementing procedures, completed inspection activities, corrective action program evaluation of related issues, and commitment closure documents.

The inspectors confirmed the licensee completed the required commitments and implemented the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program.

(34) A.1.35 Periodic Surveillance and Preventive Maintenance Program and Commitment 25 This existing program provides timely detection of aging effects through periodic testing and inspections primarily conducted during scheduled periodic maintenance activities. The licensee established inspection intervals to provide for timely detection of degradation. Inspection intervals are dependent on the component material and environment and take into consideration industry and plant-specific operating experience and manufacturers recommendations.

Commitment 25 specified:

• Implement and maintain the Periodic Surveillance and Preventive Maintenance program as described in LRA section B.1.35.

• Revise program guidance documents as necessary to include all activities, except for internal coating integrity inspections (see UFSAR section A.1.45).

Implement a coating integrity program consistent with the recommendations of LR-ISG-2013-01 to manage the effects of aging on internal coatings.

The inspectors reviewed the aging management program basis document, implementing procedures, and documentation of completed program activities and held discussions with site personnel and fleet program owners.

The inspectors reviewed the following UFSAR changes:

• LBDCR 2024-020 removed pressure relief piping waterline inspections because the licensee identified that they were inaccessible. The licensee demonstrated that they would inspect 41 percent of the carbon steel components in the same material/environment, which provides an appropriate sample.

• LBDCR 2022-053 revised the inspection frequency to once per 10 years consistent with the changes proposed in LR-ISG-2012-02, Aging Management of Internal Surfaces, Fire Water Systems, Atmospheric Storage Tanks, and Corrosion Under Insulation. Specifically, section XI.M38 reflects a 10-year frequency for managing the aging of internal surfaces.

• LBDCR 2023-045 removed the requirement to conduct visual or other NDE inspections of a representative sample of internal surfaces of components in the control rod drive, circulating water, and floor and equipment drains systems. The licensee determined that Internal Surfaces in Miscellaneous Piping and Ducting Components Program provided the same aging management reviews for the circulating water system and floor equipment drains for raw water and wastewater environments, respectively. The licensee eliminated the control rod drive system inspections because they had replaced components subject to erosion.

• LBDCR 2022-077 removed the fuel pool gate seal inspections because the licensee periodically replaces them.

The inspectors did not identify issues with the above changes.

The inspectors confirmed the licensee completed the required commitments and implemented the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program.

(35) A.1.36 Protective Coating Monitoring and Maintenance Program and Commitment 26 This existing program manages aging of Service Level I coatings inside the containment building where failure could adversely affect post-accident fluid systems that could impair safe shutdown. The program includes visual inspections of surfaces for missing or degraded coatings, including blistering, discoloration, flaking (scaling), peeling, and other signs of distress.

Commitment 26 specified:

Enhance the Protective Coating Monitoring and Maintenance program to:

• Inspect the coatings in accordance with ASTM D5163-08, Standard Guide for Establishing a Program for Condition Assessment of Coating Service Level I Coating Systems in Nuclear Power Plants.

• Inspect coatings near emergency core cooling system sumps or screens.

• Include the acceptance criteria specified in ASTM D5163-08.

The inspectors reviewed the aging management program basis document, implementing procedures, and documentation of completed program activities and held discussions with the site. The inspectors reviewed the refueling outage 23 and refueling outage 24 containment and drywell coatings inspection reports, which included several photographs of the conditions of the coatings inside the containment and the drywell. The inspectors did not identify any significant coating issues in these areas.

The inspectors determined that procedure EN-DC-220, Safety-Related Coatings, section 5.7 listed several ASTM standards related to coatings that the licensee had not identified in their license renewal commitments. The standards included ASTM D661, Standard Test Method for Evaluating Degree of Cracking of Exterior Paints and ASTM D772, Standard Test Method for Evaluating Degree of Flaking (Scaling) of Exterior Paints. The licensee could not explain the purpose or need for these standards in addition ASTM D5163-08. The licensee-initiated condition report CR-GGN-2024-04446 to resolve the concern. The inspectors determined that the licensee planned to resolve the applicable standards prior to entering the period of extended operation.

The inspectors reviewed the aging management program basis document, implementing procedures, and documentation of completed program activities and held discussions with site personnel.

The inspectors confirmed the licensee completed the required commitments and implemented the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program.

(36) A.1.37 Reactor Head Closure Studs Program This existing program manages cracking and loss of material for reactor head closure stud bolting using in-service inspection and preventive measures. The licensee performs visual examinations to identify cracking and loss of material in the connecting studs. Surface or volumetric examinations of the reactor vessel head closure studs detect and size cracks in these connections.

The inspectors reviewed the aging management program basis document, implementing procedures, and documentation of completed program activities and held discussions with site personnel.

The inspectors confirmed the licensee implemented the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program.

(37) A.1.38 Reactor Vessel Surveillance Program and Commitment 27 This existing program manages reduction of fracture toughness for reactor vessel beltline materials using material data and dosimetry. The program includes all reactor vessel beltline materials as defined by 10 CFR 50 Appendix G, section II.F, and complies with 10CFR50, Appendix H for vessel material surveillance. The NRC staff has approved an integrated surveillance program for the period of extended operation (ISP(E)), based on BWRVIP-86, Updated BWR Integrated Surveillance Program (ISP) Implementation Plan, revision 1.

Commitment 27 specified:

• Ensure that the additional requirements of the ISP(E) specified in BWRVIP-86, revision 1, including the conditions of the final NRC safety evaluation for BWRVIP-116 Integrated Surveillance Program (ISP)

Implementation for License Renewal, incorporated in BWRVIP-86, Revision 1 will be addressed before the period of extended operation; and

• Ensure that new fluence projections through the period of extended operation and the latest vessel beltline adjusted reference temperature tables are provided to the BWRVIP prior to the period of extended operation.

The inspectors reviewed the license renewal implementing document, engineering documents, drawings, implementing procedures, and industry standards. The inspectors interviewed engineering personnel and license renewal program personnel. The licensee participates in the integrated surveillance program for monitoring their reactor vessel coupons. This program uses assigned host plants to represent the embrittlement and coupon testing for other plants in the BWR fleet.

The host plant for Grand Gulf is Perry nuclear station. The last coupon removed had occurred in 2013 and the next planned testing will occur in 2039 as specified in BWRVIP-135, Integrated Surveillance Program (ISP) Data Source Book and Plant Evaluations.

The inspectors determined that the licensee used procedure SEP-FTP-GGNS, Reactor Vessel Fracture Toughness and Surveillance Material Testing at Grand Gulf Nuclear Station, to implement the program related to their reactor vessel coupons. The licensee removed one capsule in cycle 1 and maintained all remaining capsules in their vessel in the event they are needed by the integrated surveillance program. The inspectors confirmed that the licensee had implemented the guidance of BWRVIP-86, Revision 1-A: Updated BWR Integrated Surveillance Program (ISP)

Implementation Plan, that had superseded the standards in the commitment and included data throughout the period of extended operation, as required by the commitment 1. The inspectors identified that the licensee had not completed commitment 2 and had a documentation error as described in observation Reactor Vessel Surveillance Program Results in the Inspection Results section of this report.

The inspectors confirmed the licensee completed the required commitments and implemented the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program.

(38) A.1.39 RG 1.127, "Inspection of Water -Control Structures Associated with Nuclear Power Plants Program" and Commitment 28 This existing program manages deterioration and degradation of water-control structures caused by extreme environmental conditions, and the effects of natural phenomena. The program includes inspection and surveillance for slopes, canals, and other raw water-control structures associated with emergency cooling water systems or flood protection. The water-control structures included the service water cooling towers and basins and the culverts developed for flood control.

Commitment 28 specified:

Enhance the RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plant program to:

• Clarify monitoring of accessible structures on a frequency not to exceed 5 years.

• Periodically sample, test, and analyze ground water chemistry for pH, chlorides, and sulfates at least every 5 years.

• Include quantitative acceptance criteria for evaluation and acceptance based on the guidance provided in ACI 349.3R, Evaluation of Existing Nuclear Safety-Related Concrete Structures.

The inspectors reviewed examination reports, work orders, procedures, drawings, completed work activities, completed inspections, and drawings. The inspectors interviewed license renewal program personnel and the program owner. The inspectors verified that procedure EN-DC-150, revision 18, included several of the commitments described above; specifically:

(1) section 7.1.6.c specified a 5-year frequency for water-control structures

(2) Attachment 18, Grand Gulf Maintenance Rule Structures, note 11 specified that ground water would be periodically sampled every 5-years for pH, chlorides and sulfates, and

(3) section 7.2.1, generally, included the quantitative acceptance criteria of ACI 349.3R for acceptance criteria.

However, the inspectors identified a concern with meeting the quantitative criteria in ACI.349.3R (refer to section A.1.42 of this report).

The inspectors determined from review of completed surveillance and test activities for the culverts and the service water basins that the licensee maintained the culverts within design limits, that the site had nonaggressive ground water environment of pH, chlorides and sulfates, and the licensee routinely inspected the service water basins to evaluate supports and the collection of silt. Inspections of the basins identified an increasing number of coating repairs and increasing degradation of the cathodic protection system inside the basins. The licensee commissioned a study to provide options for upgrading the cathodic protection system in the basin.

The final report was under development. The final report was under development.

LCM-19-00154 was the authorization for the study.

The inspectors confirmed the licensee completed the required commitments and implemented the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program.

(39) A.1.40 Selective Leaching Program and Commitment 29 This new program includes one-time visual inspections of selected components coupled with hardness measurement or other mechanical examination techniques to determine whether selective leaching causes a loss of material and to determine whether the licensee will need to establish a periodic program to inspect for selective leaching during the period of extended operation.

Commitment 29 specified:

• Implement the Selective Leaching program as described in LRA section B.1.40.

The inspectors reviewed inspection results, engineering reports, work activities, and implementing procedures. The inspectors interviewed license renewal project personnel and the program owner. The inspectors determined that the licensee had destructively tested the fire protection jockey pump discharge check valve and both the trains A and B diesel driven test isolation valves. The tests demonstrated that fire protection system components made of gray cast iron had experienced selective leaching.

