ML19268A123
| ML19268A123 | |
| Person / Time | |
|---|---|
| Site: | Waterford  |
| Issue date: | 09/11/2019 |
| From: | Entergy Operations |
| To: | Office of Nuclear Reactor Regulation |
| Shared Package | |
| ML19269C528 | List: |
| References | |
| W3F1-2019-0064 | |
| Download: ML19268A123 (70) | |
Text
WSES-FSAR-UNIT-3 CHAPTER 18 AGING MANAGEMENT PROGRAMS AND ACTIVITIES 18-i Revsion 311 (9/19)
Section Title Page 18.0 AGING MANAGEMENT PROGRAMS AND ACTIVITIES 18-1 18.1 AGING MANAGEMENT PROGRAMS 18-1 18.1.1 Bolting Integrity Program 18-2 18.1.2 Boric Acid Corrosion Program 18-3 18.1.3 Buried and Underground Piping and Tanks Inspection Program 18-4 18.1.4 Coating Integrity 18-4 18.1.5 Compressed Air Monitoring Program 18-4 18.1.6 Containment Inservice Inspection - IWE Program 18-5 18.1.7 Containment Leak Rate Program 18-6 18.1.8 Diesel Fuel Monitoring Program 18-6 18.1.9 Environmental Qualification (EQ) of Electric Components Program 18-7 18.1.10 External Surfaces Monitoring Program 18-7 18.1.11 Fatigue Monitoring Program 18-9 18.1.12 Fire Protection Program 18-10 18.1.13 Fire Water System Program 18-10 18.1.14 Flow-Accelerated Corrosion Program 18-14 18.1.15 Inservice Inspection Program 18-15 18.1.16 Inservice Inspection - IWF Program 18-15 18.1.17 Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program 18-16 18.1.18 Internal Surfaces in Miscellaneous Piping and Ducting Components Program 18-17 18.1.19 Masonry Wall Program 18-17 18.1.20 Metal Enclosed Bus Inspection Program 18-18 18.1.21 Neutron-Absorbing Material Monitoring Program 18-19 18.1.22 Nickel Alloy Inspection Program 18-19 18.1.23 Non-EQ Electrical Cable Connections Program 18-20 18.1.24 Non-EQ Inaccessible Power Cables (>/= 400 V) Program 18-20 18.1.25 Non-EQ Sensitive Instrumentation Circuits Test Review Program 18-20 18.1.26 Non-EQ Insulated Cables and Connections Program 18-21 18.1.27 Oil Analysis Program 18-21 18.1.28 One-Time Inspection Program 18-22 18.1.29 One-Time Inspection - Small-Bore Piping Program 18-23
WSES-FSAR-UNIT-3 CHAPTER 18 AGING MANAGEMENT PROGRAMS AND ACTIVITIES 18-iI Revsion 311 (9/19)
Section Title Page 18.1.30 Periodic Surveillance and Preventive Maintenance Program 18-23 18.1.31 Protective Coating Monitoring and Maintenance Program 18-25 18.1.32 Reactor Head Closure Studs Program 18-25 18.1.33 Reactor Vessel Internals Program 18-26 18.1.34 Reactor Vessel Surveillance Program 18-26 18.1.35 Selective Leaching Program 18-27 18.1.36 Service Water Integrity Program 18-27 18.1.37 Steam Generator Integrity Program 18-28 18.1.38 Structures Monitoring Program 18-28 18.1.39 Thermal Aging Embrittlement of Cast Austenitic Stainless Steel Program 18-31 18.1.40 Water Chemistry Control - Closed Treated Water Systems Program 18-32 18.1.41 Water Chemistry Control - Primary and Secondary Program 18-32 18.2 EVALUATION OF TIME-LIMITED AGING ANALYSES 18-33 18.2.1.
Reactor Vessel Neutron Embrittlement 18-33 18.2.1.1 Reactor Vessel Fluence 18-33 18.2.1.2 Upper-Shelf Energy 18-33 18.2.1.3 Pressurized Thermal Shock 18-34 18.2.1.4 Pressure-Temperature Limits 18-34 18.2.1.5 Low Temperature Overpressure Protection (LTOP) Setpoints 18-35 18.2.2 Metal Fatigue 18-35 18.2.2.1 Class 1 Metal Fatigue 18-36 18.2.2.2 Non-Class 1 Metal Fatigue 18-38 18.2.2.3 Effects of Reactor Water Environment on Fatigue Life 18-39 18.2.3 Environmental Qualification of Electrical Components 18-40 18.2.4 Containment Liner Plate, Metal Containments, and Penetrations Fatigue Analysis 18-41 18.2.5 Other Plant-Specific TLAAs 18-41 18.2.5.1 Crane Load Cycles Analysis 18-41 18.2.5.2 Leak-Before-Break Analysis 18-41 18.2.5.3 High Energy Line Break Postulation 18-42 18.2.5.4 Reactor Vessel Internal Evaluations (Other than Fatigue) 18-42
18.3 REFERENCES
18-43
WSES-FSAR-UNIT-3 CHAPTER 18 AGING MANAGEMENT PROGRAMS AND ACTIVITIES 18-iii Revsion 311 (9/19)
List of Table(s)
Table Title 18.4-1 LICENSE RENEWAL COMMITMENT LIST
WSES-FSAR-UNIT-3 CHAPTER 18 AGING MANAGEMENT PROGRAMS AND ACTIVITIES 18-iiii Revsion 311 (9/19)
Cross References Section Revision 311 Section 18.0 LBDCR 19-013 Section 18.2 Section 18.3 Table 18.4-1
WSES-FSAR-UNIT-3 18-1 Revsion 311 (9/19) 18.0 AGING MANAGEMENT PROGRAMS AND ACTIVITIES The WF3 license renewal application (Reference 18.3-1) 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 18.3-2). As required by 10 CFR 54.21(d), this FSAR supplement contains a summary description of the programs and activities for managing the effects of aging (Section 18.1) and a description of the evaluation of time-limited aging analyses for the period of extended operation (Section 18.2). The period of extended operation is the 20 years after the expiration date of the original operating license for WF3.
18.1 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 corrective action, confirmation process, and administrative controls of the WF3 (10 CFR Part 50, Appendix B) Quality Assurance Program are applicable to all aging management programs and activities during the period of extended operation. WF3 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 WF3 Quality Assurance Program applies to safety-related structures and components.
Corrective actions and administrative (document) control for both safety-related and non-safety-related structures and components are accomplished in accordance with the established WF3 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 WF3 corrective action program, which is implemented in accordance with the quality assurance program, effects the documentation and evaluation of plant-specific operating experience. The WF3 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 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
WSES-FSAR-UNIT-3 18-2 Revsion 311 (9/19) 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 B, 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 WF3 includes review of operating experience from the same domestic and foreign sources and from NRC generic communications.
Thus, the WF3 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.
18.1.1 Bolting Integrity Program The Bolting Integrity Program manages loss of preload, cracking, and loss of material for pressure-retaining closure bolting using preventive measures and inspection activities. The Reactor Head Closure Stud Program (Section 18.1.32) manages the aging effects on the reactor head closure studs, and the Structures Monitoring Program (Section 18.1.38) manages the aging effects on structural bolting. 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 supplements 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
WSES-FSAR-UNIT-3 18-3 Revsion 311 (9/19) before leakage becomes excessive. 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 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 Program (Section 18.1.3).
The Bolting Integrity Program will be enhanced as follows.
Revise Bolting Integrity Program procedures to include submerged pressure retaining bolting.
Revise Bolting Integrity Program procedures to monitor high strength bolting locations (i.e., bolting with actual yield strength greater than or equal to 150 ksi) for cracking.
Revise Bolting Integrity Program procedures to include a volumetric examination per ASME Code Section XI, Table IWB-2500-1 for high-strength closure bolting with actual yield strength greater than or equal to 150 ksi regardless of code classification.
Revise Bolting Integrity Program documents to specify opportunistic inspections of normally inaccessible dry cooling tower area sump pump discharge piping bolted connections.
Revise Bolting Integrity Program documents to specify visual inspection of a representative sample of closure bolting (bolt heads, nuts, and threads) from components with an internal environment of a clear gas, such as air or nitrogen. 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.
18.1.2 Boric Acid Corrosion Program The Boric Acid Corrosion Program manages loss of material and increase in connection resistance for components on which borated water may leak. The program includes (a) visual inspection of external surfaces that are potentially in an environment of borated water leakage, including mechanical, electrical and structural components; (b) timely identification of leak path and removal of boric acid residues; (c) assessment of degradation due to corrosion, if any; and (d) follow-up inspection for adequacy. This program was implemented in response to NRC Generic Letter (GL) 88-05 and industry operating experience.
The program provides systematic measures to identify borated water leakage and ensure that corrosion caused by leaking borated water does not lead to unacceptable degradation of the leakage source or adjacent structures or electrical components. Visual inspections are performed to identify boric acid deposits, discoloration, staining, and moisture in areas of borated water leakage. If evidence of leakage is identified, the necessary actions are taken to determine the exact location and cause of the leakage.
When leakage is discovered by other activities (normal plant walkdowns, maintenance, etc.), the Boric Acid Corrosion Program provides for evaluations and assessments to identify and correct boric acid leakage before loss of intended function of affected components. These corrective actions include modifications to equipment design or operating procedures to reduce the probability of boric acid leakage at locations where such leaks may cause corrosion damage.
WSES-FSAR-UNIT-3 18-4 Revsion 311 (9/19) 18.1.3 Buried and Underground Piping and Tanks Inspection Program The Buried and Underground Piping and Tanks Inspection Program manages the effects of aging on external surfaces of buried piping components subject to aging management review. There are no buried tanks subject to aging management review. The program will manage loss of material and cracking through preventive and mitigative actions (i.e., coatings, backfill quality, and cathodic protection). The number of inspections is based on the effectiveness of the preventive and mitigative actions. Annual cathodic protection surveys are conducted. For steel components using an acceptance criterion other than
-850 mV instant off for demonstrating effectiveness of cathodic protection, loss of material rates are measured.
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, the sample size is increased. If a lack of soil corrosivity 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.
18.1.4 Coating Integrity Program The Coating Integrity Program consists of periodic visual inspections of coatings applied to the internal surfaces of in-scope components in an environment of raw water, treated water, lubricating oil, or fuel 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, physical testing is performed where physically possible in conjunction with coating repair or replacement.
The Coating Integrity Program will provide a one-time inspection of the internal coating for the 11-foot diameter carbon steel circulating water piping. If the one-time inspection results do not meet acceptance criteria, periodic inspections of the internal coatings will be conducted. The training and qualification of individuals involved in coating inspections of non-cementitious coatings are conducted in accordance with ASTM standards endorsed in Regulatory Guide (RG) 1.54 including limitations, if any, identified in RG 1.54 on a particular standard. For cementitious coatings, training and qualifications are based on an appropriate combination of education and experience related to inspecting concrete surfaces.
This program will be implemented prior to the period of extended operation.
18.1.5 Compressed Air Monitoring Program 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. Periodic and opportunistic internal visual inspections of components (accumulators, flex hoses, tubing, etc.) 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.
Revise Compressed Air Monitoring Program procedures to include the EDG starting air system.
WSES-FSAR-UNIT-3 18-5 Revsion 311 (9/19)
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 periodic and opportunistic visual inspections of accessible internal surfaces of system components, including accumulators, flex hoses and tubing. Specify inspections at frequencies recommended in ASME OM-S/G-1998 (Part 17).
Enhancements will be implemented prior to the period of extended operation.
18.1.6 Containment Inservice Inspection - IWE Program The Containment Inservice Inspection (CII) - IWE Program implements the requirements of 10 CFR 50.55a. The regulations in 10 CFR 50.55a impose the inservice inspection (ISI) requirements of the American Society of Mechanical Engineers (ASME) Boiler and Pressure Vessel (B&PV) Code,Section XI, Subsection IWE, for steel containments (Class MC) and steel liners for concrete containments (Class CC).
The WF3 containment is a low-leakage, free-standing steel containment vessel (SCV) consisting of a vertical upright cylinder with a hemispherical dome and an ellipsoidal bottom. The SCVs ellipsoidal bottom is encased in concrete and founded on the common concrete foundation with the shield building.
The common concrete foundation with the shield building is classified as Class CC equivalent. The steel ellipsoidal bottom plate of the SCV was erected on top of the common concrete foundation slab with a concrete slab poured on top of the bottom plate. Since the Class CC equivalent concrete foundation slab and the bottom steel plate are inaccessible, they are exempted from examination in accordance with IWL-1220(b) and IWE-1220(b). There are no tendons associated with the WF3 SCV.
The program entails periodic visual and surface examination of pressure-retaining components of the SCV for signs of degradation, assessment of damage, and corrective actions. The program includes managing the effects of aging of surfaces and components such as bolting for containment closures, SCV, containment penetrations (electrical, instrumentation, and control assemblies), mechanical penetrations, penetration bellows at the containment boundary, penetration sleeves at the containment boundary, and the personnel airlock and maintenance hatch. The moisture barrier, which is a sealant between the bottom of the SCV and the base mat, is included within the scope of the program.
Examination methods include visual and surface as required by ASME Code Section Xl, Subsection IWE.
Observed conditions that have the potential for impacting an intended function are evaluated for acceptability in accordance with ASME Code provisions and corrected in accordance with the corrective action program.
The code of record for the examination of the WF3 Class MC and Class CC components is ASME Code Section XI, Subsections IWE and IWL, 2001 Edition with the 2003 Addenda, as mandated and modified by 10 CFR 50.55a.
The CII-IWE Program includes provisions to ensure that the selection of bolting material, installation torque or tension, and the use of lubricants and sealants are appropriate for the intended purpose. Implementing procedures use 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 CII-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.
WSES-FSAR-UNIT-3 18-6 Revsion 311 (9/19)
Enhancements will be implemented prior to the period of extended operation.
18.1.7 Containment Leak Rate Program 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 Containment Leakage Testing for Water-Cooled Power Reactors," Option B; NEI 94-01 Revision 2-A, "Industry Guideline for Implementing Performance-Based Options of 10 CFR Part 50, Appendix J"; and ANSI/ANS 56.8, "Containment System Leakage Testing Requirements."
Three types of tests are performed under Option B. 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) per 10 CFR Part 50, Appendix J, Option B, demonstrates the leak-tightness and structural integrity of the containment. Type B and Type C containment local leakage rate tests (LLRTs), as defined in 10 CFR Part 50, Appendix J, are intended to detect local leaks and to measure leakage across each pressure-containing or leakage-limiting boundary of containment penetrations. Type B and C leakage rate tests are performed at frequencies in accordance with the provisions of 10 CFR Part 50, Appendix J, Option B. Type A tests are performed at frequencies no longer than 15 years in accordance with 10 CFR Part 50, Appendix J, Option B, based upon the criteria in NEI 94-01 Revision 2-A.
18.1.8 Diesel Fuel Monitoring Program The Diesel Fuel Monitoring Program manages loss of material and reduction of heat transfer due to fouling in piping, tanks and other components in an environment of diesel fuel oil. This is performed by receipt inspection before allowing fuel oil to enter the storage tanks. Parameters monitored include water content, sediment, total particulate, and levels of microbiological activity. 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. When biological activity is identified, biocides are added.
The Diesel Fuel Monitoring Program inspects low flow areas where contaminants may collect such as in the bottom of tanks. The tanks are periodically sampled, drained, cleaned, and inspected for signs of moisture, contaminants and corrosion. Internal tank inspections 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, and the extent of the condition is verified as a part of the corrective action program. Applicable industry standards and guidance documents are used to establish sampling frequency unless specified in Technical Specifications. The One-Time Inspection Program (Section 18.1.28) 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.
Revise the Diesel Fuel Monitoring Program procedures to include the auxiliary diesel generator fuel oil tank and the emergency diesel generator (EDG) fuel oil feed tanks.
Revise Diesel Fuel Monitoring Program procedures to monitor and trend water content, sediment, particulates, and microbiological activity in the fuel oil tanks within the scope of the program at least quarterly.
Revise Diesel Fuel Monitoring Program procedures to include periodic multi-level sampling of the 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.
