ML082340632

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Vermont Yankee July 2008 Evidentiary Hearing-Intervenor Exhibit NEC-UW_05, NRC, Generic Aging Lessons Learned (GALL) Report, Tabulation of Results, NUREG-1801, Vol 2, Rev. 1, (September 2005) (Excerpt)
ML082340632
Person / Time
Site: Vermont Yankee Entergy icon.png
Issue date: 09/30/2005
From:
Office of Nuclear Reactor Regulation
To:
NRC/SECY/RAS
SECY RAS
References
06-849-03-LR, 50-271-LR, Extergy-Intervenor-NEC-UW_05, RAS M-243 NUREG-1801 V2 R1
Download: ML082340632 (39)
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DOCKETED USNRC August 12, 2008 (11:00am) NEC-UW_05

-.OFFICE OF SECRETARy-RULEMAKINGS AND ADJUDICATIONS STAFF NUREG-1801, Vol. 2, Rev. I Generic Aging Lessons Generic Aging. Lessons Learned (GALL) Report Tabulation of Results Manuscript Completed: .September 2005 Date Published: September 2005 Division of Regulatory Improvement Programs Office of Nuclear Reactor Regulation U.S. Nuclear Regulatory Commission Washington, DC 20555-0001 U& NUCMIEARIfUMAOOMMSO OFFERED br Ag I'idiiw! 1 r 'I IDENtFOED C&ewa ie Af~.ADM-EEMWNI I4~-A-~L-4~ )~L&L~( -0 2-e- b-(ý ý 0 S

X.M1 METAL FATIGUE OF REACTOR COOLANT PRESSURE BOUNDARY Program Description In order not to exceed the design limit on fatigue usage, the aging management program (AMP) monitors and tracks the number of critical thermal and pressure transients for the selected reactor coolant system components.

The AMP 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 componeQnts for the plant. Examples of critical components are identified in NUREG/CR-6260 The sample of critical components can be evaluated by applying environmental life correction factors to the existing.ASME Code fatigue analyses. Formulae for calculating the environmental life correction factors are contained in NUREG/CR-6583 for carbon and low-alloy steels and in NUREG/CR-5704 for austenitic stainless, steels.

As evaluated below, this is an acceptable *optionfor managing metal fatigue for the reactor coolant pressure boundary, considering environmental effects. Thus, no further evaluation is recommended for license renewal if the applicant selects this option under 10 CFR 54.21 (c)(1)(iii) to evaluate metal fatigue for the reactor coolant pressure boundary, Evaluation and Technical Basis

1. Scope of Program:The program includes preventive measures to mitigate fatigue cracking of metal Components of the reactor coolant pressure boundary caused by anticipated cyclic strains in the material.
2. PreventiveActions: Maintaining the fatigue usage factor below the design code limit and considering the effect of the reactor water environment, as described under the program description, will provide adequate margin against fatigue cracking of reactor coolant system components due to anticipated cyclic strains.
3. ParametersMonitored/Inspected:The program monitors. all plant transients that-cause cyclic strains, which are significant contributors to the fatigue usage factor. The number of plant transients that cause significant fatigue usage for each critical reactor coolant pressure boundary component is to be monitored..Altematively, more detailed local monitoring of the plant transient may be used to compute the actual fatigue usage for each transient.
4. Detection of Aging Effects: The program provides for periodic update of the fatigue usage calculations.
5. Monitoring and Trending: The program monitors a sample of high fatigue usage locations.

This sample is.to include the locations identified in NUREG/CR-6260, as minimum, or propose alternatives based on plant configuration.

6. Acceptance Criteria:The acceptance criteria involves maintaining the fatigue usage below the design code limit considering environmental fatigue effects as described under the program description.
7. CorrectiveActions: The program provides for corrective actions to prevent the usage.

factor from exceeding the design code limit during the period of extended operation.

September 2005 X M-1 NUREG-1801, Rev. 1

Acceptable corrective actions include repair of the component, replacement of the component, and a more rigorous analysis of the component to demonstrate that the design code limit will not be exceeded during the extended period of operation. For programs that monitor a sample of high fatigue usage locations, corrective actions include a review of additional affected reactor coolant pressure boundary-locations.As discussed in the appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the corrective actions.

8. Confirmation Process:Site quality assurance procedures, review and approval processes, and administrative, controls are implemented in accordance with the requirements of Appendix B to 10 CFR Part 50. As discussed in the appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation process and administrative controls.
9. Administrative Controls:See Item 8, above.
10. OperatingExperience: The program reviews industry experience regarding fatigue cracking. Applicable experience with fatigue cracking is to be considered in selecting the monitored locations.

References NUREG/CR-5704, Effects of LWR Coolant Environmentson FatigueDesign Curves of Austenitic Stainless Steels, U.S. Nuclear Regulatory Commission, April 1999.

NUREG/CR-6260, Application of NUREG/CR-5999 Interim Fatigue Curves to Selected Nuclear Power Plant Components, U.S. Nuclear Regulatory Commission, March 1995.

NUREG/CR-6583, Effects of LWR CoolantEnvironments on Fatigue Design Curves of Carbon and Low-Alloy Steels, U.S. Nuclear Regulatory Commission, March 1998.

NUREG-1801, Rev. 1 X M.-2 September 2005

XI.M17 FLOW-ACCELERATED CORROSION Program Description The program relies on implementation of the Electric Power Research Institute (EPRI) guidelines in the Nuclear Safety Analysis Center (NSAC)-202L-R2 for an effective flow-accelerated corrosion (FAC) program. The program includes performing (a) an analysis to determine critical.locations, (b) limited baseline inspections to determine the extent of thinning at these locations, and (c) follow-up inspections to confirm the predictions, or repairing or replacing components as necessary.

Evaluation and Technical Basis

1. Scope of Program:The FAC program, described by the EPRI guidelines in NSAC-202L-R2, includes procedures or administrative controls to assure that the structural integrity of all carbon steel lines containing high-energy fluids (two phase. as well as single phase) is maintained. Valve bodies retaining pressure inthese high-energy systems are also covered by the program. The FAC program was originally outlined in NUREG-1344 and was further described through the Nuclear Regulatory Commission (NRC) Generic Letter (GL) 89-08. A program implemented in accordance with the EPRI guidelines predicts, detects, and monitors FAC in plant pipingand other components, such as valve bodies, elbows.and expanders. Such a program includes the following recommendations: (a) conducting an analysis to determine critical locations, (b) performing limited baseline inspections to determine the extent oftthinning at these locations, and (c) performing follow-up inspections to confirm the predictions,.or repairing or replacing components as-necessary. NSAC-202L-R2 (April 1999) provides general guidelines for the FAC program. To ensurethat all-the aging effects caused by FAC are properly managed, the program. includes the use of a predictive code, such as CHECWORKS, that uses the. implementation guidance of NSAC-202L-R2 to satisfy the criteria specified in I OGCFR Part 50, Appendix B, criteria for development of procedures and control of special processes. -

2.. Preventive Actions: The FAC program is an analysis, inspection, and verification program; thus, chemistry is..no there pH to control andpreventive dissolvedaction.

oxygen.However, it is noted thatofmonitoring content, andselection of water appropriate piping material, geometry, and hydrodynamic conditions, are effective~in 'reducing FAC.

3. ParametersMonitored/Inspected:The aging management program (AMP) monitors the effects of FAC on the intended function of piping and components by measuring wall

.thickness.

4. Detection of Aging Effects: Degradation of piping and components occurs by wall thinning. The inspection program delineated in NSAC-202L-R2 consists of identification of susceptible locations as indicated by operating conditions or special considerations.

Ultrasonic and radiographic testing is used to detect wall thinning. The extent and schedule of the inspections assure detection of wall thinning before the loss of intended function.

5. Monitoring and Trending:CHECWORKS or a similar predictive code is used to predict component degradation in the systems conducive to FAC, as indicated byspecific plant data, including material, hydrodynamic, and operating.conditions. CHECWORKS is September 2005 X1 M-61 NUREG-1801, Rev. 1

acceptable because it provides a bounding analysis for FAC. CHECWORKS was developed and benchmarked by using data obtained from many plants. The inspection schedule developed by the licensee on the basis of the results of such a predictive code provides reasonable assurance that structural integrity will be maintained between inspections. Inspection results are evaluated to determine if additional inspections are needed to assure that the extent of wall thinning is adequately determined, assure that intended function will not be lost, and identify corrective actions.

6. Acceptance Criteria:Inspection results are input for, a predictive computer code, such as CHECWORKS, to calculate the number of refueling or operating -cycles remaining before the component reaches the minimum allowable wall thickness. If calculations indicate that an area will reach the minimum allowed wall'thickness before the next scheduled outage, the component is to be repaired, replacedi or reevaluated.

V CorrectiveActions: Prior to service,.components for which.the acceptance criteria are not satisfied are reevaluated, repaired, or replaced. Long-term corrective actions. could include adjusting operating parameters or selecting materials- resistant to FAC. As discussed in the appendix to this report, the staff finds the requirements of 10 CFR Part 50,. Appendix B, acceptable to address the corrective actions.

8. ConfirmationProcess:Site quality assurance (QA) procedures, review and approval processes*, and administrative controls areimplemented in accordance with the requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation process and administrative controls.
9. Administrative Controls: See Item 8, above.
10. OperatingExperience:Wall-thinning problems in single-phase systems have occurred in feedwater and condensate systems (NRC IE Bulletin No. 87-01; NRC.information Notices

[INs] 81-28, 92-35, 95-11) and in two-phase piping in extraction steam lines (NRC INs 89-53, 97-84) and moisture separation reheater and feedwater heater drains (NRC INs89-753, 91-18, 93-21, 97-84). Operating experience shows that the present program, when properly implemented, is effective in managing FAC in high-energy carbon steel piping and components.