The inspectors determined that the licensee used the aging management program guidelines in NUREG-2191, section XI.M33, Selective Leaching, for implementing the one-time selective leaching sample sizes and for developing the periodic program that will be implemented during the period of extended operation.

Specifically, for the one-time sample sizes the licensee added a sample of ductile iron piping and reduced the number of samples for closed treated water systems from 20 percent or a maximum of 25 components to a sample of 3 percent or a maximum of 10 components. For the periodic program in the period of extended operation, the licensee provided guidelines for evaluating samples for selective leaching as well as planning the required number of destructive tests.

The inspectors confirmed the licensee completed the required commitments and implemented the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussion with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program.

(40) A.1.41 Service Water Integrity Program and Commitment 35 This existing program manages loss of material and fouling in open-cycle cooling water systems as described in the GGNS response to NRC GL 89-13, Service Water System Problems Affecting Safety-Related Equipment. The program also includes inspections for loss of material caused by erosion. In addition, the program includes inspections of coatings for submerged piping in the standby service water basin.

Commitment 35 specified:

• Revise Service Water Integrity program documents to include inspections for loss of material caused by erosion.

The inspectors reviewed examination reports, work orders, procedures, drawings, completed work activities, completed inspections, and drawings. The inspectors interviewed license renewal program personnel and the program owner. The inspectors reviewed open cycle cooling water inspection activities that included loop flow tests, heat exchanger inspections including photographs, heat exchanger performance testing, eddy current testing, tube plugging, microbiologically induced corrosion inspections, and corrective actions. The inspectors determined that the licensee appropriately implemented their open -cycle cooling water inspection and assessment activities.

The inspectors determined that procedure EN-DC-184, NRC Generic Letter 89-13 Service Water Program, described that erosion would be evaluated as a condition in the service water system. The inspectors determined that the licensee identified two areas of service water susceptible to erosion in engineering report M-EC81847-N1-8.0-001, GGNS Erosion Susceptibility Evaluation (ESE).

The inspectors confirmed the licensee completed the required commitments and implemented the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program.

(41) A.1.42 Structures Monitoring Program and Commitment 30 This existing program manages the effects of aging on structures and structural components, including structural bolting, within the scope of license renewal. The program was based on guidance in Regulatory Guide 1.160, Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, revision 2, and NUMARC 93-01, Industry Guidelines for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants, revision 2, to satisfy the requirement of 10 CFR 50.65.

Commitment 30 specified:

Enhance the Structures Monitoring program to:

• Clarify that the scope includes the following:

(a) Structures and structural components listed in the UFSAR supplement;

(b) In scope structural components listed in the UFSAR;

(c) The term significant degradation includes degradation that could lead to loss of structural integrity; and

(d) Guidance to perform periodic sampling, testing, and analysis of ground water chemistry for pH, chlorides, and sulfates at least every 5 years.

• Clarify that parameters monitored or inspected include:

(a) Inspection for missing nuts for structural connections;

(b) Monitoring sliding/bearing surfaces for loss of material caused by wear or corrosion, debris, or dirt.

Enhance the program to include monitoring elastomeric vibration isolators and structural sealants for cracking, loss of material, and hardening; and

(c) Periodically inspect the leak chase system associated with the upper containment and spent fuel pools to ensure the tell tales are free of significant blockage. Also inspect concrete surfaces for degradation where leakage has been observed.

• Clarify that detection of aging effects will:

(a) Include augmented inspections of vibration isolators by feel or touch to detect hardening;

(b) Require structural inspections every 5 years;

(c) Require direct visual examinations to be within 24 inches of the surface to be examined and at an angle of not less than 300 to the surface. Mirrors may be used to improve the angle of vision and accessibility in constricted areas;

(d) Specify that remote visual examination may be substituted for direct examination. Optical aids such as telescopes, borescopes, fiber optics, cameras, or other suitable instruments may be used provided such systems have an equivalent resolution capability; and

(e) Include visual examinations of roof membranes, and seals and gaskets (doors, manways, and hatches) with physical manipulation of at least 10 percent of available surface area.

• Prescribe acceptance criteria based on information provided in industry codes, standards, and guidelines including NEI 96-03, ACI 201.1R-92, ANSI/ASCE 11-99 and ACI 349.3R-96. Industry and plant-specific operating experience will also be considered in the development of the acceptance criteria.

The inspectors reviewed examination reports, procedures, drawings, completed work activities, completed inspections, and drawings. The inspectors interviewed license renewal program personnel and the program owner. The inspectors determined that the licensee included the commitments above in procedure EN-DC-150 and completed two structural inspections of the site in the last six years.

The inspectors identified several issues associated with procedure EN-DC-150 related to implementing the commitments and related to documenting inspection, which are documented in observation Structures Monitoring Program Observations in the Inspection Results section of this report.

The inspectors confirmed the licensee completed the required commitments and implemented the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program.

(42) A.1.43 Water Chemistry Control - BWR Program This existing program manages loss of material, cracking, and fouling in components exposed to a treated water environment by maintaining the concentration of contaminants below system specific limits based on BWRVIP-190, BWR Water Chemistry Guidelines - Mandatory, Needed, and Good Practice Guidance.

The inspectors reviewed procedures, industry standards, engineering reports, work orders, and chemistry trends. The licensee implemented industry guidelines for online noble metal chemistry, hydrogen water chemistry, and oxygen addition to the primary water to limit intergranular stress corrosion cracking and other stress corrosion cracking mechanisms for the reactor vessel internals.

The inspectors determined that the Grand Gulf Strategic Water Chemistry Plan described actions to implement the chemistry requirements of BWRVIP-190.

Procedure 06-CH-1B21-O-0002, Reactor Coolant Routine Chemistry, provides the guidance for complying with the reactor water chemistry limits related to chlorides, pH, and conductivity. The inspectors verified during interviews and review of primary chemistry parameters that the licensee effectively implemented their noble metal chemical injections, maintained their chlorides, sulfates and hydrogen concentrations within the required limits specified in BWRVIP-190.

Because the licensee maintained these parameters within the specifications, the licensee met the requirements in BWRVIP-62, Volume 1: Implementation Criteria for Inspection Relief for BWR Internal Components with Hydrogen Injection, that allowed them relief from some inspections. The following documents described the inspections that did not have to be conducted: BWRVIP-41-A, BWR Jet Pump Assembly Inspection and Flaw Evaluation Guidelines, BWRVIP-75-A, Technical Basis for Revisions to Generic Letter 88-01 Inspection Schedules, BWRVIP-138-A, Updated Jet Pump Beam Inspection and Flaw Evaluation Guidelines, and BWRVIP-180, Access Hole Cover Inspection and Flaw Evaluation Guidelines. The inspectors determined that the licensee effectively implemented BWRVIP-257, BWR Radiolysis Model Development, that provided the means to monitor the electrochemical potential in the primary water, which protected the reactor vessel internals from intergranular stress corrosion cracking.

The inspectors confirmed the licensee implemented the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program.

(43) A.1.44 Water Chemistry Control - Closed Treated Water Systems Program and Commitment 31 This existing program manages loss of material, cracking, and fouling in components exposed to a treated water environment, through monitoring and control of water chemistry, as well as visual inspections. The systems included in the scope of this program include:

• Drywell chilled water

• Plant chilled water

• Diesel generator cooling water subsystem for Division I and II standby diesel generators

• Diesel engine jacket water for engine-driven fire water pump

• Diesel generator cooling water subsystem for Division III HPCS diesel generator

• Turbine building cooling water

• Component cooling water Commitment 31 specified:

• Enhance the Water Chemistry Control - Closed Treated Water program to:

• Provide a corrosion inhibitor for the engine-driven fire water pump diesel jacket water.

• Periodically flush the engine jacket water and clean the heat exchanger tubes for the engine-driven fire water pump diesel.

• Test the engine jacket water for the engine-driven fire water pump diesels annually.

• Revise chemistry procedures to align the water chemistry control parameter limits with those of EPRI 1007820, Closed Cooling Water Chemistry Guideline.

• Conduct inspections for corrosion or cracking with qualified personnel whenever a boundary is opened.

• Inspect a representative sample of piping and components with the highest likelihood of corrosion or cracking at a frequency of once every 10 years for the included systems. A representative sample is 20 percent of the same material/environment population with a maximum of 25 components. The inspection methods will be in accordance with applicable ASME Code requirements, industry standards, or other plant-specific inspection and personnel qualification procedures that ensure the capability of detecting corrosion or cracking.

The inspectors reviewed procedures, industry standards, engineering reports, work orders, and chemistry trends. The inspectors determined that procedure 07-S-24-P64-C003-2, Preventive Maintenance Instruction Firewater Pump Diesel Fuel Filter Change and Related Maintenance, revision 6, required that the licensee replace the coolant, jacket water and flush the heat exchanger annually.

The inspectors did not have any concerns with the licensee decision to change their commitment from testing the engine jacket water to changing the engine jacket water annually. The licensee met bullets 1, 2, and 3 through the changes to procedure 07-S-24-P64-C003-2. The inspectors identified that the licensee appropriately changed bullet 3 using LBDCR 2021-082.

The inspectors determined procedure 08-S-03-10, Chemistry Sampling Program, attachment 4, Closed Loops, provided Table 8 that identified the chemical ranges and limits for the closed cooling water systems, which met the EPRI Closed Cooling Water Chemistry Guideline as described in bullet 4.

The inspectors determined the licensee developed procedure SEP-AMP-GGN-001, GGNS Opportunistic Inspections for Aging Management Programs, to ensure that the internals of the in-scope closed treated water continue to be inspected periodically as specified in bullets 5 and 6 for the included systems.

The inspectors determined that chemistry personnel perform routine analysis and trending of the parameters for the closed treated water systems. The licensee identified the commitments in the preventive maintenance title or cover sheet for the in-scope components. The inspectors reviewed the trends of the key parameters for the various closed cooling water systems and did not identify any concerns.