WSES-FSAR-UNIT-3 18-7 Revsion 311 (9/19)
Revise Diesel Fuel Monitoring Program procedures to include periodic cleaning and internal visual inspection of tanks within the scope of 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 cleaning and internal inspections at least once during the 10-year period prior to the period of extended operation and at succeeding 10 year intervals.
Enhancements will be implemented prior to the period of extended operation.
18.1.9 Environmental Qualification (EQ) of Electric Components Program 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.
18.1.10 External Surfaces Monitoring Program 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, 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. 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.
Inspections are performed at least once every refueling cycle by personnel qualified through a plant-specific 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 component's intended functions are maintained.
Periodic representative surface inspections of the 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 materials, the visual inspection will include 100 percent of the accessible components. The sample size of flexible polymeric components that receive physical manipulation is at least 10 percent of the available surface area.
Acceptance criteria are defined to ensure that the need for corrective action is identified before a loss of intended function. For stainless steel, a clean shiny surface is expected. 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 expected. For rigid polymeric materials, acceptable conditions are no surface changes affecting performance, such as erosion, cracking, crazing, checking, and chalking.
The External Surfaces Monitoring Program will be enhanced as follows.
Revise External Surfaces Monitoring Program procedures to include instructions to perform a 100 percent visual inspection of accessible flexible polymeric component surfaces. The visual
WSES-FSAR-UNIT-3 18-8 Revsion 311 (9/19) 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 conduct representative inspections during each 10-year period on insulated surfaces of each material type (e.g., steel, stainless steel, copper alloy, aluminum) in an air-outdoor or condensation environment.
Revise External Surfaces Monitoring Program procedures as follows:
Remove insulation in order to perform a visual inspection of a representative sample of insulated indoor component surfaces in a condensation environment and outdoor component surfaces. The inspections shall 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 of the surface area.
Alternatively, insulation can 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.
Include inspection locations based on the likelihood of corrosion under insulation (i.e.,
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).
Allow subsequent inspections to 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, and no evidence of cracking.
Ensure that if the external visual inspections of the insulation reveal damage to the exterior surface of the insulation or there is evidence of water intrusion through the insulation (e.g.,
water seepage through insulation seams or joints), periodic inspections under the insulation will continue at such intervals that would ensure the component's intended function.
Revise External Surfaces Monitoring Program procedures to provide guidance that removal of tightly adhering insulation that is impermeable to moisture is not required unless there is evidence of damage to the moisture barrier. However, the entire population of in-scope piping component surfaces 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.
Revise External Surfaces Monitoring Program procedures to include the following acceptance criteria.
Stainless steel should have a clean shiny surface with no discoloration.
Other metals should not have any abnormal surface indications.
WSES-FSAR-UNIT-3 18-9 Revsion 311 (9/19)
Flexible polymeric materials should have a uniform surface texture and color with no cracks and no dimensional change, no abnormal surface with the material in an as-new condition with respect to hardness, flexibility, physical dimensions, and color.
Rigid polymeric materials should have no erosion, cracking, checking or chalking.
Enhancements will be implemented prior to the period of extended operation.
18.1.11 Fatigue Monitoring Program 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. Tracking the number of critical thermal and pressure transients for the selected components ensures a cumulative usage factor (CUF) for fatigue within allowable limits, including environmental effects where applicable.
The Fatigue Monitoring Program will be enhanced as follows.
Revise Fatigue Monitoring Program procedures to monitor and track additional critical thermal and pressure transients for components that have been identified to have a fatigue TLAA.
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 to be more limiting than those considered in NUREG/CR-6260. Fen factors shall be determined using the formulae recommended in NUREG-1801, X.M1. The methodology for determining limiting locations will be based on EPRI report 1024995 Environmentally Assisted Fatigue Screening, Process and Technical Basis for Identifying EAF Limiting Locations with the following modifications.
Components in one thermal zone will not be used to bound components in different thermal zones.
Comparisons between components will use a fatigue correction factor (Fen) calculated with realistic dissolved oxygen values, worst case (minimum) metal strain rate, worst case (maximum) sulfur in the metal and maximum metal service temperature.
A Uen for one material will not be used to bound the Uen for a location of a different material.
Analysts will ensure that comparisons to determine limiting locations will compare usage values that are determined with comparable methods. For example, a component with a low fatigue usage value determined with a refined analysis may be more limiting than a component with a higher CUF determined with a simplified analysis.
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.
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, unanticipated new thermal events are discovered, or the geometry of components has been modified.
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Enhancements will be implemented prior to the period of extended operation.
18.1.12 Fire Protection Program The Fire Protection Program manages cracking, loss of material, delamination, separation, and change in material properties (e.g., shrinkage, loss of strength) through periodic visual inspection of components and structures with a fire barrier intended function (i.e., seals, fire barrier walls, ceilings, floors, and other fire resistant materials, such as flamastic, fire wrapping, spray-on fire proofing material, etc.). The program also performs periodic visual and functional testing of fire doors to ensure their operability.
The program includes visual inspections of not less than 10 percent of each type of penetration fire seal at least once per refueling cycle. Visual inspections of the fire barrier walls, ceilings and floors in structures within the scope of license renewal are performed at a frequency of at least once per refueling cycle. The frequency of visual inspections of the fire door surfaces and functional testing of fire door closing mechanisms and latches is at least once per refueling cycle.
The Fire Protection Program will be enhanced as follows.
Revise Fire Protection Program procedures to include an inspection at least once per refueling cycle of fire barrier walls, ceilings, and floors for any signs of degradation, such as spalling, loss of material caused by chemical attack, or reaction with aggregates.
Revise Fire Protection Program procedures to inspect fire-rated doors for any degradation of door surfaces at least once per refueling cycle.
Revise Fire Protection Program procedures to ensure fire barrier seals are inspected by personnel qualified in accordance with appropriate NFPA standards.
Revise Fire Protection Program procedures to provide acceptance criteria of no significant indications of concrete spalling, and loss of material of fire barrier walls, ceilings, and floors and in other fire barrier materials.
Revise Fire Protection Program procedures to provide acceptance criteria that specify no surface degradation of fire doors.
Enhancements will be implemented prior to the period of extended operation.
18.1.13 Fire Water System Program The Fire Water System Program manages loss of material, flow blockage due to fouling, and loss of coating integrity 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 is 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.
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., dry-pipe or downstream of the deluge valve in a deluge system) and (b) cannot be drained or 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.
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The training and qualification of individuals involved in fire water storage tank coating inspections is conducted 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, (b) no unacceptable signs of degradation or fouling are observed during non-intrusive or visual inspections, and (c) 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 the tank (e.g., peeling, delamination, blistering, flaking, cracking, or rust), the program requires 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.
a) Revise Fire Water System Program Procedures to inspect for loss of fluid in the glass bulb heat responsive elements.
b) Revise Fire Water System Program procedures to perform an inspection of each buildings wet pipe fire water system every 5 years by opening a flushing connection at the end of one main and by removing a sprinkler toward the end of one branch line for the purpose of inspecting the interior for evidence of loss of material and the presence of foreign organic or inorganic material that could result in flow obstructions or blockage of a sprinkler head. 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.
c) Revise Fire Water System Program procedures to perform an internal inspection every five years for evidence of loss of material and the presence of foreign organic or inorganic material that could result in flow obstructions or blockage of a sprinkler head of the dry piping downstream of preaction valves. 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, corrosion product deposition, and flow blockage due to fouling.
d) Revise Fire Water System Program procedures to perform an internal inspection every five years for evidence of loss of material and the presence of foreign organic or inorganic material that could result in flow obstructions or blockage of a sprinkler head of the dry piping downstream of the automatic deluge valves. 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, corrosion product deposition, and flow blockage due to fouling.
e) Revise Fire Water System Program procedures to perform an inspection of the nozzles associated with the charcoal filters for loss of material and foreign or organic material when the charcoal is replaced.
f)
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.
g) Revise Fire Water System Program procedures to remove strainers every 5 years and after each actuation to clean and inspect for damage and corroded parts.
WSES-FSAR-UNIT-3 18-12 Revsion 311 (9/19) h) 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.
i)
Revise Fire Water System Program procedures to conduct 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 cannot be drained or piping segments that allow water to collect in each 5-year interval, beginning 5 years prior to the period of extended operation.
j)
Revise Fire Water System Program procedures to perform volumetric wall thickness inspections of 20 percent of the length of piping segments that cannot be drained or piping segments that allow water to collect each 5-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 5-year interval is in different locations than previously inspected piping.
k) Revise the Fire Water System Program procedures to perform a blockage evaluation if the flowing pressure decreases by more than 10 percent from the original main drain test or previous main drain tests.
l)
Revise the Fire Water System Program procedures to flow test the charcoal filter unit's manual deluge valve systems with air on an annual basis to ensure there are no obstructions. If obstructions are found, the system shall be cleaned and retested.
m) Revise the Fire Water System Program procedures to trip test with flow at least once every 18 months the deluge valve systems for the main turbine lube oil tank and main feedwater pumps. If obstructions are found, the system shall be cleaned and retested.
n) Revise the Fire Water System Program procedures to open and close hydrant valves slowly while performing flow tests to prevent surges in the system. The program shall also require full opening of the hydrant valve.
o) Revise the Fire Water System Program procedures to verify the hydrants drain within 60 minutes after flushing or flow testing.
p) Revise Fire Water System Program procedures to perform vacuum box testing on the bottom of the tank to identify leaks. In the event the bottom of the fire water tank is uneven, the station will perform a suitable NDE technique rather than vacuum box testing to identify leaks.
q) Revise the 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, including limitations, if any, identified in RG 1.54 on a particular standard.
r)
Revise Fire Water System Program procedures to perform wet sponge and dry film testing on the coating applied to the interior of the fire water tanks.
s) 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 surrounded by coating bonded to the substrate as determined by a qualified coating specialist, or the following actions are performed:
Any 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.
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Any delaminated or peeled coating is removed.
The exposed underlying coating is verified to be securely bonded to the substrate as determined by an adhesion test endorsed by RG 1.54 at a minimum of three locations.
The outermost coating is feathered and the remaining outermost coating is determined to be securely bonded to the coating below via an adhesion test endorsed by RG 1.54 at a minimum of three locations adjacent to the defective area.
Ultrasonic testing is performed where there is evidence of pitting or corrosion to ensure the tank meets minimum wall thickness requirements.
An evaluation is performed to ensure downstream flow blockage is not a concern.
A follow-up inspection is scheduled to be performed within two years and every two years after that until the coating is repaired, replaced, or removed.
t)
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.
Lightly tapping and scraping the coating to determine the coating integrity.
Dry film thickness measurements at random locations to determine overall thickness of the coating.
Wet-sponge testing or dry film testing to identify holidays in the coating.
Adhesion testing in accordance with ASTM D3359, ASTM D4541, or equivalent testing endorsed by RG 1.54 at a minimum of three locations.
Ultrasonic testing where there is evidence of pitting or corrosion to determine if the tank thickness meets the minimum thickness criteria.
u) Revise Fire Water System Program procedures to include acceptance criteria for the fire water tanks' interior coating that include:
Indications of peeling and delamination are not acceptable.
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 on a particular standard. Blisters should be limited to a few intact small blisters that are completely surrounded by sound coating/lining bonded to the substrate. Blister size and frequency should not be increasing between inspections (e.g., reference ASTM D714-02, "Standard Test Method for Evaluating Degree of Blistering of Paints").
Indications such as cracking, flaking, and rusting are to be 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 on a particular standard.
As applicable, wall thickness measurements, projected to the next inspection, meet design minimum wall requirements.
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When conducting adhesion testing, results meet or exceed the degree of adhesion recommended in plant-specific design requirements specific to the coating/lining and substrate.
v) 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). Any signs of abnormal corrosion or blockage will be removed, its source and extent of condition determined and corrected, and entered into the corrective action program.
w) Revise Fire Water System Program procedures to specify replacement of any sprinkler heads that show signs of leakage, excessive loading, corrosion, or loss of fluid in the glass bulb heat responsive element.
x) Revise Fire Water System Program procedures to perform an obstruction evaluation if any of the following conditions exist:
There is an obstructive discharge of material during routine flow tests.
An inspector's test valve is clogged during routine testing.
Foreign materials are identified during internal inspections.
Sprinkler heads are found clogged during removal or testing.
Pin hole leaks are identified in fire water piping.
After an extended fire water system shutdown (greater than one year).
There is a 50% increase in time it takes for water to flow out the inspector test valve after the associated dry valve is tripped when compared to the original acceptance criteria or last test.
y) Revise Fire Water System Program procedures to evaluate for MIC if tubercules or slime are identified during any internal inspections of fire water piping.
z) Revise the Fire Water System Program procedures to perform preaction valve trip testing every three years with the manual isolation valve closed.
Enhancements will be implemented prior to the period of extended operation.
18.1.14 Flow-Accelerated Corrosion Program The Flow-Accelerated Corrosion (FAC) Program manages loss of material due to wall thinning caused by FAC for carbon steel 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 program relies on implementation of guidelines published by EPRI in NSAC-202L and on internal and external operating experience.
The program also manages wall thinning due to various erosion mechanisms in treated water and steam systems for all materials that may be identified through industry or plant-specific operating experience.
The Flow-Accelerated Corrosion Program will be enhanced as follows.
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Revise Flow-Accelerated Corrosion Program procedures to (1) manage wall thinning due to erosion mechanisms from cavitation, flashing, liquid droplet impingement, and solid particle impingement; (2) include susceptible locations based on the extent-of-condition reviews in response to plant-specific or industry operating experience, and EPRI TR-1011231, Recommendations for Controlling Cavitation, Flashing, Liquid Droplet Impingement, and Solid Particle Erosion in Nuclear Power Plant Piping, and NUREG/CR-6031, Cavitation Guide for Control Valves; (3) ensure piping and components replaced with FAC-resistant material and subject to erosive conditions are not excluded from inspections; and (4) include the need for continued wall thickness measurements of replaced piping until the effectiveness of the corrective action is assured.
Revise Flow-Accelerated Corrosion Program procedures to evaluate wall thinning due to erosion from cavitation, flashing, liquid droplet impingement, and solid particle impingement when determining a replacement type of material.
Enhancements will be implemented prior to the period of extended operation.
18.1.15 Inservice Inspection Program The Inservice Inspection 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 of ASME Class 1, 2 and 3 components as specified in ASME Section XI code, 2001 Edition, 2003 addendum. 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 10 CFR 50.55a. Repair and replacement activities for these components are covered in Subsection IWA of the ASME code edition of record.
Revise Inservice Inspection Program procedures to include a supplemental inspection of Class 1 CASS piping components that do not meet the material selection criteria of NUREG-0313, Revision 2, with regard to ferrite and carbon content. An inspection technique qualified by ASME or EPRI will be used to monitor cracking.
18.1.16 Inservice Inspection - IWF Program The Inservice Inspection (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 for the conduct of activities that are necessary to fulfill the requirements of ASME Section XI, as mandated by 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 implementing procedures use 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.
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Revise plant procedures to include assessment of the impact on the inspection sample representativeness if components that are part of the sample population are reworked.
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."
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.
Revise plant procedures to specify the following conditions as unacceptable:
Loss of material due to corrosion or wear, which reduces the load bearing capacity of the component support.
Debris, dirt, or excessive wear that could prevent or restrict sliding of the sliding surfaces as intended in the design basis of the support.
Cracked or sheared bolts, including high strength bolts, and anchors.
Enhancements will be implemented prior to the period of extended operation.
18.1.17 Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program The Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program performs periodic visual examinations and preventive maintenance to manage loss of material due to corrosion, loose bolting or rivets, and rail wear of cranes and hoists within the scope of license renewal and subject to aging management review, based on industry standards and guidance documents. The program includes structural components, including structural bolting, that make up the bridge, the trolley, and crane rails and includes cranes and hoists that meet the provisions of 10 CFR 54.4(a)(1) and (a)(2) and of NUREG-0612, Control of Heavy Loads at Nuclear Power Plants. The activities entail visual examinations and functional testing to ensure that cranes and hoists are capable of sustaining their rated loads.
The Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems Program will be enhanced as follows.
Revise plant procedures to specify monitoring of crane rails for loss of material due to wear; monitoring structural components of the bridge, trolley and hoists for deformation, cracking, and loss of material due to corrosion; and monitoring structural connections for loose or missing bolts, nuts, pins or rivets and any other conditions indicative of loss of bolting integrity.