References 10 CFR Part 50, Appendix B,. Quality Assurance Criteriafor Nuclear PowerPlants, Office of the Federal Register, National Archives and Records Administration, 2005.

10 .CFR Part 50.55a, Codes and Standards, Office of the Federal Register, National Archives and Records Administration, 2005.

NRC Generic Letter 89-08, Erosion/Corrosion-InducedPipe Wall Thinning, U.S. Nuclear Regulatory Commission, May 2, 1989.

NRC IE Bulletin 87-01, Thinning of Pipe Walls in NuclearPowerPlants, U.S. Nuclear Regulatory Commission, July 9, 1987.

NUREG-1801, Rev. I XI M-62 September 2005.

NRC Information Notice 81-28, Failureof Rockwell-Edward Main Steam Isolation Valves, U.S. Nuclear Regulatory Commission, September 3, 1981.

NRC Information Notice 89-53, Rupture of Extraction Steam Line on High Pressure Turbine, U.S. Nuclear Regulatory Commission, June 13, 1989.

NRC Information Notice 91-18, High-EnergyPiping Failures Causedby Wall Thinning, U.S. Nuclear Regulatory Commission, March 12, 1991.

NRC Information Notice 91-18, Supplement 1, High-EnergyPiping FailuresCaused by Wall Thinning, U.S. Nuclear Regulatory Commission, December 18, 1991.

NRC Information Notice 92-35, Higherthan PredictedErosion/Corrosionin Unisolable Reactor Coolant PressureBoundary Piping inside Containmentat a Boiling Water Reactor, U.S. Nuclear Regulatory Commission, May 6, 1992.

NRC Information Notice 93-21, Summary of NRC Staff ObservationsCompiledduring EngineeringAudits or Inspectionsof Licensee Erosion/CorrosionPrograms,U.S. Nuclear Regulatory Commission, March 25, 1993.

NRC .Information Notice 95-11, Failureof Condensate Piping Because of Erosion/Corrosionat a Flow StraighteningDevice, U.S. Nuclear Regulatory Commission, February 24, 1995.

NRC information Notice 97-84, Rupture in ExtradionSteam Piping as a Resuff of Flow-Accelerated Corrosion, U.S. Nuclear Regulatory Commission, December 11, 1997.

NSAC-202L-R2, Recommendations for an Effective Flow Accelerated Corrosion Program, Electric Power Research Institute, Palo Alto, CA, April 8, 1999.

NUREG-1 344; Erosion/Corrosion-InducedPipe Wall Thinning in U.S. Nuclear PowerPlants, P. C. Wu, U:S. Nuclear Regulatory Commission, April 1989.

September 2005 X1-M-63 NUREG-1801, Rev. "1

XI.M18 -BOLTING INTEGRITY Program Description The program relies on recommendations for a comprehensive bolting integrity program, as delineated in NUREG-1339, and-industry recommendations, as delineated in the Electric Power Research Institute (EPRI) NP-5769,.with the exceptions noted in NUREG-1 339 for safety-,

related bolting. The program relies on industry recommendations for comprehensive bolting maintenance, as delineated in EPRI TR-1 04213 for pressure retaining bolting and structural.

bolting.

The program generally includes periodic inspection of closure bolting for indication of loss of preload,, cracking, and loss of material due to corrosion, rust, etc. The program also includes

.preventive measures to preclude or minimize loss of preload and cracking.

Other aging management programs, such as XI.M 1, "ASME Section XI Inservice Inspection (IsI) Subsections IWB, IWC, and IWD" and XI.S3, "ASME.Section XI Subsection IWF" also manage inspection of safety-related bolting and supplement this bolting integrity program.

Evaluation and Technical Basis

1. Scope of Program:This program covers bolting within the scope of license renewal,
  • including: 1) safety-related bolting, 2) bolting for nuclear steam supply system (NSSS) component supports, 3) bolting for other pressure retaining components, including non-safety-related.bolting, and 4) structural bolting (actual measured yield strength _>150 ksi).

The aging management of reactor head closure studs is addressedby XI.M3, and is not included .in this program. The staffs recommendations and guidelines for comprehensive bolting integrity, programs that encompass all safety-related bolting are delineated in NUREG-1339, which include the criteria established in the 1995 edition through the 1996 addenda of ASME Code Section Xl. The industry's technical basis for the.program for safety-related bolting and guidelines for.material selection and testing, bolting preload control, ISI, plantoperation, and maintenance, and evaluation of the structural integrity of bolted joints, are outlined in EPRI NP-5769, with the exceptions noted in NUREG-1 339.

For other bolting, this information is set forth in EPRI TR-1 04213.

2. PreventiveActions: Selection of bolting material and the use of lubricants and sealants

-is in accordance with the guidelines of EPRI NP-5769, and the additional.

recommendations of NUREG-1339, to prevent or mitigate degradation and failure of safety-related bolting .(see element 10, below). NUREG-1 339 takes exception to certain items in EPRI NP-5769, and recommends additional measures with regard to them.

Bolting replacement activities include proper torquing of the bolts and checking for uniformity of the gasket-compression after assembly. Maintenance practices require the application of an appropriate preload, based on EPRI documents.

3. ParametersMonitored/Inspected:This program monitors the effects of aging on the intended function of bolting. Specifically, bolting for safety-related pressure retaining components is inspected for leakage, loss of material, cracking, and loss of preload/loss of prestress. Bolting for other pressure retaining components is inspected for signs of leakage.

NUREG-1801, Rev. 1 XI M-64 September 2005

High strength bolts (actual yield strength .150 ksi) used in NSSS component supports are monitored for cracking. Structural bolts and fasteners are inspected for indication of potential problems including loss of material, cracking, loss of coating integrity, and obvious signs of corrosion, rust, etc.

4. Detection of Aging Effects: Inspection requirements are in accordance with the ASME Section. XI, Tables IWB 2500-1, IWC 2500-1 and IVWD 2500-1 editions endorsed in 10 CFR 50.55a(b)(2) and the recommendations of EPRI NP-5769. For Class i components, Table IWB 2500-1, Examination Category B-G-I, for bolts greater than 2-inches in diameter, specifies volumetric examination of studs and bolts and visual VT-1 examination of surfaces of nuts, washers, bushings, and flanges. Examination Category B-G-2, for bolts 2-inches or smaller, requires only visualVT-.1 examination of surfaces of bolts,.

studs, and nuts. For Class 2 components, Table IWC 2500-1, Examination Category C-D, for bolts greater than 2-inches in diameter, requires volumetric examination of studs and:

bolts. Examination Categories B-P, C-H, and D-B require Visual examination (IWA-5240) during system leakage testing of all pressure-retaining Class 1, 2 and 3 components, accordingto Tables IWB 2500-1, IWC 2500-1, and IWMD 2500-1, respectively. In addition, degradation of the closure bolting due to crack-initiation, loss of prestress, or loss of material due to corrosion of the closure bolting would result in leakage. The extent and schedule of inspections, in accordance with Tables IWB 2500-1, IWC 2500-1,. and IWD 2500-1, combined with periodic system walkdowns, assure detection of leakage before the leakage becomes excessive.

For other pressure retaining bolting, periodic system walkdowns assure detection of leakage before the leakage becomes excessive.

High strength structural bolts and fasteners (actual yield strength 150 ksi) for NSSS component supports, may be subject to stress corrosion cracking (SCC). For this type of high strength structural bolts that are potentially subjected to SCC, in sizes greater than 1-inch nominal diameter, volumetric examination comparable to that of Examination Category B-G-1 is required in addition to visual examination. This requirement may be waived with adequate plant-specific justification. Structural bolts and fasteners (actual yield strength < 150 ksi) both inside and outside containment are inspected by visual' inspection (e.g., Structures Monitoring Program or equivalent).- In addition to visual and volumetric examination, degradation of these bolts and fasteners may be detected and measured by removing the bolt/fastener, a proof test by tension or torquing, in 'situ ultrasonic tests, or a hammer test If these bolts and fasteners are found cracked and/or corroded, a closer inspection is performed to assess extent of corrosion. An appropriate technique is selected on the basis of the bolting application and the applicable code.

5. Monitoring and Trending: The inspection schedules of ASME Section XI are effective and ensure timely detection of applicable aging effects. If bolting connections for pressure retaining components (not covered by ASME Section XI) is reported to' be leaking, then it may be inspected daily. If the leak rate does not increase, the inspection frequency may be decreased to biweekly or weekly.
6. Acceptance Criteria:Any indications of aging effects in ASME pressure retaining bolting are evaluated in accordance with Section XI of the ASME Code. For other pressure retaining bolting, NSSS component support bolting and structural bolting, indications of aging should be dispositioned in accordance with the corrective action process.

Septernb& 2005 X1 M-65 NUREG-1801, Rev. 1

7. CorrectiveActions: Replacement of ASME pressure retaining bolting is performed in accordance with appropriate requirements of Section Xl of the ASME Code, as.subject to the additional guidelines and recommendations of EPRI NP-5769. Replacement of other pressure retaining bolting (i.e., non-Class 1 bolting) and disposition ofdegraded structural bolting is performed in accordance with the guidelines and recommendations of EPRI TR-104213. Replacement of NSSS component support bolting is performed in accordance with EPRI NP-5769. As discussed in the appendix-to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the corrective actions.
8. ConfirmationProcess:Site quality assurance (QA) procedures, review and approval processes, and administrative controls are implemented in accordance with the requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation process and administrative controls.
9. Administrative Controls:See item 8, above.
10. OperatingExperience: Degradation of threaded bolting and fasteners in closures for the reactor. coolant pressure boundary has occurred from boric acid corrosion, SCC, and fatigue loading (NRC 1E Bulletin 82-02, NRC Generic Letter 91-17). SCC has occurred in high strength bolts used for NSSS component supports (EPRI. NP-5769). The bolting integrity program developed and implemented in accordance with commitments made in response to NRC communications on bolting events have provided an effective means of ensuring bolting reliability. These programs are documented in EPRI NP-5769 and TR-104213 and represent industry consensus.

