ML24340A025

Updated Safety Analysis Report Rev.28, Chapter 17, Quality Assurance and Appendix a

ML24340A025
Person / Time
Site:	River Bend
Issue date:	07/30/2023
From:	James Drake NRC/NRR/DORL/LPL4
To:	Entergy Nuclear Operations
References
Download: ML24340A025 (1)

Text

RBS USAR CHAPTER 17 QUALITY ASSURANCE Revision 27 17.1-1 17.1 QUALITY ASSURANCE DURING DESIGN AND CONSTRUCTION Does not apply.

RBS USAR Revision 27 17.2-1 CHAPTER 17 QUALITY ASSURANCE 17.2 QUALITY ASSURANCE DURING THE OPERATIONS PHASE The Quality Assurance program description is provided separately in Quality Assurance Program Manual.

RBS USAR Revision 27 A.1-1 APPENDIX A CHAPTER A AGING MANAGEMENT PROGRAMS AND ACTIVITIES The RBS license renewal application (Reference A.3-1) and information in subsequent related correspondence provided sufficient basis for the NRC to make the findings required by 10 CFR 54.29 (Final Safety Evaluation Report) (Reference A.3-2). As required by 10 CFR 54.21(d), this USAR supplement contains a summary description of the programs and activities for managing the effects of aging (Section A.1) and a description of the evaluation of time-limited aging analyses for the period of extended operation (Section A.2). The period of extended operation is the 20 years after the expiration date of the original operating license for RBS.

A.1 AGING MANAGEMENT PROGRAMS The integrated plant assessment for license renewal identified aging management programs necessary to provide reasonable assurance that structures and components subject to aging management review will continue to perform their intended functions consistent with the current licensing basis for the period of extended operation. This section describes the aging management programs and activities required during the period of extended operation. Aging management programs will be implemented prior to entering the period of extended operation.

The specified frequency for each periodic aging management program activity is met if the activity is performed within 1.25 times the interval specified in the program description, as measured from the previous performance or as measured from the time a specified condition on the frequency is met.

The corrective action, confirmation process, and administrative controls of the RBS (10 CFR Part 50, Appendix B) Quality Assurance Program are applicable to all aging management programs and activities during the period of extended operation. RBS quality assurance (QA) procedures, review and approval processes, and administrative controls are implemented in accordance with the requirements of 10 CFR 50, Appendix B. The RBS Quality Assurance Program applies to safety-related and important to safety structures and components.

Corrective actions and administrative (document) control for both safety-related and nonsafety-related structures and components are accomplished in accordance with the established RBS corrective action program and document control program and are applicable to all aging management programs and activities during the period of extended operation. The confirmation process is part of the corrective action program and includes reviews to assure adequacy of corrective actions, tracking and reporting of open corrective actions, and review of corrective action effectiveness. Any follow-up inspection required by the confirmation process is documented in accordance with the corrective action program.

Operating experience from plant-specific and industry sources is identified and systematically reviewed on an ongoing basis. The RBS corrective action program, which is implemented in accordance with the quality assurance program, effects the documentation and evaluation of plant-specific operating experience. The RBS operating experience program, which meets the provisions of NUREG-0737, "Clarification of TMI Action Plan Requirements," Item I.C.5, "Procedures for Feedback of Operating Experience to Plant Staff," systematically evaluates industry operating experience. The operating experience program includes active participation in the Institute of Nuclear Power Operations' operating experience program, as endorsed by the NRC. Codes are used in the corrective action program that provide for the comprehensive

RBS USAR Revision 27 A.1-2 identification and categorization of aging-specific issues for plant systems, structures, and components within the scope of license renewal.

In accordance with these programs, site-specific and industry operating experience items are screened to determine whether they involve lessons learned that may impact aging management programs (AMPs). Items are evaluated, and affected AMPs are either enhanced or new AMPs are developed, as appropriate, when it is determined that the effects of aging are not adequately managed. Plant-specific operating experience associated with managing the effects of aging is reported to the industry in accordance with guidelines established in the operating experience review program.

The results of implementing aging management programs (e.g., data from inspections, tests, analyses) are evaluated to determine whether the effects of aging are adequately managed.

These evaluations are conducted regardless of whether the acceptance criteria of the particular AMP have been met. A determination is made as to whether the frequency of future inspections should be adjusted, whether new inspections should be established, and whether the inspection scope should be adjusted. If the effects of aging are not being adequately managed, then a corrective action is entered into the 10 CFR Part 50, Appendix S, program to either enhance the AMP or develop and implement new aging management activities.

Training provided for personnel responsible for submitting, screening, assigning, evaluating, or otherwise processing plant-specific and industry operating experience, as well as for personnel responsible for implementing AMPs, is based on the complexity of the job performance requirements and assigned responsibilities. Training is scheduled on a recurring basis, which accommodates the turnover of plant personnel and the need for new training content.

Revisions to NUREG-1801, "Generic Aging Lessons Learned (GALL) Report" are developed to incorporate lessons learned from LRA reviews and from relevant industry operating experience.

For Revision 2, NRC staff reviewed industry operating experience for the period from January 2004 to approximately April 2009 to identify recommended modifications to the GALL Report.

The staff from the Division of License Renewal (DLR) analyzed operating experience information during a screening review of domestic operating experience, foreign operating experience from the international Incident Reporting System database, and NRC generic communications. The operating experience review program at RSS includes review of operating experience from the same domestic and foreign sources and from NRC generic communications.

Thus, the RSS operating experience review program includes the review of operating experience documented within each revision of NUREG-1801.

Evaluation of operating experience related to managing the effects of aging includes the consideration of affected plant systems, structures, and components; materials; environments; aging effects, aging mechanisms; aging management programs (AMPs); and the activities, criteria, and evaluations integral to the aging management programs.

A.1.1 Aboveground Metallic Tanks The Aboveground Metallic Tanks Program manages loss of material for the nonsafety-related aluminum condensate storage tank (CST), which is located outdoors on sand and concrete.

Preventive measures to mitigate corrosion were applied during construction, such as using the appropriate materials and use of a protective multi-layer vapor barrier beneath the tank.

RBS USAR Revision 28 A.1-3 The inner volume of the concrete ring foundation is filled with clean dry sand, which is sloped downward from the tank center to the tank exterior. The protective multi-layer vapor barrier beneath the tank serves as a seal at the concrete-to-tank interface. There are no indoor tanks included in this program.

Interior and exterior surfaces of the CST will be inspected. Inspections include ultrasonic testing (UT) of the CST tank bottom to assess the thickness against the design specified thickness during each 10-year period starting 10 years before the period of extended operation and periodic visual inspection of the seal between the tank bottom and concrete foundation at least once per refueling cycle.

Ultrasonic thickness measurements are used to inspect 100% of the outer 18 inches of tank bottom on a grid pattern as follows: radially at approximately 3 inches, 9 inches, and 15 inches inward from the outer wall and at a maximum of 2 feet circumferentially. At least 50% of the tank bottom thickness measurements will be on the tank bottom adjacent to the area enclosed by the outside curb.

This program will be implemented prior to the period of extended operation.

A.1.2 Bolting Integrity The Bolting Integrity Program manages loss of preload, cracking, and loss of material for pressure-retaining closure bolting using preventive measures and inspection activities.

Preventive measures include material selection (e.g., use of materials with an actual yield strength of less than 150 kilo-pounds per square inch [ksi]), lubricant selection (e.g., restricting the use of molybdenum disulfide), applying the appropriate preload (torque), and checking for uniformity of gasket compression where appropriate to preclude loss of preload, loss of material, and cracking. This program includes the inspection activities required by ASME Section XI for ASME Class 1, 2 and 3 pressure-retaining bolting. For ASME Class 1, 2 and 3 bolting and non-ASME Code class bolts, periodic system inspections (at least once per refueling cycle) ensure identification of indications of loss of preload, cracking, and loss of material before leakage becomes excessive. Submerged pressure-retaining bolting will be inspected at least once every 10 years.

In addition to periodic visual inspections with components in service, visual inspection of bolting heads, nuts and threads is performed on a representative sample of closure bolting during each 10-year interval of the period of extended operation. If the number of opportunistic inspections is insufficient, the program will provide for additional directed inspections necessary to achieve a sample of 20 percent of the population (for each material/environment combination) up to a maximum of 25 bolts during each 10-year interval of the period of extended operation.

Applicable industry standards and guidance documents, including NUREG-1339, EPRI NP-5769, and EPRI TR-104213, were used to develop the program implementing procedures. The Structures Monitoring Program (Section A.1.41) manages the aging effects on structural bolting.

The preventive measures of the Bolting Integrity Program manage loss of preload for buried fire water system bolting, which is inspected under the Buried and Underground Piping and Tanks Inspection Program (Section A.1.4).

RBS USAR Revision 27 A.1-4 The Bolting Integrity Program will be enhanced as follows:

x Revise Bolting Integrity Program procedures to include submerged closure bolting for pressure-retaining components. All accessible suppression pool suction strainer submerged closure bolting will be inspected at least once every 10 years and if the inspection is performed by divers, accessible bolting that is not removed will be checked manually to verify that it remains at least hand tight. For each combination of other submerged closure bolting material and environment, a representative sample of closure bolt assemblies will be inspected in each 10-year period of the period of extended operation. Bolt heads, threads, and nuts, if applicable, will be inspected when joints are disassembled. For each material and environment combination, the representative sample will include 20 percent of the population or at least 25 closure bolt assemblies.

Revise Bolting Integrity Program procedures to volumetrically examine high-strength bolting (regardless of code classification) (i.e., bolting with actual yield strength greater than or equal to 150 ksi) for cracking in accordance with ASME Section XI, Table IWB-2500-1, Examination Category B-G-1.

Revise Bolting Integrity Program documents to specify visual inspection of a representative sample of closure bolting (bolt heads, nuts, and threads) in air environments. A representative sample will be 20 percent of the population (for each material/environment combination) up to a maximum of 25 fasteners during each 10-year period of the period of extended operation. The inspections will be performed when the bolting is removed to the extent that the bolting threads and bolt heads are accessible for inspections that cannot be performed during visual inspection with the threaded fastener installed.

Enhancements will be implemented prior to the period of extended operation.

A.1.3 Neutron Absorbing Material Monitoring The Neutron Absorbing Material Monitoring Program is a new program that will manage change in material properties, loss of material, and reduction of neutron absorption capacity of the neutron absorbing material in the spent fuel pool. Degradation of the neutron absorbing material that could compromise the criticality analysis will be detected to assure that the required 5% sub-criticality margin is maintained during the period of extended operation. The parameters monitored include the physical condition and dimensions (corrosion, pitting, wear, blisters, bulges) and areal density (neutron absorber loss). Inspection and test frequencies will be based on plant-specific experience and will be informed by industry operating experience, but will be at least once every 10 years. Test results will be trended and, if necessary, corrective action will be taken to ensure the sub-criticality margin is met.

The program will use monitoring coupons and in-situ inspections and will follow the most current industry guidance, Nuclear Energy Institute (NEI) 16-03, Guidance for Monitoring of Fixed Neutron Absorbers in Spent Fuel Pools, Revision 0, May 2017 (ML17263A133).

This program will be implemented prior to the period of extended operation.

A.1.4 Buried and Underground Piping and Tanks Inspection The Buried and Underground Piping and Tanks Inspection Program manages the effects of aging on external surfaces of buried piping components and tanks subject to aging management review. Components included in the program are fabricated from metallic

RBS USAR Revision 27 A.1-5 materials. The program will manage loss of material and cracking through preventive and mitigative features (e.g., coatings, backfill quality, and cathodic protection) and periodic inspection activities during opportunistic and directed excavations. The number of inspections is based on the availability and effectiveness of preventive and mitigative actions as specified in Appendix B of License Renewal Interim Staff Guidance LR-ISG-2015-01. In addition to the buried stainless steel piping inspection recommended by LR-ISG-2015-01, one additional inspection of buried stainless-steel piping with silicon-based coating will be conducted during each 10-year period unless the soil is demonstrated non-corrosive and the backfill is in accordance with the recommendations of LR-ISG-2015-01. Preventive Action Category F of LR-ISG-2015-01 will be used in determining the number of inspections for portions of the in-scope buried steel piping where the cathodic protection system is not meeting performance goals (i.e.,

operational time period, effectiveness) or where the piping is not protected by a cathodic protection system unless all the requirements of moving to another preventive action category are met. A visual examination of buried carbon steel piping surfaces for evidence of cracking is performed whenever carbon steel piping surfaces are exposed. Annual cathodic protection surveys are conducted. For steel components, where the acceptance criteria for effectiveness of cathodic protection is other than -850 millivolts (mV) instant off, loss of material rates are measured.

The criterion for determining piping inspection locations will include in-scope piping protected by cathodic protection that is located in areas exceeding the limiting critical potential of -1200 mV.

The number of times and the magnitude by which the criterion is exceeded at specific locations are evaluated when determining inspection locations.

Inspections are conducted by qualified individuals. Where the coatings, backfill, or condition of exposed piping does not meet acceptance criteria such that the depth or extent of degradation of the base metal could have resulted in a loss of pressure boundary function when the loss of material rate is extrapolated to the end of the period of extended operation, an increase in the sample size is conducted. If a lack of soil corrosivity as determined by soil testing is used as a basis for a reduction in the number of inspections, then soil testing is conducted at least once in each 10-year period starting 10 years prior to the period of extended operation.

This program will be implemented prior to the period of extended operation.

A.1.5 BWR CRD Return Line Nozzle The BWR Control Rod Drive (CRD) Return Line Nozzle Program manages cracking of the CRD return line (CRDRL) reactor pressure vessel nozzle using preventive, mitigative, and inservice inspection activities. The CRDRL nozzle, which is exposed to a reactor coolant environment, was capped during construction prior to plant operation. This examination program originated through NUREG-0619 but is now governed by ASME Code,Section XI. Therefore, augmented inspections specified by NUREG-0619 are not applicable. The CRDRL inner radius is volumetrically examined to monitor the effects of cracking in accordance with the ASME Code,Section XI as part of the Inservice Inspection (ISI) Program. The examination is performed at least once each ISI interval. The scope of the program includes the CRDRL nozzle, the nozzle-to-reactor vessel weld, the nozzle-to-safe-end weld, the CRDRL nozzle cap, and the Inconel end cap to carbon steel safe end dissimilar metal weld. An enhancement is included to volumetrically examine the safe-end-to-cap weld once prior to the period of extended operation and once every 10 years during the period of extended operation. The nozzle, cap, and associated welds are included in the visual inspection (VT-2) during the reactor pressure test performed after each refueling outage.

RBS USAR Revision 27 A.1-6 Flaws detected during examination are evaluated by comparing the examination results to the acceptance standards established in ASME Code,Section XI, IWB-3512. Repair and replacement are in accordance with the requirements of ASME Section XI, IWA-4000.

A.1.6 BWR Feedwater Nozzle The BWR Feedwater Nozzle Program manages cracking due to cyclic loading on the reactor vessel's four feedwater nozzles using periodic inspection activities. Volumetric examination of the feedwater nozzle inner radii is performed in accordance with ASME Code,Section XI, Examination Category B-D. The inspections are performed at least once each ISI interval.

Flaws detected during examination are evaluated by comparing the examination results to the acceptance standards established in ASME Code,Section XI, IWB-3512. This examination program originated through NUREG-0619 but is now governed by ASME Code,Section XI.