Revise plant procedures to specify inspection frequency in accordance with ASME B30.2 or other appropriate standard in the ASME B30 series. 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.
Revise plant procedures to require that significant loss of material due to wear of crane rails and any sign of loss of bolting integrity will be evaluated in accordance with ASME B30.2 or other appropriate standard in the ASME B30 series.
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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.
18.1.18 Internal Surfaces in Miscellaneous Piping and Ducting Components Program The Internal Surfaces in Miscellaneous Piping and Ducting Components Program manages loss of material and reduction of heat transfer using representative sampling and opportunistic visual inspections of the internal surfaces of metallic and elastomeric components in environments of air-indoor (uncontrolled),
air-outdoor, condensation, diesel exhaust, raw water, or waste 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 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) up to 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 and reduction of heat transfer due to fouling. For non-metallic components, visual inspections and physical manipulation or pressurization will be used to detect evidence of surface irregularities. Visual examinations of elastomeric components will be accompanied by physical manipulation such that changes in material properties are readily observable. The sample size for physical manipulation will be at least 10 percent of accessible surface area.
Specific acceptance criteria are as follows:
Stainless steel: clean surfaces, shiny, no abnormal surface condition.
Metals: no abnormal surface condition.
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. Any 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.
18.1.19 Masonry Wall Program The Masonry Wall Program is based on guidance provided in 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 visual inspections of masonry walls that perform intended functions as defined in accordance with 10 CFR 54.4. Included are masonry walls required by 10 CFR 50.48, radiation shielding masonry walls, and masonry walls with the potential to affect safety-related components. The Structures
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Monitoring Program (Section 18.1.38) manages the effects of aging on structural steel components, steel edge supports, and steel bracing of masonry walls.
Masonry walls are inspected at least once every 5 years to ensure there is no loss of intended function.
The Masonry Wall Program will be enhanced as follows.
Revise plant procedures to ensure masonry walls located in in-scope structures are included in the scope of the Masonry Wall Program.
Revise plant procedures to include monitoring gaps between the structural steel supports and masonry walls that could potentially affect wall qualification.
Revise plant procedures to specify that masonry walls will be inspected at least once every 5 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.
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.
18.1.20 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 age-related degradation of the bus and bus connections, the bus enclosure assemblies, and the bus insulation and insulators. The program will inspect the safety-related 4.16 kV MEBs (non-segregated) between switchgear 3A3-S and 3AB3-S and 3B3-S and the safety-related 480V MEBs (non-segregated) between 3A31-S and 3AB31-S and 3B31-S.
The program provides for the visual inspection of MEB internal surface (bus enclosure assemblies) to detect age-related degradation, including cracks, corrosion, foreign debris, excessive dust buildup, and evidence of moisture intrusion. MEB insulating material is visually inspected for signs of reduced insulation resistance due to thermal/thermoxidative degradation of organics/thermoplastics, radiation-induced oxidation, moisture/debris intrusion, or ohmic heating, as indicated by embrittlement, cracking, chipping, melting, swelling, discoloration, or surface contamination, which may indicate overheating or aging degradation. The internal bus insulating supports or insulators will be inspected for structural integrity and signs of cracks. MEB external surfaces are visually inspected for loss of material due to general, pitting, and crevice corrosion. Accessible elastomers (e.g., gaskets, boots, and sealants) are inspected for degradation, including surface cracking, crazing, scuffing, and changes in dimensions (e.g., "ballooning" and "necking"), shrinkage, discoloration, hardening, and loss of strength. A sample of accessible bolted connections will be inspected for increased resistance of connection by using thermography or by measuring connection resistance using a micro-ohmmeter. Thermography will be performed on bus connections with the MEB covers in place only if the bus enclosure is equipped with an infrared window to facilitate the inspection.
For accessible bolted connections, 20 percent of the population with a maximum sample of 25 will constitute a representative sample size. Otherwise, a technical justification of the methodology and sample size used for selecting components should be included as part of the program's site documentation.
These inspections are performed at least once every 10 years.
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As an alternative to thermography or measuring connection resistance of accessible bolted connections covered with heat shrink tape, sleeving, insulating boots, etc., visual inspection of insulation material may be used to detect surface anomalies, such as embrittlement, cracking, chipping, melting, discoloration, swelling, or surface contamination. When this alternative visual inspection is used to check bolted connections, the first inspection is completed prior to the period of extended operation and at least once every 5 years thereafter.
This program will be used instead of the Structures Monitoring Program (Section 18.1.38) for external surfaces of the bus enclosure assemblies.
This program will be implemented prior to the period of extended operation.
18.1.21 Neutron-Absorbing Material Monitoring Program The Neutron-Absorbing Material Monitoring Program provides reasonable assurance that degradation of the neutron-absorbing material (Boral) used in spent fuel pools that could compromise the criticality analysis will be detected. The program relies on periodic inspection and testing to assure that the effects of aging do not cause degradation that impacts the required 5 percent sub-criticality margin through the period of extended operation. The program is established to monitor loss of material, reduction in neutron-absorbing capacity, and changes in dimension such as blisters, pits and bulges that could result in a loss of neutron absorbing capability. The parameters monitored include physical measurements and geometric changes in test coupons. The approach to relating measurement results from coupons to the condition of material in the spent fuel racks considers the exposure the coupons have received versus the exposure the spent fuel racks have received. In the event that there is a loss of neutron-absorbing capacity based on coupon testing, additional testing will be performed to ensure the sub-criticality requirements are met.
The Neutron-Absorbing Material Monitoring Program will be enhanced as follows:
Revise Neutron Absorbing Material Monitoring Program procedures to compare measurements from periodic inspections to prior measurements, and relate coupon measurement results to the performance of the spent fuel neutron-absorber materials considering differences in exposure conditions, vented/non-vented test samples, spent fuel racks, etc. Ensure the predicted boron-10 areal density will be sufficient to maintain the subcritical conditions required by technical specifications until the next coupon test.
The inspection will be performed prior to the period of extended operation and at least once every 10 years during the period of extended operation.
18.1.22 Nickel Alloy Inspection Program The Nickel Alloy Inspection Program manages cracking due to primary water stress corrosion cracking (PWSCC) for nickel-alloy (600/82/182) components and loss of material due to boric acid-induced corrosion in susceptible safety-related components in the vicinity of nickel-alloy reactor coolant pressure boundary components as required by 10 CFR 50.55a. It provides (a) inspection requirements for the reactor coolant pressure boundary components that contain PWSCC-susceptible dissimilar metals (alloys 600/82/182) and (b) inspection requirements for reactor coolant pressure boundary components in the vicinity of PWSCC-susceptible dissimilar metals (Alloy 600/82/182).
The program monitors for reactor coolant pressure boundary cracking and leakage using various methods, including non-destructive examination techniques, radiation monitoring, and visual inspections for boric acid deposits or the presence of moisture to identify cracking in the reactor coolant pressure boundary or loss of material. Inspection methods, schedules and frequencies for susceptible components are implemented in accordance with 10 CFR 50.55a. Reactor coolant leakage is calculated and trended on a
WSES-FSAR-UNIT-3 18-20 Revsion 311 (9/19) routine basis in accordance with technical specifications. The acceptance criteria for identified flaws and the methodology for evaluating the flaws are prescribed in 10 CFR 50.55a. Unacceptable indications of flaws are corrected through implementation of appropriate repair or replacement as dictated in 10 CFR 50.55a.
18.1.23 Non-EQ Electrical Cable Connections Program The Non-EQ Electrical Cable Connections Program is a one-time inspection program that consists of a representative sample of electrical connections within the scope of license renewal, which is inspected or tested at least once prior to the period of extended operation to confirm that there are no aging effects requiring management during that period. Cable connections included in this program are those connections susceptible to age-related degradation resulting in 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.
Inspection methods may include thermography, contact resistance testing, or other appropriate testing methods without removing the connection insulation, such as heat shrink tape, sleeving, or insulating boots.
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 20 percent of the connection population with a maximum sample of 25.
The inspections will be performed prior to the period of extended operation.
18.1.24 Non-EQ Inaccessible Power Cables (>/= 400 V) Program The Non-EQ Inaccessible Power Cables ( 400 V) Program will manage the aging effect of reduced insulation resistance on inaccessible power ( 400 V) cables that have a license renewal intended function.
The program provides for testing at least once every six years inaccessible or underground (e.g., in conduit, duct bank, or direct buried) power ( 400 volts) cables exposed to significant moisture to provide an indication of the condition of the conductor insulation, with the first tests occurring before the period of extended operation. The specific test should be a proven, commercially available test capable of detecting reduced insulation resistance of the cable's insulation system due to wetting or submergence. The condition of the cable insulation can be assessed with reasonable confidence using one or more of the following techniques: 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. One or more tests are used to determine the condition of the cables.
The program will include periodic inspections of manholes at least once every year (annually) to assess that cables and cable support structures are intact, but the inspection frequency will not be increased if water is found in the manholes during the inspections. In addition to the periodic manhole inspections, manhole inspections for water after event-driven occurrences, such as flooding, will be performed.
This program will be implemented prior to the period of extended operation.
18.1.25 Non-EQ Sensitive Instrumentation Circuits Test Review Program The Non-EQ Sensitive Instrumentation Circuits Test Review Program manages the aging effects of the applicable cables in the following systems or sub-systems.
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Excore neutron flux monitoring system Radiation monitoring Process monitoring system - component cooling water monitors Area radiation monitoring system - channels 24-31 Area radiation monitoring system - high range containment area monitors Area radiation system - fuel handling building Airborne monitoring system - main control room monitors The Non-EQ Sensitive Instrumentation Circuits Test Review Program provides reasonable assurance that 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.
18.1.26 Non-EQ Insulated Cables and Connections Program 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.
The program consists of accessible insulated electrical cables and connections installed in adverse localized environments to be visually inspected at least once every 10 years for cable jacket and connection insulation surface anomalies, such as embrittlement, discoloration, cracking, melting, swelling, or surface contamination, that could indicate incipient conductor insulation aging degradation from temperature, radiation, or moisture.
This program will be implemented prior to the period of extended operation.
18.1.27 Oil Analysis Program 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. Oil testing results that indicate the presence of water initiate corrective action that may include evaluating for in-leakage.
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.
WSES-FSAR-UNIT-3 18-22 Revsion 311 (9/19) 18.1.28 One-Time Inspection Program The One-Time Inspection Program consists of a one-time inspection of selected components to accomplish the following:
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 due to fouling.
Confirm the insignificance of an aging effect for situations in which additional confirmation is appropriate using inspections that verify unacceptable degradation is not occurring.
Trigger additional actions if necessary to 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 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 age-related degradation 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.
Water Chemistry Control - Primary and Secondary Program One-time inspection activity will verify the effectiveness of the Water Chemistry Control - Primary and Secondary Programs by confirming that cracking, loss of material, and reduction of heat transfer are not occurring or are occurring at a rate that will not cause a loss of intended function.
Oil Analysis Program One-time inspection activity will verify the effectiveness of the Oil Analysis Program by confirming that cracking, loss of material, and reduction of heat transfer not occurring or are occurring at a rate that they will not cause a loss of intended function.
Diesel Fuel Monitoring Program One-time inspection activity will verify the effectiveness of the Diesel Fuel Monitoring Program by confirming that loss of material or reduction of heat transfer due to foul-ing are not occurring or are occurring at a rate that will not cause a loss of intended function.
Reactor vessel flange leak detection line One-time inspection activity will confirm that cracking and loss of material are not occurring or are occurring so slowly that they will not affect the component intended function during the period of extended operation.
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Plant stack radiation monitor stainless steel tubing exposed to air-outdoor One-time inspection activity will confirm that cracking is not occurring or is occurring so slowly that it will not affect the component intended function during the period of extended operation.
The inspections will be performed within the ten years prior to the period of extended operation.
18.1.29 One-Time Inspection - Small-Bore Piping Program 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 inch in systems that have not experienced cracking. The program can also be used for systems that have experienced cracking but have implemented design changes to effectively mitigate cracking.
Ten of the 371 ASME Class 1 piping butt welds that meet the selection criteria will receive a one-time volumetric examination. Seven of the 216 ASME Class 1 socket welds that meet the selection criteria will receive a one-time volumetric or opportunistic destructive examination. 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, 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 is no need to manage age-related degradation 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.
18.1.30 Periodic Surveillance and Preventive Maintenance Program The Periodic Surveillance and Preventive Maintenance (PSPM) Program manages aging effects not managed by other aging management programs, including change in material properties, cracking, loss of material, and reduction of heat transfer.
Inspections occur at least once every 5 years during the period of extended operation, except for inspection of the circulating water intake piping. Inspection of the internal surface of the nonsafety-related concrete circulating water intake piping occurs at least once every 10 years with the first inspection prior to the period of extended operation.
Credit for program activities has been taken in the aging management review of the following systems and structures.
Inspect the wet cooling tower nozzles
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Inspect wet cooling tower chemical addition and filtration system suction piping anti-siphon holes.
Inspect submersible sump pumps and backup pumps for dry cooling towers.
Inspect emergency diesel generator system heat exchanger tubes.
Inspect external surface of stainless steel expansion joint and internal surface of stainless steel expansion joint liner in diesel exhaust.
Inspect tubes and fins of the CCW dry cooling tower radiator.
Inspect the internal surface of the portable UHS replenishment pump casing.
Inspect the circulating water intake piping internal surface (reinforced concrete portions)
Inspect the inside surface of RCP oil collection components (drip pans, enclosures, flame arrestors (tail pipe), piping, sight glass, tanks, and valve bodies).
Inspect internal and external surfaces of control room HVAC portable smoke removal fan and smoke-ejector duct.
Inspect the internal surface of a representative sample of abandoned equipment in the following nonsafety-related systems affecting safety-related systems:
Radiation monitoring (ARM, PRM)
Auxiliary steam (AS)
Blowdown (BD)
Boron management (BM)
Condensate (CD)
Chemical feed (CF)
Chilled water (CHW)
Emergency diesel cooling (EG, EGA, EGC, EGF, EGL)
Fuel pool cooling and purification (FS)
Liquid waste management (LWM)
Solid waste management (SWM)
Secondary sampling (SSL)
The PSPM Program will be enhanced as follows.
Revise PSPM Program procedures as necessary to incorporate the activities denoted above.
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Revise the PSPM Program procedures to state that the acceptance criterion is no indication of relevant degradation and such indications will be evaluated.
Enhancements will be implemented prior to the period of extended operation.
18.1.31 Protective Coating Monitoring and Maintenance Program 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 meets the technical basis of 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.
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.
The Protective Coating Monitoring and Maintenance Program will be enhanced as follows.
Revise plant procedures to specify visual inspections of coatings near sumps or screens associated with the emergency core cooling system.
The enhancement will be implemented prior to the period of extended operation.
18.1.32 Reactor Head Closure Studs Program 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, and nuts) using inservice inspection (ASME Section XI 2001 Edition 2003 Addendum Table IWB-2500-1) and preventive measures to mitigate cracking.
Preventive actions include avoiding the use of metal-plated stud bolting, use of an acceptable surface treatment, use of stable lubricants, and use of bolting material that has actual yield strength of less than 150 ksi for all studs. The program detects cracks, loss of material and leakage using visual, surface and volumetric examinations as required by ASME Section XI. The program also relies on recommendations to address reactor head closure studs degradation listed in NUREG-1339 and NRC RG 1.65.
The Reactor Head Closure Studs Program will be enhanced as follows.
Revise Reactor Head Closure Studs Program procedures to ensure that replacement studs are fabricated from bolting material with actual measured yield strength less than 150 kilo-pounds per square inch.
Revise Reactor Head Closure Studs Program procedures to exclude the use of molybdenum disulfide (MoS2) on the reactor vessel closure studs and refer to RG 1.65, Rev. 1.
Enhancements will be implemented prior to the period of extended operation.