Degradation related failures have occurred in downcomer Tee-quencher bolting in BWRs designed with drywells (ADAMS Accession Number ML050730347).. Leakage from bolted connections has been observed in reactor building closed cooling systems of BWRs.

(LER 50-341/2005-001).

The applicant is to evaluate applicable operating experience to support the conclusion that the effects of aging are adequately managed.

References 10 CFR Part 50, Appendix B, Quality Assurance Criteriafor NuclearPowerPlants, Office* of the Federal Register, National Archives and Records Administration,2005.

10 CFR 50.55a, Codes and Standards, Office of the Federal Register, National Archives and Records Administration, 2005.

ASME Section Xl, Rules for Inservice Inspection of NuclearPowerPlant Components, ASME Boiler and Pressure Vessel Code, 2001 edition including the 2002 and 2003 Addenda, American Society of Mechanical Engineers, New York, NY.

EPRI NP-5769, Degradationand Failureof Bolting in NuclearPower-Plants,Volumes 1 and 2, April 1988.

EPRI TR-1 04213, Bolted Joint Maintenance &Application Guide, Electric, December 1995.

NUREG-1801, Rev. 1 Xl M--66 September 2005

NRC Generic Letter 91-17, Generic Safety Issue 79, Bolting Degradationor Failurein Nuclear PowerPlants, U.S. Nuclear Regulatory Commission, October 17, 1991.

NRC IE Bulletin No. 82-02, Degradationof Threaded Fastenersin the Reactor Coolant Pressure Boundaryof PWR Plants, U.S. Nuclear Regulatory Commission, June 2, 1982.

NUREG-1339, Resolution of GenericSafety Issue 29: Bolting Degradationor Failurein Nuclear PowerPlants, U.S. Nuclear Regulatory Commission, June 1990.

Failure of Safety/Relief Valve Tee-Quencher Support Bolts, NRC Morning Report for March 14, 2005, ADAMS. Accession Number ML050730347.

. September 2005 XI M-67 NUREG-1801, Rev. 1

XI.M19 STEAM GENERATOR TUBE INTEGRITY Program Description The steam generator tube integrity program is applicable to managing the aging of steam generator tubes, plugs, sleeves and tube supports..

  • Mill annealed alloy 600 steam generator (SG) tubes have experienced tube degradation related to corrosion phenomena, such as primary water stress corrosion cracking (PWSCC), outside diameter stress corrosion cracking (ODSCC), intergranular attack (IGA), pitting, and wastage, along with other mechanically induced phenomena, such as denting, wear, impingement damage, and fatigue. The dominant degradation mode at this time for thermally treated alloy 600 and 690 tubes is wear. Nondestructive examination (NDE) techniques are used to inspect all tubing materials and sleeves to identify tubes with degradation that may need to be removed from service or repaired in accordance with plant technical specifications. Inaddition, operational leakage limits are included to ensure that, should substantial tube leakage develop, prompt action is. taken. These limits are included in plant technical specifications, such as standard technical specifications of NUREG-1 430, Rev. 1, forBabcock & Wilcox pressurized waterreactors (PWRs); NUREG-1431, Rev. 1, for Westinghouse PWRs; and NUREG-1432, Rev. 1, for Combustion Engineering PWRs.

.The technical specifications specify SG inspection scope, frequency, and acceptance criteria for the plugging and repairof flawed tubes. NRC Regulatory Guide (RG) 1.121, "Bases forPlugging Degraded Steam Generator Tubes," provides guidelines for determining the tube repair criteria and operational leakage limits..Acceptance criteria for the plugging and repair of flawed tubes are incorporated in plant technical specifications. In addition to flaw acceptance (or plugging/repair) criteria,-the technical specifications also specify acceptable tube repair methods (e.g., plugging and/or sleeving). Plants. may also apply for changes in their technical specifications to provide an .alternate repair criteria for SG degradation management.

.In addition to plant technical specifications, all PWR licensees have committed voluntarily to a SG degradation management program described in the Nuclear Energy Institute (NEI) 97-06,

'"Steam Generator Program-Guidelines." This program references a number of industry

  • guidelines and incorporates a balance of prevention, inspection, evaluation, .repair, and leakage monitoring measures. The NEI 97-06 document (a) includes performance criteria that are intended to provide assurance that tube integrity is being maintained consistent with the plant's licensing basis, and (b) provides guidance for monitoring and maintaining the tubes to provide assurance that the performance criteria are met at all times between scheduled inspections of the tubes. Steam generator tube integrity can be. affected by degradation of SG plugs, sleeves and tube supports. Therefore, these components are also addressed by this aging management program.

The NEI 97-06 program includes an assessment of degradation mechanisms that considers operating experience from similar steam generators (SGs) and, for each mechanism, defines the inspection techniques as well as the sampling strategy. The industry guidelines provide criteria for the qualification of personnel, specific techniques, and the associated acquisition and analysis of data, including procedures, probe selection, analysis protocols, and reporting criteria. The performance criteria pertain to structural integrity, accident-induced leakage, and operational leakage. The SG monitoring program includes guidance on assessment of degradation mechanisms, -inspection, tube integrity assessment,. maintenance., plugging, repair, and leakage monitoring, as well as procedures for monitoring and controlling secondary-side NUREG-1801, Rev. 1. XI M-68 September 2005

and primary-side water chemistry. The water chemistry program for PWRs relies on monitoring and control of reactor water chemistry and secondary water chemistry.

Lastly, NRC Generic Letter (GL) 97-06, "Degradation of Steam Generator Internals," dated December 30, 1997, notified the industry of various steam generator-tube support plate damage mechanisms identified in foreign and domestic steam generators. In response to GL 97-06, licensees indicated whether they had a program in place to detect degradation of steam generator internals, and included a description, of the inspection plans, including the inspection scope, frequency, methods, and components..

As evaluated, below, the plant technical specifications, including alternate repair criteria for SG degradation management that have been previously approved by the staff for that plant, the licensee's response to GL 97-06, and the licensee's commitment to implement the SG degradation management program described in. NEI 97-06, are adequate to manage the effects of aging on the SG tubes, plugs, sleeves, and tube supports.

Evaluation and Technical Basis

1. Scope of Program:The scope of the program is specific to SG tubes, plugs, sleeves and tube supports. The program includes preventive measures to mitigate degradation related to corrosion phenomena, assessment of degradation mechanisms, inservice inspection (ISI) of steam generator tubes, plugs, sleeves, and tube supports to detect degradation, evaluation, and plugging or repair, as needed, and"Ieakage monitoring to maintain the structural and leakage integrity of the pressure boundary. Tube and sleeve inspection scope, and frequency, plugging or repair, and leakage monitoring are in accordance. with the plant technical specifications and the licensee's SG degradation management program implemented in accordancewith NEI 97-06, Plug inspection scope and frequency, plugging or repair, and leakage monitoring are in accordance with the licensee's SG degradation management programimplemented in accordance with NEI 97-06. Lastly, tube support plate inspection scope and frequency are in accordance with the licensee's SG degradation management program implemented in accordance with NEI 97-06 as well as the program described in the licensee's rdsponse to GL 97-06.
2. Preventive Actions: The program includes preventive measures to mitigate degradation related to corrosion phenomena. The guidelines in NEI 97-06 include foreign material exclusion as a means to inhibit wear degradation. The water chemistry program for PWRs relies on. monitoring and control of reactor water chemistry based on the EPRI guidelines in TR-05714 for primary water chemistry and TR-102134 for secondary water chemistry.

The program description and the evaluation and technical basis of monitoring and maintaining reactor water chemistry are presented in Chapter XI.M2, "Water Chemistry,"

of this report.

3. ParametersMonitored/Inspected:The inspection activities in the program detect flaws in tubing,, plugs, sleeving, and degradation of tube supports needed to maintain tube integrity. Tubes are repaired or removed from service based on technical specification repair criteria. Sleeves are removed from service. based on technical specification repair criteria. Degraded plugs and tube supports are evaluated for corrective actions.
4. Detection of Aging Effects: The inspection requirements in the technical specifications are intended to detect tube and sleeve degradation. (i.e., aging effects), if they should occur. NEI 97-06 provides *additionalguidance on inspection programs to detect September 2005 XI M-69 NUREG-1801, Rev. 1

degradation of tubes, sleeves, plugs and tube supports. The intent of the inspection and repair criteria is to provide assurance of continued tube integrity between inspections. A licensee's response to GL 97-06 also provides a description of plant-specific inspection programs for detection of degraded SG internals.

5. Monitoringand Trending: Condition monitoring assessments are performed to determine whether structural and accident leakage criteria have been satisfied.

Operational assessments. are performed after inspections to verify that structural and leakage integrity will be maintained for the operating interval between inspections, which is selected in accordance with the technical specifications and NEI 97-06 guidelines.

Comparison of the results of the condition monitoring assessment with. the predictions of the previous operational assessment provides feedback. for evaluation of the adequacy of the1 operational assessment and additional insights that can be incorporated into the next operational assessment.

6. Acceptance Criteria:Assessment of tube and sleeve integrity and plugging or repair criteria of flawed and sleeved tubes is in accordance with plant technical specifications.