The inspectors confirmed the licensee completed the required commitments and implemented the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program.

(44) A.1.45 Coating Integrity Program This new program manages the effects of aging through periodic visual inspections of coatings/linings applied to the internal surfaces of components where loss of coating or lining integrity could impact the intended functions of the components. For tanks and heat exchangers, all accessible surfaces are inspected. Piping inspections are sampling-based, except for the cementitious lined fire water piping.

For coated/lined surfaces determined to not meet the acceptance criteria, physical testing is performed where physically possible (i.e., sufficient room to conduct testing) in conjunction with repair or replacement of the coating/lining.

The licensee created this new program to meet the guidance in LR-ISG-2013-01, and to align with the approved programs at Waterford 3 Steam Electric Station and Riverbend Station license renewal program activities. When creating this new program, the licensee removed the coatings integrity requirements from the service water integrity program as originally described in section A.1.41 of the UFSAR and commitment 35 and from the periodic surveillance and preventive maintenance program as originally described in section A.1.35 of the UFSAR and commitment 25.

The inspectors determined that the licensee documented the commitments listed in LR-ISG-2013-01.

Commitment 25 specified:

• During the 10-year period prior to the period of extended operation, perform visual inspections of coated internal surfaces. Perform subsequent coating inspections based on inspection results as follows.

i.

If no peeling, delamination, blisters, or rusting are observed, and any cracking and flaking is considered acceptable, perform subsequent inspections at least once every six years. If no indications are found and the redundant train has the same coating with no turbulent flow, then do not inspect the redundant train during that interval.

ii. If the inspection results do not meet (i), and a coating specialist has determined no need for remediation, then conduct subsequent inspections every other refueling outage interval.

iii. if the inspection results do not meet

(i) and a coating specialist determines remediation is required, then the coated components can be returned to service if the following actions are performed:

(1) remove blisters not completely surrounded by coating bonded to the substrate,

(2) remove any delaminated or peeled coating,

(3) ensure the exposed underlying coating is securely bonded at a minimum of three adjacent locations,

(4) feather the outer most coating and determine the coating below to be securely bonded,

(5) ultrasonic testing to ensure the component meets the minimum wall thickness requirements,

(6) an evaluation to ensure no downstream blockage, and

(7) a follow-up inspection within two years and every two years until repairing, replacing, or removing the coating.

• During the 10-year period prior to the period of extended operation, visual inspections will be performed. A qualified coatings specialist determines which of the following methods should be used to assess the condition of the coating when the visual examination identifies conditions such as cracking, peeling, blisters, delamination, rust or flaking by:

(a) Lightly tapping and scraping the coating to determine the coating integrity;

(b) Wet sponge testing or dry film testing to identify holidays in the coating;

(c) Adhesion testing in accordance with RG 1.54 at a minimum of three locations adjacent to the defective area; and

(d) Ultrasonic testing to determine if the components wall thickness meets the minimum wall thickness criteria.

• Inspect all accessible internal coated surfaces of applicable tanks and heat exchangers. For areas not readily accessible for direct inspection, such as small pipelines, heat exchangers and other equipment, consider using remote or robotic inspection tools. For piping, inspections will cover 50 percent of accessible coated piping within the system or a minimum of 73 locations of 360 degrees of one linear foot for each combination of type of coating, material the coating is protecting, and environment. Inspection locations of coated piping will be based on coating degradation susceptibility, operating experience, vendor recommendation, and safety significance.

• Individuals performing coating inspections are certified to ANSI N45.2.6, Qualifications of Inspection, Examination, and Testing Personnel for Nuclear Power Plants., and shall be required to review at least two previous inspection reports when available. A nuclear coatings subject matter expert qualified in accordance with ASTM D 7108-05, Standard Guide for Establishing Qualifications for a Nuclear Coatings Specialist, will evaluate inspection findings and prepare post-inspection reports.

• Coating inspection reports will include lists of locations identified with coating degradation including, where possible, photographs indexed to inspection location, and a prioritization of the repair areas into areas that must be repaired before returning the system to service and areas where coating repair can be postponed to a subsequent inspection or repair opportunity.

• Loss of coating integrity acceptance criteria are:

(a) Indications of peeling and delamination are not acceptable;

(b) Limit blisters to a few intact small blisters that are surrounded by sound coating bonded to the substrate. Blister size and frequency should not be increasing between inspections;

(c) Evaluate indications such as cracking, flaking, and rusting by a qualified coatings specialist;

(d) Minor cracking and spalling of cementitious coatings/linings is acceptable provided there is no evidence that the coating is debonding from the base material;

(e) As applicable, wall thickness measurements, projected to the next inspection, meet design minimum wall requirements; and

(f) Adhesion testing results, when conducted, meet or exceed the degree of adhesion recommended by design requirements.

• When exposed base metal visual inspections identifies corrosion, the results will be entered into the corrective action program. An evaluation demonstrates the component remains acceptable for continued service. As necessary, perform a volumetric examination to ensure sufficient wall thickness so that the component remains capable of performing its intended function. If repair or replacement of the coating is postponed, the evaluation will consider the minimum wall thickness requirements and the rate of corrosion and confirm the component remains acceptable for continued service until the next inspection or repair opportunity, which will be within two years.

The inspectors reviewed procedures, completed inspections and examinations, engineering reports, and the license renewal implementing document. The inspectors interviewed license renewal project personnel and corporate program engineers. The licensee developed procedure EN-DC-225, Internal Coatings Integrity Program, that implemented the detailed inspection requirements described in LR-ISG-2013-01 and the commitments as described above. From review of the completed coatings inspections, the inspectors determined that the licensee would be performing their coatings inspections on 6-year intervals as allowed by their commitments, except for the diesel fuel oil storage tanks and the diesel generator day tanks that align with the 10-year fuel oil storage tank inspections required by the fuel oil aging management program.

The inspectors confirmed that the licensee had, generally, properly

(1) transferred the commitments related to coatings integrity from the periodic surveillance and preventive maintenance program and the service water integrity program to this new program,

(2) revised UFSAR section A.1.35 and commitment 25 to refer to section A.1.45 and LR-ISG-2013-01, and

(3) revised section A.1.41 to eliminate any discussion of coatings in commitment 35. The inspectors identified no concerns with licensing basis document change request 2020-089 that compared their original coating license commitments to the requirements of LR-ISG-2013-01.

The inspectors determined that the licensee made a change to inspect the cementitious lined fire water piping opportunistically instead of periodically every 5 years with a qualified individual using a LBDCR 2023-013 and an associated process applicability determination. The inspectors determined that the licensee had not processed this change appropriately and described the details in observation Inadequate Documentation for License Basis Change to Coatings Inspections in the Inspection Results section of this report. The licensee-initiated condition report CR-GGN-2024-04581.

The inspectors confirmed the licensee completed the required commitments and implemented the procedures associated with this program prior to the period of extended operation.

Based on the review of the procedures, records, and discussions with licensee personnel, the inspectors did not identify any findings or violations of more than minor significance for this aging management program.

INSPECTION RESULTS

Observation: Inadequate Documentation for License Basis Change to Coatings Inspections 71003 The inspectors reviewed LBDCR 2013-013, which involved a change to the facility as described in the UFSAR. Specifically, LBDCR 2013-013, made under 10 CFR 50.59, involved a change to the inspection frequency for cementitious lined fire water piping from every 5 years to opportunistic. In the process applicability determination (the licensee's method for performing 10 CFR 50.59 screens), the licensee made a qualitative argument stating that they performed flow testing and monitored pressure; however, the licensee did not provide technical details related to the flow tests; consequently, the inspectors determined that the licensee had not processed this change appropriately. Specifically, Grand Gulf Nuclear Station based their change on the NRC approval of similar conditions at Fermi, as documented in the Fermi license renewal application and associated safety evaluation report (Safety Evaluation Report Related to the License Renewal of Fermi 2) (ML16190A241)section 3.0.3.2.24, exception 1. The NRC approved the change at Fermi based on detailed information related to flow testing as documented, "The staff noted that as stated in the staffs evaluation of Exception 3 associated with the Fire Water System Program, SER section 3.0.3.2.10, the applicant conducts main header flow testing every 3 years, 64 hose stations are tested every 3 years to verify no flow blockage, and multiple main drain tests are conducted every 18 months. The fire water system testing is conducted in three different buildings."

The inspectors determined LBDCR 2013-013 did not describe the quantity or types of flow testing performed at Grand Gulf Nuclear Station, nor referenced the constraints and limitations described in the Fermi safety evaluation report. However, the inspectors determined that Grand Gulf performs the following flow tests:

(1) main header loop testing every 3 years as required by technical requirements manual surveillance requirement 6.2.2.13. Seven loops that supply the standpipe system are tested to verify the water supply provides the design pressure and required flow;

(2) annual flow testing demonstrates the absence of blockage by performing a flow check on hydrants in accordance with technical requirements manual surveillance requirement 6.2.7.5;

(3) tests 74 hose stations throughout the plant as specified in technical requirements manual surveillance requirement 6.2.6.4; and

(4) quarterly and annual drain testing to check for blockage to deluge and sprinkler systems in the diesel generator, auxiliary and control buildings.

From review of the number and type of flow tests performed at Grand Gulf, the inspectors determined that the licensee did conduct similar number and type of tests described in the Fermi safety evaluation report, but LBDCR 2013-013 failed to include those details. The inspectors concluded this change involved poor documentation and the licensee change would not have required approval by the NRC; consequently, the inadequate technical justification resulted in a minor violation of 10 CFR 50.59(d)(1).