18.1.33 Reactor Vessel Internals Program The Reactor Vessel Internals Program implements the Electric Power Research Institute (EPRI) Technical Report N0. 1022863, "Materials Reliability Program: Pressurized Water Reactor (PWR) Internals Inspection and Evaluation Guidelines" (MRP-227-A), and EPRI Technical Report No. 1016609, "Materials
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Reliability Program: Inspection Standard for PWR Internals" (MRP-228), to manage the aging effects on the WF3 RVI components. WF3 is a CE Nuclear Steam Supply System (NSSS) design. The recommended activities in MRP 227-A and additional plant-specific activities not defined in MRP 227-A are implemented in accordance with Nuclear Energy Institute (NEI) 03-08, "Guideline for the Management of Materials Issues."
This program is used to manage cracking, loss of material due to wear, reduction in fracture toughness, change in dimension, and loss of preload for reactor vessel internal components intended to provide core support. The program applies the guidance in MRP-227-A for inspecting, evaluating and, if applicable, dispositioning non-conforming RVI components. The program includes expanding periodic examinations and other inspections, if the extent of the degradation identified exceeds the expected levels.
The sample selection process consisted of categorizing reactor vessel internal components into four sets:
(1) a set of primary internals component locations for the WF3 RVI design that are expected to show leading indications of the degradation effects, (2) a set of expansion internals component locations that are specified to expand the sample should the indications be more severe than anticipated, (3) a set of internals locations that are deemed to be adequately managed by existing programs, such as American Society of Mechanical Engineers (ASME) Code Section XI Examination Category B-N-3, examinations of core support structures and (4) a set of internal locations that are deemed to require no additional measures.
This process used appropriate component functionality criteria, age-related degradation susceptibility criteria, and failure consequences criteria to identify the components that will be inspected under the program. Consequently the sample selection process is adequate to assure that the intended functions of the reactor internal components are maintained during the period of extended operation.
The Reactor Vessel Internals Program will be enhanced as follows.
Revise Reactor Vessel Internals Program procedures to include the inspections identified in the inspection plan in NRC submittal W3F1-2013-0070, dated December 16, 2013, including the inspection of the core stabilizing bolts as an addition to the WF3 ASME Section XI In-Service Inspection Program.
The enhancement will be implemented prior to the period of extended operation.
18.1.34 Reactor Vessel Surveillance Program The Reactor Vessel Surveillance Program manages reduction of fracture toughness and long-term operating conditions for reactor vessel beltline materials using material data and dosimetry. The program includes all reactor vessel beltline materials as defined by 10 CFR 50 Appendix G, Section II.F, and complies with 10 CFR 50, Appendix H for vessel material surveillance.
The objective of the Reactor Vessel Surveillance Program is to provide 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. If surveillance capsules are not withdrawn during the period of extended operation, operating restrictions are specified to ensure that the plant is operated under the conditions to which the surveillance capsules were exposed. Capsules removed from the reactor vessel are tested and reported in accordance with ASTM E 185-82 to the extent practicable for the configuration of the specimens in the capsule. Any changes to the capsule withdrawal schedule, including the withdrawal schedule for spare capsules, must be approved by the NRC prior to implementation. Untested capsules placed in storage must be maintained for future insertion.
The Reactor Vessel Surveillance Program will be enhanced as follows.
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Revise the Reactor Vessel Surveillance Program to specify submittal of a withdrawal schedule for Capsule 277° to the NRC for review and approval within 1 year following the receipt of the renewed license.
The enhancement will be implemented within one (1) year following issuance of the renewed operating license.
18.1.35 Selective Leaching Program The Selective Leaching Program demonstrates the absence of selective leaching in a selected 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 condensation, raw water, waste water, treated water, or soil. A sample population is defined as components with the same material and environment combination.
Where practical the sample population will focus on components most susceptible to 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 hardness measurement or other 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 during 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 2 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.
This inspections will be performed within the 5 years prior to the period of extended operation.
18.1.36 Service Water Integrity Program The Service Water Integrity Program manages loss of material and reduction of heat transfer for components fabricated from materials such as carbon steel, copper alloy, gray cast iron, or stainless steel, and in an environment of raw water as described in the WF3 response to NRC GL 89-13. The program includes (a) surveillance and control techniques to manage effects of biofouling, corrosion, erosion, protective coating failures, and silting; (b) inspection of critical components for signs of corrosion and biofouling; and (c) tests to verify heat transfer capability of heat exchangers important to safety. The program manages loss of material due to cavitation erosion through periodic visual inspections of susceptible locations supplemented with volumetric examinations as necessary based on results of the visual inspections.
The Service Water Integrity Program will be enhanced as follows.
Revise the Service Water Integrity Program procedures to (1) flush redundant, infrequently flowed sections, and stagnant lines to ensure there is no blockage, and (2) inspect selected low flow or stagnant areas and system low points such as drains.
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Enhancements will be implemented prior to the period of extended operation.
18.1.37 Steam Generator Integrity Program The Steam Generator Integrity Program manages aging effects for the steam generator tubes, plugs, sleeves, and secondary side components contained within the steam generator in accordance with the plant technical specifications and commitments to NEI 97-06. Preventive and mitigative measures include foreign material exclusion programs and other primary and secondary side maintenance activities, such as sludge lancing and inspecting any installed plugs and replacing them when needed with updated materials as needed. The program has acceptance criteria for when a tube should be plugged based on wall thickness measurements.
Steam generator water chemistry is monitored and maintained in accordance with the Water Chemistry Control - Primary and Secondary Program. The thermally treated Alloy 690 tubes are monitored for wear based on industry experience using inspection techniques capable of detecting the aging effect. The general conditions of components (e.g., plugs when installed, sleeves, tubesheet primary side, channel head surfaces exposed to reactor coolant, partition plate, and secondary side components) are monitored visually. Visual Inspections of primary side components are performed at least once every 72 effective full power months or every third refueling outage, whichever results in more frequent inspections, and will verify no rust stains, discoloration, or distortion of the cladding that could indicate loss of material due to boric acid corrosion of base metals resulting from a breach of the cladding.
In the event degradation is noted, the corrective action program drives a more detailed inspection. The inspections are performed by qualified personnel using qualified techniques in accordance with approved station procedures. In addition primary-to-secondary leak rates are monitored as a potential indicator of steam generator tube integrity. Condition monitoring assessments are performed and documented in accordance with site-approved procedures to confirm that adequate tube integrity has been maintained since the previous inspection. Operational assessments are performed to ensure the tube integrity will be maintained until the next scheduled inspection. The acceptance criteria are in accordance with technical specifications.
The Steam Generator Integrity Program will be enhanced as follows:
Revise the Steam Generator Integrity Program to include general visual inspection of the partition plate, channel head, and tubesheet (primary side) with a frequency of at least once every 72 effective full power months or every third refueling outage, whichever results in more frequent inspections. Enhancements will be implemented prior to the period of extended operations.
18.1.38 Structures Monitoring Program 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." The scope of the Structures Monitoring Program includes structures within the scope of license renewal as delineated in 10 CFR 54.4. The program performs periodic visual examinations to monitor the condition of structures and structural components, including components such as concrete and steel components, structural bolting, component supports, and concrete masonry blocks. Inspections are performed at least once every 5 years to ensure there is no loss of intended function between inspections.
The Structures Monitoring Program includes plant procedures that use the guidance delineated in NUREG-1339 and industry recommendations delineated in Electric Power Research Institute (EPRI)
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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.
Revise plant procedures to include the following in-scope structures.
Battery house 230kV switchyard Control house 230kV switchyard Fire pump house Fire water storage tank foundations Fuel oil storage tank foundation Manholes, handholes and duct banks Plant stack Transformer and switchyard support structures and foundations Revise plant procedures to include a list of structural components and commodities within the scope of the program.
Revise plant procedures to include periodic sampling and chemical analysis of ground water.
Revise plant procedures to include the preventive actions for storage of ASTM A325, ASTM F1852, and/or ASTM A490 bolting from Section 2 of Research Council on Structural Connections publication, "Specification for Structural Joints Using ASTM A325 or A490 Bolts."
Revise plant procedures to include the following parameters to be monitored or inspected:
For concrete structures, base inspections on quantitative requirements of industry codes, standards and guidelines (e.g., ASCE 11, ACI 349.3R) and consideration of industry and plant-specific operating experience.
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.
For chemical analysis of ground water, monitor pH, chlorides and sulfates.
Revise plant procedures to include the following components to be monitored for the associated parameters:
Anchor bolts (nuts and bolts) for loss of material, and loose or missing nuts and/or bolts.
Elastomeric vibration isolators and structural sealants for cracking, loss of material, loss of sealing, and change in material properties (e.g., hardening).
Revise plant procedures to include the following:
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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.
Structures will be inspected at least once every 5 years with provisions for more frequent inspections of structures and components categorized as (a)(1) in accordance with 10 CFR 50.65.
Submerged structures will be inspected at least once every 5 years.
Sampling and chemical analysis of ground water at least once every 5 years. The program owner will review the results and evaluate any anomalies and perform trending of the results.
Revise plant procedures to inspect the SIT and RCS supports with ASTM A-540 high-strength bolting greater than one-inch nominal diameter prior to the period of extended operation and at least once every 5 years thereafter. The periodic visual inspections are intended to detect whether a corrosive environment that supports SCC potential exists or has existed since the previous inspection.
Acceptance criteria for the inspections will be the absence of evidence of moisture, residue, foreign substances, or corrosion.
Conditions that dont meet the acceptance criteria and thus indicate a potential corrosive environment that supports SCC will be entered into the corrective action program for evaluation.
Revise plant procedures to include qualitative and quantitative acceptance criteria for A-540 bolts as follows:
a) If moisture is present at or near a bolt or stud, factors considered in the evaluation include, but are not limited to:
The source of leakage or condensation that supplied the moisture.
The proximity of the moisture to the bolt or stud.
The probable or analyzed chemical characteristics of the moisture, including the presence of contaminants.
The visible or likely pathway, if any, that the liquid traversed to arrive at or near the bolt or stud.
The amount of any corrosion on or near the bolt or stud.
The material condition of the coatings on the bolt or stud, and associated support.
The characteristics of any corrosion on or near the bolt or stud.
The proximity to the bolt or stud of any nearby evidence of corrosion.
The material condition of accessible concrete or grout near the bolt or stud.
WSES-FSAR-UNIT-3 18-31 Revsion 311 (9/19) b) If there is evidence that moisture had been present at or near a bolt or stud, but no moisture is present at or near a bolt or stud, factors considered by engineering include, but will not be limited to:
The probable sources of past leakage or condensation that could have supplied the moisture.
The proximity to the bolt or stud to the evidence that moisture had been present.
The probable or analyzed chemical characteristics of any moisture residue, including the presence of contaminants.
The visible or likely pathway, if any, that the liquid may have traversed to arrive at or near the bolt or stud.
The amount of any corrosion on or near the bolt or stud.
The material condition of any coatings on the bolt or stud, and associated support.
The characteristics of any corrosion on or near the bolt or stud.
The proximity to the bolt or stud of any nearby evidence of corrosion.
The material condition of concrete or grout near the bolt or stud.
Should adverse conditions be identified during the examinations, engineering will determine if the bolting has been exposed to a corrosive environment with the potential to cause SCC. Bolts determined to have been exposed to a corrosive environment with the potential to cause SCC will be identified as within a population where SCC is a concern. A sample equal to 20 percent (rounded up to the nearest whole number) of the population, with a maximum sample size of 25 bolts, will be subject to volumetric examination. The selection of the samples will consider susceptibility to stress corrosion cracking (e.g., actual measured yield strength) and ALARA considerations.
Enhancements will be implemented prior to the period of extended operation.
18.1.39 Thermal Aging Embrittlement of Cast Austenitic Stainless Steel Program The Thermal Aging Embrittlement of Cast Austenitic Stainless Steel Program manages reduction in fracture toughness and cracking. The program consists of a determination of the susceptibility of CASS piping, piping components, and piping elements to thermal aging embrittlement based on casting method, molybdenum content, and percent ferrite. For potentially susceptible components aging management is accomplished through qualified visual inspections, such as enhanced visual examination, qualified ultrasonic testing methodology, or component-specific flaw tolerance evaluation in accordance with ASME Section XI code, 2001 Edition 2003 addendum. Applicable industry standards and guidance documents are used to delineate the program.
This program will be implemented prior to the period of extended operation.
WSES-FSAR-UNIT-3 18-32 Revsion 311 (9/19) 18.1.40 Water Chemistry Control - Closed Treated Water Systems Program The Water Chemistry Control - Closed Treated Water Systems Program manages loss of material, cracking, and reduction of heat transfer in components exposed to a treated water environment through monitoring and control of water chemistry, including the use of corrosion inhibitors, chemical testing, and visual inspections of internal surface condition. The EPRI Closed Cycle Cooling Guideline (1007820),
industry and in-house 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.
Revise Water Chemistry Control - Closed Treated Water Systems Program procedures to include high pressure fire water diesel pump jacket water system.
Revise Water Chemistry Control - Closed Treated Water Systems Program procedures to specify water chemistry parameters monitored and the acceptable range of values for these parameters that are in accordance with EPRI 1007820, industry guidance, or vendor recommendations.
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 every 10 years. 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 corrosion, fouling, or cracking. If visual examination identifies adverse conditions, additional examinations, including ultrasonic testing, are conducted.
Revise the Water Chemistry Control - Closed Treated Water Systems Program procedures to define a representative sample as 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 corrosion, fouling, or cracking.
Revise the Water Chemistry Control - Closed Treated Water Systems Program procedures to perform treated water sampling and analysis of the closed treated water systems per industry standards and in no case greater than quarterly unless justified with an additional analysis.
Revise Water Chemistry Control - Closed Treated Water Systems Program procedures to specify water chemistry parameters monitored and the acceptable range of values for these parameters that are in accordance with EPRI 1007820, industry guidance, or vendor recommendations.
Revise the Water Chemistry Control - Closed Treated Water Systems Program procedures to provide acceptance criteria for inspections. Ensure system components meet system design requirements, such as minimum wall thickness.
Enhancements will be implemented prior to the period of extended operation.
18.1.41 Water Chemistry Control - Primary and Secondary Program The Water Chemistry Control - Primary and Secondary 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 - Primary and Secondary Program monitors and controls water chemistry parameters such as pH, chloride, fluoride, and sulfate to keep peak levels of various contaminants below system specific limits. EPRI Report 1014986, Rev. 6, is used to provide
WSES-FSAR-UNIT-3 18-33 Revsion 311 (9/19) guidance for primary water chemistry, and EPRI Report 1016555, Rev. 7, is used to provide guidance for secondary water chemistry.
The One-Time Inspection Program (Section 18.1.28) uses inspections or nondestructive evaluations of representative samples to verify that the Water Chemistry Control - Primary and Secondary Program has been effective at managing aging effects. The representative sample includes low flow and stagnant areas.
18.2 EVALUATION OF TIME-LIMITED AGING ANALYSES In accordance with 10 CFR 54.21(c), an application for a renewed license requires an evaluation of time-limited aging analyses for the period of extended operation. The following time-limited aging analyses were evaluated as part of the license renewal application to meet this requirement.
18.2.1 Reactor Vessel Neutron Embrittlement The regulations governing reactor vessel integrity are in 10 CFR 50. Section 50.60 requires that light-water reactors meet the fracture toughness, pressure-temperature limits, and material surveillance program requirements for the reactor coolant pressure boundary set forth in Appendices G and H of 10 CFR
18.2.1.1 Reactor Vessel Fluence Fluence is calculated based on a time-limited assumption defined by the operating term. Therefore, analyses that evaluate reactor vessel neutron embrittlement based on calculated fluence are TLAAs. The neutron fluence values for the WF3 reactor pressure vessel beltline and extended beltline materials (plates and welds) have been projected to 55 EFPY of operation.
The methods used to calculate the WF3 vessel fluence satisfy the criteria set forth in RG 1.190, "Calculational and Dosimetry Methods for Determining Pressure Vessel Neutron Fluence." These methods are described in detail in the WF3 License Amendment Request for Use of RAPTOR-M3G Code for Neutron Fluence Calculations (Ref. 18.3-3).
FSAR Section 5.3.1.6 provides additional information on reactor pressure vessel specimen capsules and associated dosimeters. WCAP-18002-NP, July 2015, includes the results of capsules withdrawn and tested for WF3, corresponding to end of cycles 4, 11, and 19. See Section 18.1.34 for additional information on the Reactor Vessel Surveillance Program.