A.1.7 BWR Penetrations The BWR Penetrations Program manages cracking due to cyclic loading or stress corrosion cracking (SCC) and intergranular SSC (IGSCC) of BWR instrument penetrations, CRD housing and incore housing penetrations, and core plate differential pressure (P)/standby liquid control penetrations. The program is implemented through station procedures that provide for mitigation of cracking through management of water chemistry and condition monitoring through examinations of reactor vessel penetration welds.

Inspections are performed in accordance with the guidelines of BWRVIP-49-A for the instrument penetrations, BWRVIP-47-A for the CRD housing and incore housing penetrations, and BWRVIP-27-A for the core plate 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. During each refueling outage, a visual inspection (VT-2) of the instrument penetrations, CRD housing and incore housing penetrations, and core plate

P/standby liquid control penetrations are performed during the reactor coolant pressure boundary system leakage test. These BWRVIP guidelines also provide details on evaluation of flaws, expansion of scope as required, and acceptance criteria.

A.1.8 BWR Stress Corrosion Cracking The BWR Stress Corrosion Cracking Program manages IGSCC in stainless steel, cast austenitic stainless steel (CASS), and nickel alloy reactor coolant pressure boundary piping and piping welds 4 inches or larger in nominal diameter containing reactor coolant at a temperature above 93°C (200°F) during power operation regardless of code classification.

The program addresses the management of crack initiation and growth due to IGSCC in the reactor coolant piping, welds, and components through the implementation of the ISI program in accordance with ASME Code,Section XI. Inservice inspections performed as augmented examinations of the Section XI ISI program ensure that aging effects are identified and repaired before the component's loss of intended function.

The inspection frequency for welds classified as Category C is in accordance with the recommendations provided in the staff-approved BWRVIP-75-A. Welds classified as Category A are subsumed into the risk-informed inservice inspection (RI-ISI) program in accordance with the June 30, 2010, NRC safety evaluation that approved RI-ISI at RBS. During the period of extended operation, at least 10 percent of the Category A welds are inspected during each ISI

RBS USAR Revision 27 A.1-7 interval. RBS has only Category A and C welds. The program includes preventive measures including the mechanical stress improvement process (MSIP) to minimize stress corrosion cracking.

A.1.9 BWR Vessel ID Attachment Welds The BWR Vessel ID [inside diameter] Attachment Welds Program manages cracking in structural welds for BWR reactor vessel internal integral attachments. The program is implemented through station procedures that provide for mitigation of cracking of reactor vessel internal components through control of reactor water chemistry as described in the Water Chemistry Control - BWR Program (Section A.1.42) 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. The program includes welds between the vessel wall and vessel ID brackets that attach components to the vessel. The internal attachment weld can be a simple weld or a weld build-up pad on the vessel.

A.1.10 BWR Vessel Internals The BWR Vessel Internals Program manages cracking, loss of preload, loss of material, and reduction in fracture toughness for BWR vessel internal components in a reactor coolant environment. The program performs inspections and flaw evaluation in conformance with the guidelines of applicable BWRVIP reports. The program also mitigates the aging effects by controlling water chemistry with the Water Chemistry Control - BWR Program (Section A.1.42).

This program includes (1) determining the susceptibility of cast austenitic stainless-steel components to thermal embrittlement, (2) accounting for the synergistic effect of thermal aging and neutron irradiation, and (3) implementing a supplemental examination program, as necessary.

Thermal and/or neutron embrittlement in susceptible CASS and X-750 components are indirectly managed by performing periodic visual inspections capable of detecting cracks in the component. This program provides screening criteria of CASS components to determine the susceptibility to thermal aging on the basis of casting method, molybdenum content, and percent ferrite. The program also manages aging effects in stainless steel and nickel alloy components. Precipitation-hardened (PH) martensitic stainless steel (e.g., 15-5 and 17-4 PH steel) materials and martensitic stainless steel (e.g., 403, 410, 431 steel) are not used in the RBS reactor vessel internal components. The crack growth rate evaluations and fracture toughness values specified in BWRVIP-14-A, BWRVIP-99-A, and BWRVIP-100, Revision 1, are used for cracked core shroud welds exposed to the neutron fluence values specified in these BWRVIP reports. RBS follows the guidelines of BWRVIP-139, Revision 1-A for inspection and evaluation of steam dryer components.

Applicable industry standards and staff approved BWRVIP documents provide the basis for scheduling inspections to provide timely detection of aging effects, appropriate NDE inspection techniques, acceptance criteria, flaw evaluation, and repair/replacement, as needed.

The BWR Vessel Internals Program will be enhanced as follows:

Revise BWR Vessel Internals Program procedures to state that for core shroud repairs or other IGSCC repairs, the program will maintain operating tensile stresses below a threshold limit that precludes IGSCC of X-750 material.

RBS USAR Revision 27 A.1-8 The susceptibility to neutron or thermal embrittlement for reactor vessel internal components composed of CASS and X-750 alloy will be evaluated.

Revise BWR Vessel Internals Program procedures as follows: Portions of the susceptible components determined to be limiting from the standpoint of thermal aging susceptibility, neutron fluence, and cracking susceptibility (i.e., applied stress, operating temperature, and environmental conditions) will be inspected, using an inspection technique capable of detecting the critical flaw size with adequate margin. The critical flaw size will be determined based on the service loading condition and service-degraded material properties. The initial inspection will be performed either prior to or within five years after entering the period of extended operation. If cracking is detected after the initial inspection, the frequency of re-inspection will be justified based on fracture toughness properties appropriate for the condition of the component. The sample size for the initial inspection of susceptible components will be 100 percent of the accessible component population, excluding components that may be in compression during normal operations.

Enhancements will be implemented prior to the period of extended operation.

A.1.11 Coating Integrity The Coating Integrity Program entails periodic visual inspections of coatings applied to the internal surfaces of in-scope components in an environment of treated water, raw water, waste water, or lubricating oil where loss of coating or lining integrity could impact the component's or downstream component's current licensing basis intended function(s). For coated surfaces that do not meet the acceptance criteria, coating repair or replacement is accompanied by physical testing where possible. The training and qualification of individuals involved in coating inspections of noncementitious coatings are in accordance with ASTM standards endorsed in Regulatory Guide (RG) 1.54, including limitations, if any, identified in RG 1.54 for those standards. For cementitious coatings or linings, inspectors should have a minimum of five years of experience inspecting or testing concrete structures or cementitious coatings or linings, or a degree in the civil/structural discipline and a minimum of one year of experience.

This program will be implemented prior to the period of extended operation.

A.1.12 Compressed Air Monitoring The Compressed Air Monitoring Program manages loss of material in compressed air systems by periodically monitoring the air for moisture and contaminants and by inspecting system internal surfaces. Air quality is maintained in accordance with limits based on consideration of manufacturer recommendations as well as guidelines in EPRI NP-7079, EPRI TR-108147, ASME OM-S/G-1998 (Part 17), and ANSI/ISA-S7.0.01-1996. Inspection frequencies and acceptance criteria are in accordance with SOER 88-01 and applicable industry standards.

Documents such as EPRI NP-7079, ASME OM-S/G-1998 (Part 17), and ANSI/ISA-S7.0.1-1996 provide guidance on preventive measures, inspection of components, and testing and monitoring air quality. Opportunistic internal visual inspections of components are performed to monitor for signs of corrosion. Air quality parameters are trended to determine if alert levels or limits are being approached or exceeded.

The Compressed Air Monitoring Program will be enhanced as follows:

RBS USAR Revision 27 A.1-9 Revise Compressed Air Monitoring Program procedures to apply consideration of the guidance of ASME OM-S/G-1998 (Part 17), EPRI NP-7079, and EPRI TR-108147 to the limits specified for the air system contaminants.

Revise Compressed Air Monitoring Program procedures to include opportunistic visual inspections of accessible internal surfaces of system components. Specify ASME OM-S/G-1998 (Part 17) provides guidance for inspection of system components.

Enhancements will be implemented prior to the period of extended operation.

A.1.13 Containment Inservice Inspection - IWE The Containment Inservice Inspection - IWE Program is implemented through plant procedures which provide administrative controls for the conduct of activities that are necessary to fulfill the requirements of 10 CFR 50.55a, which imposes the inservice inspection (ISI) requirements of the ASME B&PV Code,Section XI, Subsection IWE, for steel containments (Class MC) and steel liners for concrete containments (Class CC). There are no tendons associated with the RBS steel containment vessel (SCV). The RBS containment system is a General Electric BWR Mark III pressure suppression containment system consisting of a drywell, vapor suppression pool, and a primary containment structure. The RBS primary containment structure is a low-leakage, free-standing SCV consisting of a vertical upright cylinder with a torispherical dome and a flat liner plate at the base. The SCV forms the containment pressure boundary and encloses the vapor suppression pool and the drywell.

The program includes the SCV and its integral attachments, containment equipment hatches, airlocks, and pressure-retaining bolting.

The program performs visual examinations (general visual, VT-1 and VT-3) to assess the general condition of the containment and to detect evidence of degradation that may affect structural integrity or leak tightness. The visual inspections monitor the condition of the SCV surface areas, including welds and base metal and integral attachments, personnel and equipment access hatches, and pressure-retaining bolting. Bolting is not susceptible to cracking and does not require surface or volumetric examinations to detect cracking per IWE.

The Containment Inservice Inspection - IWE program specifies acceptance criteria, corrective actions, supplemental inspections as required, and provisions for expansion of the inspection scope when identified degradation exceeds the acceptance criteria in accordance with ASME Code Section XI as mandated and modified by 10 CFR 50.55a. Every 10 years this program is updated to the latest ASME Section XI code edition and addendum approved by the NRC in accordance with 10 CFR 50.55a.

The Containment Inservice Inspection - IWE Program will be enhanced as follows:

Revise plant procedures to include the preventive actions for storage of ASTM A325, ASTM F1852, and ASTM A490 bolting from Section 2 of Research Council on Structural Connections publication, "Specification for Structural Joints Using ASTM A325 or A490 Bolts."

Enhancements will be implemented prior to the period of extended operation.

A.1.14 Containment Leak Rate The Containment Leak Rate Program consists of tests performed in accordance with the regulations and guidance provided in 10 CFR Part 50, Appendix J, Primary Reactor

RBS USAR Revision 28 A.1-10 Containment Leakage Testing for Water-Cooled Power Reactors, Option B; RG 1.163, "Performance-Based Containment Leak-Testing Program; NEI 94-01, Industry Guideline for Implementing Performance-Based Options of 10 CFR Part 50, Appendix J; and the conditions and limitations specified in NEI 94-01, Revision 2-A, Section 4.1, dated October 2008. The program provides for detection of pressure boundary degradation due to aging effects such as loss of leak tightness, loss of material, cracking, or loss of sealing in various systems penetrating containment. The program also provides for detection of age-related degradation in material properties of gaskets, O-rings, and packing materials for the containment pressure boundary access points.

Three types of tests are performed under Option B. Types A, B, and C leakage rate testing will be implemented in accordance with the criteria set forth in RG 1.163, NEI 94-01, Revision 3-A, and the conditions and limitations specified in NEI 94-01, Revision 2-A, Section 4.1, dated October 2008. Type A tests are performed to determine the overall primary containment integrated leakage rate at the loss of coolant accident peak containment pressure.

Performance of the integrated leakage rate test (ILRT) demonstrates the leak-tightness and structural integrity of the containment. Type B and Type C containment local leakage rate tests (LLRTs) are intended to detect local leaks and to measure leakage across each pressure-containing or leakage-limiting boundary of containment penetrations.

Corrective actions are taken if leakage rates exceed acceptance criteria.

Test frequencies for Type A, B and C leakage rate testing comply with the requirements of 10 CFR Part 50, Appendix J, Option B based upon the criteria in NEI 94-01, Revision 3-A and the conditions and limitations specified in NEI 94-01, Revision 2-A, Section 4.1, dated October 2008.

A.1.15 Diesel Fuel Monitoring The Diesel Fuel Monitoring Program manages loss of material in piping, tanks, and other components in an environment of diesel fuel oil by verifying the quality of the fuel oil source.

This is performed by receipt inspection, sampling, and limiting the quantities of contaminants before allowing it to enter the fuel oil storage tanks. Parameters monitored include water and sediment content, total particulates, and levels of microbiological organisms in the fuel oil.

Monitoring and control are performed in accordance with ASTM standards D4057, D2274, D2276, and D2709. The program includes multi-level sampling of fuel oil storage tanks. Where multi-level sampling cannot be performed due to design, a representative sample is taken from the lowest part of the tank. A stabilizer/biocide is added to new fuel.

The Diesel Fuel Monitoring Program includes periodic inspections of low flow areas where contaminants may collect such as in the bottom of tanks. The fuel oil storage tanks are periodically sampled, drained, inspected, and cleaned as needed. Internal tank inspections for signs of moisture, contaminants, and corrosion will be performed at least once during the 10-year period prior to the period of extended operation, and at least once every 10 years during the period of extended operation. Where degradation is observed, a wall thickness determination is made. Water, levels of microbiological organisms, and particulate concentrations are monitored and trended in accordance with the plant's technical specifications or at least quarterly.

The One-Time Inspection Program (Section A.1.32) includes inspections to verify that the Diesel Fuel Monitoring Program has been effective at managing the effects of aging. The Diesel Fuel Monitoring Program will be enhanced as follows:

RBS USAR Revision 28 A.1-11 Revise Diesel Fuel Monitoring Program procedures to monitor levels of microbiological organisms in the standby diesel generator (SDG) and HPCS diesel generator fuel oil storage and day tanks, and diesel-driven fire pump fuel oil storage tanks.

Revise Diesel Fuel Monitoring Program procedures to include periodic multi-level sampling of tanks within the scope of the program. Include provisions to obtain a representative sample from the lowest point in the tank, if tank design does not allow for multi-level sampling.

Revise Diesel Fuel Monitoring Program procedures to include a periodic cleaning as needed and internal visual inspection of the tanks within the program. In the areas of any degradation identified during the internal inspection, a volumetric inspection shall be performed.

In the event an internal inspection cannot be performed due to design limitations, a volumetric examination shall be performed. Perform cleanings as needed and internal inspections at least once during the 10-year period prior to the period of extended operation and at succeeding 10-year intervals.

Revise Diesel Fuel Monitoring Program procedures to (a) monitor levels of microbiological organisms and particulate concentrations in the diesel-driven fire pump fuel oil storage tanks at least quarterly, and (b) monitor levels of microbiological organisms in the SDG and HPCS diesel fuel oil storage and day tanks at least quarterly.

Revise Diesel Fuel Monitoring Program procedures to specify sampling for water and sediment in accordance with ASTM Standard D2709.

Enhancements will be implemented prior to the period of extended operation.

A.1.16 Environmental Qualification (EQ) of Electric Components The Environmental Qualification (EQ) of Electric Components Program manages the effects of thermal, radiation, and cyclic aging through the use of aging evaluations based on 10 CFR 50.49(f) qualification methods. As required by 10 CFR 50.49, EQ components are refurbished, replaced, or their qualification is extended prior to reaching the aging limits established in the evaluation. Reanalysis of an aging evaluation addresses attributes of analytical methods, data collection and reduction methods, underlying assumptions, acceptance criteria, and corrective actions. Some aging evaluations for EQ components are time-limited aging analyses (TLAAs) for license renewal.

A.1.17 External Surfaces Monitoring The External Surfaces Monitoring Program manages aging effects of components fabricated from metallic, elastomeric, and polymeric materials through periodic visual inspection of external surfaces for evidence of loss of material, cracking, reduced thermal insulation resistance, and change in material properties. When appropriate for the component and material, physical manipulation, such as pressing, flexing and bending, is used to augment visual inspections to confirm the absence of elastomer hardening and loss of strength. The External Surfaces Monitoring Program is also credited for situations where the material and environment combinations are the same for the internal and external surfaces such that the external surfaces are representative of the internal surfaces.