Observation: Structures Monitoring Program Observations 71003 The inspectors identified concerns with how the licensee documented the 5-year inspections and how the licensee included the commitments and guidance in procedure EN-DC-150, as described below:

Procedure EN-DC-150, attachment 18, Grand Gulf Maintenance Rule Structures, provided guidance for inspecting some structures contrary to the commitment to inspect on a 5-year frequency. Specifically, Table 1, Grand Gulf Specific Job Plan or Model Work Order Number and PMRQ/PM Numbers, specifically identified areas to be inspected on a 10-year frequency because they were in high radiation areas or required coordination to remove heavy floor plugs. The inspectors did not consider either of these sufficient justification for not performing the inspections during the period of extended operation on a 5-year frequency.

The licensee documented this deficiency in condition report CR-GGN-2024-04392. The inspectors identified that this may also be a concern for structures considered low risk if they are also license renewal structures. The inspectors determined that the licensee planned to correct this to be a 5-year frequency before they enter the period of extended operation.

Given that the license has yet to enter the period of extended operation, the inspectors determined that this did not represent a violation of regulatory requirements.

Procedure EN-DC-150, section 5.2, item 1 indicates that certain areas need not be inspected because of characteristics such as high radiation areas, operationally sensitive areas or items that involve an extraordinary expenditure of plant resources. The inspectors indicated that some of the listed characteristics would be inadequate justification to forego inspection of the associated structures in those areas.

Procedure EN-DC-150, section 7.2.1 specifies that, The inspection and interpretation criteria of ACI 349.3R, Evaluation of Existing Nuclear Safety-Related Concrete Structures, and ACI 201.1R, Guide for Making a Condition Survey of Concrete in Service, may be used as a guide during Maintenance Rule Walk down activities associated with concrete inspections/evaluations. The inspectors determined that the commitment required adding the quantitative guidance contained in ACI 349.3R; consequently, the inspectors determined that the use of may should have been a shall or a will so that the use of the guidance could not be considered optional during future inspections. Given that the license has yet to enter the period of extended operation, the inspectors determined that this did not represent a violation of regulatory requirements.

Procedure EN-DC-150, Attachment 2, Pre-Screen/Acceptance Criteria, in the general guidance section refers to the criteria in another attachment that is qualitative and expected individuals to recognize to refer to the quantitative guidance located in section 5.1 of ACI 349.3R for acceptable indications. The inspectors found this connection weak. Particularly, since the quantitative screening criteria for indications that must be dispositioned are listed in the next step and refers to the same attachment with qualitative descriptions.

Observation: Condensate Storage Tank Observations 71003 The inspectors walked down the exterior of the condensate storage tank and identified issues associated with the condition of the tank and the implementing the commitment.

The inspectors observed that the condensate storage tank had visible rust stains, a deformed top, and caulking that appeared deteriorated and cracked. The inspectors found the plastic deformation of the condensate storage tank originated during pre-operational testing during plant startup; however, during the baseline aging management inspections, the licensee identified that subsequent damage had occurred and attributed the additional damage to a valve failure and over-pressurization of the tank. The inspectors reviewed calculation EC-0086535 "Fitness for Service Evaluation for Condensate Storage Tank, which evaluated the condensate storage tank damage, and did not identify any issues with the conclusion that the damage to the condensate storage tank did not affect its function.

The licensee used the NRC guidance in LR-ISG-2012-02 to perform a one-time external inspection of the condensate storage tank, instead of periodic external inspections.

Specifically, the licensee utilized note 10 of LR-ISG-2012-02, which states:

A one-time inspection conducted in accordance with the One-Time Inspection Program may be conducted in lieu of periodic instructions if an evaluation conducted before the PEO and during each 10-year period during the PEO demonstrates the absence of environmental impacts in the vicinity of the plant because of:

(a) the plant being located within approximately 5 miles of a saltwater coastline. or within 1/2 mile of a highway that is treated with salt in the wintertime or in areas in which the soil contains more than trace amounts of chlorides,

(b) cooling towers where the water is treated with chlorine or chlorine compounds, and

(c) chloride contamination from other agricultural or industrial sources. The evaluation should include soil sampling in the vicinity of the tank (because soil results indicate atmospheric fallout accumulating in the soil and potentially affecting tank surfaces) and sampling of residue on the top and sides of the tank to ensure that chlorides or other deleterious compounds are not present at sufficient levels to cause pitting corrosion, crevice corrosion, or cracking.

The inspectors determined that the site has cooling towers treated with chlorine compounds near the condensate storage tank; therefore, section

(b) above applies. However, the inspectors reviewed the soil and tank surface swab sample results that demonstrated very low detectable levels of chlorine, therefore the inspectors identified no concerns with the licensees conclusion that chloride residues would not adversely affect the condensate storage tank.

During a walkdown of the condensate storage tank, inspectors also observed caulking that appeared deteriorated, separated from the vertical surface, and cracked. Although the aging management program required inspection and physical manipulation of the caulking, the last walkdown performed by the licensee failed to identify the cracked and degraded caulking.

Additionally, the implementing procedure 17-S-01-18, Aboveground Metallic Tanks Program Inspections, revision 0 and lacked specifics on acceptable conditions for the caulking. In response to this issue, the licensee generated condition report CR-GGNS-2024-04214. The inspectors reviewed the licensees assessment of the degraded caulking, and determined the condensate storage tank would continue to fulfil its function based on the recent NDE examinations, visual inspections, and engineering assessments. Because the tank is not safety related, and the plant had not entered the period of extended operation, the inspectors determined there was not a violation of regulatory requirements.

Observation: Inadequate Justification for Licensing Basis Change to AMP Inspection Frequencies 71003 The inspectors reviewed LBDCR 2022-0083, a change that revised UFSAR section A.1 to apply a grace period to the frequency of performing aging management program periodic activities during the period of extended operation. This 25 percent grace period applied generically to each periodic aging management program activity described in UFSAR Appendix A and was intended to mirror the 25 percent grace period applied in the Technical Specifications. However, the licensee did not provide adequate technical justification for why the change was not adverse, nor a decrease in the effectiveness of the aging management programs. Specifically, the licensee had not documented

(1) inspection data to conclude the adequacy of increasing the inspection frequencies for each program that it would apply, or existing frequencies were too short,

(2) any technical justification for deviating from the GALL report guidance, nor

(3) in the safety evaluation report issued for Grand Gulf Nuclear Station.

Instead, the licensee relied on qualitative criteria in the process applicability determination (the licensee's term for a 10 CFR 50.59 screen). Although the licensee used the LBDCR to revise the UFSAR, the inspectors determined that no violation existed because the licensee had not entered the period of extended operation at the time of the inspection, nor did the licensee invoke a 25 percent grace to any license renewal inspection activity. As a result of the NRC's observation, the licensee generated condition report CR-GGN-2024-04387.

Observation: Walkdown Observations 71003 During review of the external surfaces aging management program and during plant walkdowns, the inspectors had the following observations:

• The inspectors reviewed GGNS ME-19-00018, Review of the External Surfaces Monitoring Program for License Renewal Implementation, revision 0, actions 5A and 5b. The actions required the development of new program instructions to identify the underground components and annotate the new program instructions with

[(GGNS) UFSAR A.1.18]. The inspectors identified that the licensee had not annotated five out of eight preventive maintenance descriptions with [(GGNS) UFSAR A.1.18] as described. Further, the licensee did not have the completed procedure EN-DC-178, System Walkdowns, checklist attached to several the work orders as described in procedure sections 5.1.d.c) and 7.1, and two work orders did not have completion notes indicating the inspection was completed and/or satisfactory. The licensee-initiated condition report CR-GGN-2024-04421 to document these programmatic deficiencies. The inspectors determined that the licensee had completed the work, and these documentation issues were of minor safety significance.

• The inspectors walked down the Divisions I and II heating ventilation air conditioning equipment room and the standby gas treatment recirculation system on the refuel floor to evaluate ductwork with flexible connections. During the walkdown, the inspectors identified a 2.5-foot tear in the flex connection of the safeguard switchgear/batt room exhaust fan (1Z77C001A) ductwork and failed patch repairs on the flex connection at standby gas treatment recirculation system recirculation fan (1T48C001A). The licensee-initiated condition reports CR-GGN2024-04423 and CR-GGN2024-04427, screened the issues for operability, and determined the equipment remained operable but degraded. The inspectors reviewed the licensees operability determination of the deficiencies in the ductwork and did not identify any concerns. The inspectors determined that these material deficiencies were of minor safety significance based on the acceptable performance of the equipment in its as-found condition.

• The inspectors identified degraded CO2 piping insulation going into the tank located outside in the elements. The licensee generated condition report CR-GGN-2024-04234 to document the deficiency and initiated work orders 54167422 and 54167423 to repair the insulation to prevent corrosion of the piping. The inspectors determined that the degraded insulation had no operational impact on the function of the tank. The inspectors determined that this material deficiency was of minor safety significance because of the lack of an operational impact on the tank.

• During a walkdown of the train A fire water storage tank, the inspectors identified a dent on the external surface of the tank and questioned any impact. The licensee documented the issue in condition report CR-GGN-2024-04233 to evaluate corrective actions because it could potentially result in coating degradation. The inspectors determined that this material deficiency was of minor safety significance because of the lack of an operational impact on the tank.

Observation: Reactor Vessel Surveillance Program Results 71003 The inspectors had the following observations related to review of the reactor vessel surveillance program. Specifically:

• The inspectors determined that the licensee had not formally transmitted their results to the BWRVIP program as described in commitment 2. The inspectors determined that the licensee emailed the parameter tables for 54 EFPY to the BWRVIP rather than send a letter as required by their procedures. The licensee-initiated condition report CR-GGN-2024-4530 to document the deficiency. Because the licensee had not entered the period of extended operation, the inspectors determined that no violation of regulatory requirements existed.

• The inspectors determined that engineering reports and UFSAR section 4.3.2.8 described that shroud and top guide fluence results exceeded the screening criteria of 5E20 n/cm2 for the upper shroud, top guide, N6 nozzle welds. This screening criteria identified those components would not be granted relief from required inspections because the analysis uncertainty exceeded the guidance of + 20 percent in RG 1.190, Calculational and Dosimetry Methods for Determining Pressure Vessel Neutron Fluence. The licensee identified that the UFSAR had out-of-date information and determined that calculation MPM-814779, Neutron Transport Analysis for Grand Gulf Nuclear Station, revision 6, used computational fluid dynamics to improve the modeling of the region above the fuel that reduced the uncertainty values less than 20 percent. The licensee-initiated condition report CR-GGN-2024-04451 to document the deficiency in the UFSAR. The inspectors determined that this documentation deficiency was of minor safety significance because design information demonstrated that the licensee met the requirements.