The criteria for plugging or repairing SG tubes and sleeves are based on NRC RG 1.121 or other criteria previously reviewed and approved by the staff and incorporated into plant technical specifications. Some examples of acceptance criteria that are applicable under certain circumstances include F*, L*, or NRC Generic Letter(GL) 95-05, "Voltage-Based Repair Criteria for Westinghouse Steam Generator Tubes-Affected by Outside-Diameter Stress-Corrosion Cracking."

7. CorrectiveActions: Tubes and sleeves containing flaws that do not meet the acceptance criteria are plugged or repaired. Degraded plugs and tube supports are evaluated for corrective actions. As discussed in the appendix to this report, the staff finds the requirements of 1.0 CFR Part 50, Appendix B, acceptable to address the corrective actions.
8. Confirmation Process:Site' quality assurance (QA) procedures, review and approval processes, and administrative controls are implemented in accordance with the requirements of 10 CFR Part 50, Appendix B. As discussed in the'appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address.the confirmation process and administrative controls.
9. Administrative Controls:See Item8, above.
10. OperatingExperience: Failures to detect some flaws, uncertainties in flaw sizing, inaccuracies in flaw locations, and the inability to detect some cracks at locations with dents have been reviewed in NRC Information Notice (IN) 97-88. Recent experience indicates the importance of performing a complete inspection by using appropriate techniques and components for the reliable detection of tube degradation and to provide assurance that new forms of.degradation are detected. Implementation of the program provides reasonable assurance that SG tube integrity is maintained consistent with the plants' licensing basis for the period of extended operation. Experience with the condition monitoring and-operational assessments required for plants that have implemented the alternate repair criteria in NRC GL 95-05 has shown that the predictions of the operational assessments have generally been consistent with the results of the subsequent. condition monitoring assessments. In cases where discrepancies have been noted, adjustments have been made in the operational assessment models to improve agreement in NUREG-1801, Rev. I XI M-70 September 2005

. ............. .. - - ---- - --- ...

subsequent assessments. In addition, the industry has programslprocesses for incorporating lessons learned from plant operation into guidelines referenced in NEI 97-06.

References 10 CFR Part 50, Appendix B, Quality Assurance Criteria for NuclearPowerPlants, Office of the Federal Register, National Archives and Records Administration, 2005.

10 CFR Part.50.55a, Codes and Standards, Office of the Federal Register, National Archives and Records Administration, 2005.

EPRI TR-102134, PWR Secondary Water ChemistryGuidelines:Revision 3, Electric Power Research Institute, Palo Alto, CA, May 1993.

EPRI TR-105714, PWR Primary Water Chemistry Guidelines: Revision 3, Electric Power Research institute, Palo Alto, CA, November 1995.

EPRI TR-1 07569, PWR Steam GeneratorExamination Guidelines: Revision 6, Electric Power Research Institute, Palo Alto, CA, October 2002.

NEI 97-06, Rev. 1, Steam GeneratorProgramGuidelines, Nuclear Energy Institute, January 2001.

NRC Generic Lietter 95-05, Voltage-Based Repair Criteriafor Westinghouse Steam Generator Tubes Affected by Outside-DiameterStress-CorrosionCracking, U.S. Nuclear Regulatory Commission, August 3, 1995.

NRC Generic Letter 97-06, Degradationof Steam GeneratorInternals, U.S. Nuclear Regulatory Commission, December 30, 1997.

NRC Information Notice, 97-88, Experiences during Recent.Steam GeneratorInspections,.U.S.

Nuclear Regulatory Commission, December 12, 1997.

NRC Regulatory Guide, 1.83, Rev. 1, Inservice Inspection of PressurizedWater Reactor Steam GeneratorTubes, U.S. Nuclear Regulatory Commission; July 1975.

NRC Regulatory Guide, 1.121, Bases for Plugging DegradedPWR Steam GeneratorTubes, U.S. Nuclear Regulatory Commission, August 1976.

NUREG-1430, Rev. 1, Standard.TechnicalSpecificationsfor Babcock and Wilcox' Pressurized Water Reactors, U.S. Nuclear Regulatory Commission, April 1995.

NUREG-1431, Rev. 1, StandardTechnical Specificationsfor Westinghouse PressurizedWater Reactors, U.S. Nuclear Regulatory Commission, April 1995.

NUREG-1 432, Rev. 1; Standard Technical Specificationsfor Combustion Engineering PressurizedWater Reactors, U.S. Nuclear Regulatory Commission, April 1995.

September 2005 X1 M-71 NUREG-1801, Rev. 1

XI.M20 OPEN-CYCLE COOLING WATER SYSTEM Program Description The program relies on implementation of the recommendations of the Nuclear Regulatory Commission (NRC) Generic Letter (GL) 89-13 to ensure that the effects of aging on the open-cycle cooling water (OCCW) (or service water) system, will be managed for the extended. period of operation. The program includes surveillance and control techniques to manage aging effects

-caused by biofouling, corrosion, erosion, protective coating failures, and silting in the OCCW system or'structures and components serviced by the OCCW system.

Evaluation and Technical Basis

1. Scope of Program:The program addresses the aging effects of material loss and fouling due to micro- or macro-organisms and various corrosion. mechanisms. Because the characterdstics of the service water system may be specific to each facility, the occW.

system is defined as a system or systems that transfer heat from safety-related systems, structures, and components (SSC) to the ultimate heat sink (UHS). If an intermediate system is used between the safety-related SSCs and the system rejecting. heat to the UHS, that intermediate. system performs the function. of a service water.system and, is thus included in the scope of recommendations of NRC GL 89-13. The guidelines of NRC.

GL 89-13 include (a) surveillance and control of biofouling; (b) a test program to verify heat transfer capabilities; (c) routine inspection and a maintenance program to, ensure that corrosion, erosion, protective coating failure, silting, and biofouling cannot degrade the performance of safety-related systems serviced by OCCW; (d) a system walk down inspection to ensure compliance with the licensing .basis;. and.(e) a review of maintenance, operating, and training practices and procedures.

2. PreventiveActions: The system components are constructed of appropriate materials and lined or coated to protect the underlying metal surfaces from. being exposed to aggressive cooling water environments. Implementation of NRC GL 89-13 includes a condition and performance monitoring program; control or preventive measures, such as chemical treatment, whenever the potential for biological fouling species exists; 'or flushing of infrequently used systems. Treatment with chemicals mitigates microbiologically-influenced corrosion (MIC) and buildup of macroscopic biological fouling species, such as blue mussels, oysters, or clams. Periodic flushing of the system removes accumulations

.of biofouling agents, corrosion products, and silt.

3. ParametersMonitored/Inspected:Adverse effects on system or component

.performance are caused by accumulations of'biofouling agents, corrosion products, and silt. Cleanliness and material integrity of piping, components, heat exchangers,'

elastomers, and their internal linings or coatings (when applicable) that are part.of the OCCW system or that are cooled by the OCCW system are periodically inspected, monitored, or tested to ensure heat transfer capabilities. The programn ensures (a) removal, of accumulations of biofouling agents, corrosion products, and silt, and (b) detection of defective protective coatings and corroded OCCW system piping and components that could adversely affect performance of their intended safety functions.

4. Detection of Aging Effects: Inspections for biofouling, damaged-coatings, and degraded material condition are conducted. Visual inspections are typically performed; however, nondestructive testing, such as ultrasonic testing, eddy current testing, and heat transfer NUREG-1801, Rev. 1 Al M-72 September 2005

capability testing, are effective methods to measure surface condition and. theextent of wall thinning associated with the service water system piping and components, when determined necessary.

5. Monitoringand Trending: Inspection scope, method (e.g., visual or nondestructive examination [NDE]), and testing frequencies are in accordance with the utility commitments.under NRCGL 89-13. Testing and inspections are done annually and during refueling outages. Inspections or nondestructive testingwill determine the extent of biofouling, the condition of the surface coating, the magnitude of localized pitting, and the amount of MIC, if applicable. Heat transfer testing results ate documented in plant test procedures and are trended.and reviewed by the appropriate group.
6. Acceptance Criteria:Biofouling is removed or reduced.as part of the surveillance and control process. The program for managing biofouling and aggressive cooling water environments for OCCW systems is preventive. Acceptance criteria are based on effective cleaning of biological fouling organisms and maintenance of protective coatings or linings are emphasized.
7. CorrectiveActions: Evaluations are performed fortest or inspection results that do not satisfy established acceptance criteria and a problem.or condition report is initiated to document the concern in accordance with plant administrative procedures. The corrective actions program ensures that the conditions adverse to quality are promptly corrected. If the deficiency is assessed to be significantly adverse to quality, the cause of the.condition is determined, and an action plan is developed -to preclude repetition. As discussed in the appendix to this report, the stafffinds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the corrective actions.
8. ConfirmationProcess:Site quality assurance (QA) procedures, review and approval processes, and administrative controls are implemented in-accordance with the requirements of 10 CFR Part 50; Appendix B. As discussed in the appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation process and administrative controls..
9. Administrative Controls: See Item 8, above.
10. OperatingExperience: Significant microbiologically-influenced corrosion (NRC Information Notice [IN] 85-30), failure of protective coatings (NRC IN 85-24), arid. fouling (NRC IN 81-21, IN 86-96) have been observed in a numberof heat exchangers. The guidance of NRC GL 89-13 has been implemented.for approximately 10 years and has been effective in managing aging effects due to biofouling, corrosion, erosion-, protective coating failures, and silting in structures and components serviced by OCCW systems.

References 10 CFR Part 50, Appendix B, QualityAssurance Criteriafor NuclearPowerPlants, Office of the Federal Register, National Archives and Records Administration, 2005.

NRC Generic Letter 89-13, Service Water System ProblemsAffecting Safety-Related Components, U.S. Nuclear Regulatory Commission, July 18, 1989.

