2CAN070409, Unit 2, License Renewal Application Clarifications
| ML042160286 | |
| Person / Time | |
|---|---|
| Site: | Arkansas Nuclear  |
| Issue date: | 07/22/2004 |
| From: | Mitchell T Entergy Operations |
| To: | Document Control Desk, Office of Nuclear Reactor Regulation |
| References | |
| 2CAN070409, TAC MB8402 | |
| Download: ML042160286 (14) | |
Text
I
-~En tergy Entergy Operations, Inc.
1448 S.R. 333 Russeliville, AR 72802 Tel 501 858 5000 2CAN070409 July 22, 2004 U.S. Nuclear Regulatory Commission Attn: Document Control Desk Washington, DC 20555-0001
Subject:
License Renewal Application Clarifications TAC No. MB8402 Arkansas Nuclear One - Unit 2 Docket No. 50-368 License No. NPF-6
Dear Sir or Madam:
By letters dated May 19, 2004 (2CAN050404), June 16, 2004 (2CAN060403),
June 10, 2004 (2CAN060401), and July 1, 2004 (2CAN070404), Entergy provided responses to requests for additional information (RAls) for the Arkansas Nuclear One, Unit 2 (ANO-2) License Renewal Application (LRA). During teleconferences on June 30, 2004, and July 7, 2004, the Staff requested clarifications to several of these previously docketed RAI responses. These clarifications are contained in Attachment 1 along with other additional requested clarifications.
New commitments contained in this submittal are summarized in Attachment 2. Should you have any questions concerning this submittal, please contact Ms. Natalie Mosher at (479) 858-4635.
I declare under penalty of perjury that the foregoing is true and correct. Executed on July 22, 2004.
Safety Assurance Attachments
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2CAN070409 Page 2 cc:
Dr. Bruce S. Mallett Regional Administrator U. S. Nuclear Regulatory Commission Region IV 611 Ryan Plaza Drive, Suite 400 Arlington, TX 76011-8064 NRC Senior Resident Inspector Arkansas Nuclear One P.O. Box 310 London, AR 72847 U. S. Nuclear Regulatory Commission Attn: Mr. Drew Holland Mail Stop 0-7 D1 Washington, DC 20555-0001 U. S. Nuclear Regulatory Commission Attn: Mr. Greg Suber Mail Stop 0-11 F1 Washington, DC 20555-0001 Mr. Bernard R. Bevill Director, Division of Radiation Control and Emergency Management Arkansas Department of Health 4815 West Markham Street, Slot 30 Little Rock, AR 72205-3867
Attachment I 2CAN070409 LRA Clarifications to 2CAN070409 Page 1 of 9 LRA Clarifications RAI 2.4-7 Clarification: The Staff requested that part (d) of the RAI be addressed for the unit auxiliary transformer foundation and the main transformer foundation. Also, the Staff could not determine if the entire turbine building had been included in the scope of license renewal. The Staff requested Entergy to submit the technical basis for concluding that the unit auxiliary transformer foundation and the main transformer foundation are not subject to an aging management review; and clarify its treatment of the turbine building.
Response: As noted in the response to RAI 2.5-2 (correspondence dated June 21, 2004 (2CAN060404)), neither the main transformers nor the auxiliary transformer are included in the station blackout recovery path. Neither the main transformers nor the auxiliary transformer perform a safety-related function, affect a safety-related function, or are credited for a regulated event, so they are not subject to aging management review. Thus, their foundations are not subject to aging management review. The turbine building (as a whole) is in the scope of license renewal because it contains commodities that are subject to aging management review.
RAI 2.4-8 Clarification: The Staff requested clarification if Type B local leak rate testing, in accordance with the requirements of IOCFR Appendix J, is being credited to manage the leak-tightness of the cable feed-through assembly.
Response: Leak tightness of electrical penetrations is tested in accordance with the requirements of 1 OCFR50 Appendix J as indicated in LRA table 3.5.2-1. The effects of aging on resilient seals of electrical penetration assemblies are managed by Type B testing performed as required by Appendix J. This includes resilient seals associated with the cable feed through assemblies. Line item 3.5.1-6 of Table 3.5.1 applies to resilient seals associated with cable feed-through assemblies of the electrical penetrations.