EXIT MEETINGS AND DEBRIEFS

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

• On August 15, 2024, the inspectors presented the License Renewal Phase 2 Inspection results to Mr. Grant Flynn, General Manager of Plant Operations, and other members of the licensee staff.

During this inspection, the inspectors closed the following commitments and reviewed the associated aging management programs listed in the updated final safety evaluation report supplement: 1, 2, 3, 4, 5, 6, 7, 8, 9, 10, 11, 12, 13, 14, 15, 16, 17, 18, 19, 20, 21, 22, 24, 25, 26, 27, 28, 29, 30, 31, 32, 33, 34, 35, and 36.

As described in the report, the inspectors did not close commitment 23 and the associate aging management program.

DOCUMENTS REVIEWED

Inspection

Procedure

Type

Designation

Description or Title

Revision or

Date

71003

Calculations

EC-0086535

Fitness For Service Evaluation for

Condensate Storage Tank

71003

Calculations

GGNS-MS-40

ASME Class 1 Components Fatigue Cycle

Counting

71003

Calculations

MC-Q1B13-23003

Grand Gulf Environmentally Assisted

Fatigue Calculations

71003

Corrective

Action

Documents

CR-HQN-

24-00332

71003

Corrective

Action

Documents

CR-GGN-

2015-03429, 2016-08327, 2017-09178,

2017-09632, 2017-11897, 2018-06999,

2019-00096, 2020-02502, 2020-11591,

21-02499, 2021-06768, 2021-07534,

21-07746, 2021-09004, 2021-09457,

22-02113, 2022-02194, 2022-06347,

22-07007, 2022-07044, 2022-09022,

22-09138, 2022-09418, 2022-10023,

22-10084, 2023-02060, 2023-14982,

23-16421, 2023-16605, 2023-16606,

23-17502, 2019-06628, 2023-14150,

2018-09338, 2023-13765, 2024-02102,

2019-08674, 2021-02004, 2019-08990,

21-01387, 2021-02340, 2018-03724,

20-04379, 2020-10539, 2020-00499

71003

Corrective

Action

WT-HQN-

2019-00031-000014

Inspection

Procedure

Type

Designation

Description or Title

Revision or

Date

Documents

71003

Corrective

Action

Documents

Resulting from

Inspection

CR-GGN-

24-04185, 2024-04214, 2024-04233,

24-04234, 2024-04265, 2024-04315,

24-04365, 2024-04382, 2024-04387,

24-04389, 2024-04392, 2024-04397,

24-04398, 2024-04402, 2024-04404,

24-04421, 2024-04423, 2024-04427,

24-04434, 2024-04438, 2024-04441,

24-04442, 2024-04443, 2024-04446,

24-04455, 2024-04529, 2024-04530,

24-04581

71003

Drawings

A-0108

Units 1 & 2 Control Building - Access

Control Floor Plan at EL. 93'-0"

71003

Drawings

A-0113

Units 1 & 2 Control Building - Switchgear

Rooms Floor Plan at EL. 111'-0"

71003

Drawings

A-0115

Units 1 & 2 Control Building - Computer

Room Floor Plan at EL. 148'-0"

71003

Drawings

20

Units 1 & 2 Control Building - Control Room

Floor Plan at EL. 166'-0"

71003

Drawings

A-0150

Units 1 & 2 Radwaste Building Floor Plan at

EL. 93'-0"

71003

Drawings

29

Units 1 & 2 Masonry Details without Vertical

Reinforcement

71003

Drawings

A-0730A

Units 1 & 2 Masonry Details

71003

Drawings

A-0731A sheet 3 of 4

Units 1 & 2 Masonry Details with

Reinforcing for Control and Turbine

Buildings

71003

Drawings

A-0731A sheet 4 of 4

Units 1 & 2 Masonry Details with

Reinforcing for Control and Turbine

Buildings

71003

Drawings

A-0731B

Units 1 & 2 Masonry Details with

Reinforcing - Auxiliary Unit 1 & Radwaste

Buildings

71003

Drawings

C-0020

Site & Yard Work Erosion Control & General 21

Inspection

Procedure

Type

Designation

Description or Title

Revision or

Date

Site Drainage Plan (marked up)

71003

Drawings

C-0022A

Site & Yard Work Site Drainage Structures

Plan, Sections, and Details

71003

Drawings

C-0022B

Site & Yard Work Site Drainage Structures

Plan, Sections, and Details

71003

Drawings

C-0022C

Site & Yard Work Site Drainage Structures

Plan and Sections

71003

Drawings

C-0038A

Units 1 & 2 Electrical Manholes Reinforced

Concrete Plans Sections & Details

71003

Drawings

C-1730

Units 1 & 2 SSW Cooling Tower Basin

Reinforced Concrete Base Mat Plan &

Sections

71003

Drawings

C-1734

Units 1 & 2 SSW Cooling Tower Basin

Reinforced Concrete Wall Sections &

Details

71003

Drawings

C-1750

Units 1 & 2 SSW Cooling Tower Basin

Cooling Tower Reinforced Concrete Plan -

El. 144'-6" & Sections & Details

71003

Drawings

C-6027

Plan Culvert No. 1 Elevation Set Points for

Surveying

71003

Drawings

E-0660

Site Raceway Plan Units 1 & 2

71003

Drawings

E-0664

Manhole and Trench Typical Details Units 1

& 2

71003

Drawings

E-0697

Raceway Plan 34.5 kV Substations Units 1

& 2

71003

Drawings

E-0698

Raceway Plan and Sections 34.5 kV

Substations Units 1 & 2

71003

Drawings

E-0812

115KV Tie Line, Electrical Arrangement

Plans and Elevation

71003

Drawings

M-0035E

P & I Diagram, Fire Protection System

71003

Drawings

M1067M

P&ID Instrument Air

71003

Engineering

Changes

084499

Issue EQ-License Renewal (EQ-LR)

Screening Report Engineering Report NO.

GGNS-EQ-20-00001

2/3/2021

Inspection

Procedure

Type

Designation

Description or Title

Revision or

Date

71003

Engineering

Changes

089023

Remove Hydrogen Analyzers from the EQ

program

71003

Engineering

Changes

20952

Extended Power Uprate Condensate Full

Flow Filtration System

71003

Engineering

Changes

223

Updating Cathodic Protection Anode Bed:

Site 4 1R62S007

71003

Engineering

Changes

90716

Cathodic Protection - Additional Anode Bed

Inside Protected Area, North-West Yard

71003

Engineering

Changes

93912

Service Life for 10-HBC-83 SSW Piping

Identified with Degradation

71003

Engineering

Changes

95161

Updating Cathodic Protection Anode Bed in

South Parking Lot

71003

Engineering

Changes

GGN-ECR-0000023795_

Supplement_2020-16-11 - Engineering to

Review/Approve Curtiss Wright's Nuclear

Environmental Test Procedure NO.

Q1535.0, Rev. 2 & Q1535.1, Rev. 0 FOR

T48 RCS Damper Actuators

71003

Engineering

Evaluations

GGNS-EP-08-LRD08

Aging Management Program Evaluation

Results Electrical

C

71003

Engineering

Evaluations

GGNS-006

Assessment of Primary System Chemistry

Control under Extended Power Operating

Conditions

3/21/2013

71003

Engineering

Evaluations

GGNS-EP-08-LRD05

Aging Management Program Evaluation

Report, Class 1 Mechanical (BWR

Feedwater Nozzle

71003

Engineering

Evaluations

GGNS-EP-08-LRD06

Aging Management Program Evaluation

Report Non-Class 1 Mechanical

71003

Engineering

Evaluations

GGNS-EP-08-LRD07

Aging Management Program Evaluation

Report Civil/Structural

71003

Engineering

Evaluations

GGNS-EP-08-LRD08

Aging Management Program Evaluation

Results - Electrical

71003

Engineering

Evaluations

GGNS-EP-22-00003

Non-EQ Sensitive Instrumentation Circuits

Test Review Program Report

71003

Engineering

GGNS-EP-22-00004

GGNS RF23 Outage Microbiological

Inspection

Procedure

Type

Designation

Description or Title

Revision or

Date

Evaluations

Induced Corrosion, Moderate Energy and

Erosion

71003

Engineering

Evaluations

GGNS-EP-22-00006

Buried Fuel Oil Storage Tank External

Surface Inspection Evaluation

71003

Engineering

Evaluations

GGNS-EP-22-00007

Aging Management Program Evaluation

Report One-Time Inspection - Small-Bore

Piping Program Weld Inspections

71003

Engineering

Evaluations

GGNS-EP-22-00008

Non-EQ Cable Connections Program

Report

71003

Engineering

Evaluations

GGNS-EP-24-00004

GGNS RF24 Outage Microbiological

Induced Corrosion and Moderate Energy

Executive Summary

71003

Engineering

Evaluations

GGNS-EP-24-00005

Selective Leaching Program Inspection

Report

71003

Engineering

Evaluations

GGNS-EQ-20-00001

Engineering Report - Grand Gulf Nuclear

Station Environmental Qualification

Screening for the License Renewal Period

1/26/2021

71003

Engineering

Evaluations

GGNS-ME-08-AMM23

Aging Management Review of the

Condensate and Refueling Water Storage

and Transfer System

71003

Engineering

Evaluations

GGNS-ME-19-00001

Review of the 115 kV Inaccessible

Transmission Cable Program for License

Renewal Implementation Report

71003

Engineering

Evaluations

GGNS-ME-19-00002

Review of the Aboveground Metallic Tanks

Program for License Renewal

Implementation

71003

Engineering

Evaluations

GGNS-ME-19-00004

Review of the Boraflex Monitoring Program

for License Renewal Implementation.