The calculation of fluence is treated as a TLAA that has been projected to the end of the period of extended operation in accordance with 10 CFR 54.21(c)(1)(ii) and used as an input to the analyses in the following sections.
18.2.1.2 Upper-Shelf Energy For the license renewal application, upper-shelf energy (USE) was evaluated for all materials included in the beltline. Fracture toughness criteria in 10 CFR 50 Appendix G requires that beltline materials maintain USE no less than 50 ft-lb during operation of the reactor. The 55 EFPY USE values for the beltline materials were determined using methods consistent with RG 1.99, Revision 2, "Radiation Embrittlement of Reactor Vessel Materials." The value of peak 1/4T fluence is used.
Two methods can be used to predict the decrease in USE with irradiation, depending on the availability of credible surveillance capsule data as defined in RG 1.99. For vessel beltline materials that are not in the surveillance program or for locations with non-credible data, the Charpy USE is assumed to decrease as a function of fluence and copper content, as indicated in RG 1.99, Revision 2 (Position 1.2). When two or
WSES-FSAR-UNIT-3 18-34 Revsion 311 (9/19) more credible surveillance data sets are available from the reactor, they may be used to determine the Charpy USE of the surveillance material. The surveillance data are then used in conjunction with the regulatory guide to predict the change in USE of the reactor vessel material due to irradiation (Position 2.2).
The 55 EFPY Position 1.2 USE values of the vessel materials can be predicted using the corresponding 1/4T fluence projection, the copper content of the materials, and Figure 2 in RG 1.99, Revision 2. The predicted Position 2.2 USE values are determined for the reactor vessel materials that are contained in the surveillance program by using the plant surveillance data along with the corresponding 1/4T fluence projection.
All of the beltline materials in the WF3 reactor vessel are projected to remain no less than the USE limit of 50 ft-lb (per 10 CFR 50 Appendix G) through 55 EFPY. Therefore, the WF3 reactor vessel Charpy USE TLAA has been projected to the end of the period of extended operation in accordance with 10 CFR 54.21(c)(1)(ii).
18.2.1.3 Pressurized Thermal Shock 10 CFR 50.61 provides rules for protection against pressurized thermal shock events for pressurized water reactors. Licensees are required to perform an assessment of the projected values of reference temperature whenever a significant change occurs in projected values of the adjusted reference temperature for pressurized thermal shock (RTPTS), or upon request for a change in the expiration date for the operation of the facility. Section 10 CFR 50.61 provides screening criteria as acceptable if RTPTS is lower than 270°F for plates, forgings, and axial welds and RTPTS is lower than 300°F for circumferential welds.
Section 10 CFR 50.61(c) provides two methods for determining RTPTS. Position 1 applies for material that does not have surveillance data available, and Position 2 applies for material with surveillance data.
Positions 1 and 2 are described in RG 1.99, Revision 2. Adjusted reference temperatures are calculated for both Positions 1 and 2 by following the guidance in RG 1.99, Sections 1.1 and 2.1, respectively, using copper and nickel content of beltline materials and end-of-life fluence projections.
The beltline materials in the WF3 reactor vessel is below the RTPTS screening criteria values of 270°F for plates, forgings, and axial welds and 300°F for circumferentially oriented welds through 55 EFPY.
Therefore, the WF3 reactor vessel RTPTS TLAA has been projected to the end of the period of extended operation in accordance with 10 CFR 54.21(c)(1)(ii).
18.2.1.4 Pressure-Temperature Limits Appendix G of 10 CFR 50 requires operation of the reactor pressure vessel within established pressure-temperature (P-T) limits. These limits are established by calculations that utilize the materials and fluence data obtained through the Reactor Vessel Surveillance Program (Section 18.1.34). The P-T limits are calculated for several years into the future and remain valid for an established period of time.
The provisions of 10 CFR 50 Appendix G require the P-T limit curves be maintained and updated as necessary.
The WF3 P-T limits for the reactor coolant system are described in Technical Specifications (TS) 3.4.8.1.
TS Figure 3.4-2, Reactor Coolant System Pressure-Temperature Limits, identifies the current WF3 heatup curve. TS Figure 3.4-3, Reactor Coolant System Pressure-Temperature Limits, identifies the current WF3 cooldown curve. The analyses used to determine P-T limit curves are considered TLAAs. The WF3 P-T limit curves included in the Technical Specifications are valid through 32 EFPY. Prior to exceeding 32 EFPY, WF3 will generate new P-T limit curves to support plant operation beyond 32 EFPY.
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TS 4.4.8.1.2 states the reactor vessel material irradiation surveillance specimens shall be removed and examined to determine changes in material properties, at the intervals required by 10 CFR Part 50 Appendix H in accordance with the reactor vessel material surveillance program withdrawal schedule in FSAR Table 5.3-10. The results of these examinations shall be used to update TS Figures 3.4-2 and 3.4-3.
Surveillance specimen capsule 83° was removed at 24.66 EFPY and analysis results were provided in March 2015.
The WF3 P-T limit curves will be updated, as 10 CFR 50 Appendix G requires, through the period of extended operation in conjunction with the Reactor Vessel Surveillance Program (Section 18.1.34).
Therefore, P-T limit curves TLAAs will be adequately managed for the period of extended operation in accordance with 10 CFR 54.21(c)(1)(iii).
18.2.1.5 Low Temperature Overpressure Protection (LTOP) Setpoints The WF3 Technical Specification bases state that an operating shutdown cooling loop, connected to the RCS, provides overpressure relief capability and will prevent RCS overpressurization. This is accomplished by an LTOP relief valve located in each shutdown cooling loop, as identified in FSAR Section 5.2B.3. In addition, the overpressure protection system provides a diverse means of protection against RCS overpressurization at low temperatures.
Each time the P-T limit curves are revised, the LTOP relief setpoints are reevaluated. Therefore, the LTOP limits are considered part of the calculation analyses of P-T curves. The P-T limit curves are updated prior to exceeding applicable EFPY limits. See Section 18.2.1.4 for further information on the P-T limit curves.
Therefore, the effects of aging associated with the LTOP setpoints TLAA will be adequately managed for the period of extended operation in accordance with 10 CFR 54.21(c)(1)(iii).
18.2.2 Metal Fatigue Fatigue analyses are considered TLAAs for Class 1 and non-Class 1 mechanical components. Fatigue is an age-related degradation mechanism caused by cyclic stressing of a component by either mechanical or thermal stresses.
The aging management reviews that were performed for license renewal identify mechanical components that are within the scope of license renewal and are subject to aging management review. When TLAA -
metal fatigue is identified in the aging management program column of the tables in Section 3 of the license renewal application, the associated fatigue analyses are evaluated in this section. Evaluation of TLAAs per 10 CFR 54.21(c)(1) determines whether (i)
The analyses remain valid for the period of extended operation, (ii)
The analyses have been projected to the end of the period of extend operation, or (iii)
The effects of aging on the intended function(s) will be adequately managed for the period of extended operation.
Documentation of the evaluation of Class 1 component fatigue analyses is provided in Section 18.2.2.1.
Fatigue analysis of non-Class 1 mechanical components is discussed in Section 18.2.2.2. Screening for environmentally adjusted fatigue effects is documented in Section 18.2.2.3.
WSES-FSAR-UNIT-3 18-36 Revsion 311 (9/19) 18.2.2.1 Class 1 Metal Fatigue Fatigue evaluations performed in the design of WF3 Class 1 components in accordance with ASME Section III requirements are contained in the equipment stress reports and associated analyses. The fatigue evaluations calculate a cumulative usage factor (CUF) for each component or subassembly based on a specified number of design cycles for that component. Because the design cycles may be the number of transient cycles that were assumed for a 40 year license term, these calculations of CUFs are considered TLAAs.
Design cyclic loadings and thermal conditions for the Class 1 components are defined by the applicable design specifications for each component. The original design specifications established the initial set of transients that were used in the design of the components and are included as part of each component stress report. FSAR Table 3.9-1 "Transients Used in Stress Analysis of Code Class 1 Components" lists the transients that were used for the stress analyses of the RCS components. FSAR Table 3.9-3, "Transients and Operative Conditions for Code Class 1 Non-NSSS Piping," identifies the transients that were used as input to the piping stress analyses. Some component specific locations such as the pressurizer and safety injection nozzles were also analyzed for design transients beyond the original set of transients in response to thermal stratification and component specific stresses that are identified in the individual stress analyses.
The WF3 Technical Requirements Manual TRM 5.7-1 lists the requirement to maintain the reactor coolant system components within the component cyclic or transient limits. WF3 will manage the aging effects due to fatigue of these components using the Fatigue Monitoring Program in accordance with 10 CFR 54.21(1)(c)(iii). The WF3 Fatigue Monitoring Program monitors transient cycles that contribute to fatigue usage and is further described in FSAR Section 18.1.11.
Reactor Vessel FSAR Table 5.2-1, "Codes and Addenda Applied to Reactor Coolant Pressure Boundary," identifies the codes and addenda applied to the reactor vessel. The reactor vessel was designed to ASME Section III, Class 1 through Summer 1971 Addenda.
The original reactor vessel head has been replaced. The replacement reactor vessel head was designed to ASME Section III, Class 1 1998 edition through 2000 addenda.
WF3 will monitor transient cycles using the Fatigue Monitoring Program (Section 18.1.11) and assure that corrective action specified in the program is taken if any of the actual cycles approach their analyzed numbers. As such, the Fatigue Monitoring Program will manage the effects of aging due to fatigue on the reactor vessel in accordance with 10 CFR 54.21(c)(1)(iii).
Reactor Vessel Internals The WF3 reactor vessel internals are not pressure boundary components since they are internal to the reactor vessel. As described in the FSAR Section 3.9.5, in the design of critical reactor vessel internals components which are subject to fatigue, the stress analysis was performed utilizing the design fatigue curve of Figure I-9.2 of Section III of the ASME Boiler and Pressure Vessel Code. Stress reports were generated for several specific reactor vessel internals locations to support component replacement or reanalysis.
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WF3 will monitor transient cycles using the Fatigue Monitoring Program (Section 18.1.11) and assure that corrective action specified in the program is taken if any of the actual cycles approach their analyzed numbers. As such, the Fatigue Monitoring Program will manage the effects of aging due to fatigue on the reactor vessel internals in accordance with 10 CFR 54.21(c)(1)(iii).
Pressurizer The pressurizer is described in FSAR Section 5.4.10 and is shown in Figure 5.4-6. As identified in FSAR Table 5.2-1, the pressurizer was designed to ASME Boiler and Pressure Vessel Code,Section III, Class 1, through Summer 1971 Addenda. Structural weld overlays have been installed on the pressurizer surge nozzle, the pressurizer safety valve nozzles, and the pressurizer spray nozzle. The heater sleeves that remain in service were repaired. The pressurizer side shell temperature measurement nozzle and upper and lower head instrument nozzles were replaced.
The Fatigue Monitoring Program (Section 18.1.11) will manage the effects of aging due to fatigue on the pressurizer in accordance with 10 CFR 54.21(c)(1)(iii).
Steam Generators Replacement steam generators have been installed at WF3 as identified in FSAR Section 5.4.2 and shown in Figure 5.4-5. As identified in FSAR Table 5.2-1, the replacement steam generators were designed to ASME Boiler and Pressure Vessel Code,Section III, Class 1, 1998 Edition through 2000 Addenda. In addition to the RCS transients identified in FSAR Section 3.9.1.1, the replacement steam generators fatigue analysis included evaluation of component specific transients such as the tube leak tests.
The Fatigue Monitoring Program (Section 18.1.11) will manage the effects of aging due to fatigue on the steam generators in accordance with 10 CFR 54.21(c)(1)(iii).
Control Element Drive Mechanisms As described in FSAR Section 4.1, the control element drive mechanisms have been replaced. The control element drive mechanisms are described in FSAR Sections 3.9.4 and 4.1 and shown in FSAR Figure 3.9-13. As described in FSAR Table 5.2-1, the replacement control element drive mechanisms are designed to ASME Boiler and Pressure Vessel Code,Section III, Nuclear Power Plant Components, Class 1, 1998 Edition and 2000 Addenda.
The Fatigue Monitoring Program (Section 18.1.11) will manage the effects of aging due to fatigue on the control element drive mechanisms in accordance with 10 CFR 54.21(c)(1)(iii).
Reactor Coolant Pumps The reactor coolant pumps are described in FSAR Sections 3.9.1 and 5.4.1 and are shown in FSAR Figures 5.4-1 and 5.4-2. As identified in FSAR Table 5.2-1, the pump casings were designed to ASME Boiler and Pressure Vessel Code,Section III, Class 1, through Winter 1971 Addenda.
The Fatigue Monitoring Program (Section 18.1.11) will manage the effects of aging due to fatigue on the reactor coolant pumps in accordance with 10 CFR 54.21(c)(1)(iii).
WSES-FSAR-UNIT-3 18-38 Revsion 311 (9/19)
Reactor Coolant System Class 1 Piping and Valves The hot legs, cold legs and pressurizer surge piping was supplied by the nuclear steam system supplier (NSSS), ABB Combustion Engineering, and controlled by project specifications. The Class 1 tributary lines analyses include consideration of location specific transients such as loss of charging and loss of letdown.
Structural weld overlays (SWOL) have been installed on piping for the hot leg surge nozzle, hot leg 2 inch drains, and the hot leg shutdown cooling nozzles.
Large bore Class 1 valves described in FSAR Section 3.9.1.1.2 are within the scope of the metal fatigue analysis for Class 1 piping.
The Fatigue Monitoring Program (Section 18.1.11) will manage the effects of aging due to fatigue on the reactor coolant system Class 1 piping and valves in accordance with 10 CFR 54.21(c)(1)(iii).
18.2.2.2 Non-Class 1 Metal Fatigue Non-Class 1 Pressure Boundary Piping Using Stress Range Reduction Factors The impact of thermal cycles on non-Class 1 piping and in-line components is reflected in the calculation of the allowable stress range. The design of ASME III Code Class 2 and 3 or B31.1 piping systems incorporates a stress range reduction factor for determining acceptability of 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 7000 thermal cycles. The allowable stress range is reduced by the stress range reduction factor if the number of thermal cycles exceeds 7000 (ASME Boiler and Pressure Vessel Code, Division 1, Subsection NC, Class 2 Components). For the systems that are subjected to elevated temperatures above the fatigue threshold, thermal cycles have been projected for 60 years of plant operation for the piping and in-line components. These projections indicate that 7000 thermal cycles will not be exceeded for 60 years of operation. Therefore, the non-Class 1 pipe stress calculations are valid for the period of extended operation in accordance with 10 CFR 54.21(c)(1)(i).
Flexible Connections and Expansion Joints As part of the review of the WF3 documentation for fatigue, a search was performed for analyses of mechanical flexible connectors and expansion joints that were identified during the aging management review process. TLAAs were identified for emergency diesel generator intake air and exhaust expansion joints. The review of these analyses determined these flexible connectors were qualified for more cycles than are expected through the period of extended operation. The design analyses were determined to remain valid for the period of extended operation in accordance with 10 CFR 54.21(c)(1)(i).
Non-Class 1 Heat Exchangers with Fatigue Analysis Although the letdown and regenerative heat exchangers are in the Class 2 portion of the system, a fatigue analysis was completed for these components. The Fatigue Monitoring Program (Section 18.1.11) will manage the effects of aging due to fatigue on the letdown and regenerative heat exchangers in accordance with 10 CFR 54.21(c)(1)(iii).
WSES-FSAR-UNIT-3 18-39 Revsion 311 (9/19) 18.2.2.3 Effects of Reactor Water Environment on Fatigue Life Industry test data indicate that certain environmental effects (such as temperature and dissolved oxygen content) in the primary systems of light water reactors could result in greater susceptibility to fatigue than would be predicted by fatigue analyses based on the ASME Section III design fatigue curves. The ASME design fatigue curves were based on laboratory tests in air and at low temperatures. Although the failure curves derived from laboratory tests were adjusted to account for effects such as data scatter, size effect, and surface finish, these adjustments may not be sufficient to account for actual plant operating environments.