RBS USAR Revision 27 A.1-12 Inspections are performed at least once every refueling cycle by personnel qualified through a plant-specific training program. Deficiencies are documented and evaluated under the corrective action program. Surfaces that are not readily visible during plant operations and refueling outages are inspected when they are made accessible and at such intervals that would ensure the components intended functions are maintained.

Periodic visual inspections of a representative sample of in-scope mechanical indoor components under insulation (with process fluid temperature below the dew point) and outdoor components under insulation will be performed.

For polymeric (or non-metallic) materials, the visual inspection will include 100 percent of the accessible components. The flexible polymeric or elastomeric components that receive physical manipulation constitute at least 10 percent of the available surface area.

For stainless steel, the acceptance criterion is a clean, shiny surface. Other metals should not have abnormal surface indications. For flexible polymeric materials, a uniform surface texture (no cracks) and no change in material properties (e.g., hardness, flexibility, physical dimensions, color unchanged from when the material was new) are the acceptance criteria. For rigid polymeric materials, acceptable conditions are no surface abnormalities, such as erosion, cracking, crazing, checking, and chalking.

Thermal insulation is credited to reduce heat transfer from certain components to ensure that functions described in 10 CFR 54.4(a) are successfully accomplished. Insulation is installed in accordance with manufacturer specifications, including configuration features such as overlap and location of seams. Inspections of insulated components where the insulation is required to reduce heat transfer will be performed to ensure insulation degradation due to moisture intrusion has not occurred.

The External Surfaces Monitoring Program will be enhanced as follows:

Revise External Surfaces Monitoring Program procedures to include instructions to perform a visual inspection of accessible flexible polymeric component surfaces. The visual inspection should identify indicators of loss of material due to wear to include dimensional change, surface cracking, crazing, scuffing, and for flexible polymeric materials with internal reinforcement, the exposure of reinforcing fibers, mesh, or underlying metal. In addition, 10 percent of the available flexible polymeric surface area should receive physical manipulation to augment the visual inspection to confirm the absence of hardening and loss of strength (e.g., HVAC flexible connectors).

Revise External Surfaces Monitoring Program procedures to specify the following for in-scope insulated components in a condensation or air - outdoor environment.

3/4 Periodic representative inspections will be conducted during each 10-year period during the period of extended operation.

3/4 For a representative sample of in-scope insulated indoor components with an environment of condensation (because the component is operated below the dew point) and insulated outdoor components, insulation will be removed for visual inspection of the component surface. Inspections include a minimum of 20 percent of the in-scope piping length for each material type (e.g., steel, stainless steel, copper alloy, aluminum), or for components with a configuration which does not conform to a 1-foot axial length determination (e.g., valve, accumulator), 20 percent

RBS USAR Revision 27 A.1-13 of the surface area. Alternatively, insulation will be removed and a minimum of 25 inspections performed that can be a combination of 1-foot axial length sections and individual components for each material type.

3/4 Inspection locations will be locations with a higher likelihood of corrosion under insulation (CUI). For example, CUI is more likely for components experiencing alternate wetting and drying in environments where trace contaminants could be present and for components that operate for long periods of time below the dew point. Subsequent inspections will consist of 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.

- No loss of material due to general, pitting or crevice corrosion, beyond that which could have been present during initial construction.

- No evidence of cracking.

If the external visual inspections of the insulation reveal damage to its exterior surface or if there is evidence of water intrusion through the insulation (e.g.,

water seepage through insulation seams/joints), periodic inspections under the insulation will continue as described above.

3/4 Removal of tightly adhering insulation that is impermeable to moisture is not required unless there is evidence of damage to the moisture barrier. If the moisture barrier is intact, the likelihood of CUI is low for tightly adhering insulation. Tightly adhering insulation is considered a separate population from the remainder of insulation installed on components subject to aging management review. The entire population of accessible piping component surfaces subject to aging management review that have tightly adhering insulation will be visually inspected for damage to the moisture barrier with the same frequency as for other types of insulation inspections. These inspections will not be credited towards the inspection quantities for other types of insulation.

x Revise External Surfaces Monitoring Program procedures to include the following acceptance criteria.

3/4 Stainless steel should have a clean, shiny surface with no discoloration. There should be no leakage of stainless-steel components in an environment of air containing halides.

3/4 Other metals should not have abnormal surface indications.

3/4 Flexible polymeric materials should have a uniform surface texture with the material in an as-new condition with no cracks, crazing, scuffing, discoloration, dimensional change, exposure of internal reinforcement for reinforced elastomers, hardening as evidenced by a loss of suppleness during manipulation where the component and material are appropriate for manipulation, and no shrinkage or loss of strength.

3/4 Rigid polymeric materials should have no erosion, cracking, checking, or chalking.

Enhancements will be implemented prior to the period of extended operation.

A.1.18 Fatigue Monitoring

RBS USAR Revision 27 A.1-14 The Fatigue Monitoring Program ensures that fatigue usage remains within allowable limits for components identified to have a fatigue TLAA by (a) tracking the number of critical thermal and pressure transients for selected components, (b) verifying that the severity of monitored transients is 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 including those from NUREG/CR-6260 and those components identified to be more limiting than the components specified in NUREG/CR-6260, and (d) addressing applicable fatigue exemptions. Tracking the number of critical thermal and pressure transients for the selected components ensures a cumulative usage factor (CUF) within allowable limits, including environmental effects where applicable. The environmental effects on fatigue for the identified critical components will be evaluated.

The Fatigue Monitoring Program will be enhanced as follows:

3/4 Revise Fatigue Monitoring Program procedures to monitor and track critical thermal and pressure transients for components with a fatigue TLAA.

3/4 Develop a set of fatigue usage calculations that consider the effects of the reactor water environment for a set of sample reactor coolant system components. This sample shall include the locations identified in NUREG/CR-6260, and additional plant-specific component locations in the reactor coolant pressure boundary if they are found more limiting than those considered in NUREG/CR-6260. Environmental correction factors (Fen) shall be determined using the formulae recommended in NUREG-1801, X.M1.

Stress analysis methods used as inputs to fatigue analyses will consider all six stress components. An environmentally assisted fatigue analysis using NUREG/CR-6909 will not use average temperature for complex transients. For simple transients that use average temperature, when the minimum temperature is below the threshold temperature, the maximum and threshold temperature will be used to calculate the average temperature.

3/4 Revise Fatigue Monitoring Program procedures to provide updates of the fatigue usage calculations on an as-needed basis if an allowable cycle limit is approached, or in a case where a transient definition has been changed, an unanticipated new thermal event is discovered, or the geometry of a component has been modified.

The second enhancement on environmentally assisted fatigue usage calculations will be implemented at least two years prior to entering the period of extended operation. All other enhancements will be implemented prior to the period of extended operation.

A.1.19 Fire Protection The Fire Protection Program manages the following through periodic visual inspection of components and structures with a fire barrier intended function.

x Carbon steel components (loss of material).

x Concrete components (cracking and loss of material).

x Masonry walls (cracking and loss of material).

x Fire resistant materials (loss of material, change in material properties, cracking/delamination, and separation).

RBS USAR Revision 27 A.1-15 Elastomer components (increased hardness, shrinkage, and loss of strength).

The Fire Protection Program manages aging effects for components that serve a fire barrier function. Fire barriers include assemblies such as penetration fire seals, walls, floors, ceilings, fire-rated doors, cable tray enclosures, cable or conduit wraps, fire stops, junction boxes, and other fire-resistant materials that serve a fire barrier intended function. Fire barrier inspections are performed at a frequency in accordance with the NRC-approved fire protection program and Technical Requirements Manual.

The periodic visual inspection and functional test of the Halon fire suppression system associated with the power generation control complex is performed to examine for signs of corrosion and degradation that may lead to the loss of material of the Halon fire suppression system. The frequency of the periodic functional test is in accordance with the NRC-approved fire protection program and the Technical Requirements Manual.

A.1.20 Fire Water System The Fire Water System Program manages loss of material, and flow blockage due to fouling for in-scope, long-lived, passive, water-based fire suppression system components using periodic flow testing and visual inspections in accordance with NFPA 25 (2011 Edition). In addition, the fire water system pressure is monitored such that a loss of system pressure is immediately detected and corrective action initiated. When visual inspections are used to detect loss of material and fouling, the inspection technique is capable of detecting surface irregularities that could indicate wall loss due to corrosion, corrosion product deposition, and flow blockage due to fouling. The program also manages loss of coating integrity for the fire water tanks.

Testing or replacement of sprinkler heads that have been in service for 50 years is performed in accordance with the 2011 Edition of NFPA 25. Portions of the water-based fire water system that (a) are normally dry, but periodically subject to flow (e.g., downstream of the deluge valve in a deluge system) and (b) allow water to collect are subject to augmented examination beyond that specified in NFPA 25. The augmented examinations for the portions of normally dry piping that are periodically wetted include (a) periodic full flow tests at the design pressure and flow rate, or internal inspections, and (b) volumetric wall thickness evaluations. Augmented examinations for the system include periodic volumetric wall thickness evaluations, at a minimum rate of 5 inspections in each refueling cycle.

The training and qualification of individuals involved in fire water storage tank coating inspections are in accordance with ASTM International standards endorsed in RG 1.54, including limitations, if any, identified in RG 1.54 on a particular standard.

Program acceptance criteria include (a) the water-based fire protection system can maintain required pressure, and (b) no unacceptable signs of degradation or fouling are observed during non-intrusive or visual inspections.

In the event surface irregularities are identified, testing is performed to ensure minimum design pipe wall thickness is maintained. In the event the fire water tank fails to meet the acceptance criteria for coating or tank surface condition (e.g., peeling, delamination, blistering, flaking, cracking, or rust), the program specifies an evaluation to ensure the tank can perform its intended function until the next inspection and that downstream flow blockage is not a concern.

The Fire Water System Program will be enhanced as follows:

RBS USAR Revision 27 A.1-16 x

Revise Fire Water System Program procedures to perform an internal inspection of the auxiliary building and diesel generator building preaction systems dry piping for loss of material every five years. Perform an inspection by removing a sprinkler from the branch line most remote from the source of water or using an inspector's test valve. In the event foreign material is found in a preaction system that could result in flow obstructions or blockage of a sprinkler head in a building, each in-scope preaction system in that building shall have an internal inspection.

x Revise Fire Water System Program procedures to perform an internal inspection every five years of the dry piping downstream of the deluge valves for the control building cable vaults (WS-6A, WS-6B and WS-6C), cable tunnel spray system (WS-8D), tunnels (WS-8E, WS-8F, WS-8G, WS-8H, WS-8K, WS-8L, WS-8M and WS-8N), and auxiliary building water curtains (WS-19 and WS-20) at 70-foot elevation and 141-foot elevation.

The inspection shall be performed by opening a flushing connection, removing the most remote sprinkler head, and using a method capable of detecting surface irregularities that could indicate wall loss below nominal pipe wall thickness due to corrosion product deposition and flow blockage due to fouling. In the event foreign material is found in an in-scope deluge system in a building during the five-year internal inspection of piping, the dry piping of each in-scope deluge system in that building shall have an internal inspection.

x Revise Fire Water System Program procedures to perform an internal piping inspection of every other wet fire water system every five years by opening a flushing connection at the end of one main and by removing a closed sprinkler head toward the end of one branch line for the purpose of inspecting the interior for evidence of loss of material and the presence of foreign material that could result in flow obstructions or blockage of sprinkler head or nozzles. The inspection method used shall be capable of detecting surface irregularities that could indicate wall loss below nominal pipe wall thickness due to corrosion, corrosion product deposition, and flow blockage due to fouling. Ensure procedures require a follow-up volumetric wall thickness evaluation where irregularities are detected. In the event foreign material is found, all wet pipe systems in that building shall have an internal inspection before returning to service.

x Revise Fire Water System Program procedures to perform flow testing of underground piping in accordance with NFPA 291.

x Revise Fire Water System Program procedures to inspect fire water sprinkler heads in accordance with NFPA 25, Section 5.2.1.1, with the exception of sprinkler orientation, foreign material, physical damage, and loading due to dust or debris.

x Revise Fire Water System Program procedures to inspect the interior of the fire water tanks in accordance with NFPA 25 (2011 Edition), Sections 9.2.6 and 9.2.7, including sub-steps, using the guidance of SSPC-SP2, Hand Tool Cleaning; SSPC-SP3, Power Tool Cleaning; SSPC-SP11, Cleaning of Bare Metal; and SSPC-SP WJ-1, 2, 3 and 4, Water Jet Cleaning. Perform the interior inspection with the tank completely drained.

x Revise Fire Water System Program procedures to remove mainline strainers, inspect for damage and corroded parts, clean every five years, and add a requirement to flush

RBS USAR Revision 27 A.1-17 mainline strainers (basket or screen) until clear at least once per refueling cycle if a fire water system actuation occurred or flow testing occurred during that refueling cycle.

x Revise Fire Water System Program procedures to specify that sprinkler heads are tested or replaced in accordance with NFPA 25 (2011 Edition), Section 5.3.1.

x Revise Fire Water System Program procedures to specify a flow test or flush sufficient to detect potential flow blockage or conduct a visual inspection of 100 percent of the internal surface of piping segments that allow water to collect in each five-year interval, beginning five years prior to the period of extended operation.

x Revise Fire Water System Program procedures to specify volumetric wall thickness inspections of 20 percent of the length of piping segments that allow water to collect in each five-year interval of the period of extended operation. Measurement points shall be obtained to the extent that each potential degraded condition can be identified (e.g.,

general corrosion, microbiologically induced corrosion [MIC]). The 20 percent of piping that is inspected in each five-year interval is in different locations than previously inspected piping.

x Revise Fire Water System Program procedures to perform main drain tests on 20 percent of the standpipes and risers in accordance with NFPA 25 (2011 Edition),

Sections 6.3.1.5 and 13.2.5.

x Revise Fire Water System Program procedures to specify an annual air flow test of the charcoal filter units that are in scope for license renewal. If obstructions are found, the system shall be cleaned and retested.

x Revise Fire Water System Program procedures to verify the hydrants drain within 60 minutes after flushing or flow testing.

x Revise Fire Water System Program procedures to ensure the training and qualification of the individual performing the evaluation of fire water storage tank coating degradation is in accordance with ASTM International standards endorsed in RG 1.54 guidance, including limitations, if any, identified in RG 1.54 on a particular standard.

x Revise the Fire Water System Program procedures to ensure a fire water tank is not returned to service after identifying interior coating blistering, delamination or peeling unless there are only a few small intact blisters that are not growing in size or number and are surrounded by coating bonded to the substrate as determined by a qualified coating specialist, or the following actions are performed:

3/4 Blistering in excess of a few small intact blisters that are not growing in size or number or blistering not completely surrounded by coating bonded to the substrate is removed.

3/4 Delaminated or peeled coating is removed.

3/4 The exposed underlying coating is verified securely bonded to the substrate as determined by an adhesion test endorsed by RG 1.54 at a minimum of three locations.

RBS USAR Revision 27 A.1-18 3/4 The outermost coating is feathered, and the remaining outermost coating is determined securely bonded to the coating below at a minimum of three locations adjacent to the defective area via an adhesion test endorsed by RG 1.54.

3/4 Ultrasonic testing is performed where there is evidence of pitting or corrosion to ensure the tank meets minimum wall thickness requirements.

3/4 An evaluation is performed to ensure downstream flow blockage is not a concern.