71003

Engineering

Evaluations

GGNS-ME-19-00005

Review of the Buried Piping and Tanks

Inspection Program for License Renewal

Implementation

71003

Engineering

Evaluations

GGNS-ME-19-00006

Review of the BWR CRD Return Line

Nozzle Program for License Renewal

Implementation

Inspection

Procedure

Type

Designation

Description or Title

Revision or

Date

71003

Engineering

Evaluations

GGNS-ME-19-00007

Review of the BWR Feedwater Nozzle

Program for License Renewal

Implementation

71003

Engineering

Evaluations

GGNS-ME-19-00013

Review of the Containment Inservice

Inspection-IWE Program for License

Renewal Implementation

71003

Engineering

Evaluations

GGNS-ME-19-00014

Review of the Containment Inservice

Inspection-IWL Program for License

Renewal Implementation

71003

Engineering

Evaluations

GGNS-ME-19-00015

Review of the Containment Leak Rate

Program for License Renewal

Implementation

71003

Engineering

Evaluations

GGNS-ME-19-00017

Review of the Environmental Qualification

(EQ) of Electric Components Program for

License Renewal Implementation

71003

Engineering

Evaluations

GGNS-ME-19-00020

Review of the Fire Protection Program for

License Renewal Implementation

71003

Engineering

Evaluations

GGNS-ME-19-00021

Review of the Fire Water System Program

for License Renewal Implementation

71003

Engineering

Evaluations

GGNS-ME-19-00022

Review of the Flow-Accelerated Corrosion

Program for License Renewal

Implementation

71003

Engineering

Evaluations

GGNS-ME-19-00025

Review of the Inspection of Overhead

Heavy Load and Light Load (Related to

Refueling) Handling Systems Program for

License Renewal Implementation

71003

Engineering

Evaluations

GGNS-ME-19-00027

Review of the Masonry Wall Program for

License Renewal Implementation

71003

Engineering

Evaluations

GGNS-ME-19-00028

Review of the Non-EQ Cable Connections

Program for License Renewal

Implementation

71003

Engineering

Evaluations

GGNS-ME-19-00029

Review of the Non-EQ Inaccessible Power

Cables (400 V to 35 kV) Program for

License Renewal Implementation

Inspection

Procedure

Type

Designation

Description or Title

Revision or

Date

71003

Engineering

Evaluations

GGNS-ME-19-00030

Review of the Non-EQ Instrumentation

Circuits Test Review Program for License

Renewal Implementation

71003

Engineering

Evaluations

GGNS-ME-19-00031

Review of the Non-EQ insulated Cables and

Connections Program for License Renewal

Implementation

71003

Engineering

Evaluations

GGNS-ME-19-00035

Review of the Periodic Surveillance and

Preventive Maintenance Program and

Coating Integrity Program for License

Renewal Implementation

71003

Engineering

Evaluations

GGNS-ME-19-00038

Review of the Reactor Vessel Surveillance

Program for License Renewal

Implementation

71003

Engineering

Evaluations

GGNS-ME-19-00039

Review of the RG 1.127, Inspection of

Water-Control Structures Associated with

Nuclear Power Plants Program for License

Renewal Implementation

71003

Engineering

Evaluations

GGNS-ME-19-00040

Review of the Selective Leaching Program

for License Renewal Implementation

71003

Engineering

Evaluations

GGNS-ME-19-00041

Review of the Service Water Integrity

Program for License Renewal

Implementation

71003

Engineering

Evaluations

GGNS-ME-19-00042

Review of the Structures Monitoring

Program for License Renewal

Implementation

71003

Engineering

Evaluations

GGNS-ME-19-00043

Review of the Water Chemistry Control -

BWR Program for License Renewal

Implementation

71003

Engineering

Evaluations

GGNS-ME-19-00044

Review of the Water Chemistry Control -

Closed Treated Water Systems Program for

License Renewal Implementation

71003

Engineering

Evaluations

GGNS-NE-10-00073

Pressure-Temperature Limits Report for

Entergy Operations, Inc. Grand Gulf

Nuclear Station

Inspection

Procedure

Type

Designation

Description or Title

Revision or

Date

71003

Engineering

Evaluations

GGNS-RF-20-015

CRD Return Safe End-To-Pipe Cap or Pipe

Cross Circ.

3/7/2016

71003

Engineering

Evaluations

GGNSILRT.22-L220520A

Grand Gulf Nuclear Station 2022 ILRT Final

Test Report

5/20/2022

71003

Engineering

Evaluations

ISI-VE-16-013

CRD Return Safe End-to-Pipe Cap or Pipe

Cross Circ

3/7/2016

71003

Engineering

Evaluations

MPM-814779

Neutron Transport Analysis for Grand Gulf

Nuclear Station

71003

Engineering

Evaluations

NEDO-33868

Grand Gulf Nuclear Station Pressure and

Temperature Limits Report (PTLR) up to 54

Effective Full-Power Years

71003

Engineering

Evaluations

WT-WTGGN-2019-00105-CA-2

Identify and document the reactor vessel

internal components composed of X-750

alloy, precipitation-hardened (PH)

martensitic stainless steel (e.g., 15-5 and

17-4 PH steel), and martensitic stainless

steel (e.g., 403, 410, 431 steel)

71003

Engineering

Evaluations

WT-WTGGN-2019-00105-CA-3

Evaluate the susceptibility to neutron or

thermal embrittlement for reactor vessel

internal components composed of X-750

alloy, precipitation-hardened (PH)

martensitic stainless steel (e.g., 15-5 and

17-4 PH steel), and martensitic stainless

steel (e.g., 403, 410, 431 steel)

71003

Engineering

Evaluations

WT-WTGGN-2019-00127-00019

LRID GGNS-ME-19-00035 R0, Attach 1,

Action 3b-2. Revise EN-DC-340, Section

5.4, with new step [2]: Using the

characteristics listed in Section 5.3,

determine the susceptible components in

each system to be inspected.

8/7/2022

71003

Engineering

Evaluations

WT-WTGGN-2019-00127-00041

LRID GGNS-ME-19-00035 R0, Attach 1,

Action 2-Annotate EN-DC-324, Section 2.3,

with [(GGNS) UFSAR-A.1.35]

3/31/2023

71003

Engineering

WTGGN-2019-000133, CA10

GGNS Selective Leaching Populations for

Inspection

Procedure

Type

Designation

Description or Title

Revision or

Date

Evaluations

License Renewal Implementation

71003

Miscellaneous

Response to NO-20

71003

Miscellaneous

CS-156 Response for CO2 Tank CR WO

71003

Miscellaneous

EC and Turbine Building Discussion

71003

Miscellaneous

NRC RFI Response 111

71003

Miscellaneous

NRC RFI Response 114

71003

Miscellaneous

NRC RFI Response 171 _NO-21

71003

Miscellaneous

0900596-3

Grand Gulf Nuclear Power Station CP

System Design, Installation and

Energization

4/14/2010

71003

Miscellaneous

1301124.400

Grand Gulf Nuclear Station APEC

Interrupted Only Re-Survey

71003

Miscellaneous

1900041.402

Failure Analysis Standby Service Water

Pipe Section

71003

Miscellaneous

1E51C002-TI (F802)

Entergy Operations - Grand Gulf - Oil

Analysis Severity Summary

71003

Miscellaneous

200699.A

Grand Gulf Nuclear Station Hydrogen Water

Chemistry Benchmark Test Report

4/26/2023

71003

Miscellaneous

200699.A

Grand Gulf Nuclear Station Hydrogen Water

Chemistry Benchmark Test Report

71003

Miscellaneous

2300499.401

Grand Gulf 2024 InTellusAPEC' Survey

Report

7/2024

71003

Miscellaneous

2300499.402

Grand Gulf 2024 Cathodic Protection

Annual Survey Report

71003

Miscellaneous

- 9330521 - 000

Grand Gulf License Renewal

Implementation Assessment

71003

Miscellaneous

6000000306

PM for SP45MHS15: Post Flooding Type

Event Manway Inspection

71003

Miscellaneous

600376A

PQE - GGNS - Buchanan Terminal Blocks

9/5/2022

71003

Miscellaneous

AQR-67368 (EPDM)

PQE - GGNS - ASCO Solenoid Valves

10/28/2021

71003

Miscellaneous

BWRVIP-257: BWR Vessel and

Internals Project

BWR Radiolysis Model Development

3.1

71003

Miscellaneous

CO2 1P64A003

CO2 Clean Agent Inspection Instructions

Inspection

Procedure

Type

Designation

Description or Title

Revision or

Date

71003

Miscellaneous

DRN-21-0649

Perform editorial change at next revision to

correct commitment identified in Step 2.3.6

to read "36186" and change A.1.2 to read

A.1.3. Att 9.3 should be Att 3

5/26/2021

71003

Miscellaneous

EN-EP-S-002-MULTI

7.2 Pipe/Tank Coating Visual

Inspection Checklist - 12" KSF Piping - Fire

Protection

7/15/2024

71003

Miscellaneous

EQDP-EQ25.2-001

Raymond Control Systems Electric Damper

Actuators

71003

Miscellaneous

F-C4197-4

PQE - GGNS - American Insulated Wire

Cables

4/27/2023

71003

Miscellaneous

F-C4350-4

PQE - GGNS - Anaconda Wires

9/2/2022

71003

Miscellaneous

FTN No. R06045-0032-019

21 Buried Piping Soil Sample Corrosivity

Analysis Report

9/16/2021

71003

Miscellaneous

GE-NE-523-A71-0594-A (DRF

137-0010-7Class II May 2000)

Alternate BWR Feedwater Nozzle

Inspection Requirements

71003

Miscellaneous

GGN-ECR- 023795

Engineering to Review/Approve Curtiss

Wrights Nuclear Environmental Test

Procedure N

O. Q1535.0, Rev. 2 & Q1535.1,

Rev. 0 for T 48 RCS Damper Actuators

6/15/2020

71003

Miscellaneous

GGNS-BWRWATERCHEM-STRAT

Strategic Water Chemistry Plan

71003

Miscellaneous

GGNS-CS-20-00001

RF-22 Containment and Drywell Coatings

Inspection Report

4/29/2020

71003

Miscellaneous

GGNS-CS-22-0000 I

RF-23 Containment and Drywell Coatings

Inspection Report

4/28/2022

71003

Miscellaneous

GL-80-95

Generic Activity A-10

11/13/1980

71003

Miscellaneous

GL-96-04

Boraflex Degradation in Spent Fuel Pool

Storage Racks

6/26/1996

71003

Miscellaneous

GNR0-2012/00089

Response to Request for Additional

Information (RAI) Set 27 dated July 17,

2012,

8/13/2012

71003

Miscellaneous

GNRO-2012/00029

Response to Request for Additional

Information (RAI) dated May 1, 2012.