RAI 3.5-2 Clarification: The Staff requested Entergy to provide information regarding the adequacy of Type B leak rate testing frequency to monitor aging degradation of seals and gaskets at ANO-2 and the aging management of seals and gaskets for mechanical and electrical penetrations (other than those associated with the equipment hatch and airlocks).
Response: Gaskets associated with containment mechanical penetrations are consumables that are replaced each time the bolted joint is disassembled. In addition, such penetrations are tested under the containment leak rate program as required by 1 OCFR50, Appendix J. As indicated in LRA Table 3.5.2-1, containment electrical penetrations (which include cable feed-through assemblies) are included in the containment leak rate program.
The effects of aging on seals and gaskets associated with mechanical and electrical penetrations are managed by the containment leak rate program. Line item 3.5.1-6 of Table 3.5.1 applies to seals and gaskets associated with mechanical penetrations and electrical penetrations.
ANO-2 is committed to Option B of 1 OCFR50, Appendix J for performing containment leakage rate testing. Option B allows Type B test intervals up to 120 months; however, normally it is performed more frequently than every 120 months. Type B testing of ANO-2 mechanical and electrical penetrations is performed at least once every 120 months.
Component specific testing frequency is based on the safety significance and historical performance of the penetrations in accordance with Option B of IOCFR50, Appendix J.
Attachment I to 2CAN070409 Page 2 of 9 RAI 3.5-4(c) Clarification: The Staff stated that the Boric Acid Corrosion Prevention Program only addresses the conditions affected by boric acid exposure. It cannot, by itself, indicate the condition of the concrete structures. Section XL.S6 of NUREG-1 801 recommends the use of American Concrete Institute (ACI) 349-3R, as part of the Structures Monitoring Program (as summarized in ANO-2 aging management program B.1.27), for identifying and evaluating degradation of concrete structures, including the structures inside containment. The Staff requested that Entergy provide the requested information in RAI 3.5-4(c) in terms of the criteria established in Chapter 5 of ACI 349-3R.
Response: The Structures Monitoring Program is used for evaluation of concrete structures. The evaluation criteria in ACI 349-3R are incorporated in the Structures Monitoring Program. The Structures Monitoring Program provides the same criteria for identifying concrete degradation as ACI-349-3R. During the latest inspection, the concrete of the primary shield wall and the reactor pressure vessel support structure was acceptable without further evaluation in accordance with the criteria of ACI 349-3R, Section 5.1. No cracking or spalling of the primary shield wall or reactor pressure vessel support concrete structures was noted during the inspection.
RAI 3.5-6 Clarification: The Staff requested Entergy to provide an aging management program for the intake canal or a justification for its exclusion.
Response: As shown in Tables 3.5.2-3, the structures monitoring program is credited with managing the effects of aging on the intake structure components and commodities. In addition to the intake structure and emergency cooling pond, water-control structures at ANO-2 also include the intake canal. As discussed in the clarified response to RAI 3.5-9, aging management review of the intake canal did not identify any aging effects requiring management. Therefore, no aging management program is needed for the intake canal.
RAI 3.5-7 Clarification: The Staff requested Entergy to explain the very limited scope, and why the monitoring of spent fuel pool water level cannot be credited as an aging management program.
Response: The response should have said, "This activity was not credited as an aging management program because of its very limited scope." This was intended to reflect the treatment of spent fuel pool level monitoring in NUREG-1 801, which identifies spent fuel pool level monitoring in the aging management program column in Item A5.2-b but does not include it in the program descriptions of Section Xl of NUREG-1801. Spent fuel pool level monitoring is credited to verify effectiveness of the water chemistry control program to manage the effects of aging on the spent fuel pool liner. At ANO-2 this activity is performed as required by ANO-2 Technical Specification 4.9.10.
to 2CAN070409 Page 3 of 9 RAI 3.5-8 Clarification: The Staff requested Entergy to provide a technical bases for its aging management review conclusion that stress corrosion cracking (SCC) is not an aging effect for high strength bolts referred to in the response to RAI 3.5-8 and that cracking of bolting in an air environment due to SCC has not been observed in a survey of industry experience.
Response: The high strength bolts referred to in the response to RAI 3.5-8 are identified in ANO-2 SAR Section 3.8.3.6.2.2. A more detailed review revealed that these bolts have a yield strength less than 150 ksi. No high strength bolts having a yield strength greater than 150 ksi were used in structural connections at ANO-2. This was confirmed through review of a number of material test reports for ANO-2 high strength bolts.