3/4 A follow-up inspection is scheduled within two years and every two years after that until the coating is repaired, replaced, or removed.

x Revise Fire Water System Program procedures to determine the extent of coating defects on the interior of the fire water tanks by using one or more of the following methods when conditions such as cracking, peeling, blistering, delamination, rust, or flaking are identified during visual examination.

3/4 Lightly tapping and scraping the coating to determine the coating integrity.

3/4 Dry film thickness measurements at random locations to determine overall thickness of the coating.

3/4 Wet-sponge testing or dry film testing to identify holidays in the coating.

3/4 Adhesion testing in accordance with ASTM D3359, ASTM D4541, or equivalent testing endorsed by RG 1.54 at a minimum of three locations.

3/4 Ultrasonic testing where there is evidence of pitting or corrosion to determine if the tank thickness meets the minimum thickness criteria.

x Revise Fire Water System Program procedures to include acceptance criteria of no abnormal debris (i.e., no corrosion products that could impede flow or cause downstream components to become clogged). Signs of abnormal corrosion or blockage will be removed, and its source and extent of condition determined and corrected. The condition will be entered into the corrective action program.

x Revise Fire Water System Program procedures to include the following acceptance criteria for the fire water tanks' interior coating:

3/4 Indications of peeling and delamination are not acceptable.

3/4 Blisters are evaluated by a coatings specialist qualified in accordance with an ASTM International standard endorsed in RG 1.54 including limitations, if any, identified in RG 1.54 associated with use of a particular standard. Blisters should be limited to a few intact small blisters that are not growing in number or size and are completely surrounded by sound coating/lining bonded to the substrate. Blister size and frequency should not be increasing between inspections (e.g., reference ASTM D714-02, "Standard Test Method for Evaluating Degree of Blistering of Paints").

RBS USAR Revision 27 A.1-19 3/4 Indications such as cracking, flaking, and rusting are evaluated by a coatings specialist qualified in accordance with an ASTM International standard endorsed in RG 1.54 including limitations, if any, identified in RG 1.54 associated with use of a particular standard.

3/4 As applicable, wall thickness measurements, projected to the next inspection, meet design minimum wall requirements.

3/4 Coating meets the plant-specific design requirements for the coating/lining and substrate, including the required degree of adhesion when performing adhesion testing.

3/4 Revise Fire Water System Program procedures to specify replacement of sprinkler heads that show signs of leakage, excessive loading, or corrosion.

x Revise Fire Water System Program procedures to perform an obstruction evaluation if any of the following conditions exist:

3/4 There is an obstructive discharge of material during routine flow tests.

3/4 An inspector's test valve is clogged during routine testing.

3/4 Foreign material is identified during internal inspections.

3/4 Sprinkler heads are found clogged during removal or testing.

3/4 Pin-hole leaks are identified in fire water piping.

3/4 After an extended fire water system shutdown (greater than one year).

x Revise Fire Water System Program procedures to evaluate for MIC if tubercules or slime are identified during internal inspections of fire water piping.

x Revise Fire Water System Program procedures to conduct augmented volumetric wall thickness examinations of fire water system piping. Inspections will be performed during the period of extended operation as long as the frequency of occurrence of loss of material meets the criteria for recurring internal corrosion. Procedures shall specify wall thickness measurements at a minimum of five selected locations per refueling cycle. The number of augmented examinations will be increased if substantial corrosion is detected during inspections. Corrosion will be considered substantial if the component does not meet plant-specific acceptance criteria (such as the minimum wall thickness required by the design code) or experiences a reduction in wall thickness greater than 50 percent of nominal wall thickness. For through-wall leaks and material loss greater than 50 percent of nominal wall thickness, four additional locations will be examined during the next refueling cycle. Where the identified material loss is 30 percent to 50 percent of nominal wall thickness and the calculated remaining life is less than two years, two additional locations will be examined during the next refueling cycle.

RBS USAR Revision 27 A.1-20 x

Revise Fire Water System Program procedures to perform a full flow test on hose rack HR96, Control Building 135'0" elevation stairwell in accordance with Section 6.3.1 of NFPA 25 (2011 edition).

x Revise Fire Water System Program procedures to test hydrants FHY9. FHY1 0 and FHY11 annually in accordance with Section 7.3.2 of NFPA 25 (2011 Edition) and test FHY13 with the hydrant valve partially open until any foreign material has cleared.

x Revise Fire Water System Program procedures to conduct examinations of the fire water storage tank floors. The first examination shall be performed prior to the period of extended operation (PEO) following removal of the existing coating and the subsequent examination will be performed during the first 10 years of the PEO.

The examinations shall consist of a low-frequency electromagnetic test (LFET) scan, or equivalent, and ultrasonic testing (UT) where there is indication of potential thinning of the floor plates. In place of the LFET scan, or equivalent, 25 UT thickness measurements may be performed of the tank floor (at least four measurements in each quadrant, at least three of which will examine the area within six inches of where the wall meets the floor).

Enhancements will be implemented prior to the period of extended operation.

A.1.21 Flow-Accelerated Corrosion The Flow-Accelerated Corrosion (FAC) Program manages loss of material due to wall thinning caused by FAC for piping and components through (a) performing an analysis to determine systems susceptible to FAC, (b) conducting appropriate analysis to predict wall thinning, (c) performing wall thickness measurements based on wall thinning predictions and operating experience, and (d) evaluating measurement results to determine the remaining service life and the need for replacement or repair of components. The FAC Program relies on implementation of guidelines published by EPRI in NSAC-202L and on internal and external operating experience.

The FAC program also manages wall thinning due to various erosion mechanisms in treated water or steam systems.

The FAC Program will be enhanced as follows:

x Revise FAC Program procedures to manage wall thinning due to erosion mechanisms such as cavitation, flashing, liquid droplet impingement, and solid particle impingement.

x Revise FAC Program procedures to include susceptible locations based on the extent-of-condition reviews in response to plant-specific or industry operating experience.

x Revise FAC Program procedures to (1) evaluate wall thinning due to erosion from cavitation, flashing, liquid droplet impingement, and solid particle impingement when determining a replacement type of material, and (2) ensure piping and components replaced with FAC-resistant material and subject to erosive conditions are not excluded from inspections until effectiveness of piping replacement or other corrective action has been confirmed.

x Revise procedures to ensure that error reporting continues to be performed for RBS FAC software during the period of extended operation.

Enhancements will be implemented prior to the period of extended operation.

RBS USAR Revision 27 A.1-21 A.1.22 Inservice Inspection The Inservice Inspection (ISI) Program manages cracking, loss of material, and reduction in fracture toughness for ASME Class 1, 2, and 3 pressure-retaining components including welds, pump casings, valve bodies, integral attachments, and pressure-retaining bolting using periodic volumetric, surface, and visual examination and leakage testing as specified in ASME Section XI code, as mandated by 10 CFR 50.55a. Additional limitations, modifications, and augmentations described in 10 CFR 50.55a are included as a part of this program. Every 10 years this program is updated to the latest ASME Section XI code edition and addendum approved by the NRC in accordance with 10 CFR 50.55a. Repair and replacement activities for these components are covered in Subsection IWA of the ASME code edition of record.

A.1.23 Inservice Inspection - IWF The Inservice Inspection (ISI) - IWF (ISI-IWF) Program performs periodic visual examinations of ASME Class 1, 2, and 3 piping and component supports to determine general mechanical and structural condition or degradation of component supports. The examinations include verification of clearances, settings and physical displacements, and identification of loose or missing parts, debris, corrosion, wear, erosion, or the loss of integrity at welded or bolted connections. The ISI-IWF Program is implemented through plant procedures which provide administrative controls, including corrective actions, for the conduct of activities that are necessary to fulfill the requirements of ASME Section XI, as mandated by 10 CFR 50.55a.

Every 10 years this program is updated to the latest ASME Section XI code edition and addendum approved by the NRC in accordance with 10 CFR 50.55a. The monitoring methods are effective in detecting the applicable aging effects, and the frequency of monitoring provides reasonable assurance that significant degradation can be identified prior to a loss of intended function.

The ISI-IWF Program includes plant procedures that use the recommendations delineated in NUREG-1339 and industry recommendations delineated in Electric Power Research Institute (EPRI) NP-5769, NP-5067 and TR-104213 to ensure proper specification of bolting material, lubricant, and installation torque.

The ISI-IWF Program will be enhanced as follows:

x Revise plant procedures to include the preventive actions for storage of ASTM A325, ASTM F1852, and ASTM A490 bolting from Section 2 of Research Council on Structural Connections publication, "Specification for Structural Joints Using ASTM A325 or A490 Bolts."

x Revise plant procedures to specify that detection of aging effects will include monitoring anchor bolts for loss of material, loose or missing nuts and bolts, and cracking of concrete around the anchor bolts.

x Revise plant procedures to include assessment of the impact on the inspection sample, in terms of sample size and representativeness, if components that are part of the sample population are re-worked.

x Revise plant procedures to specify the following conditions as unacceptable:

RBS USAR Revision 27 A.1-22 3/4 Loss of material due to corrosion or wear that reduces the load bearing capacity of the component support.

3/4 Debris, dirt, or excessive wear that could prevent or restrict sliding of the sliding surfaces as intended in the design basis of the support.

3/4 Cracked or sheared bolts, including high strength bolts, and anchors.

Enhancements will be implemented prior to the period of extended operation.

A.1.24 Inspection of Overhead Heavy Load and Light Load (Related to Refueling)

Handling Systems The Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program performs periodic inspections and preventive maintenance to manage loss of material due to corrosion, loose bolting or rivets, and rail wear of cranes and hoists, based on industry standards and guidance documents. The program includes structural components, including structural bolting, that make up the bridge, the trolley, lifting devices, and crane rails and includes cranes and hoists within the scope of license renewal and subject to aging management review. The activities entail visual examinations and functional testing to ensure that cranes and hoists are capable of sustaining their rated loads. The number and the magnitude of lifts made by the hoist or crane are also reviewed.

The Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program will be enhanced as follows:

x Revise plant procedures to ensure that the program manages loss of material due to wear for the crane rails; manages deformation, cracking, and loss of material due to corrosion for bridge, trolley and hoists structural components; and manages loss of bolting integrity for structural connections by monitoring for loose or missing bolts, nuts, pins or rivets and any other conditions indicative of loss of bolting integrity.

x Revise plant procedures to specify inspection frequency will be in accordance with ASME B30.2 or other appropriate standard in the ASME B30 series. The inaccessible or infrequently used cranes and hoists will be inspected prior to use.

Bolted connections will be visually inspected for loose or missing bolts, nuts, pins or rivets at the same frequency as crane rails and structural components.

x Revise plant procedures to specify the acceptance criteria for any visual indication of loss of material due to corrosion or wear and any visual sign of loss of bolting pre-load is evaluated according to ASME B30.2 or other applicable industry standard in the ASME B30 series.

x Revise plant procedures to specify that maintenance and repair activities will utilize the guidance provided in ASME B30.2 or other appropriate standard in the ASME B30 series.

Enhancements will be implemented prior to the period of extended operation.

RBS USAR Revision 28 A.1-23 A.1.25 Internal Surfaces in Miscellaneous Piping and Ducting Components The Internal Surfaces in Miscellaneous Piping and Ducting Components Program manages loss of material and change in material properties using representative sampling and opportunistic visual inspections of the internal surfaces of metallic and elastomeric components in environments of air - indoor, air - outdoor, condensation, exhaust gas, raw water, and waste water, and of fiberglass in treated water. Internal inspections will be performed during periodic system and component surveillances or during the performance of maintenance activities when the surfaces are accessible for visual inspection.

Where practical, the inspections will focus on the bounding or leading components most susceptible to aging because of time in service and severity of operating conditions. At a minimum, in each 10-year period during the period of extended operation, a representative sample of 20 percent of the population (defined as components having the same combination of material, environment, and aging effect) or a maximum of 25 components per population will be inspected. Opportunistic inspections will continue in each period even if the minimum sample size has been inspected.

For metallic components, visual inspection will be used to detect evidence of loss of material.

For fiberglass, visual inspection will be used to detect surface irregularities, which are evidence of change in material properties and cracking. For elastomeric components, visual inspections will be used to detect loss of material due to wear.

Specific acceptance criteria are as follows:

Stainless steel: clean surfaces, shiny, no abnormal surface condition.

Metals: no abnormal surface condition.

Fiberglass: no cracking, blistering, or other abnormal surface conditions.

Elastomers: a uniform surface texture and color with no cracks, no unanticipated dimensional change, and no abnormal surface conditions.

Conditions that do not meet the acceptance criteria are entered into the corrective action program for evaluation. Indications of relevant degradation will be evaluated using design standards, procedural requirements, current licensing basis, and industry codes or standards.

This program will be implemented prior to the period of extended operation.

A.1.26 Masonry Wall The Masonry Wall Program is based on guidance provided in I.E.Bulletin 80-11, "Masonry Wall Design," and Information Notice (IN) 87-67, "Lessons Learned from Regional Inspections of Licensee Actions in Response to I.E.Bulletin 80-11." The program includes masonry walls within the scope of license renewal as delineated in 10 CFR 54.4. The program manages aging effects so that the evaluation basis established for each masonry wall within the scope of license renewal remains valid through the period of extended operation.

The program includes periodic visual inspection of masonry walls in the scope of license renewal to detect loss of material and cracking of masonry units and mortar. The aging effects

RBS USAR Revision 27 A.1-24 are entered in the corrective action program for further analysis, repair, or replacement. The Structures Monitoring Program (Section A.1.41) manages the effects of aging on structural steel components, such as steel edge supports and steel bracing of masonry walls.

Masonry walls are inspected at least once every five years to ensure there is no loss of intended function.

The Masonry Wall Program will be enhanced as follows:

x Revise plant procedures to ensure masonry walls located in in-scope structures are included in the scope of the Masonry Wall Program.

x Revise plant procedures to include monitoring gaps between the structural steel supports and masonry walls that could potentially affect wall qualification.

x Revise plant procedures to specify that masonry walls will be inspected at least once every five years with provisions for more frequent inspections in areas where significant aging effects (missing blocks, cracking, etc.) are observed to ensure there is no loss of intended function between inspections.

x Revise plant procedures to include acceptance criteria for masonry wall inspections that ensure observed aging effects (cracking, loss of material, or gaps between the structural steel supports and masonry walls) do not invalidate the wall's evaluation basis or impact its intended function.

Enhancements to this program will be implemented prior to the period of extended operation.

A.1.27 Non-EQ Electrical Cable Connections The Non-EQ Electrical Cable Connections Program is a one-time inspection program that provides reasonable assurance that the intended functions of the metallic parts of electrical cable connections are maintained consistent with the current licensing basis through the period of extended operation. Cable connections included are those connections susceptible to age-related degradation resultingin increased resistance of connection due to thermal cycling, ohmic heating, electrical transients, vibration, chemical contamination, corrosion, or oxidation that are not subject to the environmental qualification requirements of 10 CFR 50.49.

This program provides for one-time inspections that will be completed prior to the period of extended operation on a sample of connections. The factors considered for sample selection will be application (medium and low voltage, defined as < 35 kV), circuit loading (high loading),

connection type, and location (high temperature, high humidity, vibration, etc.). The representative sample size will be based on 20 percent of the connection population with a maximum sample of 25.

Inspection methods may include thermography, contact resistance testing, or other appropriate quantitative test methods without removing the connection insulation, such as heat shrink tape, sleeving, or insulating boots.

The inspections will be performed prior to the period of extended operation.