As reported in SECY-95-245, the NRC believes that no immediate staff or licensee action is necessary to deal with the environmentally assisted fatigue issue. In addition, the staff concluded that it could not justify requiring a backfit of the environmental fatigue data to operating plants. However, the NRC concluded that, because metal fatigue effects increase with service life, environmentally assisted fatigue should be evaluated for any proposed extended period of operation for license renewal.
NUREG-1801,Section X.M1 says the applicant "addresses the effects of the coolant environment on component fatigue life by assessing the impact of the reactor coolant environment on a sample of critical components for the plant". There is no analysis of environmentally assisted fatigue (EAF) under the current licensing basis. Rather, the effect on fatigue life of the reactor water environment is a new consideration for license renewal. Applying the Fen factors is not required during the initial 40 years of operation, consistent with the closure of Generic Safety Issue (GSI) 190. The full EAF evaluation will be completed for WF3 by reanalysis prior to the period of extended operation as identified by the enhancement to the Fatigue Monitoring Program (Section 18.1.11).
Original design basis fatigue calculations typically include conservatism meant to simplify the analyses, such as lumping all transients together and considering them all to be as severe as the worst transient for a particular location. As a part of incorporating the effects on fatigue of the reactor water environment, the design basis fatigue analyses may be revised for locations that would exceed a CUF of 1.0. CUFs will be determined using an NRC-approved version of the ASME code or NRC-approved alternative (e.g.,
NRC-approved code case).
WF3 will update the fatigue usage calculations using refined fatigue analyses to determine valid CUFs less than 1.0 when accounting for the effects of reactor water environment prior to the period of extended operation. This includes applying the appropriate Fen factors to valid CUFs determined using an NRC-approved version of the ASME code or NRC-approved alternative (e.g., NRC-approved code case).
WF3 will review design basis ASME Class 1 component fatigue evaluations to ensure the locations evaluated for the effects of the reactor coolant environment on fatigue include the most limiting components within the reactor coolant pressure boundary. Environmental effects on fatigue for these critical components will be evaluated using one of the following sets of formulae.
Carbon and Low Alloy Steels Those provided in NUREG/CR-6583, using the applicable ASME Section III fatigue design curve.
Those provided in Appendix A of NUREG/CR-6909, using either the applicable ASME Section III fatigue design curve or the fatigue design curve for carbon and low alloy steel provided in NUREG/CR-6909 (Figures A.1 and A.2, respectively, and Table A.1).
A staff-approved alternative.
WSES-FSAR-UNIT-3 18-40 Revsion 311 (9/19)
Austenitic Stainless Steels Those provided in NUREG/CR-5704, using the applicable ASME Section III fatigue design curve.
Those provided in NUREG/CR-6909, using the fatigue design curve for austenitic stainless steel provided in NUREG/CR-6909 (Figure A.3 and Table A.2).
A staff-approved alternative.
Nickel Alloys Those provided in NUREG/CR-6909, using the fatigue design curve for austenitic stainless steel provided in NUREG/CR-6909 (Figure A.3 and Table A.2).
A staff-approved alternative.
If an acceptable CUF cannot be calculated, WF3 will repair or replace the affected locations before exceeding an environmentally adjusted CUF of 1.0.
An EAF 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.
Therefore, WF3 will manage the effects of fatigue, including environmentally assisted fatigue, under the Fatigue Monitoring Program (Section 18.1.11) for the period of extended operation in accordance with 10 CFR 54.21(c)(1)(iii).
18.2.3 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 sets forth requirements for EQ programs.
Qualification is established for the environmental and service conditions expected for 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 WF3 Environmental Qualification of Electric Components Program (EQ Program, Section 18.1.9) 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 WF3 EQ Program ensures that the EQ components are maintained in accordance with their qualification bases.
The WF3 EQ Program was established to meet WF3 commitments for 10 CFR 50.49. The program is consistent with NUREG-1801,Section X.E1, "Environmental Qualification (EQ) of Electric Components."
The WF3 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).
WSES-FSAR-UNIT-3 18-41 Revsion 311 (9/19) 18.2.4 Containment Liner Plate, Metal Containments, and Penetrations Fatigue Analysis As identified in FSAR Section 3.8.2.3, the containment vessel was designed to exhibit a general elastic behavior under accident and earthquake conditions of loading. No permanent deformations due to primary stresses have been permitted in the design under any condition of loading. A fatigue evaluation was not performed for the containment vessel design.
WF3 has penetration bellows that are reviewed as part of the structural aging management reviews. As described in FSAR Section 3.6.2.4, these bellows are designed for a minimum of 7000 thermal cycles and 200 design seismic movements (cycles). The calculated allowable cycles were in excess of the required 7000 cycles. This number of cycles is more than these expansion joints will experience through the period of extended operation. The analyses remain valid in accordance with 10 CFR 54.21(c)(1)(i).
18.2.5 Other Plant-Specific TLAAs 18.2.5.1 Crane Load Cycles Analysis Cranes that were designed to Crane Manufacturer's Association of America Specification #70 (CMAA-70) have cycles specified as part of their design analysis. While there is no analysis that involves time-limited assumptions defined by the current operating term, for example, 40 years, crane cycle limits are nevertheless evaluated as a TLAA for cranes that were designed to CMAA 70. The WF3 cranes designed to CMAA-70 are the polar crane, fuel handling building (FHB) crane, and the radwaste cask handling bridge crane (located in the auxiliary building).
A review of the cranes at WF3 was performed to determine which cranes were designed to CMAA-70.
CMAA-70 (1975 Edition) Table 3.3.3.1.3-1 identifies crane service classes with the corresponding range of loading cycles. The allowable range of loading cycles considered is up to 100,000 load cycles for a CMAA-70 Service Class A1 crane.
The expected number of applicable crane cycles is below the top of the lowest cyclic loading range in CMAA-70 of 100,000 cycles, and the associated TLAAs remain valid for the period of extended operation in accordance with 10 CFR 54.21(c)(1)(i).
18.2.5.2 Leak-Before-Break Analysis FSAR Section 3.6.3 identifies that the leak before break (LBB) analysis is used to eliminate from the structural design bases the dynamic effects of double-ended guillotine breaks and equivalent longitudinal breaks. LBB analyses consider the thermal aging of cast austenitic stainless steel (CASS) piping and fatigue transients that drive the flaw growth during plant operation. Because these two analysis considerations could involve time-limited assumptions defined by the current term of operation, LBB analyses were further reviewed as potential TLAAs for WF3.
LBB analyses consider the thermal aging of the CASS piping and fatigue transients that drive flaw growth during operation of the plant. Because these two analysis considerations could be defined by the current term of operation, LBB analyses were further reviewed as potential TLAAs for WF3 main coolant loop and the pressurizer surge line components.
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Thermal Aging of CASS Thermal aging results in an increase in the yield strength of CASS and a decrease in fracture toughness, the decrease being proportional to the level of ferrite in the material. Thermal aging in these stainless steels will continue until the saturation, or fully aged, point is reached. Bounding fracture toughness values were used in the evaluation for the main coolant loop pump safe ends and the pressurizer surge line components. Since LBB evaluations use saturated (fully aged) fracture toughness properties, the evaluation of the thermal aging of CASS portion of the analysis does not have a material property time-dependency and is not a TLAA.
Fatigue Crack Growth The other LBB analysis consideration that could be time-limited is the accumulation of fatigue transient cycles that could invalidate the fatigue crack growth analysis. The LBB analysis determined that fatigue crack growth effects will be very small when analyzing for the full set of design transients. The basis of the evaluation of fatigue crack growth effects in the LBB analysis will remain unchanged so long as the number of transient occurrences remains below the number assumed for the analysis of fatigue crack growth effects. A review of applicable analyses identified the fatigue crack growth analysis is a TLAA. Therefore, the effects of aging associated with the leak before break (LBB) fatigue crack growth analyses for the main coolant loops and pressurizer surge line piping will be managed by the Fatigue Monitoring Program (Section 18.1.11) for the period of extended operation in accordance with 10 CFR 54.21(c)(1)(iii).
18.2.5.3 High Energy Line Break Postulation As described in FSAR Section 3.6.2.1.1.2, ASME Section III, Code Class 1 piping (excluding RCS loop and surge piping) rupture locations have been postulated in any piping run or branch at terminal ends and other intermediate points in accordance with RG 1.46, Protection Against Pipe Whip Inside Containment (May 1973) and Branch Technical Position MEB 3-1 issued with Generic Letter 87-11, Relaxation in Arbitrary Intermediate Pipe Rupture Requirements. Postulated rupture locations for Class 1 piping are as follows:
(1) Terminal points (2) Any intermediate points between terminal ends where the CUF exceeds 0.1 (based upon normal and upset plant conditions and OBE).
(3) Any intermediate points between terminal ends where the primary plus secondary stress intensities derived on an elastic basis is greater than 2.0 Sm in ferritic and 2.4 Sm in austenitic piping materials (based on normal and upset plant conditions and OBE).
The fatigue analysis to determine a CUF for the intermediate points is considered a TLAA. The Fatigue Monitoring Program (Section 18.1.11) identifies when the transients affecting high-energy piping systems are approaching their analyzed number of cycles. Therefore, the CUF calculations used to determine HELB postulated break locations are TLAAs that will be managed for the period of extended operation in accordance with 10 CFR 54.21(c)(1)(iii).
18.2.5.4 Reactor Vessel Internal Evaluations (Other than Fatigue)
During service, reactor vessel internal (RVI) and core support component materials are exposed to a high-temperature aqueous environment, fast neutron irradiation, and applied loads. WF3 evaluated the effect of extended power uprate (EPU) conditions on the potential for degradation of RVI component materials. The evaluation addressed age-related degradation mechanisms of materials that could be
WSES-FSAR-UNIT-3 18-43 Revsion 311 (9/19) affected by the reactor coolant temperature and by neutron and gamma irradiation. The evaluations found that neutron and gamma flux are lower than considered in the original design. Therefore, the level of irradiation-induced embrittlement was not expected to change significantly with the uprate. Also, embrittlement of CASS components as a result of thermal aging and neutron irradiation was not significantly affected by the power uprate. However, extended power uprate evaluations to determine the effects of fluence on RVI components are considered TLAAs because they were based on operation through the original 40-year operating term.
The WF3 Reactor Vessel Internals Program (Section 18.1.33) will manage the effects of aging associated with RVI TLAAs for the period of extended operation in accordance with 10 CFR 54.21(c)(1)(iii).
18.3 REFERENCES
18.3-1 Entergy Operations, Inc, W3F1-2016-0012, License Renewal Application Waterford Steam Elec-tric Station, Unit 3, March 23, 2016 (ADAMS Accession No. ML16088A324) 18.3-2 U.S. Nuclear Regulatory Commission, Safety Evaluation Report Related to the License Renewal of Waterford Steam Electric Station Unit 3, August 2018 (ADAMS Accession No. ML18228A668) 18.3-3 Entergy Operations, Inc., W3F1-2017-0065, "License Amendment Request for Use of RAPTOR-M3G Code for Neutron Fluence Calculations." November 28, 2017. (ADAMS Accession Number ML17332A898)
WSES-FSAR-UNIT-3 Table 18.4-1 (Sheet 1 of 16)
Revision 311 (9/19)
LICENSING RENEWAL COMMITMENT LIST 18.4 LICENSE RENEWAL COMMITMENT LIST No.
Program or Activity Commitment Implementation Schedule Source (Letter Number) 1 Bolting Integrity Enhance the Bolting Integrity Program as follows:
- a.
Revise Bolting Integrity Program procedures to include submerged pressure retaining bolting
- b.
Revise Bolting Integrity Program Inspected procedures to monitor high strength bolting locations (i.e., bolting with actual yield strength greater than or equal to 150 ksi) for cracking
- c.
Revise Bolting Integrity Program procedures to include a volumetric examination per ASME Code Section Xl, Table IWB-2500-1, for high strength closure bolting with actual yield strength greater than or equal to 150 ksi regardless of code classification
- d.
Revise Bolting Integrity Program documents to specify opportunistic inspections of normally submerged dry cooling tower area sump pump discharge piping bolting
- e.
Revise Bolting Integrity Program documents to specify visual inspection of a representative sample of closure bolting (bolt heads, nuts, and threads) from components with an internal environment of a clear gas, such as air or nitrogen.
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.
Prior to June 18, 2024 W3F1-2016-0012 March 23, 2016 (ML16088A324)
W3F1-2016-0063 October 13, 2016 (ML16287A675)
W3F1-2017-0026 April 11, 2017 (ML17102A856) 2 Buried and Underground Piping and Tanks Inspection Implement the Buried and Underground Piping and Tanks Inspection Program as described in LRA Section B.1.3.
Prior to June 18, 2024, or the end of the last refueling outage prior to December 18, 2024, whichever is later.
W3F1-2016-0012 March 23, 2016 (ML16088A324)
W3F1-2016-0063 October 13, 2016 (ML16287A675) 3 Coating Integrity Implement the Coating Integrity Program as described in LRA Section B.1.4.
Prior to June 18, 2024, or the end of the last refueling outage prior to December 18, 2024, whichever is later.
W3F1-2016-0012 March 23, 2016 (ML16088A324)
W3F1-2016-0063 October 13, 2016 (ML16287A675)
W3F1-2016-0074 December 7, 2016 (ML16342C485)
WSES-FSAR-UNIT-3 Table 18.4-1 (Sheet 2 of 16)
Revision 311 (9/19)
LICENSING RENEWAL COMMITMENT LIST No.
Program or Activity Commitment Implementation Schedule Source (Letter Number) 4 Compressed Air Monitoring Enhance the Compressed Air Monitoring Program as follows:
- a.
Revise Compressed Air Monitoring Program procedures to include the EDG starting air system
- b.
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
- c.
Revise Compressed Air Monitoring Program procedures to include periodic and opportunistic visual inspections of accessible internal surfaces of system components, including accumulators, flex hoses, and tubing. Specify inspections at frequencies recommended in ASME OM-S/G-1998 (Part 17)
Prior to June 18, 2024 W3F1-2016-0012 March 23, 2016 (ML16088A324) 5 Containment Inservice Inspection-IWE Enhance the Containment Inservice Inspection Program 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 of Structural Connections publication Specification for Structural Joints Using ASTM A325 or A490 Bolts.
Prior to June 18, 2024, or the end of the last refueling outage prior to December 18, 2024, whichever is later.
W3F1-2016-0012 March 23, 2016 (ML16088A324)
WSES-FSAR-UNIT-3 Table 18.4-1 (Sheet 3 of 16)
Revision 311 (9/19)
LICENSING RENEWAL COMMITMENT LIST No.
Program or Activity Commitment Implementation Schedule Source (Letter Number) 6 Diesel Fuel Monitoring Enhance the Diesel Fuel Monitoring Program as follows:
- a.
Revise the Diesel Fuel Monitoring Program procedures to include the auxiliary diesel generator fuel oil tank and the emergency diesel generator (EDG) fuel oil feed tanks
- b.
Revise Diesel Fuel Monitoring Program procedures to monitor and trend water content, sediment, particulates, and microbiological activity in the fuel oil tanks within the scope of the program at least quarterly
- c.
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
- d.
Revise Diesel Fuel Monitoring Program procedures to include periodic cleaning and internal visual inspection of tanks within the scope of 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 cleaning and internal inspections at least once during the 10-year period prior to the period of extended operation and at succeeding 10-year intervals Prior to June 18, 2024, or the end of the last refueling outage prior to December 18, 2024, whichever is later.
W3F1-2016-0012 March 23, 2016 (ML16088A324)
WSES-FSAR-UNIT-3 Table 18.4-1 (Sheet 4a of 16)
Revision 311 (9/19)
LICENSING RENEWAL COMMITMENT LIST No.
Program or Activity Commitment Implementation Schedule Source (Letter Number) 7 External Surfaces Monitoring Enhance the External Surfaces Monitoring Program as follows:
- a.
Revise External Surfaces Monitoring Program procedures to include instructions to perform a 100 percent 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)
- b.
Revise External Surfaces Monitoring Program procedures to conduct representative inspections during each 10-year period on insulated surfaces of each material type (e.g., steel, stainless steel, copper alloy, aluminum) in an air-outdoor or condensation environment
- c.
Revise External Surfaces Monitoring Program procedures as follows
- 1.