RAI 3.5-9 Clarification: The Staff requested Entergy to demonstrate why the intake canal does not need an aging management program. The Staff also stated that the intake canal being qualified as seismic Category 1 further demonstrates that it needs an aging management program.
Response: The circulating water system for ANO-1 is supplied by the intake canal. The ANO-2 systems that utilize the intake canal as a suction source are the service water and fire protection systems. The intake canal is qualified as seismic Category 1 because it supports emergency operation of ANO-1 (consistent with the requirements of 10CFR54.4, seismic classification of a system, structure, or component does not imply its need for aging management program). The intake canal was conservatively included in the scope of license renewal for ANO-2 and subject to aging management review because it provides an alternate suction source (in addition to assured source provided by the emergency cooling pond) for the service water and fire protection systems.
The intake canal slope has been engineered to limit erosion caused by wind and is further protected by vegetation. Degradation due to flooding has not been a concern. The intake canal was designed with the capacity to supply circulating water to ANO-1. The required flow for ANO-1 circulating water is approximately 30 times the flow required for ANO-2 service water and fire protection systems. After approximately 30 years of operation, the intake canal capacity is still greater than required for ANO-1 circulating water. Because of its significant overcapacity, there are no credible aging effects for the intake canal that would result in it not being able to supply the minimum required flow for ANO-2 through the period of extended operation.
In summary, there are no aging effects requiring an aging management program for the intake canal. This is consistent with the previously approved Staff position documented in NUREG-1743, Safety Evaluation Report related to the license renewal of ANO-1.
to 2CAN070409 Page 4 of 9 RAI 4.5-2 Clarification: The Staff requested Entergy to propose a plan or a program that would provide a valid time-limited aging analysis (TLAA) for each group of tendons in the ANO-2 containment.
Response: In accordance with Regulatory Guide (RG) 1.35, Revision 2, the ANO-2 projected trend lines were developed from ANO-1 initial data since ANO-2 data was not available and the same containment design was used for both units. In the fall of 2000, these trend lines were used to check six ANO-2 tendons (three verticals and three hoops).
The measured results were consistent with the trend lines. If future tendon examination data diverges from the expected trend, the discrepancy will be addressed in accordance with requirements of the Containment Inservice Inspection (ISI) Program (IWE/IWL) under the current licensing basis.
Notwithstanding the above, consistent with 10CFR54.21 (c)(1)(iii), loss of tendon prestress will be managed during the period of extended operation by continued implementation of tendon inspections required by the American Society of Mechanical Engineers ASME Code Section XI IWL. In accordance with NUREG 1800, Section 4.5.3.1.3, relevant operating experience, including the experience with prestressing systems described in Information Notice 99-10, will be considered.
In summary, the ANO-2 Containment ISI Program in accordance with the requirements of ASME Code Section XI IWL will provide reasonable assurance that the effects of aging on the intended functions of tendons will be adequately managed for the period of extended operation in accordance with the provisions of 10CFR54.21(c)(1)(iii).
RAI 2.3-1 Restated: LRA Section 2.1.1 states that license renewal drawings were prepared to indicate components subject to aging management review. However, the license renewal drawing legends indicate that the highlighted portions of the systems with flags represent the systems and components that are within the scope of license renewal.
There appears to be an inconsistency between the drawing legend and the LRA statement.
The Staff requested the applicant to clarify which one is correct. 10CFR54.21 (a)(2) requires applicants to describe and justify the methods used in paragraph 10CFR54.21(a)(1) of 10CFR54.21. LRA Section 2.1.2 briefly describes the screening methodology as such: ufor each mechanical system within the scope of license renewal, the screening process identified those components that are subject to an aging management review." This description of the screening methodology, specifically for mechanical systems, is not clear to the Staff. It does not adequately describe the method used to determine how a component is screened from further evaluation. Please provide an appropriate description and justification for the methodology used to perform the screening of mechanical components, including a discussion of how the system evaluation boundaries were established and component intended functions were determined.