A.1.28 Non-EQ Inaccessible Power Cables ( 400 V)

RBS USAR Revision 27 A.1-25 The Non-EQ Inaccessible Power Cables ( 400 V) Program manages the aging effect of reduced insulation resistance on the inaccessible power cable systems ( 400 V) that have a license renewal intended function. The program includes periodic actions to minimize inaccessible cable exposure to significant moisture. Significant moisture is defined as periodic exposures to moisture that last more than a few days (e.g., cable wetting or submergence in water). In this program, inaccessible power cables ( 400 V) exposed to significant moisture are tested at least once every six years to provide an indication of the condition of the cable insulation properties. Test frequencies are adjusted based on test results and operating experience. The specific type of test performed is a proven test for detecting deterioration of the cable insulation. A proven, commercially available test will be used for detecting deterioration of the insulation system due to wetting or submergence for inaccessible power cables ( 400 V) included in this program, such as dielectric loss (dissipation factor/power factor), AC voltage withstand, partial discharge, step voltage, time domain reflectometry, insulation resistance and polarization index, line resonance analysis, or other testing that is state-of-the-art at the time the tests are performed.

The program includes periodic inspections for water accumulation in manholes at least once every year (annually). In addition to the periodic manhole inspections, manhole inspections for water after event-driven occurrences, such as flooding, will be performed. The inspections will include direct observation that cables are not wetted or submerged, that cables, splices, and cable support structures are intact, and dewatering systems (i.e., sump pumps) and associated alarms, if applicable, operate properly. Inspection frequency will be increased as necessary based on evaluation of inspection results. In addition to the periodic manhole inspections, operation of dewatering systems will be inspected, and operation verified prior to any known or predicted heavy rain or flooding events.

This program will be implemented prior to the period of extended operation.

A.1.29 Non-EQ Insulated Cables and Connections The Non-EQ Insulated Cables and Connections Program provides reasonable assurance the intended functions of insulated cables and connections 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. An adverse localized environment is a condition in a limited plant area that is significantly more severe than the plant design environment for the cable or connection insulation materials.

Accessible insulated cables and connections within the scope of license renewal installed in an adverse localized environment will be visually inspected for cable and connection jacket surface anomalies, such as embrittlement, discoloration, cracking, melting, swelling, or surface contamination. The program inspection includes all accessible cables and connections in localized adverse environments. The condition of accessible cables will represent, with reasonable assurance, all cables and connections in the adverse localized environment.

This program will visually inspect accessible cables in an adverse localized environment at least once every 10 years, with the first inspection prior to the period of extended operation.

This program will be implemented prior to the period of extended operation.

A.1.30 Non-EQ Sensitive Instrumentation Circuits Test Review

RBS USAR Revision 27 A.1-26 The Non-EQ Sensitive Instrumentation Circuits Test Review Program manages the aging effects of the applicable cables in the neutron monitoring and process radiation monitoring systems or sub-systems. The program provides reasonable assurance the intended functions of sensitive, high-voltage, low-signal cables exposed to adverse localized equipment environments caused by heat, radiation and moisture (i.e., neutron flux monitoring instrumentation and process radiation monitoring) can be maintained consistent with the current licensing basis through the period of extended operation. Most 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 or findings of surveillance testing programs will be performed once every 10 years, with the first review occurring 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 system (such as insulation resistance tests or time domain reflectometry) will occur at least once every 10 years, with the first test occurring before the period of extended operation. Applicable industry standards and guidance documents are used to delineate the program.

This program will be implemented prior to the period of extended operation.

A.1.31 Oil Analysis The Oil Analysis Program ensures that loss of material and reduction of heat transfer are not occurring by maintaining the quality of the lubricating oil. The program ensures that contaminants (primarily water and particulates) are within acceptable limits. Testing activities include sampling and analysis of lubricating oil for contaminants. The presence of water can indicate in-leakage, and particulates can be indicative of corrosion products.

The One-Time Inspection Program uses inspections or non-destructive evaluations of representative samples to verify that the Oil Analysis Program has been effective at managing the aging effects of loss of material and reduction of heat transfer.

A.1.32 One-Time Inspection The One-Time Inspection Program consists of a one-time inspection of selected components to accomplish the following:

x Verify the effectiveness of aging management programs designed to prevent or minimize the effects of aging to the extent that they will not cause the loss of intended function during the period of extended operation. The aging effects evaluated are loss of material, cracking, and reduction of heat transfer.

x Confirm the insignificance of an aging effect using inspections that verify unacceptable degradation is not occurring.

x In the event of unacceptable inspection results, trigger additional actions that ensure the intended functions of affected components are maintained during the period of extended operation.

The sample size will be 20 percent of the components in each material-environment-aging effect group up to a maximum of 25 components. Identification of inspection locations will be based

RBS USAR Revision 28 A.1-27 on the potential for the aging effect to occur. Examination techniques will be established NDE methods with a demonstrated history of effectiveness in detecting the aging effect of concern, including visual, ultrasonic, and surface techniques. Acceptance criteria will be based on applicable ASME or other appropriate standards, design basis information, or vendor-specified requirements and recommendations. Any indication or relevant condition will be evaluated.

The need for follow-up examinations will be evaluated based on inspection results.

The One-Time Inspection Program will not be used for structures or components with known aging mechanisms or when the environment in the period of extended operation is not expected to be equivalent to that in the prior 40 years.

The program will include activities to verify effectiveness of aging management programs and activities to confirm the insignificance of aging effects as described below.

Diesel Fuel Monitoring Program (Section A.1.15)

One-time inspection activity will verify the effectiveness of the Diesel Fuel Monitoring Program by confirming that unacceptable loss of material and fouling are not occurring.

Oil Analysis Program (Section A.1.31)

One-time inspection activity will verify the effectiveness of the Oil Analysis Program by confirming that unacceptable loss of material, cracking, and fouling are not occurring.

Water Chemistry Control - BWR Program (Section A.1.42)

One-time inspection activity will verify the effectiveness of the Water Chemistry Control -

BWR Program by confirming that unacceptable cracking, loss of material, and fouling are not occurring.

Reactor vessel flange leak detection components One-time inspection activity of leak detection components (not including the N17 nozzle) will confirm that cracking and loss of material are not occurring or are occurring so slowly that the aging effect will not affect the component intended function during the period of extended operation.

A representative sample of internal and external surfaces of RHR piping passing through the waterline region of the suppression pool One-time inspection activity will confirm that loss of material is not occurring or is occurring so slowly that the aging effect will not affect the component intended function during the period of extended operation.

RBS USAR Revision 27 A.1-28 A representative sample of internal and external surfaces of nuclear pressure relief piping passing through the waterline region of the suppression pool One-time inspection activity will confirm that loss of material is not occurring or is occurring so slowly that the aging effect will not affect the component intended function during the period of extended operation.

A representative sample of internal and external surfaces of RCIC piping passing through the waterline region of the suppression pool One-time inspection activity will confirm that loss of material is not occurring or is occurring so slowly that the aging effect will not affect the component intended function during the period of extended operation.

A representative sample of stainless steel component external surfaces exposed to outdoor air A one-time surface examination will confirm that cracking of components externally exposed to air recently introduced into a building is not occurring.

A representative sample of stainless steel component external surfaces exposed to outdoor air A one-time visual examination will confirm that loss of material of components externally exposed to air recently introduced into a building is not occurring.

A representative sample of aluminum component external surfaces exposed to outdoor air A one-time visual examination will confirm that loss of material of components externally exposed to air recently introduced into a building is not occurring.

A representative sample of service water system containment and auxiliary building vacuum release piping that cannot be vented between the check valves and the treated water source.

One-time inspection will confirm that loss of material is not occurring or is occurring so slowly that the aging effect will not affect the component intended function during the period of extended operation.

Inspections will be performed within the 10 years prior to the period of extended operation.

A.1.33 One-Time Inspection - Small-Bore Piping The One-Time Inspection - Small-Bore Piping Program augments ASME Code,Section XI requirements and is applicable to small-bore ASME Code Class 1 piping and components with a nominal pipe size diameter less than 4 inches (NPS < 4) and greater than or equal to NPS 1 in systems that have not experienced cracking of ASME Code Class 1 small-bore piping. The

RBS USAR Revision 28 A.1-29 program can also be used for systems that have experienced cracking but have implemented design changes to effectively mitigate cracking.

The program provides a one-time volumetric or opportunistic destructive inspection of a 3-percent sample or maximum of 10 ASME Class 1 piping butt weld locations and a 3-percent sample or a maximum of 10 ASME Class 1 socket weld locations that are susceptible to cracking. Volumetric examinations are performed using a demonstrated technique that is capable of detecting the aging effects in the volume of interest. In the event the opportunity arises to perform a destructive examination of an ASME Class 1 small-bore socket weld that meets the susceptibility criteria, then the program takes credit for two volumetric examinations.

The program includes pipes, fittings, branch connections, and full and partial penetration welds.

This program includes a sampling approach. Sample selection is based on susceptibility to stress corrosion, cyclic loading (including thermal, mechanical, and vibration fatigue), thermal stratification, thermal turbulence, dose considerations, operating experience, and limiting locations of total population of ASME Class 1 small-bore piping locations.

The program includes measures to verify that degradation is not occurring, thereby either confirming that there are no aging effects requiring management or validating the effectiveness of any existing program for the period of extended operation. If evidence of cracking is revealed by this one-time inspection, it will be entered into the corrective action program to determine extent of condition, and a follow-up periodic inspection will be managed by a plant-specific program.

The inspection will be performed within the six years prior to the period of extended operation.

A.1.34 Periodic Surveillance and Preventive Maintenance The Periodic Surveillance and Preventive Maintenance (PSPM) Program includes periodic inspections and tests to manage aging effects including cracking, loss of material, reduction of heat transfer, in cases where no NUREG-1801 program was found appropriate to manage the particular aging effects for specific components. At a minimum, in each 10-year period during the period of extended operation, a representative sample of 20 percent of the population (defined as components having the same combination of material, environment, and aging effect) or a maximum of 25 components per population is inspected. Where practical, the inspections will focus on the bounding or leading components most susceptible to aging because of time in service and severity of operating conditions. Indications or relevant conditions of degradation detected are evaluated.

Credit for program activities has been taken in the aging management review for the following components or commodities.

RBS USAR Revision 27 A.1-30 x

Visually inspect the surface of the high-pressure core spray, residual heat removal, low pressure core spray, and reactor core isolation cooling suppression pool suction strainers for debris.

x In the plant drains system, visually inspect the internal and external surface of pump casings and piping components within sumps to manage loss of material and cracking.

Visually inspect the external surface of the pump suction strainer within sumps to manage loss of material.

x In the service water system, visually inspect the external surfaces of SWC and SWP pump casings to manage loss of material.

x For the standby diesel generators, visually inspect the external surface of heat exchanger (intercooler) tube fins to manage reduction of heat transfer at least once every eight years.

x Inspect the internal surfaces of abandoned equipment in the following nonsafety-related systems affecting safety-related systems to manage loss of material:

3/4 Leak detection system (system code 207) 3/4 Makeup water system (system code 659) 3/4 Fuel pool cooling system (system code 602) 3/4 Reactor water cleanup system (system code 601) 3/4 Standby service water system (system code 256) 3/4 Process radiation monitoring system (system code 511 3/4 Floor and equipment drains system (system code 609) x For metallic components, visually inspect components in the following systems to detect evidence of reduction of heat transfer:

3/4 Service water system 3/4 Fire protection - water system 3/4 Combustible gas control system 3/4 Standby diesel generator system 3/4 HPCS diesel generator system 3/4 Control building HVAC system 3/4 Miscellaneous HVAC systems

RBS USAR Revision 27 A.1-31 x

For metallic components, visually inspect components in the following systems, and when appropriate, perform surface examinations, to detect evidence of cracking:

3/4 Combustible gas control system 3/4 Standby diesel generator system 3/4 HPCS diesel generator system 3/4 Control building HVAC system 3/4 Plant drains system x

Inspect the following heat exchanger surfaces exposed to normal service water for fouling and flow blockage:

3/4 EGT-E1A, B standby diesel generator jacket water coolers, at a frequency of once per ten years.

3/4 E22-ES001, HPCS diesel generator system, at a frequency of once per twelve years.

3/4 HVK-CHL 1A, B, C, D, control building chillers, at a frequency of once per six years.

x Inspect the surface of the polymer high-voltage insulators for transmission conductors on the RSS#1 and RSS#2 lines x

Perform corona scans (UV) of the polymer high-voltage insulators for transmission conductors on the RSS#1 and RSS#2 lines The PSPM Program will be enhanced as follows:

x Revise PSPM Program procedures as necessary to incorporate the activities identified above.

x Revise PSPM Program procedures to state that the acceptance criterion is no indication of relevant degradation and that such indications will be evaluated.

Enhancements will be implemented prior to the period of extended operation.

A.1.35 Protective Coating Monitoring and Maintenance The Protective Coating Monitoring and Maintenance Program manages the effects of aging on Service Level I coatings applied to external surfaces of carbon steel and concrete inside containment (e.g., steel containment vessel shell, structural steel, supports, penetrations, and concrete walls and floors). The program is implemented using the guidance provided in Regulatory Guidance 1.54 and ASTM D 5163-08. The program provides an effective method to assess coating condition through visual inspections by identifying degraded or damaged coatings and providing a means for repair of identified problem areas.

RBS USAR Revision 27 A.1-32 Service Level I protective coatings are not credited to manage the effects of aging. Proper monitoring and maintenance of protective coatings inside containment ensures operability of post-accident safety systems that rely on water recycled through the containment. The proper monitoring and maintenance of Service Level I coatings ensures there is no coating degradation that would impact safety functions, for example, by clogging emergency core cooling system suction strainers.

A.1.36 Reactor Head Closure Studs The Reactor Head Closure Studs Program manages cracking and loss of material due to wear or corrosion for reactor head closure studs bolting (studs, washers, nuts, and flange threads) using inservice inspection and preventive measures to mitigate the effects of aging. Preventive actions include use of an acceptable surface treatment, use of stable lubricants, use of bolting materials with low susceptibility to SCC, and avoidance of the use of metal-plated stud bolting.

The program detects cracks, loss of material, and leakage using visual, surface, and volumetric examinations as required by ASME Section XI. Every 10 years this program is updated to the latest ASME Section XI code edition and addendum approved by the NRC in accordance with 10 CFR 50.55a. The program also relies on recommendations to address reactor head closure bolting degradation listed in NUREG-1339 and NRC RG 1.65.

The Reactor Head Closure Studs Program will be enhanced as follows:

x Revise Reactor Head Closure Studs Program procedures associated with procurement requirements to ensure replacement studs are fabricated from bolting material with actual measured yield strength less than 150 ksi.

The enhancement will be implemented prior to the period of extended operation.

A.1.37 Reactor Vessel Surveillance The Reactor Vessel Surveillance Program manages reduction of fracture toughness and long-term operating conditions for reactor vessel beltline materials as defined by 10 CFR 50 Appendix G, Section II.F using material data and dosimetry. The program ensures that the specimen exposure, capsule withdrawal, sample testing, and capsule storage meet the requirements of 10 CFR 50, Appendix H for vessel material surveillance and American Society for Testing and Materials (ASTM) E 185.

The program provides sufficient material data and dosimetry to (a) monitor irradiation embrittlement at the end of the period of extended operation and (b) establish operating restrictions on the inlet temperature, neutron spectrum, and neutron flux after a surveillance capsule is withdrawn for testing. Surveillance capsule testing and reporting, to the extent practicable, is performed in accordance with the requirements of ASTM E 185 Standard.