5/1/2012

71003

Miscellaneous

GNRO-2012/00105

Response to Requests for Additional

9/13/2012

Inspection

Procedure

Type

Designation

Description or Title

Revision or

Date

Information (RAI) Set 32 dated August

15,2012.

71003

Miscellaneous

GNRO-2012/00155

Response to Requests for Additional

Information (RAI) Set 43 dated November

30, 2012.

2/18/2012

71003

Miscellaneous

GNRO-2012100042

Response to Request for Additional

Information (RAI) dated April 17, 2012.

5/15/2012

71003

Miscellaneous

GNRO-2016/00052

Clarification of Grand Gulf Nuclear Station

Containment Leak Rate Program

Description.

9/23/2016

71003

Miscellaneous

GNRO-2016/00054

Additional Clarification of the Grand Gulf

Nuclear Station Containment Leak Rate

Program Description

10/3/2016

71003

Miscellaneous

IEPSON Report No. NE-21-05-1

Vendor Report: Non-EQ Insulated Cable

and Connection Inspection Report

71003

Miscellaneous

ISI-UT-20-021

UT Calibration/Examination Nozzle to

vessel Weld

3/7/2020

71003

Miscellaneous

ISI-UT-20-023

UT Calibration/Examination Nozzle inner

Radius

3/7/2020

71003

Miscellaneous

Job # 03-08-211.127 &

03-08-211.135

Standby Service Water Basins

4/11/2018

71003

Miscellaneous

Job # 08211.75

Standby Service Water Inspection

9/20/2013

71003

Miscellaneous

LBDCR (Licensing Basis

Document Change Request )20-089

Comparison of Existing Program with

LR-ISG-2013-01

2/16/2020

71003

Miscellaneous

LBDCR 2019-044

EC 79268 replaces the existing PGCC fire

detection and suppression subsystem

equipment

07/31/2019

7/31/2019

71003

Miscellaneous

LBDCR 2020-074

Revise UFSAR Section A.1.4 and Section

A.4, Item 4 license renewal commitments

for the Boraflex Monitoring Program as

shown below.

2/10/2019

71003

Miscellaneous

LBDCR 2021-078

Closed Treated Water Chemistry Control

(A.1.44) Eliminate Incorrect EPRI Guideline

11/29/2021

Inspection

Procedure

Type

Designation

Description or Title

Revision or

Date

Reference

71003

Miscellaneous

LBDCR 2021-081

Section A.1.7 of the UFSAR require

updating for BWR Feedwater Nozzle (A.1.7)

11/11/2021

71003

Miscellaneous

LBDCR 2021-082

Closed Treated Water Chemistry Control

(A.1.44) Fire Pump Diesel Jacket Water

Program Change

11/30/2021

71003

Miscellaneous

LBDCR 2022-008

Buried and Underground Piping and Tanks

(BUPT) (A.1.5) Revise AMP in Accordance

with NRC LR-ISG-2015-01

1/18/2022

71003

Miscellaneous

LBDCR 2022-030

Structures Monitoring (A.1.42) Make

Inspection Intervals Consistent with

NUREG-1801, XI.S6

4/15/2022

71003

Miscellaneous

LBDCR 2022-031

UFSAR Section A.1.15 to correct Types A,

B and C leakage rate testing requirement.

3/21/2022

71003

Miscellaneous

LBDCR 2022-086

BUPT (A.1.5) Extend Inspection Interval for

Diesel Fuel Oil Storage Tank 1P81A001

11/30/2022

71003

Miscellaneous

LBDCR 2023-013

Coating Integrity (A.1.45) Allow

Opportunistic Only Inspection of Buried Fire

Water Piping Internals

3/13/2023

71003

Miscellaneous

LBDCR 2023-014

Inservice Inspection-IWF Program

enhancement description in UFSAR Section

A.1.24 needs revision.

2/15/2022

71003

Miscellaneous

M-EC81847-N1-8.0-001

GGNS Erosion Susceptibility Evaluation

(ESE)

71003

Miscellaneous

MPL-04-221

PQE - GGNS - Eugen Seitz-AG - Control

Valves

3/22/2023

71003

Miscellaneous

NUC2018139-NSR-CIF-002

Fire Water Storage Tank B (interior} Coating

Inspection Report

8/20/2018

71003

Miscellaneous

PM 0003291201

SP45MHS15 Inspect &

Func4/2/2024tionally Test Sump Pumps

4/2/2024

71003

Miscellaneous

PM 6000000306

SP45MHS15 Inspect MH Following

Flooding Rain Event

4/15/2024

71003

Miscellaneous

PM 6000001136

J3885/J3881, ESF-12, Feeder Underground

2/14/2023

Inspection

Procedure

Type

Designation

Description or Title

Revision or

Date

Cable Testing.

71003

Miscellaneous

R06045-0032-019

Condensate Storage Tank Buried Piping

Soil Sample Corrosivity Analysis Report

10/24/2019

71003

Miscellaneous

RCN-089

20 SSW Basin Project Underwater

Coating Inspection and Repair

2/2020

71003

Miscellaneous

RCN-107

22 SSW Basin Project Pipe Coating &

Component inspection, Coating &

Component Repair

11/2022

71003

Miscellaneous

Report #4877

Fuel Channel Fastener Noble Metals

Sampling at Grand Gulf Nuclear Station

8/2021

71003

Miscellaneous

Spec 6655

General Cable Uniblend PVC High Speed

EPR/Copper Tape Shield/PVC,

Medium-Voltage Power, Shielded

9/2016

71003

NDE Reports

RHR 1B Final RF24 Eddy Current

Inspection Report

3/13/2024

71003

NDE Reports

RHR 2B Final RF24 Eddy Current

Inspection Report

3/14/2024

71003

NDE Reports

Eddy Current Inspection of Division 1 Diesel

Generator Jacket Water HX P75B004A

4/2019

71003

NDE Reports

CEP-NDE-0901

Visual Examination of Pressure Retaining

Bolting (VT-1)

3/10/2020

71003

NDE Reports

CEP-NDE-0901

Visual Examination of Pressure Retaining

Bolting (VT-1)

3/25/2020

71003

NDE Reports

CEP-NDE-0901

Visual Examination of Pressure Retaining

Bolting (VT-1)

3/5/2020

71003

NDE Reports

ENO-82

Division II Emergency Diesel Generator

Jacket Water Cooler P75B004B

1/11/2021

71003

NDE Reports

ENO-97

RHR Heat Exchanger 1E12B002A Eddy

Current Inspection Report

3/17/2022

71003

NDE Reports

GGGF1-RFO23-346221

RF23 IVVI Full Report

4/12/2022

71003

NDE Reports

GGGF1-RFO24-350349

RF24 IVVI Full Report

3/22/2024

71003

NDE Reports

GGN-EP-24-00008

GGN RF-24 Reactor Vessel Internals

Management (RVIM) Program Post-Outage

Report

6/11/2024

Inspection

Procedure

Type

Designation

Description or Title

Revision or

Date

71003

NDE Reports

GGNS-EP-20-0003

Grand Gulf Nuclear Station RF22 In-Vessel

Visual Inspection (IVVI) Final Report

8/5/2020

71003

NDE Reports

GGNS-EP-20-0004

GGNS RF22 Reactor Vessel Internals

Management Program Post Outage Report

71003

NDE Reports

GGNS-EP-22-00001

GGNS RF23 Reactor Vessel Internals

Management Program Post Outage Report

5/23/2022

71003

NDE Reports

JB1-24-332910-SHRD

In-Vessel UT Examination Summary Sheet

3/17/2024

71003

Procedures

07-S-14-226

General Maintenance Instruction Spent Fuel

Cask Crane Periodic Inspection.

71003

Procedures

01-S-08-16

Chemical Treatment Program

71003

Procedures

2-S-01-35

Outside Rounds

105

71003

Procedures

04-1-01-N19-2

Condensate Full Flow Filtration System

71003

Procedures

04-S-01-P64-1

Fire Protection Water System

71003

Procedures

04-S-03-P64-20

Transformer Deluge Functional and Full

Flow Test

71003

Procedures

04-S-03-P64-3

Fire Protection Deluge and Sprinkler Valve

Testing

71003

Procedures

05-1-02-VI-2

Off-Normal Event Procedure Hurricanes,

Tornados, and Severe Weather

148

71003

Procedures

05-1-02-Vl-1

Off Normal Event Procedure Flooding

20

71003

Procedures

06-CH-1B21-O-0002

Reactor Coolant Routine Chemistry

110

71003

Procedures

06-CH-1P75-Q-0055

Division 1 Standby Diesel Generator Fuel

Oil Tank A003A Viscosity, Insolubles, Water

and Sediment

110

71003

Procedures

06-ME-1000-R-0007

Charcoal Adsorber Chemical Analysis

110

71003

Procedures

06-ME-1P75-O-0002

Standby Diesel Generator Fuel Oil Storage

Tank Cleaning and Inspection

110

71003

Procedures

06-ME-1P75-Q-0001

Removal of Water from Diesel Generator

Fuel Oil Storage Tank

108

71003

Procedures

06-ME-1P81-O-0002

HPCS Diesel Generator Fuel Oil Storage

Tank Cleaning and Inspection

107

71003

Procedures

06-ME-SP64-R-0045

Surveillance Procedure Ventilation System

Fire Dampers Inspection

117

71003

Procedures

06-ME*lPBl-0-0002

HPCS Diesel Generator Fuel Oil Storage

105

Inspection

Procedure

Type

Designation

Description or Title

Revision or

Date

Tank Cleaning and Inspection

71003

Procedures

06-OP-SP64-A-0012

Annual Yard Fire Hydrant and Spent Fuel

Pool Oscillating Nozzles Flow Check

110

71003

Procedures

06-OP-SP64-D-0044

Fire Door Check

20

71003

Procedures

06-OP-SP64-M-0001

SP64-C001, Jockey Fire

Pump Monthly Cycle Time Monitoring

114

71003

Procedures

06-OP-SP64-M-0047

Unit 1 Fire Hose Station and Fire

Extinguisher Maintenance

20

71003

Procedures

06-OP-SP64-O-0010

Fire Suppression Water System Loop Flow

Test

108

71003

Procedures

06-OP-SP64-R-0019

Sprinkler System Functional Tests

116

71003

Procedures

06-OP-SP64-R-0019

Sprinkler System Functional Tests

117

71003

Procedures

06-OP-SP64-R-0047

Surveillance Procedure Fire Rated

Assembly Visual Inspection.