September 2005 XI M-73 NUREG-1801, Rev. 1

NRC Generic'Letter 89-13, Supplement 1, Service Water System Problems Affecting Safety-Related Components, U.S. Nuclear Regulatory Commission, April 4, 1990.

NRC Information Notice 81-21, PotentialLoss of DirectAccess to Ultimate Heat Sink, U.S. Nuclear Regulatory Commission, July 21,1981.

NRC Information Notice 85-24, Failuresof Protective Coatingsin Pipes and Heat Exchangers, U.S: Nuclear Regulatory Commission, March 26, 1985.

NRC Information Notice 85-30, MicrobiologicallyInduced Corrosionof ContainmentService Water System, U.S. Nuclear Regulatory Commission, April 19, 1985.

NRC Information Notice 86-96, Heat ExchangerFouling Can Cause Inadequate Operabilityof Service Water Systems, U.S. Nuclear Regulatory Commission, November 20, 1986.

,NUREG-1801, Rev. 1 AI M-74 Septernber 2005

XI.M21 CLOSED-CYCLE COOLING WATER SYSTEM Program Description The program includes (a) preventive measures to minimize corrosion and stress corrosion.

cracking (SCC) and (b) testing and inspection to monitor the effects of corrosion and SCC on.

the intended function of.the component. The program relies on maintenance of system corrosion inhibitor concentrations within the specified limits. of Electric Power Research Institute

,(EPRI) TR-1 07396 to minimize corrosion and.SCC. Non-chemistry monitoringtechniques such as testing and inspection in accordance with guidance in EPRI TR-107396 for closed-cycle cooling water (CCCw) systems provide one acceptable method to evaluate system and component performance. These measures will ensure that the intended functions of the CCCW system and-components serviced by the .CC0W system are not compromised byaging.

Evaluation and Technical Basis

1. Scope of Program:A CCCW system is defined as part of the service water system that is not subject to significant sources of contamination, in which water chemistry is controlled and in which heat is not directly rejected to a heat sink. The program described in this section applies only to such a system. If one or more of these conditions are not satisfied, the system is to be considered an open-cycle cooling water-system. The staff notes that ifthe adequacy of cooling water chemistry control cannot be confirrned,-the system is treated as an open-cycle system as indicated in Action III of Generic Letter (GL) 89-13.
2. Preventive Actions: The program relies on the use of appropriate materials, lining, or coating to protect-the underlying metal surfaces and maintain system corrosion inhibitor concentrations within the specified limits of EPRI TR*-107396 to minimize corrosion and SCC. The program includes monitoring and control of cooling water chemistry to minimize exposure'to aggressive environments and application of corrosion inhibitor in the CCCW system to mitigate general, crevice, and pitting corrosion as well as SCC;
3. ParametersMonitored/Inspected:The aging management program monitors the effects of corrosion and SCC by testing and inspection in-accordance with guidance inEPRI TR-107396 to evaluate system and component condition. For pumps, the parameters

-monitored include flow, discharge pressures, and suction pressures. For heat exchangers,

'the parameters monitored include flow, inlet and outlet temperatures, and differential pressure.

4. Detection of Aging Effects: Control of water chemistry does not preclude corrosion or SCC at locations of stagnant flow conditions-or crevices. Degradation of a component due to corrosion or SCC would result in degradation of system or component performance.

. The extent and schedule of inspections and testing should assure detection of corrosion or SCC before the loss of the intended function of the component. Performance and functional testing ensures acceptable functioning of the CCCW system or components serviced by the CCCW system. For systems and components in continuous operation, performance adequacy should be verified by monitoring component performance -through data trends for evaluation of heat transfer capability, system branch flow changes and chemistry data trends.. Components not normally in operation are periodically tested to ensure operability. .

September 2005 X1 M-7 5 NUREG-1 801, Rev. 1

5. Monitoringand Trending:.Thefrequency of sampling water chemistry varies and can occur on a continuous, daily, weekly, or as needed basis, as indicated by plant operating conditions and the type of chemical treatment. In accordance with EPRI TR-1 07396, internal visual inspections and performance/functional tests are to be performed periodically to demonstrate system operability and confirm the effectiveness of the-program. Tests to evaluate heat removal capability of the system and degradation of system components may also be used. The testing intervals should be established based on plant-specific considerations such as system conditions, trending, and past operating experience, and may be adjusted based on the results of a reliability analysis, type of service, frequency of operation, or age .of components and systems.
6. Acceptance Criteria:Corrosion inhibitor concentrations are maintained within the limits specified in the EPRI water chemistry guidelines for CCCW. System and component performance test results are evaluated in accordance with system and component design basis requirements. Acceptance criteria and tolerances are to be based on system design parameters and functions.
7. Corrective Actions: Corrosion inhibitor concentrations outside the allowable limits are returned to the acceptable range within the time period specified in the EPRI water chemistry guidelines for.CCCW. If the system or component fails to perform adequately, corrective actions are taken. As discussed in the appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the corrective actions.
  • 8. ConfirmationProcess:Site quality assurance (QA) procedures, review and approval processes, and administrative controls are implemented in accordance with the requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix'to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation process and administrative controls.
9. Administrative Controls: See Item 8, above.
10. OperatingExperience: Degradation of closed-cycle cooling water systems due to corrosion product buildup (NRC Licensee Event Report [LER] 50-327/93-029-00) or through-wall cracks in supply lines (NRC 50-280/91-019r00) has been observed in operating plants. Accordingly, operating experience demonstrates the need for this program.

References 10 CFR Part 50, Appendix B, QualityAssurance Criteriafor Nuclear PowerPlants, Office of the Federal Register, National Archives and Records Administration, 2005.

EPRI TR-107396, Closed Cooling Water ChemistryGuidelines, Electric Power Research Institute, Palo. Alto, CA, October 1997.

NRC Generic Letter 89-13, Service Water System Problems Affecting Safety-Related Components, U.S. Nuclear Regulatory Commission, July 18, 1989.

NRC Generic Letter 89-13, Supplement 1, Service Water System Problems Affecting Safety-Related Components, U.S. Nuclear Regulatory Commission, April 4,1990.

NUREG-1801, Rev. 1 X1 M-76 September 2005

NRC Licensee Event Report LER 50-280/91-019-00, Loss of ContainmentIntegrity due to Crack in Component Cooling Water Piping,October 26, 1991.

NRC Licensee-Event Report LER 50-327/93-029-00, Inoperable.Check Valve in the Component Cooling System asa Result of a Build-Up of Corrosion Productsbetween Valve Components, December 13, 1993.

September 2005 XI M-77 NUREG-1801, Rev. i

XI.M22 BORAFLEX MONITORING Program Description A Boraflex monitoring program for the actual Boraflex panels is implemented in the spent fuel racks to assure that no unexpected degradation- of the Boraflex material would compromise the criticality analysis in-support of the design of spent fuel storage racks. The applicable aging management program (AMP), based on manufacturer's recommendations,- relies on periodic inspection, testing, monitoring, and analysis of the criticality design to assure that the required 5% subcriticality margin is maintained. The frequency of the inspection and testing depends on the condition of the Boraflex, with a maximum of five years. Certain accelerated samples are tested every two years. Results based on test coupons have been found to be unreliable in determining the degree to which the actual Boraflex panels have been degraded. Therefore, this AMP includes: (1) performing neutron attenuation testing, called blackness testing, to determine gap spentformation fuel pool inwater Boraflex and panels; (2) Completing sampling and analysis for silica levels in the trending the results by using the EPRI RACKLIFE predictive code or its equivalent on a monthly, quarterly, or annual basis (depending on Boraflex panel condition);

and (3) measuring boron areal density by techniques such as the BADGER device. Corrective actions are initiated if the test results find that the 5% subcriticality margin cannot be maintained because of current or projected future Boraflex degradation.

Evaluation-and Technical Basis

1. Scope of Progran:The AMP manages the effects of aging on sheets of neutron-absorbing materials affixed to spent fuel racks. For Boraflex panels, gamma irradiation and long-term exposure to the wet-pool environment cause shrinkage resulting in gap formation, gradual degradation of the polymer matrix, and the release of silica to the spent fuel storage pool Water. This results in the loss of boron carbide in the neutron absorber

,sheets..

2. PreventiveActions: For Boraflex panels, monitoring silica levels in the storage pool water, measuring gap formation by blackness testing, periodically measuring boron areal density, and applying predictive. codes, are performed. These actions ensure that degradation of the. neutron-absorbing material is identified andcorrected so the spent fuel storage racks will.be capable of performing their intended functions during the period of extended operation, consistent with current licensing basis (CLB) design conditions.
3. ParametersMonitored/Inspected:The parameters monitored include physical conditions of the Boraflex panels, such as gap formation and decreased boron areal

.density, and the concentration of the silica in the spent fuel pool. These-are conditions directly related to degradation of the Boraflex material.. When Boraflex is subjected to gamma radiation and long-term exposure to the spent fuel pool environment, the silicon polymer matrix becomes degraded and silica filler and boron carbide are released into the spent fuel pool water. As indicated in the Nuclear Regulatory Commission (NRC)

Information Notice (IN) 95-38 and NRC Generic Letter (GL) 96-04, the loss of boron carbide (washout) from Boraflex is characterized by slow dissolution of silica from the surface of the Boraflex and a gradual thinning of the material. Because Boraflex contains about 25% silica, 25% polydimethyl siloxane polymer, and 50% boron carbide, sampling and analysis of the presence of silica in the spent fuel pool provide an indication of depletion of boron carbide from Boraflex; however, the degree to which Boraflex has degraded is ascertained through measurement of the boron areal density.