The Reactor Vessel Surveillance Program has been integrated into the BWRVIP Integrated Surveillance Program (ISP). The surveillance sample materials remaining in the RBS reactor pressure vessel (RPV) are maintained for possible future use. The BWRVIP ISP replaces individual plant reactor pressure vessel surveillance capsule programs with representative weld and base materials data from host reactors. Throughout the term of the ISP, the BWRVIP monitors the progress, coordinates actions such as withdrawal and testing of capsules and reporting of surveillance capsule test results, and identifies additional program needs.

The BWRVIP identifies and implements changes to the program as the need arises. When specific changes are identified to the ISP testing matrix, withdrawal schedule, or testing and

RBS USAR Revision 27 A.1-33 reporting of individual capsule results, these modifications are submitted to the NRC in a timely manner so that appropriate arrangements can be made for implementation. RBS maintains participation in the BWRVIP ISP consistent with provisions of NUREG-1801 Section XI.M31.

The integrated surveillance program for the extended period of operation (ISP(E)), based on BWRVIP document BWRVIP-86, Revision 1-A, has been approved for use by the NRC.

BWRVIP-135 and ISP capsule reports BWRVIP-113NP, Revision 1; BWRVIP-87NP, Revision 1; BWRVIP-111 NP, Revision 1; and BWRVIP-169NP, Revision 1, provide reactor pressure vessel surveillance data and other technical material information for the plants participating in the ISP for use in predicting adjusted reference temperature and upper shelf energy at the end of the period of extended operation.

A.1.38 RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants RBS is not committed to the requirements of RG 1.127; however, the RBS RG 1.127 program was developed based on guidance provided in RG 1.127, Revision 1, and provides an inservice inspection and surveillance program for the RBS raw water-control structures associated with standby service water cooling and service water cooling systems or flood protection. The program performs periodic visual examinations to monitor the condition of water-control structures and structural components, including structural steel and structural bolting associated with water-control structures and miscellaneous steel associated with these structures. The program addresses degradation due to the effects of aging, degradation due to extreme environmental conditions, and the effects of natural phenomena that may affect water-control structures. The program requires periodic monitoring and maintenance of water-control structures so that the consequences of degradation due to the effects of aging can be prevented or mitigated in a timely manner.

The program will perform periodic sampling and chemical analysis of ground water for pH, chlorides, and sulfates on a frequency of at least once every five years to ensure that the ground water has not become aggressive.

The RG 1.127 Program will be enhanced as follows:

x Revise plant procedures to include a list of structural components and commodities within the scope of license renewal to be monitored in the program.

x Revise plant procedures to include the preventive actions for storage of ASTM A325, ASTM F1852, and ASTM A490 bolting from Section 2 of Research Council on Structural Connections publication, "Specification for Structural Joints Using ASTM A325 or A490 Bolts."

x Revise plant procedures to include the following parameters to be monitored or inspected:

3/4 For concrete structures and components, include loss of material, loss of bond, increase in porosity and permeability, loss of strength, and reduction in concrete anchor capacity due to local concrete degradation.

3/4 For chemical analysis of ground water, monitor pH, chlorides and sulfates.

RBS USAR Revision 28 A.1-34 3/4 Anchor bolts (nuts and bolts) for loss of material, and loose or missing nuts and bolts.

x Revise plant procedures to include the following requirements:

3/4 Structures will be inspected on an interval not to exceed five years with provisions for more frequent inspections of structures and components categorized as (a)(1) in accordance with 10 CFR 50.65.

3/4 Inspection of submerged structures at the same inspection interval and limitations as the other structures in the program.

3/4 Sampling and chemical analysis of ground water at least once every five years. The program owner will review the results, evaluate anomalies, and trend the results.

Enhancements will be implemented prior to the period of extended operation.

A.1.39 Selective Leaching The Selective Leaching Program demonstrates the absence of selective leaching through assessment of a sample of components (i.e., 20 percent of the population with maximum of 25 components) fabricated from gray cast iron and copper alloys (except for inhibited brass) that contain greater than 15 percent zinc or greater than 8 percent aluminum in an environment of raw water, treated water, waste water, or soil. A population is defined as components with the same material and environment combination. Where practical, the sample will focus on components most susceptible to the effects of aging due to time in service, severity of operating condition, and lowest design margin. The program will include a one-time visual inspection of selected components coupled with mechanical examination techniques such as destructive testing, scraping, or chipping to determine whether loss of material is occurring due to selective leaching that may affect the ability of a component to perform its intended function through the period of extended operation.

For buried components with coatings, no selective leaching inspections are necessary where coating degradation has not been identified. For buried components with degraded coating or no coatings, the sample size is 20 percent of the population up to a maximum of 25 components. If only minor coating damage has been identified, the sample size may be reduced to 5 percent of the population with a maximum of 6 components. Minor coating degradation is defined as (a) there were no more than two instances of degradation identified in the 10-year period prior to the period of extended operation, and (b) the pipe could be shown to meet unreinforced opening criteria of the applicable piping code when assuming the pipe surface affected by the coating degradation is a through-wall hole.

Follow-up of unacceptable inspection findings includes an evaluation using the corrective action program and expansion of the inspection sample size and location.

These inspections will be performed within the five years prior to the period of extended operation.

A.1.40 Service Water Integrity The Service Water Integrity Program manages loss of material and reduction of heat transfer for service water system components fabricated from carbon steel, carbon steel with copper

RBS USAR Revision 27 A.1-35 cladding, stainless steel, and copper alloy in an environment of treated water. The program includes periodic (a) testing of the RHR heat exchangers to verify heat transfer capability, (b) inspection and maintenance of the auxiliary building unit coolers, (c) routine maintenance (cleaning) of the RHR heat exchanger radiation monitor coolers, and (d) routine maintenance (cleaning) of the penetration valve leakage control system (PVLCS) compressor aftercoolers.

The program includes inspecting the safety-related carbon steel piping in the standby service water cooling tower exposed to raw water. Inspections will include submerged piping and the distribution piping in the tower at locations with an air-to-water interface. The nozzles on the standby service water distribution piping are inspected. There are no internal coatings in components crediting the Service Water Integrity Program for managing the effects of aging.

The Service Water Integrity Program will be enhanced as follows:

3/4 Revise Service Water Integrity Program documents to inspect the safety-related carbon steel piping in the standby service water cooling tower exposed to raw water.

Inspections will include visual inspection of accessible submerged piping at least once every 10 years. Five volumetric inspections per 10-year period of the period of extended operation will be performed to determine wall thickness of the horizontal distribution piping in the tower at locations with an air-to-water interface.

Enhancements will be implemented prior to the period of extended operation.

A.1.41 Structures Monitoring The Structures Monitoring Program manages the effects of aging on structures and structural components, including structural bolting, within the scope of license renewal.

The program was developed based on guidance in RG 1.160, Revision 2, "Monitoring the Effectiveness of Maintenance at Nuclear Power Plants," and NUMARC 93-01, Revision 2, "Industry Guidelines for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants,"

to satisfy the requirement of 10 CFR 50.65, "Requirements for Monitoring the Effectiveness of Maintenance at Nuclear Power Plants." Inspections are performed at least once every five years to ensure that aging degradation leading to loss of intended functions will be detected and that the extent of degradation can be determined to ensure there is no loss of intended function between inspections. The scope of the Structures Monitoring Program includes structures within the scope of license renewal as delineated in 10 CFR 54.4.

The Structures Monitoring Program includes plant procedures that use the guidance delineated in NUREG-1339 and industry recommendations delineated in EPRI NP-5769, NP-5067 and TR-104213 to ensure proper specification of bolting material, lubricant, and installation torque.

The Structures Monitoring Program will be enhanced as follows:

x Revise plant procedures to include the following in-scope structures:

3/4 Auxiliary control building 3/4 Circulating water switchgear house No. 1 3/4 Condensate storage tank foundation 3/4 Electrical tunnels and piping tunnels 3/4 Fire protection storage tanks foundation 3/4 Fuel oil storage tank foundation

RBS USAR Revision 28 A.1-36 3/4 Manholes, handholes and duct banks 3/4 Transformer and switchyard support structures and foundations x

Revise plant procedures to include a list of structural components and commodities within the scope of license renewal.

x Revise plant procedures to include periodic sampling and chemical analysis of ground water.

x Revise plant procedures to include the preventive actions for storage of ASTM A325, ASTM F1852, and ASTM A490 bolting from Section 2 of Research Council on Structural Connections publication, "Specification for Structural Joints Using ASTM A325 or A490 Bolts."

x Revise plant procedures to include the following parameters to be monitored or inspected:

3/4 For concrete structures and components, include loss of material, loss of bond, increase in porosity and permeability, loss of strength, and reduction in concrete anchor capacity due to local concrete degradation.

3/4 For chemical analysis of ground water, monitor pH, chlorides and sulfates.

x Revise plant procedures to include the following components to be monitored for the associated parameters:

3/4 Anchor bolts (nuts and bolts) for loss of material, and loose or missing nuts and bolts.

3/4 Elastomeric vibration isolators and structural sealants for cracking, loss of material, loss of sealing, and change in material properties (e.g., hardening).

x Revise plant procedures to include the following:

3/4 Visual inspection of elastomeric material should be supplemented by feel or touch to detect hardening if the intended function of the elastomeric material is suspect.

Include instructions to augment the visual examination of elastomeric material with physical manipulation of at least 10 percent of available surface area.

3/4 Inspection of submerged structures at the same inspection interval and limitations as the other structures in the program.

3/4 Sampling and chemical analysis of ground water at least once every five years. The program owner will review the results and evaluate any anomalies and perform trending of the results.

x Revise plant procedures for procuring bolting greater than one inch in diameter to only procure bolting material with actual measured yield strength less than 150 ksi.

Enhancements will be implemented prior to the period of extended operation.

RBS USAR Revision 28 A.1-37 A.1.42 Water Chemistry Control - BWR The Water Chemistry Control - BWR Program manages loss of material, cracking and reduction of heat transfer in components in an environment of treated water through periodic monitoring and control of water chemistry. The Water Chemistry Control - BWR Program monitors and controls chemical species and water quality to keep levels of various contaminants below system-specific limits. BWRVIP-190, BWR Water Chemistry Guidelines, provides guidance for the program.

The One-Time Inspection Program (Section A.1.32) uses inspections or non-destructive evaluations of representative samples to verify that the Water Chemistry Control - BWR Program has been effective at managing aging effects. The representative sample includes low flow and stagnant areas.

A.1.43 Water Chemistry Control - Closed Treated Water Systems The Water Chemistry Control - Closed Treated Water Systems Program manages loss of material, cracking, and reduction of heat transfer in components in a closed treated water environment through monitoring and control of water chemistry, including the use of corrosion inhibitors, chemical testing, and visual inspections of internal surfaces. The EPRI Closed Cooling Water Guideline, industry and site operating experience, and vendor recommendations are used to delineate the program.

The Water Chemistry Control - Closed Treated Water Systems Program will be enhanced as follows:

x Revise the Water Chemistry Control - Closed Treated Water Systems Program procedures to inspect accessible components whenever a closed treated water system boundary is opened. Ensure that a representative sample of piping and components is inspected at a frequency of at least once every 10 years.

x These inspections will be conducted in accordance with applicable ASME Code requirements, industry standards, or other plant-specific inspection guidance by qualified personnel using procedures that are capable of detecting loss of material, reduction of heat transfer, or cracking.

x If visual examination identifies adverse conditions, then additional examinations, including ultrasonic testing, are conducted. Components inspected will be those with the highest likelihood of corrosion, reduction of heat transfer due to fouling, or cracking.

x A representative sample is 20 percent of the population (defined as components having the same material, environment, and aging effect combination) with a maximum of 25 components. Components inspected will be those with the highest likelihood of loss of material, reduction of heat transfer, or cracking.

x Revise the Water Chemistry Control - Closed Treated Water Systems Program procedures to provide acceptance criteria for inspections of accessible components.

Ensure system components meet system design requirements, such as minimum wall thickness.

Enhancements will be implemented prior to the period of extended operation.

RBS USAR Revision 28 A.1-38 A.1.44 Metal-Enclosed Bus Inspection Program The Metal-Enclosed Bus Inspection Program provides for the inspection of the internal and external portions of metal-enclosed bus (MEB) to identify the effects of aging on the bus and bus connections, the bus enclosure assemblies, and the bus insulation and insulators. The program will inspect the MEB in the power supply path from the preferred station transformers RTX-XSR1E and RTX-XSR1F to 13.8 KV switchgear NPS-SWG1A and NPS-SWG1B. The included buses are RTX-BD1A for NPS-SWG1A and RTX-BD1B for NPS-SWG1B.

The program provides for the visual inspection of MEB, including the enclosure internal surface, insulation, and bus supports. The MEB enclosure internal surfaces are visually inspected for evidence of loss of material, aging degradation of the insulating supports, cracks, corrosion, foreign debris, excessive dust buildup, and evidence of moisture intrusion. MEB insulation is visually inspected for signs of embrittlement, cracking, melting, swelling, surface contamination and discoloration. The internal bus insulating supports, or insulators will be inspected for structural integrity, signs of cracks, and loose or damaged mounting hardware. MEB external surfaces are visually inspected for loss of material. Accessible elastomers (e.g., gaskets, boots, and sealants) are inspected for indications of change in material properties, such as surface cracks.

A sample of accessible bolted electrical connections will be inspected for increased connection resistance by thermography or by measuring connection resistance using a micro-ohmmeter.

Thermography can be credited on bus connections with the MEB covers in place only if the bus enclosure is equipped with an infrared window to facilitate the inspection. A representative sample is 20 percent of the population with a maximum sample of 25.

MEB inspections, including sampling of accessible bolted connections, are performed at least once every 10 years beginning in the 10-year period prior to the period of extended operation.

As an alternative to thermography or measuring connection resistance of accessible bolted connections covered with heat shrink tape, sleeving, insulations boots, etc., visual inspection of insulation material may be used to detect surface anomalies, such as embrittlement, cracking, melting, discoloration, swelling, or surface contamination When this alternative visual inspection is used to check bolted connections, inspections are performed at least once every 5-years beginning in the 10-year period prior to the period of extended operation.

RBS USAR Revision 27 A.2-2 A.2.1.3 Pressure-Temperature Limits Appendix G of 10 CFR 50 requires that the reactor vessel remain within established pressure-temperature (P-T) limits. These limits are calculated using fluence and materials data, including data obtained through the Reactor Vessel Surveillance Program (Section A.1.37).

The P-T limit curves will continue to be updated, as required by Appendix G of 10 CFR Part 50, assuring that limits remain valid through the period of extended operation.

The effects of aging associated with the P-T limits will be managed for the period of extended operation in accordance with 10 CFR 54.21(c)(1)(iii).

A.2.1.4 Upper Shelf Energy Upper shelf energy (USE) is evaluated for beltline materials. Fracture toughness criteria in 10 CFR 50 Appendix G require that beltline materials maintain USE no less than 50 ft-lb during operation of the reactor unless it is demonstrated that lower values of Charpy upper-shelf energy will provide margins of safety against fracture equivalent to those required by Appendix G of Section XI of the ASME Code. The 54 EFPY USE values for the beltline materials were determined using methods consistent with RG 1.99, Revision 2. The value of peak 1/4T fluence was used. The results of the evaluation demonstrate that all beltline materials meet the 10 CFR 50 Appendix G criteria through 54 EFPY.

The time-limited aging analysis for USE has been projected to the end of the period of extended operation in accordance with 10 CFR 54.21(c)(1)(ii).