Supplemental Response: Scoping was performed at the system level. Systems and structures that perform intended functions are in scope as indicated in Tables 2.2-1 a, 2.2-1 b, and 2.2-3. Systems and structures that are not within the scope of license renewal are listed in Tables 2.2-2 and 2.2-4. If a system is in scope, then all of the components in that system are conservatively considered within the scope of license renewal for the purpose of identifying components and structures that are subject to aging management review.
to 2CAN070409 Page 5 of 9 The identification of components subject to aging management review began with determining the system evaluation boundary. The evaluation boundary includes those portions of the system necessary to ensure the intended functions of the system will be performed. Components needed to support system level intended functions identified in the scoping process were included within the evaluation boundary. System components that do not support an intended function were outside the evaluation boundary and not considered further. System functions were identified based on applicable plant licensing and design documentation. The applicable sections of the safety analysis report (SAR),
technical specifications, maintenance rule scoping documents, upper level documents, and ANO topical reports for the NRC regulations identified in 10CFR54.4(a)(3) were used to determine system functions and identify components that perform intended functions required to accomplish those system functions. The license renewal boundary on the LRA drawings, as identified by the boundary flags or system color codes, may be defined as the evaluation boundary between the portion of the system that performs an intended function (requires aging management review) and the portion of the system that does not perform an intended function (does not require aging management review).
Within the evaluation boundary, screening is performed to determine components that are subject to aging management review. For screening in accordance with 1 OCFR54.21 (a)(1),
structures and components subject to aging management review are those that perform an intended function without moving parts or a change in configuration or properties and that are not subject to replacement based on a qualified life or specified time period. Each component subject to aging management review is assigned a component intended function such as pressure boundary or heat transfer that supports the system intended function. Individual components are grouped together where possible to allow disposition of the entire group with a single aging management review. Components were grouped based on common materials of construction and common environments. The aging effects requiring management were then identified for each component group. These component groups are the component types identified in the LRA Section 3.x.2 tables.
RAI 2.3.4.2-1: LRA Section 2.3.4.2 states that the second block valve (outboard) on each train of the main feedwater system is safety-related. License renewal drawing LRA-M-2206, Sheet 1, does not highlight the valves (2-CV-1 023-2 and 2CV-1 073-2) as being subject to aging management review. These valves (as the backup main feedwater isolation valves) receive an isolation signal to close during steam line breaks (either via the main steam isolation signal or the containment spray actuation signal). These valves are credited in the SAR Chapter 15 analyses. Provide justification for not including the outboard second feedwater block valve within the scope of license renewal, and not including its valve body as being subject to an aging management review.
Clarified Response: The main feedwater system, which includes valves 2-CV-1023-2 and 2CV-1 073-2, has an intended function within the scope of license renewal to provide feedwater isolation, which relies on the closure of the valve disc by the motor operator.
Therefore, the system, including the valves, is in scope. The second (outboard) block valves are safety-related components. However, the safety function of providing feedwater isolation is performed by the internals of the valve with moving parts (active components).
The loss of valve body pressure boundary in this portion of the system would divert feedwater flow from the line and not prevent satisfactory isolation of flow to the steam to 2CAN070409 Page 6 of 9 generators. These valves perform their function with moving parts and in accordance with 10CFR54.21(a)(1)(i) are not subject to aging management review.
RAI 3.1.1-3 Restated: For Item 3.1.1-21, the applicant states that the feedwater ring discussed in Generic Aging Lessons Learned Section IV.D1I.3-a is applicable to Combustion Engineering System 80 steam generators and is not applicable to the Westinghouse steam generators at ANO-2. However, the Staff understands that the ANO-2 steam generators do have a feedwater ring and fittings which have a potential for degradation under adverse operating conditions. Justify why these components are not included in the scope of the license renewal and not subject to aging management.
Revised Response: The internal feedwater distribution rings are within the scope of license renewal but are not subject to aging management review since they do not support an intended function of the steam generators. There are no design basis events or regulated events at ANO-2 that rely on the steam generator feedwater ring for successful mitigation and recovery from the event. However, a visual inspection of the feedwater distribution ring and J-nozzles is performed at least once every five years as part of the ANO Steam Generator Integrity Program.
Clarification: The Staff requested Entergy to add a reference to Nuclear Energy Institute (NEI) 97-06 to Section A.2.1.26 of the ANO-2 SAR Supplement.
Response: Entergy will add a reference to NEI 97-06 to Section A.2.1.26, "Steam Generator Integrity Program," (page A-17) in the SAR Supplement. Section A.2.1.26 of the ANO-2 SAR Supplement will read as follows (changes shown in bold).