Remove insulation in order to perform a visual inspection of a representative sample of insulated indoor components surfaces in a condensation environment and outdoor component surfaces. The inspections shall 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 of the surface area. Alternatively, insulation can 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
- 2.
Include inspection locations based on the likelihood of corrosion under insulation (i.e., 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)
- 3.
Allow subsequent inspections to 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, and no evidence of cracking Prior to June 18, 2024, or the end of the last refueling outage prior to December 18, 2024, whichever is later.
W3F1-2016-0012 March 23, 2016 (ML16088A324)
W3F1-2016-0069 November 10, 2016 (ML16315A235)
W3F1 -201
WSES-FSAR-UNIT-3 Table 18.4-1 (Sheet 4b of 16)
Revision 311 (9/19)
LICENSING RENEWAL COMMITMENT LIST No.
Program or Activity Commitment Implementation Schedule Source (Letter Number)
- 4.
Ensure that if the external visual inspections of the insulation reveal damage to the exterior surface of the insulation or there is evidence of water intrusion through the insulation (e.g., water seepage through insulation seams or joints), periodic inspections under the insulation will continue at such intervals that would ensure the component's intended function
- d.
Revise External Surfaces Monitoring Program procedures to provide guidance that removal of tightly adhering insulation that is impermeable to moisture is not required unless there is evidence of damage to the moisture barrier. However, the entire population of in-scope piping component surfaces 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
- e.
Revise External Surfaces Monitoring Program procedures to include the following acceptance criteria Stainless steel should have a clean shiny surface with no discoloration Other metals should not have any abnormal surface indications Flexible polymeric materials should have a uniform surface texture and color with no cracks and no dimensional change, no abnormal surface with the material in an as-new condition with respect to hardness, flexibility, physical dimensions, and color Rigid polymeric materials should have no erosion, cracking, checking, or chalking
WSES-FSAR-UNIT-3 Table 18.4-1 (Sheet 5 of 16)
Revision 311 (9/19)
LICENSING RENEWAL COMMITMENT LIST No.
Program or Activity Commitment Implementation Schedule Source (Letter Number) 8 Fatigue Monitoring Enhance the Fatigue Monitoring Program as follows:
- a.
Revise Fatigue Monitoring Program procedures to monitor and track additional critical thermal and pressure transients for components that have been identified to have a fatigue TLAA
- b.
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 location identified in NUREG/CR-6260 and additional plant-specific component locations in the reactor coolant pressure boundary if they are found to be more limiting than those considered in NUREG/CR-6260. Fen factors shall be determined using the formulae listed in LRA Section 4.3.3 The methodology for determining limiting locations will be based on EPRI report 1024995 Environmentally Assisted Fatigue Screening, Process and Technical Basis for Identifying EAF Limiting Locations with the following modifications.
Components in one thermal zone will not be used to bound components in different thermal zones.
Comparisons between components will use a fatigue correction factor (Fen) calculated with realistic dissolved oxygen values, worst case (minimum) metal strain rate, worst case (maximum) sulfur in the metal and maximum metal service temperature.
A Uen for one material will not be used to bound the Uen for a location of a different material.
- c.
Analysts will ensure that comparisons to determine limiting locations will compare usage values that are determined with comparable methods. For example, a component with a low fatigue usage value determined with a refined analysis may be more limiting than a component with a higher CUF determined with a simplified analysis.
- d.
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.
- e.
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, unanticipated new thermal events are discovered, or the geometry of components has been modified.
Enhancement to develop a set of fatigue usage calculations:
prior to December 18, 2022.
Remaining two enhancements:
prior to June 18, 2024.
W3F1-2016-0012 March 23, 2016 (ML16088A324)
W3F1-2016-0070 December 12, 2016 (ML16347A672)
W3F1-2017-0039 May 12, 2017 (ML17137A017)
WSES-FSAR-UNIT-3 Table 18.4-1 (Sheet 6 of 16)
Revision 311 (9/19)
LICENSING RENEWAL COMMITMENT LIST No.
Program or Activity Commitment Implementation Schedule Source (Letter Number) 9 Fire Protection Enhance the Fire Protection Program as follows:
- a.
Revise Fire Protection Program procedures to include an inspection at least once per refueling cycle of fire barrier walls, ceilings, and floors for any signs of degradation, such as spalling, loss of material caused by chemical attack, or reaction with aggregates
- b.
Revise Fire Protection Program procedures to inspect fire-rated doors for any degradation of door surfaces at least once per refueling cycle.
- c.
Revise Fire Protection Program procedures to ensure fire barrier seals are inspected by personnel qualified in accordance with appropriate NFPA standards
- d.
Revise Fire Protection Program procedures to provide acceptance criteria of no significant indications of concrete spalling, and loss of material of fire barrier walls, ceilings, and floors and in other fire barrier materials.
- e.
Revise Fire Protection Program procedures to provide acceptance criteria that specify no surface degradation of fire doors Prior to June 18, 2024 W3F1-2016-0012 March 23, 2016 (ML16088A324)
WSES-FSAR-UNIT-3 Table 18.4-1 (Sheet 7a of 16)
Revision 311 (9/19)
LICENSING RENEWAL COMMITMENT LIST No.
Program or Activity Commitment Implementation Schedule Source (Letter Number) 10 Fire Water System Enhance the Fire Water System Program as follows:
- a.
Revise Fire Water System Program Procedures to inspect for loss of fluid in the glass bulb heat responsive elements
- b.
Revise Fire Water System Program procedures to perform an inspection of each buildings wet pipe fire water system every 5 years by opening a flushing connection at the end of one main and by removing a sprinkler toward the end of one branch line for the purpose of inspecting the interior for evidence of loss of material and the presence of foreign organic or inorganic material that could result in flow obstructions or blockage of a sprinkler head. 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.
- c.
Revise Fire Water System Program procedures to perform an internal inspection every five years for evidence of loss of material and the presence of foreign organic or inorganic material that could result in flow obstructions or blockage of a sprinkler head of the dry piping downstream of preaction valves. 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, corrosion product deposition, and flow blockage due to fouling
- d.
Revise Fire Water System Program procedures to perform an internal inspection every five years for evidence of loss of material and the presence of foreign organic or inorganic material that could result in flow obstructions or blockage of a sprinkler head of the dry piping downstream of the automatic deluge valves.
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, corrosion product deposition, and flow blockage due to fouling.
- e.
Revise Fire Water System Program procedures to perform an inspection of the nozzles associated with the charcoal filters for loss of material and foreign or organic material when the charcoal is replaced
- f.
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.
Prior to June 18, 2024, or the end of the last refueling outage prior to December 18, 2024, whichever is later.
W3F1-2016-0012 March 23, 2016 (ML16088A324)
W3F1-2016-0069 November 10, 2016 (ML16315A235)
W3F1-2017-0002 January 16, 2017 (ML17016A027)
WSES-FSAR-UNIT-3 Table 18.4-1 (Sheet 7b of 16)
Revision 311 (9/19)
LICENSING RENEWAL COMMITMENT LIST No.
Program or Activity Commitment Implementation Schedule Source (Letter Number)
- g.
Revise Fire Water System Program procedures to remove strainers every 5 years and after each actuation to clean and inspect for damage and corroded parts.
- h.
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.
- i.
Revise Fire Water System Program procedures to conduct 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 cannot be drained or piping segments that allow water to collect in each 5-year interval, beginning 5 years prior to the period of extended operation
- j.
Revise Fire Water System Program procedures to perform volumetric wall thickness inspections of 20 percent of the length of piping segments that cannot be drained or piping segments that allow water to collect each 5-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, MIC). The 20 percent of piping that is inspected in each 5-year interval is in different locations than previously inspected piping.
- k.
Revise the Fire Water System Program procedures to perform a blockage evaluation if the flowing pressure decreases by more than 10 percent from the original main drain test or previous main drain tests.
- l.
Revise the Fire Water System Program procedures to flow test the charcoal filter unit's manual deluge valve systems with air on an annual basis to ensure there are no obstructions. If obstructions are found, the system shall be cleaned and retested.
- m.
Revise the Fire Water System Program procedures to trip test with flow at least once every 18 months the deluge valve systems for the main turbine lube oil tank and main feedwater pumps. If obstructions are found, the system shall be cleaned and retested
- n.
Revise the Fire Water System Program procedures to open and close hydrant valves slowly while performing flow tests to prevent surges in the system. The program shall also require full opening of the hydrant valve.
- o.
Revise the Fire Water System Program procedures to verify the hydrants drain within 60 minutes after flushing or flow testing.
WSES-FSAR-UNIT-3 Table 18.4-1 (Sheet 7c of 16)
Revision 311 (9/19)
LICENSING RENEWAL COMMITMENT LIST No.
Program or Activity Commitment Implementation Schedule Source (Letter Number)
- p.
Revise Fire Water System Program procedures to perform vacuum box testing on the bottom of the tank to identify leaks. In the event the bottom of the fire water tank is uneven, the station will perform a suitable NDE technique rather than vacuum box testing to identify leaks.
- q.
Revise the 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, including limitations, if any, identified in RG 1.54 on a particular standard.
- r.
Revise Fire Water System Program procedures to perform wet sponge and dry film testing on the coating applied to the interior of the fire water tanks.
- s.
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 surrounded by coating bonded to the substrate as determined by a qualified coating specialist, or the following actions are performed:
- Any 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
- Any delaminated or peeled coating is removed
- The exposed underlying coating is verified to be securely bonded to the substrate as determined by an adhesion test endorsed by RG 1.54 at a minimum of three locations
- The outermost coating is feathered and the remaining outermost coating is determined to be securely bonded to the coating below via an adhesion test endorsed by RG 1.54 at a minimum of three locations adjacent to the defective area
- Ultrasonic testing is performed where there is evidence of pitting or corrosion to ensure the tank meets minimum wall thickness requirements
- An evaluation is performed to ensure downstream flow blockage is not a concern
WSES-FSAR-UNIT-3 Table 18.4-1 (Sheet 7d of 16)
Revision 311 (9/19)
LICENSING RENEWAL COMMITMENT LIST No.
Program or Activity Commitment Implementation Schedule Source (Letter Number)
- A follow-up inspection is scheduled to be performed within two years and every two years after that until the coating is repaired, replaced, or removed
- t. 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.
Lightly tapping and scraping the coating to determine the coating integrity Dry film thickness measurements at random locations to determine overall thickness of the coating Wet-sponge testing or dry film testing to identify holidays in the coating Adhesion testing in accordance with ASTM D3359, ASTM D4541, or equivalent testing endorsed by RG 1.54 at a minimum of three locations Ultrasonic testing where there is evidence of pitting or corrosion to determine if the tank thickness meets the minimum thickness criteria
- u.
Revise Fire Water System Program procedures to include acceptance criteria for the fire water tanks' interior coating that include Indications of peeling and delamination are not acceptable 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 on a particular standard. Blisters should be limited to a few intact small blisters that are completely surrounded by sound coating/lining bonded to the substrate. Blister size and frequency should not be increasing between inspections (e.g.,
reference ASTM D714-02, "Standard Test Method for Evaluating Degree of Blistering of Paints")
Indications such as cracking, flaking, and rusting are to be 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 on a particular standard As applicable, wall thickness measurements, projected to the next inspection, meet design minimum wall requirements When conducting adhesion testing, results meet or exceed the degree of adhesion recommended in plant-specific design requirements specific to the coating/lining and substrate
- v. 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). Any signs of abnormal corrosion or blockage will be removed, its source and extent of condition determined and corrected, and entered into the corrective action program
WSES-FSAR-UNIT-3 Table 18.4-1 (Sheet 7e of 16)
Revision 311 (9/19)
LICENSING RENEWAL COMMITMENT LIST No.
Program or Activity Commitment Implementation Schedule Source (Letter Number)
- w. Revise Fire Water System Program procedures to specify replacement of any sprinkler heads that show signs of leakage, excessive loading, corrosion, or loss of fluid in the glass bulb heat responsive element
- x. Revise Fire Water System Program procedures to perform an obstruction evaluation if any of the following conditions exist:
- There is an obstructive discharge of material during routine flow tests
- An inspector's test valve is clogged during routine testing
- Foreign materials are identified during internal inspections
- Sprinkler heads are found clogged during removal or testing
- Pin hole leaks are identified in fire water piping
- After an extended fire water system shutdown (greater than one year)
- There is a 50% increase in time it takes for water to flow out the inspector test valve after the associated dry valve is tripped when compared to the original acceptance criteria or last test
- y. Revise Fire Water System Program procedures to evaluate for MIC if tubercules or slime are identified during any internal inspections of fire water piping
- z. Revise the Fire Water System Program procedures to perform preaction valve trip testing every three years with the manual isolation valve closed.
WSES-FSAR-UNIT-3 Table 18.4-1 (Sheet 8 of 16)
Revision 311 (9/19)
LICENSING RENEWAL COMMITMENT LIST No.
Program or Activity Commitment Implementation Schedule Source (Letter Number) 11 Flow-Accelerated Corrosion Enhance the Flow-Accelerated Corrosion Program as follows:
- a.
Revise Flow-Accelerated Corrosion Program procedures to (1) manage wall thinning due to erosion mechanisms from cavitation, flashing, liquid droplet impingement, and solid particle impingement; (2) include susceptible locations based on the extent-of-condition reviews in response to plant-specific or industry operating experience, and EPRI TR-1011231, Recommendations for Controlling Cavitation, Flashing, Liquid Droplet Impingement, and Solid Particle Erosion in Nuclear Power Plant Piping, and NUREG/CR-6031, Cavitation Guide for Control Valves; (3) ensure piping and components replaced with FAC-resistant material and subject to erosive conditions are not excluded from inspections; and (4) include the need for continued wall thickness measurements of replaced piping until the effectiveness of the corrective action is assured
- b.
Revise Flow-Accelerated Corrosion Program procedures to evaluate wall thinning due to erosion from cavitation, flashing, liquid droplet impingement, and solid particle impingement when determining a replacement type of material.
Prior to June 18, 2024 W3F1-2016-0012 March 23, 2016 (ML16088A324) 12 Inservice Inspection - IWF Enhance the ISI-IWF Program as follows:
- a. 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
- b. 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.
- c. Revise plant procedures to specify the following conditions as unacceptable:
Loss of material due to corrosion or wear, which reduces the load bearing capacity of the component support Debris, dirt, or excessive wear that could prevent or restrict sliding of the sliding surfaces as intended in the design basis of the support Cracked or sheared bolts, including high strength bolts, and anchors
- d. Revise plant procedures to include assessment of the impact on the inspection sample representativeness if components that are part of the sample population are reworked Prior to June 18, 2024 W3F1-2016-0012 March 23, 2016 (ML16088A324)
W3F1-2016-0070 December 12, 2016 (ML16347A672)
WSES-FSAR-UNIT-3 Table 18.4-1 (Sheet 9 of 16)
Revision 311 (9/19)
LICENSING RENEWAL COMMITMENT LIST No.
Program or Activity Commitment Implementation Schedule Source (Letter Number) 12.a Inservice Inspection Program Revise Inservice Inspection Program procedures to include a supplemental inspection of Class 1 CASS piping components that do not meet the material selection criteria of NUREG-0313, Revision 2, with regard to ferrite and carbon content. An inspection technique qualified by ASME or EPRI will be used to monitor cracking.
Prior to June 18, 2024 W3F1-2016-0074 December 7, 2016 13 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 follows:
- a.
Revise plant procedures to specify monitoring of crane rails for loss of material due to wear; monitoring structural components of the bridge, trolley and hoists for deformation, cracking, and loss of material due to corrosion; and monitoring structural connections for loose or missing bolts, nuts, pins or rivets and any other conditions indicative of loss of bolting integrity.
- b.
Revise plant procedures to specify inspection frequency in accordance with ASME B30.2 or other appropriate standard in the ASME B30 series.
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.
- c.
Revise plant procedures to require that significant loss of material due to wear of crane rails and any sign of loss of bolting integrity will be evaluated in accordance with ASME B30.2 or other appropriate standard in the ASME B30 series.
- d.
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 Prior to June 18, 2024 W3F1-2016-0012 March 23, 2016 (ML16088A324 14 Internal Surfaces in Miscellaneous Piping and Ducting Components Implement the Internal Surfaces in Miscellaneous Piping and Ducting Components Program as described in LRA Section B.1.18.