NUREG-1801, Rev. 1 XI M-78 September 2005

4. Detection of Aging Effects: The amount of boron carbide released from the Boraflex panel is determined through direct measurement of boron areal density and correlated with the levels of silica present with a predictive code. This is supplemented with detection of gaps through blackness testing and periodic verification of boron loss through areal density measurement techniques such as the BADGER device.
5. Monitoring and Trending: The periodic inspection measurements and analysis are to be compared- to values of previous measurements and analysis to provide a continuing level of data for trend analysis.
6. Acceptance Criteria:The 5% subcriticality margin of the spent fuel racks is to be maintained for the. period of extended operation.
7. CorrectiveActions: Corrective actions are initiated if the test results find that the 5%

subcriticality margin cannotbe maintained because of the current or projected future degradation. Corrective actions .consist of providing additional neutron-absorbing capacity by Boral orboron steel inserts, or other optionsi which are available to maintain a subcriticality margin of 5%. As discussed in the appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the corrective actions.

8. Confirmation Process:Site quality assurance (QA) procedures, site review and approval processes, and administrative controls are implemented in accordance with the requirements of 10 CFR Part 50, Appendix B: As discussed in the appendixto this report, the staff finds the requirements of 10 CFR.Part 50, Appendix. B, acceptable to address the Confirmation process and administrative controls.
9. Administrative Controls: See item 8, above.
10. OperatingExperience: The NRC IN 87-43 addresses the problems of development of
  • tears and gaps (average 1-2 in., with.the largest 4 in.) in Boraflex sheets due to gamma radiation-induced shrinkage of the material. NRC INs 93-70 and 95-38 and NRC GL 96-04 address several cases of significant degradation of Boraflex.test coupons due to accelerated dissolution of Boraflex caused by pool water flow through panel enclosures and high accumulated gamma dose. Two spent.fuel rack cells with about 12 years of service have only 40% of the Boraflex remaining. In such cases, the Boraflex may be replaced by boron steel inserts or by a completely new rack system using Boral.

Experience with boron steel is limited; however, the application of Boral for use in the.

spent fuel storage racks predates the manufacturing and use of Boraflexl The experience with Boraflex panels indicates that coupon surveillance programs are not reliable.

Therefore, during the period of extended operation, the measurement of boron areal density correlated, through a predictive code, with silica levels in the pool wateris verified.

These monitoring programs provide assurance that degradation of Boraflex sheets is monitored, so that appropriate actions can be taken in a timely manner if significant loss of neutron-absorbing capability is occurring. These monitoring programs ensure that the Boraflex sheets will maintain their integrity and will be effective in performing its intended function.

September 2005 . X1 M-79 NUREG-1801, Rev. 1

References 10 CFR Part 50, Appendix B, QualityAssurance Criteriafor NuclearPower Plants, Office of the Federal Register, National Archives and Records Administration, 2005.

BNL-NU REG-25582, Corrosion Considerationsin the Use of Boralin Spent Fuel Storage Pool Racks, January 1979.

EPRI NP-6159, An Assessment of Boraflex Performancein Spent-Nuclear-FuelStorage Racks, Electric Power Research Institute, Palo Alto, CA, December 14, 1988:

EPRI TR-101986, Boraflex Test Results and Evaluation, Electric Power Research Institute, Palo Alto, CA, March 1, 1993.

EPRI TR-103300, Guidelines for Boraflex Use in Spent-Fuel Storage Racks, Electric Power Research Institute, Palo-Alto, CA, December 1, 1993.

NRC Generic Letter 96-04, Boraflex Degradationin Spent Fuel Pool Storage Racks, U.S..Nuclear Regulatory Commission, June 26, 1996.

NRC Information Notice 87-43, Gaps in Neutron Absorbing Material in High Density Spent Fuel Storage Racks, U.S. Nuclear Regulatory Commission, September 8,1987.

NRC Information Notice 93-70, Degradationof Boiraflex Neutron AbsorberCoupons, U.S. Nuclear Regulatory Commission, September 10, 1993.

NRC Information Notice 95-38, Degradationof Boraflex Neutron Absorberin Spent Fuel Storage Racks, U.S. Nuclear Regulatory Commission, September 8, 1995.

NRC Regulatory Guide 1.26, Rev. 3, Quality Group Classificationsand Standardsfor Water, Steam, and Radioactive-Waste-ContainingComponents of NuclearPowerPlants (for Comment), U.S. Nuclear Regulatory Commission, February 1976.

NUREG-1801, Rev. 1 X1 M-80. September 2005

XL.M23 INSPECTION OF OVERHEAD HEAVY LOAD AND UGHT LOAD.(RELATED TO REFUELING) HANDLING SYSTEMS Program Description Most commercial nuclear facilities have between 50 and 100 cranes. Many are industrial grade cranes,.which meet the requirements of 29 CFR Volume XVII, Part 1910, and Section 1910.179.

Most are not within the scope of 10 CFR 54.4, and, therefore are not required to be part of the integrated plant assessment (IPA).

Normally, fewer than 10 cranes'fall within the scope of 10 CFR 54.4.

The program demonstrates that testing and monitoring programs have been implemented and have ensured that the structures, systems, and components of these craqnes are capable of sustaining their rated loads. This is their intended function during the period of extended-operation. It is noted that many of the systems and components of these cranes perform an intended function with moving. parts or with a change in configuration, or subject to replacement based on qualified life. In these instances, these types of crane systems and components are not within the scope of this aging management program (AMP). This program is primarily concerned with structural components that make up the bridge and trolley. NUREG-0612, "Control of Heavy Loads at Nuclear Power Plants," provides specific guidance on the control of.

overhead heavy load cranes.

Evaluation and Technical Basis

1. Scope of Program:The.program manages the effects of general corrosion on the crane and trolley structural components for those cranes that are within the scope of 10 CFR 54.4, and the effects of wear on the rails in thle rail system.
2. Preventive Actions: No preventive actions are identified. The crane, program is an inspection program.
3. ParametersMonitored/Inspected:The program evaluates the effectiveness of the maintenance monitoring program and the effects of past and future usage on the structural reliability of cranes.
4. Detection of Aging Effect: Crane rails and -structural components are visually inspected on a routine basis for degradation.
5. Monitoring and Trending: Monitoring and trending are not required as part of the crane inspection program.
6. Acceptance Criteria:Any significant visual. indication of loss of material due to corrosion or wear is evaluated according to applicable industry standards and good industry practice. The crane may also have been designed to a specific Service Class as defined in the Crane Manufacturers Association of America, Inc. (CMAA) Specification #70 (or later revisions), or CMAA Specification #74 (or later revisions). The specification that was applicable at the time the crane was manufactured is used.

September 2005 XI M-81 NUREG-1801, Rev. 1

7. CorrectiveActions: Site corrective actions program, quality assurance (QA) procedures, site review and approval process, andadministrative controls are implemented in accordance with the requirements of 10 CFR Prt 50, Appendix B. As discussed in the appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the corrective actions, confirmation process, and administrative controls.
8. Confirmation Process:See Item 7, above.
9. Administrative Controls:See Item 7,. above.
10. OperatingExperience -There has been no history of corrosion-related degradation that has impaired cranes. Likewise, because cranes have not been operated beyond their design lifetime, there have been no significant fatigue-related structural failures.

References 10 CFR Part 50,,Appendix B, Quality Assurance.Criteriafor Nuclear PowerPlants, Office of the Federal Register, National Archives and Records Administration, 2005.

Crane Manufactures Association of Amenca,.Inc., CMAA Specification No. 70, Specificationsfor Electric Overhead Traveling Cranes, 1970 (or later revisions)

Crane Manufactures Association of America, Inc., CMAA Specification No. 74, Specificationsfor Top Running and Under Running Single GirderElectric Overhead Traveling Cranes, 1974 (orlaterrevisions)

Electric Overhead Crane Institute, Inc NUREG-0612, Controlof Heavy Loads at NuclearPower Plants, U.S. Nuclear Regulatory Commission, 1980.

NRC Regulatory Guide 1.160, Rev. 2, Monitoringthe Effectiveness of Maintenance at Nuclear PowerPlants, U.S. Nuclear Regulatory. Commission, March 1997.

NUREG-1801, Rev. 1 X1 M-82 September 2005

XI.M24 COMPRESSED-AIR MONITORING Program Description The program consists of inspection, monitoring, and testing of the entire system.*This includes (a) frequent leak testing of valves, piping, and other system components, especially those made of carbon steel and stainless *steel; and (b) preventive monitoring that checks air quality at various locations in the system to ensure that oil, wvater, rust, dirt, and other Contaminants are kept within thespecified limits. The aging management program (AMP) provides for timely corrective actions to ensure that the system is operating within specified limits.

The AMP is based on results of the plant owner's response to Nuclear Regulatory Commission (NRC) Generic Letter (GL) 88-14, augmented by previous NRC Information Notices (IN) 8 1-38, IN 87-28, and IN 87-28 S1, and by the Institute of Nuclear Power Operations Significant..

Operating Experience Report (INPO SOER) 88701. The NRC GL 88-14, issued after several

'years of study of problems and failures of instrument air systems, recommends each holderof an operating license' to perform an extensive design and operations review and verification of its instrument air system. The'GL 88-14 also recommends.the licensees to describe their program for maintaining proper instrument air quality. The AMP also incorporates provisions conforming to the guidance of the Electric Power Research Institute (EPRI) NP-7079, issued in 1990, to assist utilities in identifying and correcting system problems in the instrument air system and to enable them to maintain required industry safety standards. Subsequent to these initial actions by all plant licensees to implement an improved AMP, some utilities decided to replace their instrument air system with newer models and types of components. The EPRI then issued TR-1 08147, which addresses maintenance of the latest compressors and other instrument air system components currently in use at those plants. The American Society of Mechanical Engineers operations and maintenan ce standards and guides (ASME OMS/G-1998, Part 17) provides additional guidance to the 'maintenance, of the instrument air system by offering recommended test methods, test intervals, parameters to be measured and evaluated, acceptance criteria, corrective actions, and'records requirements.