In the industry, steam generator tubes have experienced degradation related to corrosion phenomena, such as primary water SCC, outside diameter SCC, intergranular attack, pitting, and wastage, along with other mechanically induced phenomena, such as denting, wear, impingement damage, and fatigue. Using NEI 97-06 as a guideline, the Steam Generator Integrity Program uses nondestructive examination techniques to identify tubes that are defective and need to be removed from service or repaired in accordance with the guidelines of the Technical Specifications. In addition, the Steam Generator Integrity Program uses nondestructive examination techniques to manage the effects of aging on secondary side internals needed to maintain tubing integrity.
Clarification: LRA aging management program B.1.18, element 4, does not identify how specific aging effects will be detected for each aging effecUmechanism. For example, the aging management program includes emergency diesel generator (EDG) maintenance inspections and EDG surveillance testing. The applicant concludes that EDG maintenance inspection activities will manage the aging effects of loss of material (include due to selective leaching), cracking, fouling and change in material properties for various components. However, it is not clear how these aging effects are detected because different aging mechanisms require different detection methods. The Staff requested Entergy to identify the detailed aging effect detection methods for each of these various aging mechanisms and justify the technical basis for the method.
to 2CAN070409 Page 7 of 9 Response: The following table lists aging effect detection methods and technical basis for EDG maintenance inspections.
Aging Effect Detection of Aging Effects Technical Basis Loss of Every 24 months, during the Visual inspection determines evidence material EDG maintenance of significant corrosion or selective (including that inspection, visual inspections leaching.
due to are used to manage loss of Note:
selective material (including that due Details on enhancements to this leaching) to selective leaching).
program to manage loss of material due to selective leaching are not available but will be developed prior to the period of extended operation.
Enhancements to manage loss of material due to selective leaching will be consistent with NUREG aging management program XI.M33 which includes hardness testing.
Cracking Every 24 months, during the Visual inspection and liquid penetrant EDG maintenance testing determines evidence of inspection, non-destructive significant cracking.
examination (NDE) techniques are used to manage cracking.
Fouling Every 24 months, during the Visual inspection during maintenance EDG maintenance determines evidence of material inspection, visual inspections buildup on heat exchanger tubes.
are used to manage fouling.
Also, annual thermal performance testing on service water cooled heat Thermal performance testing detects exchangers is used to loss of heat transfer which is an manage fouling.
indication of fouling.
Change in Every 24 months, during the Visual inspection and manipulation material EDG maintenance determines whether flex hoses remain properties inspection, visual inspections flexible without cracking.
are used to manage change in material properties.
Clarification: LRA Table 3.3.2-5 credits the Water Chemistry Control Program and Periodic Surveillance and Preventive Maintenance Program for managing aging effects in the chemical and volume control system (CVCS) stainless steel pump casing. LRA Section B.1.18, Periodic Surveillance and Preventive Maintenance Program, identifies the CVCS periodic surveillance testing with managing aging effects in the charging pump casings, but specific inspection criteria is not identified. Clarify what specific inspections or tests are conducted to assure that aging is not occurring in the charging pump casings and identify the frequency and acceptance criteria applicable to this surveillance testing. Identify to 2CAN070409 Page 8 of 9 specific criteria and operating experience for elements 3, 4, 5, 6, and 10 that demonstrate loss of material in the charging pump casings is being effectively managed.
Response: As indicated in LRA Table 3.3.2-5, for the charging pump casings, loss of material due to wear and cracking due to fatigue are the aging effects requiring management that are managed by the Periodic Surveillance and Preventive Maintenance Program.
Parameters monitored:
Loss of material: Loss of material is caused by wear of the pump casings where the bore comes into contact with the adjusting and plunger rings. The condition of the bore is monitored for burrs and raised areas - evidence of excessive wear. During pump testing, charging pump flow rates and vibration are monitored as indicators of excessive wear.
During this test a visual inspection for leakage is also performed.
Cracking: During maintenance inspections, plunger caps are inspected for indications of cracking.
Detection of aging effects:
Loss of material: Quarterly surveillance tests manage loss of material of the charging pump casings since excessive wear would impact pump flow capacity or vibration. If surveillance test results warrant or the charging pumps are otherwise disassembled for maintenance, visual inspections of bore surfaces confirm they are free of burrs and raised areas -
evidence of excessive wear.
Cracking: Inspections for wear or damage, including cracking, are performed on any parts removed during maintenance.
Monitoring and trending:
Surveillance testing -and maintenance activities provide for monitoring and trending of aging degradation. Testing and inspection intervals are established such that they provide for timely detection of component degradation. Data is monitored for indication of degradation.