Prior to June 18, 2024 W3F1-2016-0012 March 23, 2016 (ML16088A324)
WSES-FSAR-UNIT-3 Table 18.4-1 (Sheet 10 of 16)
Revision 311 (9/19)
LICENSING RENEWAL COMMITMENT LIST No.
Program or Activity Commitment Implementation Schedule Source (Letter Number) 15 Masonry Wall Enhance the Masonry Wall Program as follows:
- a.
Revise plant procedures to ensure masonry walls located within in-scope structures are included in the scope of the Masonry Wall Program
- b.
Revise plant procedures to include monitoring gaps between the structural steel supports and masonry walls that could potentially affect wall qualification
- c.
Revise plant procedures to specify that masonry walls will be inspected at least once every 5 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
- d.
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.
Prior to June 18, 2024 W3F1-2016-0012 March 23, 2016 (ML16088A324) 16 Metal Enclosed Bus Inspection Implement the Metal Enclosed Bus Inspection Program as described in LRA Section B.1.20 Prior to June 18, 2024 W3F1-2016-0012 March 23, 2016 (ML16088A324) 17 Neutron-Absorbing Material Monitoring Enhance the Neutron-Absorbing Material Monitoring Program as follows:
- a.
Revise Neutron-Absorbing Material Monitoring Program procedures to compare measurements from periodic inspections to prior measurements, and relate coupon measurement results to the performance of the spent fuel neutron-absorber materials considering differences in exposure conditions, vented/non-vented test samples, spent fuel racks, etc. Ensure the predicted boron-10 areal density will be sufficient to maintain the subcritical conditions required by technical specifications until the next coupon test.
Prior to June 18, 2024 The inspection will be performed prior to the period of extended operation and at least once every 10 years during the period of extended operation W3F1-2016-0012 March 23, 2016 (ML16088A324)
W3F1-2017-0002 January 16, 2017 (ML17016A027) 18 Non-EQ Electrical Cable Connections Implement the Non-EQ Electrical Cable Connections Program as described in LRA Section B.1.23.
Prior to June 18, 2024, or the end of the last refueling outage prior to December 18, 2024, whichever is later.
W3F1-2016-0012 March 23, 2016 (ML16088A324)
WSES-FSAR-UNIT-3 Table 18.4-1 (Sheet 11 of 16)
Revision 311 (9/19)
LICENSING RENEWAL COMMITMENT LIST No.
Program or Activity Commitment Implementation Schedule Source (Letter Number) 19 Non-EQ Inaccessible Power Cables
(> 400 V)
Implement the Non-EQ Inaccessible Power Cables (> 400 V) Program as described in LRA Section B.1.24.
Prior to June 18, 2024, or the end of the last refueling outage prior to December 18, 2024, whichever is later.
W3F1-2016-0012 March 23, 2016 (ML16088A324) 20 Non-EQ Sensitive Instrumentation Circuits Test Review Implement the Non-EQ Sensitive Instrumentation Circuits Test Review Program as described in LRA Section B.1.25.
Prior to June 18, 2024, or the end of the last refueling outage prior to December 18, 2024, whichever is later.
W3F1-2016-0012 March 23, 2016 (ML16088A324) 21 Non-EQ Insulated Cables and Connections Implement the Non-EQ Insulated Cables and Connections Program as described in LRA Section B.1.26.
Prior to June 18, 2024, or the end of the last refueling outage prior to December 18, 2024, whichever is later.
W3F1-2016-0012 March 23, 2016 (ML16088A324) 22 One-Time Inspection Implement the One-Time Inspection Program as described in LRA Section B.1.28.
Prior to June 18, 2024, or the end of the last refueling outage prior to December 18, 2024, whichever is later.
W3F1-2016-0012 March 23, 2016 (ML16088A324)
W3F1 -2016-0069 November 10, 2016 (ML16315A235)
W3F1-2016-0071 January 9, 2017 (ML17009A409)
W3F1 -2017-0005 February 1, 2017 (ML17032A516)
W3F1-2017-0015 March 16, 2017 (ML17075A412) 23 One-Time Inspection -
Small-Bore Piping Implement the One-Time Inspection - Small-Bore Piping Program as described in LRA Section B.1.29.
Prior to June 18, 2024, or the end of the last refueling outage prior to December 18, 2024, whichever is later.
W3F1-2016-0012 March 23, 2016 (ML16088A324)
W3F1-2016-0070 December 12, 2016 (ML16347A672)
WSES-FSAR-UNIT-3 Table 18.4-1 (Sheet 12 of 16)
Revision 311 (9/19)
LICENSING RENEWAL COMMITMENT LIST No.
Program or Activity Commitment Implementation Schedule Source (Letter Number) 24 Periodic Surveillance and Preventive Maintenance Enhance the PSPM Program as described in LRA Section B.1.30.
Prior to June 18, 2024, or the end of the last refueling outage prior to December 18, 2024, whichever is later.
W3F1-2016-0012 March 23, 2016 (ML16088A324)
W3F1 -2016-0069 November 10, 2016 (ML16315A235)
W3F1-2016-0070 December 12, 2016 (ML16347A672)
W3F1-2016-0071 January 9, 2017 (ML17009A409)
W3F1 -2017-0005 February 1, 2017 (ML17032A516)
W3F1 -2017-0006 February 23, 2017 (ML17054D239)
W3F1-2017-0015 March 16, 2017 (ML17075A412) 25 Protective Coating Monitoring and Maintenance Enhance the Protective Coating Monitoring and Maintenance Program as follows:
- a.
Revise plant procedures to specify visual inspections of coatings near sumps or screens associated with the emergency core cooling system Prior to June 18, 2024, or the end of the last refueling outage prior to December 18, 2024, whichever is later.
W3F1-2016-0012 March 23, 2016 (ML16088A324) 26 Reactor Head Closure Studs Enhance the Reactor Head Closure Studs Program as follows:
- a.
Revise Reactor Head Closure Studs Program procedures to ensure that replacement studs are fabricated from bolting material with actual measured yield strength less than 150 kilo-pounds per square inch
- b.
Revise Reactor Head Closure Studs Program procedures to exclude the use of molybdenum disulfide (MoS2) on the reactor vessel closure studs and refer to RG 1.65, Rev. 1 Prior to June 18, 2024, or the end of the last refueling outage prior to December 18, 2024, whichever is later.
W3F1-2016-0012 March 23, 2016 (ML16088A324)
WSES-FSAR-UNIT-3 Table 18.4-1 (Sheet 13 of 16)
Revision 311 (9/19)
LICENSING RENEWAL COMMITMENT LIST No.
Program or Activity Commitment Implementation Schedule Source (Letter Number) 27 Reactor Vessel Internals Enhance the Reactor Vessel Internals Program as follows:
- a.
Revise Reactor Vessel Internals Program procedures to include the inspections identified in the inspection plan in NRC submittal W3F1-2013-0070, dated December 16, 2013, including the inspection of the core stabilizing bolts as an addition to the WF3 ASME Section XI In-Service Inspection Program Prior to June 18, 2024, or the end of the last refueling outage prior to December 18, 2024, whichever is later.
W3F1-2016-0012 March 23, 2016 (ML16088A324) 28 Selective Leaching Implement the Selective Leaching Program as described in LRA Section B.1.35.
Prior to June 18, 2024, or the end of the last refueling outage prior to December 18, 2024, whichever is later.
W3F1-2016-0012 March 23, 2016 (ML16088A324) 29 Service Water Integrity Enhance the Service Water Integrity Program as follows:
- a.
Revise Service Water Integrity Program procedures to (1) flush redundant, infrequently flowed sections, and stagnant lines to ensure there is no blockage, and (2) inspect selected low flow or stagnant areas and system low points such as drains Prior to June 18, 2024, or the end of the last refueling outage prior to December 18, 2024, whichever is later.
W3F1-2016-0012 March 23, 2016 (ML16088A324)
W3F1 -2016-0069 November 10, 2016 (ML16315A235)
W3F1-2016-0070 December 12, 2016 (ML16347A672)
W3F1-2017-0015 March 16, 2017 (ML17075A412)
WSES-FSAR-UNIT-3 Table 18.4-1 (Sheet 14a of 16)
Revision 311 (9/19)
LICENSING RENEWAL COMMITMENT LIST No.
Program or Activity Commitment Implementation Schedule Source (Letter Number) 30 Structures Monitoring Enhance the Structures Monitoring Program as follows:
- a.
Revise plant procedures to include the following in-scope structures:
Battery house 230kV switchyard Control house 230kV switchyard Fire pump house Fire water storage tank foundations Fuel oil storage tank foundation Manholes, handholes and duct banks Plant stack Transformer and switchyard support structures and foundations
- b.
Revise plant procedures to include a list of structural components and commodities within the scope of the program
- c.
Revise plant procedures to include periodic sampling and chemical analysis of ground water
- d.
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"
- e.
Revise plant procedures to include the following parameters to be monitored or inspected:
For concrete structures, base inspections on quantitative requirements of industry codes, standards and guidelines (e.g.,
ASCE 11, ACI 349.3R) and consideration of industry and plant-specific operating experience 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 For chemical analysis of ground water, monitor pH, chlorides and sulfates
- f.
Revise plant procedures to include the following components to be monitored for the associated parameters:
Prior to June 18, 2024, or the end of the last refueling outage prior to December 18, 2024, whichever is later.
W3F1-2016-0012 March 23, 2016 (ML16088A324)
W3F1 -2017-0026 April 11, 2017 (ML17102A856)
WSES-FSAR-UNIT-3 Table 18.4-1 (Sheet 14b of 16)
Revision 311 (9/19)
LICENSING RENEWAL COMMITMENT LIST No.
Program or Activity Commitment Implementation Schedule Source (Letter Number)
Anchor bolts (nuts and bolts) for loss of material and loose or missing nuts and bolts Elastomeric vibration isolators and structural sealants for cracking, loss of material, loss of sealing, and change in material properties (e.g., hardening)
- g.
Revise plant procedures to include the following:
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 Structures will be inspected at least once every 5 years with provisions for more frequent inspections of structures and components categorized as (a)(1) in accordance with 10 CFR 50.65 Submerged structures will be inspected at least once every 5 years Sampling and chemical analysis of ground water at least once every 5 years. The program owner will review the results and evaluate any anomalies and perform trending of the results
- h.
Revise plant procedures to inspect the SIT and RCS supports with ASTM A-540 high-strength bolting greater than one-inch nominal diameter prior to the period of extended operation and at least once every 5 years thereafter. The periodic visual inspections are intended to detect whether a corrosive environment that supports SCC potential exists or has existed since the previous inspection.
Acceptance criteria for the inspections will be the absence of evidence of moisture, residue, foreign substances, or corrosion Conditions that dont meet the acceptance criteria and thus indicate a potential corrosive environment that supports SCC will be entered into the corrective action program for evaluation
- i.
Revise plant procedures to include qualitative and quantitative acceptance criteria for A-540 bolts as follows:
- 1) If moisture is present at or near a bolt or stud, factors considered by engineering include, but will not be limited to:
WSES-FSAR-UNIT-3 Table 18.4-1 (Sheet 14c of 16)
Revision 311 (9/19)
LICENSING RENEWAL COMMITMENT LIST No.
Program or Activity Commitment Implementation Schedule Source (Letter Number)
The source of leakage or condensation that supplied the moisture.
The proximity of the moisture to the bolt or stud.
The probable or analyzed chemical characteristics of the moisture, including the presence of contaminants.
The visible or likely pathway, if any, that the liquid traversed to arrive at or near the bolt or stud.
The amount of any corrosion on or near the bolt or stud.
The material condition of the coatings on the bolt or stud, and associated support.
The characteristics of any corrosion on or near the bolt or stud.
The proximity to the bolt or stud of any nearby evidence of corrosion.
The material condition of accessible concrete or grout near the bolt or stud.
- 2) If there evidence that moisture had been present at or near a bolt or stud, but no moisture is present at or near a bolt or stud, factors considered by engineering include, but will not be limited to:
The probable sources of past leakage or condensation that could have supplied the moisture.
The proximity to the bolt or stud to the evidence that moisture had been present.
The probable or analyzed chemical characteristics of any moisture residue, including the presence of contaminants.
The visible or likely pathway, if any, that the liquid may have traversed to arrive at or near the bolt or stud.
The amount of any corrosion on or near the bolt or stud.
The material condition of any coatings on the bolt or stud, and associated support.
The characteristics of any corrosion on or near the bolt or stud.
The proximity to the bolt or stud of any nearby evidence of corrosion.
The material condition of concrete or grout near the bolt or stud.
Should adverse conditions be identified during the examinations, engineering will determine if the bolting has been exposed to a corrosive environment with the potential to cause SCC. Bolts determined to have been exposed to a corrosive environment with the potential to cause SCC will be identified as within a population where SCC is a concern. A sample equal to 20 percent (rounded up to the nearest whole number) of the population, with a maximum sample size of 25 bolts will be subject to volumetric examination. The selection of the samples will consider susceptibility to stress corrosion cracking (e.g., actual measured yield strength) and ALARA considerations.
WSES-FSAR-UNIT-3 Table 18.4-1 (Sheet 15 of 16)
Revision 311 (9/19)
LICENSING RENEWAL COMMITMENT LIST No.
Program or Activity Commitment Implementation Schedule Source (Letter Number) 31 Thermal Aging Embrittlement of Cast Austenitic Stainless Steel Implement the Thermal Aging Embrittlement of Cast Austenitic Stainless Steel Program as described in LRA Section B.1.39.
Prior to June 18, 2024.
W3F1-2016-0012 March 23, 2016 (ML16088A324) 32 Water Chemistry Control -
Closed Treated Water Systems Enhance the Water Chemistry Control - Closed Treated Water Systems Program as follows:
- a.
Revise Water Chemistry Control - Closed Treated Water Systems Program procedures to include high pressure fire water diesel pump jacket water system
- b.
Revise Water Chemistry Control - Closed Treated Water Systems Program procedures to specify water chemistry parameters monitored and the acceptable range of values for these parameters that are in accordance with EPRI 1007820, industry guidance, or vendor recommendations
- c.
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 every 10 years. 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 corrosion, fouling, or cracking. If visual examination identifies adverse conditions, additional examinations, including ultrasonic testing, are conducted
- d.
Revise the Water Chemistry Control - Closed Treated Water Systems Program procedures to define a representative sample as 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 corrosion, fouling, or cracking
- e.
Revise the Water Chemistry Control - Closed Treated Water Systems Program procedures to perform treated water sampling and analysis of the closed treated water systems per industry standards and in no case greater than quarterly unless justified with an additional analysis
- f.
Revise Water Chemistry Control - Closed Treated Water Systems Program procedures to specify water chemistry parameters monitored and the acceptable range of values for these parameters that are in accordance with EPRI 1007820, industry guidance, or vendor recommendations
- g.
Revise the Water Chemistry Control - Closed Treated Water Systems Program procedures to provide acceptance criteria for inspections. Ensure system components meet system design requirements, such as minimum wall thickness Prior to June 18, 2024.
W3F1-2016-0012 March 23, 2016 (ML16088A324)
WSES-FSAR-UNIT-3 Table 18.4-1 (Sheet 16 of 16)
Revision 311 (9/19)
LICENSING RENEWAL COMMITMENT LIST No.
Program or Activity Commitment Implementation Schedule Source (Letter Number) 33 Steam Generator Integrity Enhance the Steam Generator Integrity Program as follows:
- a.
Revise the Steam Generator Integrity Program to include general visual inspection of the partition plate, channel head, and tubesheet (primary side) with a frequency of at least once every 72 effective full power months or every third refueling outage, whichever results in more frequent inspections Prior to June 18, 2024 W3F1-2016-0075 December 7, 2016 (ML16342A491)
W3F1-2017-0015 March 16, 2017 (ML17075A412) 34 Reactor Vessel Surveillance Enhance the Reactor Vessel Surveillance Program as follows:
- a.
Revise Reactor Vessel Surveillance Program procedures to specify submittal of a withdrawal schedule for Capsule 277° to the NRC for review and approval within one (1) year following the receipt of the renewed license Within one year following issuance of the renewed license.
W3F1-2017-0023 March 30, 2017 (ML17089A358)