Evaluation and Technical Basis

1. Scope of Program:The program manages the effects of corrosion and the presence of unacceptable levels of contaminants on the intended function of the compressed air system. The AMP includes frequent leak testing of valves, piping, and other system components, especially those made of carbon steel and stainless steel, and a preventive maintenance program to check air quality at several locations in the system.
2. PreventiveActions: The system air quality is monitored and maintained in accordance with the plant owner's testing and inspection plans, which are designed to ensure that the.

system and components meet specified operability requirements. These requirements are

.prepared from consideration of manufacturer's recommendations for individual components and guidelines.based on ASME OM-SIG-1998,. Part 17; ISA-S70.01-1996;

  • EPRI NP-7079; and EPRI TR-108147. The preventive maintenance program addresses various aspects of the inoperability of ai'r-operated'components due to corrosion and the' presence of oil, water, rust, and other contaminants.
3. ParametersMonitored/Inspected:Inservice inspection (IS1) and testing is performed to verify proper air quality and confirm that maintenance practices, emergency procedures, September 2005 X1 M-63 NUREG-1801, Rev. 1

and training are adequate to ensure that the intended function of the. air system is maintained.

4. Detection of Aging Effects: Guidelines in EPRI NP-7079, EPRI TR-108147, and ASME OM-S/G-1998, Part 17, ensure timely detection of degradation of the compressed air system function. Degradation of the piping and any components would become evident by observation of excessive corrosion, by the discovery of unacceptable leakage rates, and by failure. of the system or any item of components to meet specified performance limits.

. 5. Monitoring and Trending: Effects of corrosion and the presence of contaminants are monitored by visual inspection and periodic system and componenttests, including leak rate tests on the system and on individual items of components. These tests verify proper operation by comparing measured values of performance with specified performance limits. Test data are analyzed and compared to data from previous tests to provide for timely detection of aging effects.

6. Acceptance Criteria:Acceptance criteria are established for the system and for.

individual components that contain specific limits or acceptance ranges based on design basis conditions and/or components vendor specifications. The testing results are analyzed to Verify that the design and performance of the system is in accordance with its intended function.

7. CorrectiveActions: Corrective actions are taken if any parameters are out of acceptable ranges, such as moisturecontent in the system air. As discussed in the appendix to this-report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the corrective actions.
8. Confirmation Process:The site corrective actions program, quality assurance (QA) procedures, site review and approval process, and administrative controls are:,

implemented in accordancewith the requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, the staff finds the requirements of 10 CFR Part.

50, Appendix B, acceptable to address the confirmation process and administrative controls.

9. Administrative.Controls: See Item 8, above.
10. OperatingExperience: Potentially significant safety-related problems pertaining to air systems have been documented in NRC IN 81-38, IN 87-28, IN.87-28 S1 and license event report (LER).50-237/94-005-3. Some of the systems that have been significantly degraded or have failed due to the problems in the air system include the decay heat removal, auxiliary feedwater, main steam.isolation, containment isolation, and fuel pool seal system. As a result of NRC GL 88-14 and consideration ofINPO SOER 88-01, EPRI NP-7079, and EPRI TR-1 08147, performance of air systems has improved significantly.

References 10 CFR Part 50, Appendix B, Quality Assurance Criteriafor NuclearPowerPlants, Office of the Federal Register, National Archives and Records Administration, 2005.

NUREG-1801, Rev. 1 Xl M-84 " September 2005

ASME OM-S/G-1998, Part -17, Performance Testing of InstrumentAir Systems Information Notice Light-WaterReactorPower Plants, IISA-S7.0.1-1996, "Quality Standard for Instrument Air," American Society of Mechanical Engineers, New York, NY, 1998.

EPRI NP-7079, InstrumentAir System: A Guide for Power PlantMaintenance Personnel, Electric Power Research Institute, Palo Alto, CA, December 1990.

EPRI/NMAC TR-1 08147, Compressorand Instrument Air System Maintenance Guide: Revision to NP-7079, Electric Power Research Institute, Palo Alto, CA., March 1998.

INPO SOER 88-01, InstrumentAir System Failures,May 18,1988.

N RC Generic Letter 88-14, InstrumentAir Supply ProblemsAffecting Safety-Related Components, U.S. Nuclear Regulatory Commission, August 8, 1988..

NRC Information Notice 81-38, PotentiallySignificant Components FailuresResulting from Contaminationof Air-Operated Systems, U.S. Nuclear Regulatory Commission, December-17, 1981.

NRC Information Notice 87-28, Air Systems Problems at U.S. Light Water Reactors, U.S. Nuclear Regulatory Commission, June 22, 1987.

NRC Information Notice 87-28, Supplement 1, Air Systems Problems at U.S. Light Water Reactors, U.S. Nuclear Regulatory Commission, December 28, 1987.

NRC Licensee Event Report LER 50-237/94-005-3, Manual Reactor Scram due to Loss of InstrumentAir Resulting from Air Receiver Pipe Failure Causedby ImproperInstallation of Threaded Pipe during Initial Construction,U.S. Nuclear Regulatory Commission, April 23, 1997.

Sepýernber 2005 XI M-85 NUREG-1801, Rev. 1

XI.M25 BWR REACTOR WATER CLEAN UP SYSTEM Program Description The program includes inservice inspection (ISl) and monitoring and control of reactor coolant water chemistry to manage the effects of stress corrosion cracking (SCC) or intergranular stress corrosion cracking (IGSCC) on the intended function of austenitic stainless steel (SS) piping in the reactor water cleanup (RWCU) system. Based on the Nuclear Regulatory Commission (NRC) criteria related to inspection guidelines for RWCU piping welds outboard of the second isolation valve, the program includes the measures delineated in NUREG-0313, Rev. 2, and NRC Generic Letter (GL) 88-01. Coolant water chemistry is monitored and maintained in accordance with the Electric Power Research Institute (EPRI) guidelines in boiling water reactor vessel and internals project (BWRVIP) -29(TRr1 03515) to minimize the potential of cracking due to SCC or IGSCC.

Evaluation and Technical Basis

1. Scope of Program:Based on the NRC letter (September 15, 1995) on the screening criteria related to inspection guidelines for RWCU piping welds outboard of the second isolation valve, the program includes the measures delineated in NUREG-0313, Rev. 2, and NRC GL 88-01 to monitor SCC or IGSCC and its effects on the intended function of.

austenitic SS piping. The screening criteria include:

a. Satisfactory completion of all actions requested in NRC GL 89-10,
b. No detection of IGSCC in RWCU welds inboard of the second isolation valves (ongoing inspection in accordance with the guidance in NRC GL 88-01), and
c. No detection of IGSCC in RWCU welds outboard of the second isolation valves after inspecting a minimum of 10% of the susceptible piping.

No IGSCC inspection is recommended for plants that meet all the above three criteria or that meet criterion (a) and piping is made of material that is resistant to IGSCC.

2. Preventive Actions: The comprehensive program outlined in NUREG-0313 and NRC GL 88-01 addresses improvements in all three elements that, in combination, cause SCC or IGSCC. These elements are a susceptible (sensitized) material, a significant tensile stress, and an aggressive environment. The program delineated in NUREG-0313 and NRC GL 88-01 includes recommendations regarding selection of materials that are resistant to sensitization, use of,special processes that reduce residual tensile stresses, and monitoring.and maintenance of coolant chemistry. The resistant materials are used for new and replacement components and include low-carbon grades of austenitic SS and weld metal, with a maximum carbon of 0.035 wt.% and a minimum ferrite of 7.5% in weld metal and cast austenitic stainless steel (CASS). Inconel 82 is the only commonly used nickel-base weld metal considered resistant to sCC; other nickel-alloys, such as Alloy 600, are evaluated on an individual basis. Special processes are used for existing as well as new and replacement components. These processes include solution heat treatment, heat sink welding, induction heating, and mechanical stress improvement.

The program delineated in NUREG-0313 and NRC GL 88-01. varies depending on the plant- specific reactor water chemistry to mitigate SCC or IGSCC.

NUREG-1801, Rev. I AI M-86 September 2005

.3. ParametersMonitored/Inspected:The aging management program (AMP) monitors SCC or IGSCC of austenitic SS piping by detection and sizing of cracks. by implementing the inspection guidelines delineated in the NRC screening criteria for the RWCU piping outboard of isolation valves. The following schedules are followed:

Schedule A: No inspection is required for plantsthat meet all three criteria set forth above, or if they meet only criterion (a). Piping is made of material that is resistant to IGSCC, as described above in preventive actions.-

Schedule B: For plants that meet only criterion (a): Inspect at least 2% of the welds or two welds every refueling outage, whichever sample is larger.

Schedule C: For plants that donot meet criterion (a): Inspect at least 10% of the welds every refueling outage.

4. Detection of Aging Effects: The extent, method, and schedule of the inspection and test techniques delineated in the NRC inspection criteria for RWCU piping and NRC GL 88-01 are designed to maintain structural integrity and to detect aging effects before the loss of intended function of austenitic SS. piping and fittings. Guidelines for the inspection schedule, methods, personnel, sample expansion, and leak detection guidelines are based on theguidelines of NRC GL 88-01.