A.2.1.5 Reactor Vessel Circumferential Weld Inspection Relief Relief from reactor vessel circumferential weld inservice inspection (ISI) examination requirements was granted by the NRC. The reactor vessel circumferential weld inspection relief for the period of extended operation will be submitted to the NRC in accordance with 10 CFR 50.55(a). The effects of aging associated with the time-limited aging analysis for reactor vessel circumferential weld inspection relief will be managed in accordance with 10 CFR 54.21(c)(1)(iii).

A.2.1.6 Reactor Vessel Axial Weld Failure Probability The NRC safety evaluation report (SER) for BWRVIP-74-A evaluated the failure frequency of axially oriented welds in BWR reactor vessels. Applicants for license renewal must evaluate axially oriented RPV welds to show that their failure frequency remains below the value calculated in the BWRVIP-74 SER.

The SER states that an acceptable way to do this is to show that the mean RTNDT of the limiting axial beltline weld at the end of the period of extended operation is less than the values specified in the SER.

The projected 54 EFPY RBS mean RTNDT values are less than the 32 EFPY mean RTNDT provided by the NRC SER for BWRVIP-05. The reactor vessel axial weld failure probability TLAA has been projected through the period of extended operation in accordance with 10 CFR 54.21(c)(1)(ii).

RBS USAR Revision 27 A.2-3 A.2.1.7 Reactor Pressure Vessel Core Reflood Thermal Shock Analysis General Electric Report NEDO-10029 is referenced in USAR Section 5.3. NEDO-10029 addressed the concern for brittle fracture of the reactor pressure vessel due to reflood following a postulated loss of coolant accident (LOCA). The thermal shock analysis documented in the report assumed a design basis LOCA followed by a low pressure coolant injection (LPCI),

accounting for the effects of neutron embrittlement at the end of 40 years. Because this analysis bounded only 40 years of operation, reflood thermal shock of the reactor pressure vessel has been identified as a TLAA requiring evaluation for the period of extended operation.

A later analysis of the BWR vessels was developed in 1979 (Ranganath, S., "Fracture Mechanics Evaluation of a Boiling Water Reactor Vessel Following a Postulated Loss of Coolant Accident," Fifth International Conference on Structural Mechanics in Reactor Technology, Berlin, Germany, August 1979 (Accession No. 9110110105 in NRC ADAMS Public Legacy Library)). The Ranganath analysis has been used to evaluate the TLAA through the period of extended operation because it evaluates the bounding LOCA event for a BWR-6 vessel design, which is a main steam line break.

The maximum ART value calculated for the RBS RPV beltline material is 110.7°F. Using the equation for fracture toughness KIC presented in Appendix A of ASME Section XI and the maximum ART value, the material reaches upper shelf at 215°F, which is well below the minimum 380°F temperature predicted for the thermal shock event at the time of peak stress intensity. Therefore, the revised analysis has projected the TLAA through the period of extended operation. The reactor pressure vessel core reflood thermal shock TLAA has been projected to the end of the period of extended operation in accordance with 10 CFR 54.21(c)(1)(ii).

A.2.2 Metal Fatigue A.2.2.1 Class 1 Metal Fatigue Fatigue evaluations were performed in the design of RBS Class 1 components in accordance with their design requirements. ASME Section III fatigue evaluations are contained in analyses and stress reports, and because they are based on a number of transient cycles assumed for a 40-year operating term, these evaluations are considered TLAA.

RBS utilizes cycle counting, cycle-based fatigue monitoring, and stress-based fatigue monitoring. The Fatigue Monitoring Program (Section A.1.18) tracks and evaluates transient cycles and requires corrective actions if limits are approached.

The Fatigue Monitoring Program ensures that the numbers of transient cycles experienced by the plant remain within the numbers of cycles assumed in the fatigue analysis.

The following provides additional information for specific Class 1 components.

Reactor Pressure Vessel As described in USAR Section 5.3.3.1 and shown in USAR Figure 5.3-1, the reactor pressure vessel is a vertical, cylindrical pressure vessel of welded construction.

Stress-based fatigue analyses are used for monitoring the RBS feedwater nozzles. The transients necessary to track to ensure the continuing validity of fatigue analyses for other RPV locations have been identified. The Fatigue Monitoring Program (Section A.1.18) will manage

RBS USAR Revision 27 A.2-4 the effects of aging due to fatigue on the reactor vessel in accordance with 10 CFR 54.21(c)(1)(iii).

Reactor Pressure Vessel Internals For reactor vessel internals components with fatigue TLAAs, the effects of aging due to fatigue will be managed by the BWR Vessel Internals Program (Section A.1.10) for the period of extended operation in accordance with 10 CFR 54.21(c)(1)(iii). The program performs inspections and flaw evaluations in accordance with the guidelines of applicable BWRVIP reports. This program manages the aging effects of cracking, loss of preload, loss of material, and reduction in fracture toughness for BWR vessel internal components in a reactor coolant environment.

BWRVIP guidance does not specify inspection of the core plate and core plate stiffener beams.

A review of the associated fatigue calculation determined the usage factors for the core plate and stiffener beams would remain below 1 with the cycles projected for 60 years of operation.

The counting of cycles under the Fatigue Monitoring Program (Section A.1.18) will ensure these usage factors remain below 1. Therefore, the Fatigue Monitoring Program will manage the effects of aging due to fatigue of the core plate and stiffener beams in accordance with 10 CFR 54.21 (c)(1 )(iii).

Reactor Recirculation Pumps As described in USAR Section 3.9.3.1.6B, the recirculation pumps are designed in accordance with the ASME Code,Section III, considering the transients identified in USAR Section 3.9.1.1.11B.

Transient cycles are monitored in accordance with the Fatigue Monitoring Program (Section A.1.18), which assures that action is taken if the accrued number of cycles of a transient approaches the analyzed number of cycles. As such, the Fatigue Monitoring Program will manage the effects of aging due to fatigue on the reactor recirculation pumps in accordance with 10 CFR 54.21(c)(1)(iii).

Control Rod Drives The Class 1 portions of the control rod drives were analyzed for fatigue. Transient cycles are monitored using the Fatigue Monitoring Program (Section A.1.18), which assures that action is taken if the accrued number of cycles of a transient approaches the analyzed number of cycles.

As such, the Fatigue Monitoring Program will manage the effects of aging due to fatigue on the control rod drives in accordance with 10 CFR 54.21(c)(1)(iii).

Class 1 Piping and In-Line Components Detailed fatigue analyses were generated to analyze multiple locations within the ASME Class 1 boundary on each system. The Fatigue Monitoring Program (Section A.1.18) will monitor the accrued cycles and utilize cycle-based fatigue monitoring and stress-based fatigue monitoring.

The Fatigue Monitoring Program will manage the effects of aging due to fatigue on the ASME Section III piping in accordance with 10 CFR 54.21(c)(1)(iii).

A.2.2.2 Non-Class 1 Fatigue The non-Class 1 fatigue screening document in Appendix H of the EPRI Mechanical Tools was used to determine locations susceptible to fatigue cracking in non-Class 1 systems at RBS. The

RBS USAR Revision 27 A.2-5 first step in the screening process was to identify non-Class 1 components that may have normal or upset condition operating temperature in excess of 220ºF for carbon steel or 270ºF for stainless steel. Components that were identified in the appropriate aging management reviews as above the threshold for fatigue are further evaluated for fatigue in the following sections. The components identified for fatigue are grouped into one of the two major categories of (1) piping and in-line components (tubing, piping, traps, thermowells, valve bodies, etc.) or (2) non-piping components (tanks, vessels, heat exchangers, pump casings, turbine casings, expansion joints, etc.)

Piping and In-Line Components The impact of thermal cycles on non-Class 1 components is addressed in the calculation of the allowable stress range. The design of ASME III Code Class 2 and 3 or ANSI B31.1 piping systems incorporates a stress range reduction factor for piping design with respect to thermal stresses. In general, a stress range reduction factor of 1.0 in the stress analyses applies for up to 7,000 thermal cycles. The allowable stress range is reduced by the stress range reduction factor if the number of thermal cycles exceeds 7,000.

Thermal cycles for the non-Class 1 systems have been evaluated for 60 years of plant operation. For many plant systems, significant temperature cycles are coincident with plant heatups and cooldowns, which are limited to well below 7,000 cycles. Systems with transients that are independent of plant heatups and cooldowns (e.g., SRV actuations, component surveillance testing) have been evaluated, and 7,000 thermal cycles will not be exceeded for 60 years of operation. Therefore, the non-Class 1 piping and in-line components stress calculations remain valid for the period of extended operation in accordance with 10 CFR 54.21(c)(1)(i).

Non-Piping Components The ECCS suction strainers were evaluated for loadings from the SRV operation and earthquake cycles as part of the design. The allowable number of cycles was far in excess of anticipated cycles. Therefore, these analyses for strainers are valid for the period of extended operation in accordance with 10 CFR 54.21(c)(1)(i).

Design specifications and calculations for metal flex hoses and expansion joints were identified with fatigue analyses for a bounding number of cycles, which were identified as TLAAs.

Evaluation of the analyses for each of these systems determined the number of analyzed cycles was adequate for 60 years of operation. Therefore, these metal flex hose and expansion joint fatigue TLAAs remain valid for the period of extended operation in accordance with 10 CFR 54.21(c)(1)(i).

A.2.2.3 Effects of Reactor Water Environment on Fatigue Life NUREG/CR-6260 addresses the application of environmental correction factors to fatigue analyses (CUFs) and identifies locations of interest for consideration of environmental effects.

Section 5.6 of NUREG/CR-6260 identified the following component locations to be the most sensitive to environmental effects for newer vintage General Electric plants. These locations are directly relevant to RBS.

(1) Reactor vessel shell and lower head (2) Reactor vessel feedwater nozzle

RBS USAR Revision 27 A.2-6 (3) Reactor recirculation piping (including inlet and outlet nozzles)

(4) Core spray line reactor vessel nozzle and associated Class 1 piping (5) Residual heat removal nozzles and associated Class 1 piping (6) Feedwater line Class 1 piping The Fatigue Monitoring Program includes an enhancement to complete the environmentally assisted fatigue evaluation (see Section A.1.18). The Fatigue Monitoring Program will manage the effects of aging due to fatigue, including environmentally assisted fatigue, for the period of extended operation in accordance with 10 CFR 54.21(c)(1)(iii).

The environmentally assisted fatigue evaluation reviews all of the Class 1 fatigue analyses in order to identify the transients that the Fatigue Monitoring Program must track to ensure that the fatigue usage factors considering environmental effects will not exceed 1.0 without appropriate corrective actions as specified in the program. This includes all of the NUREG-6260 locations.

The environmentally assisted fatigue evaluation utilizes NUREG/CR-6909 (ANL-06/08), "Effect of LWR Coolant Environments on the Fatigue Life of Reactor Materials," in the evaluation of environmentally assisted fatigue for all materials. Environmental correction factors applied to CUFs with different material types are material specific environmental correction factors. A cumulative usage factor (CUF) from one material type is not used to bound a CUF for another material type.

Piping The piping evaluations are performed using ASME Code NB-3600. The fatigue analyses for Class 1 piping locations throughout the plant are based on the loads experienced at those locations. For the purpose of evaluating environmentally assisted fatigue, a thermal zone is a section of piping that experiences the same transients and the transients are the same from a pressure and temperature perspective. A CUF in one thermal zone can only be used to bound a CUF for the same material in other thermal zones if a bounding temperature is used and the transients in the other thermal zones are the same or a subset of the transients in the first thermal zone. The following criteria are used to select the locations in each thermal zone for further consideration of environmentally assisted fatigue.

• The location with the highest CUF.

• The location with the second highest CUF if it is at least 50 percent of the highest CUF.

• The location with the third highest CUF if it is at least 75 percent of the highest CUF.

The NUREG/CR-6260 locations are evaluated regardless of their CUF.

Reactor Vessel The reactor vessel fatigue analysis has CUFs calculated for more locations than the locations identified in NUREG/CR-6260. The CUFs for reactor vessel locations that are part of the wetted reactor coolant system pressure boundary are evaluated.

Valves and Pump Casings The RBS Class 1 valves and the reactor recirculation pump casings have fatigue analyses with CUFs that are included in the review. Class 1 valves in the following systems are included:

• Main steam (including safety relief valves)

RBS USAR Revision 27 A.2-7

• Feedwater

• Residual heat removal

• Reactor recirculation

• High pressure core spray

• Low pressure core spray

• Reactor water cleanup

• Reactor core isolation cooling Piping Penetrations The evaluation includes the fatigue analyses for the pressure boundary location on the flued heads of Class 1 piping penetrations.

The environmentally assisted fatigue evaluation for RBS Class 1 components is a comprehensive evaluation of plant-specific component locations in the wetted portions of the reactor coolant pressure boundary. The evaluation includes all NUREG/CR-6260 locations. The evaluation demonstrates that the Fatigue Monitoring Program is monitoring the transients necessary to ensure that fatigue analyses that are adjusted to reflect the effects of the reactor coolant environment remain valid during the period of extended operation. If monitoring indicates that a CUF may exceed 1.0 when considering environmental effects, then appropriate corrective actions will be taken as specified in the Fatigue Monitoring Program.

A.2.3 Environmental Qualification of Electrical Components All operating plants must meet the requirements of 10 CFR 50.49, which defines the scope of electrical components to be included in an EQ program and also provides the requirements an EQ program must meet. Qualification is established for the environmental and service conditions during normal plant operation and also those conditions postulated for plant accidents. A record of qualification for in-scope components must be prepared and maintained in auditable form. Equipment qualification evaluations for EQ components that result in a qualification of at least 40 years, but less than 60 years, are considered TLAAs for license renewal.

The RBS Environmental Qualification of Electric Components Program (EQ Program, Section A.1.16) manages component thermal, radiation, and cyclical aging, as applicable, through aging evaluations based on 10 CFR 50.49(f) qualification methods. As required by 10 CFR 50.49, EQ components not qualified for the current license term are to be refurbished, replaced, or have their qualification extended prior to reaching the aging limits established in the evaluation. The RBS EQ Program ensures that the EQ components are maintained in accordance with their qualification bases.

The RBS EQ Program implements RBS commitments for 10 CFR 50.49. The program is consistent with NUREG-1801,Section X.E1, "Environmental Qualification (EQ) of Electric Components." The RBS EQ Program will manage the effects of aging on the intended function(s) of EQ components that are the subject of EQ TLAAs for the period of extended operation in accordance with 10 CFR 54.21(c)(1)(iii).

A.2.4 Containment Liner Plate, Metal Containments, and Penetrations Fatigue Analysis RBS utilizes a BWR Mark III containment. As described in USAR Section 3.8.2.4.1, fatigue analysis requirements for the steel containment cylinder and dome are evaluated in accordance with the requirements of ASME B&PV Code Section III, Division I, Subsection NE. The

RBS USAR Revision 27 A.2-8 containment vessel was evaluated for fatigue at locations on the shell adjacent to the penetrations. Fatigue analysis requirements for the floor liner plate are evaluated in accordance with the requirements of ASME B&PV Code,Section III, Division 2. Further review of the containment dynamic loading effects are contained in USAR Appendix 6A. The cycles used for the analyses are tracked as required under the Fatigue Monitoring Program. Therefore, the Fatigue Monitoring Program manages the effects of aging associated with the basemat liner and containment shell fatigue analyses in accordance with 10 CFR 54.21(c)(1)(iii).