2

71003

Procedures

06-OP-SP64-R-0048

Visual Inspection of Fire Wrapped

Raceways

110

71003

Procedures

06-OP-SP64-R-0049

Surveillance Procedure Fire Rated Sealed

Penetrations Visual Inspection.

113

71003

Procedures

06-TE-1000-V-0001 - Attachment I

(Intense Rainfall)

Culvert No. 1 Embankment Stability

Inspection/Survey

2

71003

Procedures

06-TE-1000-V-0001, Attachment II

- (5-year Stability)

Culvert No. 1 Embankment Stability

Inspection/Survey

2

71003

Procedures

06-TE-1000-V-0001, Attachment III

(visual inspection)

Culvert No. 8a Embankment Stability

Inspection/Survey Visual Inspection

2

71003

Procedures

06-TE-1000-V-0001, Attachment IV

(visual inspection)

Culvert No. 9a Embankment Stability

Inspection/Survey Visual Inspection

2

71003

Procedures

06-TE-1000-V-0001, Attachment V

- (Visual Inspection)

Culvert No. 11 Embankment Stability

Inspection/Survey Visual Inspection

2

71003

Procedures

07-1-24-P64-10

Preventive Maintenance Instruction Internal

Inspection of (P64) Sprinkler Piping

71003

Procedures

07-S-05-300

Maintenance Procedure Control and Use of

Cranes and Hoists

118

71003

Procedures

07-S-14-185

Periodic Inspection New Fuel Bridge Crane

71003

Procedures

07-S-14-196

General Maintenance Instruction Frequent

Inspection

Procedure

Type

Designation

Description or Title

Revision or

Date

and Periodic Inspections of Drywell Valve

Handling Crane.

71003

Procedures

07-S-14-2

Inspection of Tanks and Vessels

71003

Procedures

07-S-14-2

Inspection of Tanks and Vessels

71003

Procedures

07-S-14-272

Periodic Inspection and Maintenance

Containment Polar Crane

71003

Procedures

07-S-14-306

1000 CFM AAF Reactor Water Sampling

Filter Train Filter Removal and Replacement

71003

Procedures

07-S-24-P64-A001-l

Preventive Maintenance Instruction

Inspection of Firewater Storage Tanks

71003

Procedures

07-S-24-P64-C003-2

Preventive Maintenance Instruction

Firewater Pump Diesel Fuel Filter Change

and Related Maintenance

71003

Procedures

08-S-03-10

Chemistry Sampling Program

71003

Procedures

08-S-03-10

Chemistry Sampling Program

71003

Procedures

08-S-03-14

Chemical Additions to Plant Systems

71003

Procedures

08-S-03-21

Sampling Instrument Air, Emergency Diesel

Starting Air and ADS Air Systems

71003

Procedures

17-S-02-300

Fuel and Core Component Movement

Control

134

71003

Procedures

17-S-03-29

GL 89-13 Thermal Performance Data

Collection and Analysis

71003

Procedures

17-S-06-22, Attachment I

SSW A Performance - Flow Balance

71003

Procedures

17-S-06-23, Attachment 2

SSW B Performance - Flow Balance

71003

Procedures

20-S-03-410

NETCO Badger Assembly and Testing

71003

Procedures

CEP-APJ-001

Primary Containment Leakage Rate Testing

(10CFR50 Appendix J) Program Plan.

71003

Procedures

CEP-CII-004

General And Detailed Visual Examinations

of Concrete Containments

311

71003

Procedures

CEP-COS-0100

Control and Use of Iddeal Concepts

Software

71003

Procedures

CEP-COS-0110

Control and Use of the Iddeal Software

Suite Version 8 Schedule Works and

Version 9

311

Inspection

Procedure

Type

Designation

Description or Title

Revision or

Date

71003

Procedures

CEP-RR-001

ASME Section XI Repair/Replacement

Program

20

71003

Procedures

EN-CY-100

Conduct of Chemistry

71003

Procedures

EN-DC-141

Design Inputs

71003

Procedures

EN-DC-150

Condition Monitoring of Maintenance Rule

Structures

71003

Procedures

EN-DC-164

Environmental Qualification (EQ) Program

71003

Procedures

EN-DC-184

NRC Generic Letter 89-13 Service Water

Program

71003

Procedures

EN-DC-210

Environmental Qualification Master List

Control

71003

Procedures

EN-DC-225

Internal Coating Integrity Program

71003

Procedures

EN-DC-315

Flow Accelerated Corrosion Program

71003

Procedures

EN-DC-334

Primary Containment Leakage Rate Testing

(Appendix J)

71003

Procedures

EN-DC-343

Underground Piping and Tanks Inspection

and Monitoring Program

71003

Procedures

EN-DC-346

Cable Reliability Program

71003

Procedures

EN-DC-346

Cable Reliability Program

71003

Procedures

EN-DC-348

Non-EQ Insulated Cables and Connections

Inspection

71003

Procedures

EN-DC-352

Containment Inservice Inspection

(IWE/IWL) Program Duties and

Responsibilities

71003

Procedures

EN-EP-S-039-G

Testing Standard for Safety-Related Heat

Exchangers Cooled by Standby Service

Water

71003

Procedures

EN-FAP-LR-024

One-Time Inspection

71003

Procedures

EN-FAP-LR-025

Selective Leaching Inspection

71003

Procedures

EN-FAP-LR-026

License Renewal Non-EQ Electrical Cable

Connection AMP

71003

Procedures

EN-FAP-LR-027

License Renewal Sensitive Instrumentation

Circuits Review

71003

Procedures

EN-MA-101

Conduct of Maintenance

Inspection

Procedure

Type

Designation

Description or Title

Revision or

Date

71003

Procedures

EN-MA-106

Planning

71003

Procedures

EN-MA-119

Material Handling Program

71003

Procedures

GGNS-ME-19-00044

Review of the Water Chemistry Control -

Closed Treated Water Systems Program for

License Renewal Implementation

71003

Procedures

NEI 94-01

Nuclear Energy Institute Guideline for

Implementing Performance-Based Option of

CFR Part 50, Appendix J

3A

71003

Procedures

SEP 300046-01

Procedure for Assembly of the Boron-10

Areal Density Meter and Testing of

BORAFLEX Panels in the Grand Gulf Spent

Fuel Pool

9/10/2013

71003

Procedures

SEP-AMP-GGN-001

GGNS Opportunistic Inspections for Aging

Management Programs

71003

Procedures

SEP-AMP-GGN-002

GGNS Selective Leaching Inspection

Program

71003

Procedures

SEP-APJ-003

Primary Containment Leakage Rate testing

(Appendix J) Program

71003

Procedures

SEP-CISI-102

Program Section for ASME Section XI,

Division 1 GGNS Containment Inservice

Inspection Program

71003

Procedures

SEP-FPP-GGN-001

Grand Gulf Nuclear Station Fire Protection

Plan

71003

Procedures

SEP-FTP-GGNS

Reactor Vessel Fracture Toughness and

Surveillance Material Testing at Grand Gulf

Nuclear Station

71003

Procedures

SEP-ISI-GGN-001

Program Section for ASME Section XI,

Division 1 GGNS In-Service Inspection

Program.

71003

Procedures

SEP-LUB-GGN-002

GGN Oil Analysis Program

71003

Procedures

SEP-RVI-002

Grand Gulf Reactor Vessel Internals (RVI)

Inspection Program Plan

71003

Procedures

SEP-UIP-GGN

Underground Components Inspection Plan

71003

Work Orders

WO 00301379, 00341201, 00343525,

Inspection

Procedure

Type

Designation

Description or Title

Revision or

Date

00475870, 00478454, 00498799,

00508919,, 00517297, 00517363,

00517364, 00521211, 00536589,

00539303, 00539308, 00539309,

00539310, 00539311, 00539584,

00540666, 00541768, 00541776,

00542071, 00542074, 00545592,

00552829, 00557228, 00557747,

00560901, 00582811, 00584688,

00586081, 00586247, 00586248,

00587004, 00593737, 51568842,

2316310, 52471291, 52692653,

2711534, 52714172, 52766831,

2768155, 52814249, 52815722,

2816375, 52823908, 52827464,

2903917, 52906920, 52916603,

2916749, 52927882, 52933599,

2935202, 52935629, 52937886,

2943993, 52944359, 52946542,

2946644, 52953913, 52958537,

2962719, 52969230, 52970389,

2971020, 52971020, 52982973,

2986859, 52991743, 52994449,

2995657, 53003030, 53007654,

53008832, 53012086, 53013164,

53014595, 53017398, 53019370,

53019796, 53020508, 53024505,

54047064, 54090912