Trending within the Corrective Action Program will identify the need for additional testing or inspections.
Acceptance criteria:
Loss of material: In surveillance procedures, acceptance criteria are provided for required flow and acceptable vibration.
Cracking: Indications of cracking will result in replacement of the affected component.
Operating experience Cracking due to high cycle fatigue was identified in the operating experience review as an aging effect requiring management for the pump casing plunger caps. A review of condition reports did not identify additional instances of CVCS pump casing aging effects.
to 2CAN070409 Page 9 of 9 Clarification: For the aging management program B.1.24 Service Water Integrity under attribute 4, detection of aging effects, the LRA identifies an enhancement concerning visual inspection to detect selective leaching. Provide the technical justification for performing visual inspections without hardness testing to detect selective leaching. Also, under operating experience, the LRA indicates that minor through wall piping leaks have occurred and the service water components are routinely inspected to ensure loss of material and cracking will not degrade the ability of the service water system to perform its intended function. Identify the type of inspections used to detect the aging effects of loss of material and cracking and provide justification for the inspection method.
Response: Specific details on the enhancements to the Service Water Integrity Program for managing loss of material due to selective leaching are not available but will be developed prior to the period of extended operation. Enhancements to the program to manage loss of material due to selective leaching will be consistent with NUREG-1801 aging management program Xl.M33 which includes hardness testing.
As indicated in the LRA, detection of aging effects for the ANO-2 Service Water Integrity Program will be consistent with NUREG-1801 aging management program XL.M20. See NUREG-1801 aging management program Xl.M20 for details of the inspections.
Clarification: The Staff requested Entergy to provide a justification for its method for managing crack initiation and growth for the reactor coolant system (RCS) small-bore piping of 1-inch nominal pipe size (NPS) or less.
Response: The ANO-2 Program entitled 'Inservice Inspection - Inservice Inspection" discussed in Section B.1.14 of Appendix B of the ANO-2 LRA addresses small-bore piping inspections for piping in the RCS between 1-inch and 4-inch NPS. A risk-informed approach was used to select piping for volumetric inspection and the inspections are performed each inspection interval.
The most risk-significant piping locations selected for the pipe sizes between 1-inch and 4-inch NPS provide a representative sample of piping that has the same material and environment combination, and the same identified aging effects as the 1-inch and smaller piping. In addition, the risk (based on probability and consequences) of failure of the 1-inch and smaller piping is less than the risk of failures at locations selected for inspection in the small-bore piping inspection program. Consistent with the ASME Section Xl Code, 1-inch and smaller piping is exempt from surface and volumetric examinations since volumetric examination of 1-inch piping is not practical and the consequences of leakage from these smaller pipes are less than the consequences of leakage from larger piping. Operating experience has confirmed that leakage from 1-inch and smaller piping is readily detected and corrected prior to loss of system function. As part of the ANO-2 "Inservice Inspection -
Inservice Inspection" Program, visual inspection of the 1-inch and smaller piping, in conjunction with volumetric examinations of larger piping of the same material, adequately manages the effects of aging prior to loss of function. This approach is consistent with that for ANO-1 which was evaluated and approved by the NRC as documented in NUREG-1743.
2CAN070409 List of Regulatory Commitments to 2CAN070409 Page 1 of 1 List of Regulatory Commitments The following table identifies those actions committed to by Entergy in this document. Any other statements in this submittal are provided for information purposes and are not considered to be regulatory commitments.
TYPE (Check One SCHEDULED ONE.
COMPLETION TIME CONTINUING DATE COMMITMENT ACTION COMPLIANCE (If Required)
The ANO-2 groundwater chemistry will X
Prior to be monitored by sampling from July 17, 2018 representative sample points at least once every 10 years. The samples will be analyzed for pH, chlorides and sulfates. The sampling will be initiated prior to the period of extended operation.
Specific details on the enhancements to X
July 17, 2018 the Service Water Integrity Program for managing loss of material due to selective leaching are not available but will be developed prior to the period of extended operation. Enhancements to the program to manage loss of material due to selective leaching will be consistent with NUREG-1801 aging management program XL.M33 which includes hardness testing.
In accordance with NUREG 1800, X
July, 17, 2018 Section 4.5.3.1.3, the relevant operating experience, including the experience with prestressing systems described in Information Notice 99-10, will be considered.