The containment penetrations are described in USAR Section 3.8.2.1.2. The piping penetrations consist of sleeved penetrations for high temperature piping and unsleeved penetrations for low temperature piping. Detailed fatigue calculations were generated for the containment penetrations at RBS. The pipe and flued heads of the penetrations are evaluated as part of the piping pressure boundary. Critical locations of the penetration within the ASME Code Class MC boundary were evaluated for fatigue. The electrical penetrations were evaluated, and stresses were found to be so low that fatigue analysis was not required.

Containment structural components including the personnel airlocks, polar crane, equipment hatch, drywell airlock, drywell combination door/hatch assembly, and drywell head were evaluated for fatigue. The evaluation results were either a fatigue waiver or a fatigue analysis for each component. Tracking of cycles in accordance with the Fatigue Monitoring Program provides assurance of the ongoing validity of the waivers and the analyses through the period of extended operation.

As shown on USAR Figure 3.8-4, expansion joints (bellows) are utilized on sleeved penetrations. The specification required these be qualified for 14,000 cycles due to pipe thermal loads, 500 operating basis earthquake (OBE) cycles, and 20,000 SRV lift cycles. Plant startups, OBE cycles, and SRV cycles are tracked, and the associated systems will not exceed 7000 cycles. Therefore, the analyses for the bellows are adequate for the period of extended operation.

As shown in USAR Figures 3.8-8 and 9.1-20, bellows are utilized on the fuel transfer tube. As shown in USAR Figure 9.1-20 and USAR Table 9.1-3, the upper bellows are safety-related.

This bellows is designed for seismic events that are tracked (none have occurred) and 150 cycles of flexing. The inclined fuel transfer system blind flange is removed and reinstalled on average, twice per operating cycle. Approximately 70 such reinstallations are expected through the end of the period of extended operation. Tracking the installation cycles is unnecessary because the bellows are designed for more than twice the expected number of cycles.

RBS will manage the aging effects due to fatigue for the containment components using the Fatigue Monitoring Program (Section A.1.18) in accordance with 10 CFR 54.21(c)(1)(iii).

A.2.5 Other Plant-Specific TLAAs A.2.5.1 Erosion of Main Steam Line Flow Restrictors USAR Section 5.4.4.4 states that flow restrictors erode very slowly and conservatively postulates that even with an erosion rate of 0.004 inches per year, the increase in choked flow after 40 years would be no more than 5 percent.

Entergy evaluated the erosion rate for the main steam flow restrictors in RBS-ME-16-00008 "GEH 003N4606, Rev. 2, River Bend Station Unit 1 Main Steam Flow Restrictors, April 2016 (Proprietary)" (EC-RBS-0000075698). The evaluation considered the specific material for the flow restrictors and determined the expected erosion rate. The evaluation determined the

RBS USAR Revision 27 A.2-9 expected erosion rate would be much less than the conservative value in the USAR. Using the lower expected corrosion rate, the increase in flow restrictor diameter after 60 years would result in a choked flow increase of less than the 5 percent value identified as acceptable in USAR Section 5.4.4.4.

This analysis has been projected through the period of extended operation in accordance with 10 CFR 54.21(c)(1)(ii).

A.2.5.2 Postulation of High Energy Line Break (HELB) Locations USAR Section 3.6.2.1.5.1A indicates that the determination of intermediate high energy line break (HELB) locations relied on an evaluation of cumulative usage factors (CUFs). As long as other stress criteria were also met, a break is not postulated at a location if the CUF is less than 0.1.

The Fatigue Monitoring Program (Section A.1.18) will identify if the numbers of cycles are approaching the analyzed numbers of cycles. If the cycle limit will be exceeded, the program requires a review of the design calculations based on an assumed cycle limit to determine the necessary corrective actions.

Therefore, the fatigue calculations used for determining the intermediate HELB locations are evaluated in accordance with 10 CFR 54.21(c)(1)(iii). The Fatigue Monitoring Program (Section A.1.18) will manage the associated effects of aging.

A.2.5.3 Fluence Effects for Reactor Vessel Internals The design specification for the reactor vessel internals components includes requirements beyond the ASME design requirements for austenitic stainless steel base metal components exposed to greater than 1 x 1021 nvt (> 1 MEV) or weld metal exposed to greater than 5 x 1020 nvt (> 1 MEV), where nvt equals neutron density (n) multiplied by neutron velocity (v),

multiplied by time (t).

The effects of fluence for 60 years of operation (54 EFPY) were analyzed for the reactor vessel internals components included in the design specification. Location-specific fluence levels were determined. The internal core support structure components were then evaluated against the fluence criteria in the design specification. The evaluation determined that the RBS internal core support structure components meet the design specification for operating conditions through 54 EFPY.

Therefore, this analysis has been projected through the period of extended operation in accordance with 10 CFR 54.21(c)(1)(ii).

A.2.5.4 Crane Load Cycles Analysis Cranes that were designed to Crane Manufacturer's Association of America Specification #70 (CMAA-70) have an expected range of lifting cycles specified as part of their design. While there is no analysis that involves time-limited assumptions defined by the current operating term, for example, 40 years, fatigue evaluations are nevertheless evaluated as TLAAs for cranes that were designed to CMAA-70.

A review of the cranes at RBS was performed to determine which cranes were designed to CMAA-70. The spent fuel cask trolley crane and reactor building polar crane included CMAA-70 Service Class A1 in their design specification. The fuel building bridge crane includes CMAA-70

RBS USAR Revision 27 A.2-10 Service Class B in its design specification. The number of load cycles for which a crane is qualified under CMAA-70 Service Class A1 and B is based on load class and load cycles. The minimum range is 20,000 to 100,000 cycles.

The total estimated number of lifts for each of these cranes (spent fuel cask trolley crane, fuel building bridge crane, and reactor building polar crane) is well below 100,000 cycles. Therefore, the expected number of lifts is well below the value specified in CMAA-70, and the crane fatigue evaluation remains valid for the period of extended operation consistent with 10 CFR 54.21(c)(1)(i).

RBS USAR Revision 27 A.3-1 A.3 REFERENCES A.3.1 Entergy Letter: License Renewal Application (RBG -47735 dated May 25, 2017)

A.3.2 Safety Evaluation Report (SER) Related to the License Renewal of River Bend Station, Unit 1, August 2018 (ML18138A355)

RBS USAR Revision 27 A.4-1 A.4 LICENSE RENEWAL COMMITMENT LIST No.

Program or Activity Commitment Implementation Schedule Source (Letter Number) 1 Aboveground Metallic Tanks Implement the Aboveground Metallic Tanks Program as described in LRA Section A.1.1.

Prior to February 28, 2025.

RBG-47735 RBG-47818 2

Bolting Integrity Enhance the Bolting Integrity Program as described in LRA Section A.1.2.

Prior to February 28, 2025.

RBG-47735 RBG-47828 3

Neutron Absorbing Material Monitoring Implement the Neutron Absorbing Material Monitoring Program as described in LRA Section A.1.3.

Prior to February 28, 2025, or the end of the last refueling outage prior to August 29, 2025, whichever is later.

RBG-47735 RBG-47830 RBG-47848 4

Buried and Underground Piping and Tanks Inspection Implement the Buried and Underground Piping and Tanks Inspection Program as described in LRA Section A.1.4.

Prior to February 28, 2025, or the end of the last refueling outage prior to August 29, 2025, whichever is later.

RBG-47735 RBG-47813 RBG-47850 RBG-47860 5

BWR Vessel Internals Enhance the BWR Vessel Internals Program as described in LRA Section A.1.10.

Prior to February 28, 2025.

RBG-47735 RBG-47818 RBG-47873 6

Coating Integrity Implement the Coating Integrity Program as described in LRA Section A.1.11.

Prior to February 28, 2025, or the end of the last refueling outage prior to August 29, 2025, whichever is later.

RBG-47735 RBG-47805

RBS USAR Revision 27 A.4-2 No.

Program or Activity Commitment Implementation Schedule Source (Letter Number) 7 Compressed Air Monitoring Enhance the Compressed Air Monitoring Program as described in LRA Section A.1.12.

Prior to February 28, 2025.

RBG-47735 8

Containment Inservice Inspection - IWE Enhance the CII-IWE Program as described in LRA Section A.1.13.

Prior to February 28, 2025, or the end of the last refueling outage prior to August 29, 2025, whichever is later.

RBG-47735 9

Diesel Fuel Monitoring Enhance the Diesel Fuel Monitoring Program as described in LRA Section A.1.15.

Prior to February 28, 2025, or the end of the last refueling outage prior to August 29, 2025, whichever is later.

RBG-47735 RBG-47812 RBG-47849 RBG-47860 10 External Surfaces Monitoring Enhance the External Surfaces Monitoring Program as described in LRA Section A.1.17.

Prior to February 28, 2025, or the end of the last refueling outage prior to August 29, 2025, whichever is later.

RBG-47735 RBG-47883 11 Fatigue Monitoring Enhance the Fatigue Monitoring Program as described in LRA Section A.1.18.

Enhancement to develop a set of fatigue usage calculations: prior to August 29, 2023.

Remaining enhancements: prior to February 28, 2025.

RBG-47735

RBS USAR Revision 27 A.4-3 No.

Program or Activity Commitment Implementation Schedule Source (Letter Number) 11a Fatigue Monitoring Revise the Fatigue Monitoring Program description (Section 7B) of RBS-EP-15-00006, "Aging Management Program Evaluation Report Class 1 Mechanical," to state acceptable corrective actions include repair of the component, replacement of the component, and a more rigorous analysis of the component to demonstrate that the design code limit will not be exceeded during the period of extended operation.

Prior to February 28, 2025.

RBG-47735 RBG-47846 12 Fire Water System Enhance the Fire Water System Program as described in LRA Section A.1.20.

Prior to February 28, 2025, or the end of the last refueling outage prior to August 29, 2025, whichever is later.

RBG-47735 RBG-47805 RBG-47818 12a Fire Water System Remove existing coating, perform bottom thickness measurements and recoat the fire water storage tanks Within seven years prior to February 28, 2025.

RBG-47735 RBG-47818 13 Flow-Accelerated Corrosion Enhance the Flow-Accelerated Corrosion Program as described in LRA Section A.1.21.

Prior to February 28, 2025.

RBG-47735 RBG-47860 14 Inservice Inspection -IWF Enhance the ISI-IWF Program as described in LRA Section A.1.23.

Prior to February 28, 2025.

RBG-47735 RBG-47883 15 Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Enhance the Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program as described in LRA Section A.1.24.

Prior to February 28, 2025.

RBG-47735

RBS USAR Revision 27 A.4-4 No.

Program or Activity Commitment Implementation Schedule Source (Letter Number) 16 Internal Surfaces in Miscellaneous Piping and Ducting Components Implement the Internal Surfaces in Miscellaneous Piping and Ducting Components Program as described in LRA Section A.1.25.

Prior to February 28, 2025.

RBG-47735 RBG-47835 RBG-47860 17 Masonry Wall Enhance the Masonry Wall Program as described in LRA Section A.1.26.

Prior to February 28, 2025.

RBG-47735 18 Non-EQ Electrical Cable Connections Implement the Non-EQ Electrical Cable Connections Program as described in LRA Section A.1.27.

Prior to February 28, 2025, or the end of the last refueling outage prior to August 29, 2025, whichever is later.

RBG-47735 19 Non-EQ Inaccessible 3RZHU&DEOHV9

Implement the Non-EQ Inaccessible Power Cables

 V) Program as described in LRA Section A.1.28.

Prior to February 28, 2025, or the end of the last refueling outage prior to August 29, 2025, whichever is later.

RBG-47735 RBG-47828 20 Non-EQ Insulated Cables and Connections Implement the Non-EQ Insulated Cables and Connections Program as described in LRA Section A.1.29.

Revise RBS report, Aging Management Program Evaluation Results - Electrical, to include directions to perform an engineering evaluation in the corrective actions program element.

Prior to February 28, 2025, or the end of the last refueling outage prior to August 29, 2025, whichever is later.

RBG-47735 RBG-47828

RBS USAR Revision 27 A.4-5 No.

Program or Activity Commitment Implementation Schedule Source (Letter Number) 21 Non-EQ Sensitive Instrumentation Circuits Test Review Implement the Non-EQ Sensitive Instrumentation Circuits Test Review Program as described in LRA Section A.1.30.

Prior to February 28, 2025, or the end of the last refueling outage prior to August 29, 2025, whichever is later.

RBG-47735 22 One-Time Inspection Implement the One-Time Inspection Program as described in LRA Section A.1.32.

Prior to February 28, 2025, or the end of the last refueling outage prior to August 29, 2025, whichever is later.

RBG-47735 RBG-47834 RBG-47860 23 One-Time Inspection -

Small-Bore Piping Implement the One-Time Inspection - Small-Bore Piping Program as described in LRA Section A.1.33.

Prior to February 28, 2025, or the end of the last refueling outage prior to August 29, 2025, whichever is later.

RBG-47735 24 Periodic Surveillance and Preventive Maintenance Enhance the PSPM Program as described in LRA Section A.1.34.

Prior to February 28, 2025, or the end of the last refueling outage prior to August 29, 2025, whichever is later.

RBG-47735 RBG-47805 RBG-47835 RBG-47846 RBG-47860 RBG-47861 RBG-47867

RBS USAR Revision 27 A.4-6 No.

Program or Activity Commitment Implementation Schedule Source (Letter Number) 25 Reactor Head Closure Studs Enhance the Reactor Head Closure Studs Program as described in LRA Section A.1.36.

Prior to February 28, 2025, or the end of the last refueling outage prior to August 29, 2025, whichever is later.

RBG-47735 RBG-47883 26 RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants Enhance the RG 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants Program as described in LRA Section A.1.38.

Prior to February 28, 2025, or the end of the last refueling outage prior to August 29, 2025, whichever is later.

RBG-47735 27 Selective Leaching Implement the Selective Leaching Program as described in LRA Section A.1.39.

Prior to February 28, 2025, or the end of the last refueling outage prior to August 29, 2025, whichever is later.

RBG-47735 RBG-47812 28 Structures Monitoring Enhance the Structures Monitoring Program as described in LRA Section A.1.41.

Prior to February 28, 2025, or the end of the last refueling outage prior to August 29, 2025, whichever is later.

RBG-47735 RBG-47842 RBG-47860 29 Water Chemistry Control

- Closed Treated Water Systems Enhance the Water Chemistry Control - Closed Treated Water Systems Program as described in LRA Section A.1.43.

Prior to February 28, 2025.

RBG-47735

RBS USAR Revision 28 A.4-7 No.

Program or Activity Commitment Implementation Schedule Source (Letter Number) 30 Control Rod Drive Return Line Nozzle Program Enhance the Control Rod Drive Return Line Nozzle Program as described in LRA Section A.1.5.

Prior to February 28, 2025, or the end of the last refueling outage prior to August 29, 2025, whichever is later.

RBG-47735 RBG-47812 30a Control Rod Drive Return Line Nozzle Program The N-10 safe end cap weld will be volumetrically examined.

Prior to February 28, 2025, or the end of the last refueling outage prior to August 29, 2025, whichever is later.

RBG-47812 31 Service Water Integrity Enhance the Service Water Integrity Program as described in LRA Section A.1.40.

Prior to February 28, 2025.

RBG-47735 RBG-47834 32 Neutron Absorbing Material Monitoring Install aluminum boron-carbide neutron absorbing material before the period of extended operation so that the Boraflex material in the spent fuel pool will not be credited to perform a neutron absorption function. Entergy shall submit a letter to the NRC, within 60 days following installation of the new neutron absorbing material, confirming that the Boraflex material is no longer credited for neutron absorption.

Prior to February 28, 2025, or the end of the last refueling outage prior to August 29, 2025, whichever is later.

RBG-47735 RBG-47830 RBG-47848