NRC GL 88-01' recommends that the detailed inspection procedure, components, and

-examination personnel bequalified by a formal program approved by the NRC. Inspection.

can reveal cracking and leakage. of coolant. The extent and frequency of inspections recommended by the -program are based on the condition of each weld (e.g., whether the weldments were made from IGSCC-resistant material, whether a stress improvement process was applied to a weldment to reduce the residual stresses, and how the weld was repaired if it had been cracked).

5. Monitoring and Trending: The extent and schedule for inspection in accordance with the recommendations of NRC GL 88-01 provide timely detection of cracks and leakage of coolant. Based on inspection results, NRC GL 88-0.1 provides guidelines for additional.

samples of weldsto be inspected when one or more cracked welds are found.in a weld category.

6. Acceptance Criteria:The NRC GL 88-01 recommends that any indication detected be evaluated in accordance with the requirements of ASME Section XI, Subsection IWB-
  • 3640 (2001 edition" includingthe 2002 and 2003 Addenda).
7. CorrectiveActions: The guidance for weld overlay repair, stress improvement, or replacementis provided in NRC GL 88-01. As discussed in the appendix to this report, the

. staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the corrective actions.

8. ConfirmationProcess: Site quality assurance (QA) procedures, review and approval processes, and administrative controlslare implemented in accordance with requirements 8

An applicant may rely on a different version of the ASME Code, but should justify such use. An applicant may wish to refer to the SOC for an update of 10 CFR § 50.55a to justify use of a more recent edition of the Code.

September 2005 XI M-87. NUREG-1801, Rev. 1

of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the confirmation process and administrative controls.

9. Administrative Controls: See Item 8, above-
10. OperatingExperience: The IGSCC has occurred in small- and large-diameter boiling water reactor (BWR) piping made of austenitic stainless steels or nickel alloys. The comprehensive program outlined in NRC GL 88-01 and NUREG-031 3 addresses improvements in allelements that cause SCC or IGSCC (e.g., susceptible, material, significant tensile stress, and an aggressive environment) and is effective in managing IGSCC in austenitic SS piping in the RWCU system.

References 10 CFR Part 50, Appendix B, QualityAssurance Criteriafor NuclearPowerPlants,Office of the Federal Register, National Archives and Records Administration, 2005.

ASME Section XI, Rules for Inservice Inspection of Nuclear.PowerPlant Componentsý ASME Boiler and Pressure Vessel Code, 2001 edition including the 2002 and 2003 Addenda, American Society of Mechanical Engineers, New York, NY.

BWRVIP-29 (EPRI TR-103515), BWR Vessel and InternalsProject,BWR Water Chemistry Guidelines-1993 Revision, Normal and Hydrogen Water Chemistry, Electric Power Research Institute, Palo Alto, CA, February 1994.

Letter from Joseph W. Shea, U.S. Nuclear Regulatory Commission, to George A. Hunter, Jr.,

PECO Energy Company, Reactor Water Cleanup,(RWCU) System Weld Inspections at Peach Bottom Atomic PowerStation, Units 2 and 3 (TAC Nos. M92442 and M92443),

September 15, 1995.

NRC Generic Letter 89-10, Safety-related Motor Operated Valve Testing and Surveillance, U.S.

Nuclear Regulatory Commission, June 28, 1989; through supplement 7, January.24, 1996.

NRC Generic Letter 88-01, NRC Position on IGSCC in BWR Austenitic Stainless Steel-Piping, U.S. ]Nuclear Regulatory Commission, January 25, 1988.

NUREG-0313, Rev. 2, Technical Report on MaterialSelection and ProcessingGuidelines for.

BWR Coolant PressureBoundary Piping, W. S. Hazelton and W. H. Koo, U.S. Nuclear Regulatory Commission, 1988.

NUREG-1801, Rev. 1 X1 M--88 September 2005

XI.M26 FIRE PROTECTION Program Description For operating plants, the fire protection aging management program (AMP) includes a fire barrier inspection program and a diesel-driven fire pump inspection program. The fire barrier inspection program requires periodic visual inspectionof fire barrier penetration seals, fire barrier walls, ceilings, and floors, and periodic visual inspection-and functional tests of fire rated doors to ensure that their operability is maintained The -diesel-driven fire pump inspection program requires that the pump be periodically tested to ensure that the fuel supply line can perform the intended function. The AMP also includes periodic inspection and testing of the halon/carbon dioxide (CO 2) fire suppression system.

Evaluation and Technical Basis

1. Scope of Program:For operating plants, the AMP manages the aging effects on the intended function of the penetration seals, fire barrier walls, ceilings, and floors, and all fire rated doors (automatic or manual) that perform a fire barrier function. It also manages the aging effects on the intended function of the fuel supply line. The AMP also includes management of the aging effects on the intended function of the halon/C0 2 fire*

suppression system.

-2. Preventive Actions: For operating plants, the fire hazard analysis assesses the fire potential and fire hazard in all plant areas. It also specifies measures for fire prevention, fire detection, fire suppression, and fire containment and alternative shutdown capability.

for each fire area containing structures, systems, and components important to safety.

3. ParametersMonitoredlInspected:Visual inspection of approximately 10% of each type of penetration seal is performed during walkdowns carried out at least once every -

refueling outage. These inspections examine anysignof degradation such as cracking, seal separation from walls and components, separation of layers-of material, rupture and puncture of seals, which are directly caused by increased hardness, and shrinkage of seal material due to weathering. Visual inspection of the fire barrier walls, ceilings, and floors.

examines any sign of degradation such as cracking, spalling, and loss of material caused by freeze-thaw, chemical attack, and reaction with aggregates.. Fire-rated doors are visually inspected on a plant-specific interval-to verify the integrity of door surfaces and for clearances. The plant-specific inspection intervals are to be determined by engineering evaluation to detect degradation of the fire doors priorto the loss of intended function.

The diesel-driven fire pump is under observation during performance tests such as flow and discharge tests, sequential starting capability tests, and controller function tests for detection of any degradation of the fuel supply line.

The periodic visual inspection and function test is performed at least once every six months to examine, the signs, of degradation of the halon/C0 2 fire suppression system.

Material conditions that may affect the performance of the system, such as corrosion, mechanical damage, or damage to dampers, are observed during these tests.

4. Detection of Aging Effects: Visual inspection of penetration seals detects cracking, seal separation from walls and components; and rupture and puncture of seals. Visual inspection by fire protection qualified inspectors of approximately 10% of each type of seal September 2005 X1 M-89 NUREG-1801, Rev. 1

in Walkdowns. is performed at least once every refueling cycle. If any sign of degradation is detected within that sample, the scope of the inspection is expanded to include additional seals: Visual inspection by fire protection qualified inspectors of the fire barrier walls, ceilings, and floors, performed in walkdowns atleast once every, refueling outage ensures timely detection ofconcrete cracking, spalling, and loss of material. Visual inspection by fire protection qualified inspectors detects any sign of degradation of the fire door such as wear and missing parts. Periodic visual inspection and function tests detect degradation -of the fire doors before there is a loss of intended function.

Periodic tests performed at least once every refueling outage, such as flow and discharge tests, sequential starting capability tests, and controller function tests performed on diesel-driven fire pump ensure fuel supply line performance. The.performance tests detect degradation of the fuel supply lines before the loss of the component intended function.

Visual inspections of the halon/CO 2 fire suppression system detect any sign of added degradation, such as corrosion, mechanical damage, or damage to dampers. The periodic function test and inspection performed at least once every six months detects degradation of the halon/CO 2 fire suppression system before the loss of the component intended function.

5. Monitoring andTrending:The aging effects of weathering on fire barrier penetration sealsare detectable by visual inspection and, based on operating experience, visual inspections are performed at least once every refueling outage to detect any sign of degradation of fire barrier penetration seals prior to loss, of the intended function.

Concrete cracking, spalling, and loss of material are detectable by visual inspection and, based on operating experience, visual inspection performed at least once every refueling outage detects any sign of degradation of the fire barrier walls, ceilings, and floors before there is a loss of the.intended function. Based on operating experience, degraded integrity.

orclearances in the fire door are detectable by visual inspection performed on a plant-specific frequency. The visual inspections. detect degradation of the fire doors prior to loss of the intended function.

The performance of the fire pump is monitored during the periodic test to detect any degradation in the fuel supply lines. Periodic testing provides data (e.g., pressure) for trending necessary.

The performance of the halon/C0 2 fire suppression system is monitored during the periodic test to detect any degradation in the system. These periodic tests provide data necessary for trending.

6. Acceptance Criteria:Inspection results are acceptable if there are no visual indications (outside those allowed by approved penetration seal configurations) of cracking, separation of sealsfrom Walls and components, separation of layers of material, or ruptures or punctures of seals; no visual indications of concrete cracking, spalling and loss of material of fire barrier walls, ceilings, and floors; no visual indications of missing parts, holes, and wear and .no deficiencies in the. functional tests of fire doors. No corrosion is acceptable in the fuel supply line for the diesel-driven fire pump. Also, any signs of corrosion and mechanical damage of the halon/CO 2 fire suppression system are not acceptable.

NUREG-1801, Rev. 1 XI M-90 September 2005

7. CorrectiveActions: For fire protection structures and components identified within scope*

that are subject to an AMR for license renewal, theapplicant's 10 CFR Part 50, Appendix B, program is used for corrective actions, confirmation. process, and administrative controls for aging management during theperiod of extended operation. This commitment is documented in the final safety analysis report (FSAR) supplement in accordance with 10 CFR 54.21(d). As discussed in the appendix to this report, the staff finds the requirements of 10 CFR Part 50, Appendix B, acceptable to address the corrective actions ' confirmation process, and administrative controls.

8. Confirmation Process:See Item 7, above.
9. Administrative Controls:See Item 7, above.
10. OperatingExperience: Silicone foam fire barrier penetration seals have experienced splits, shrinkage, voids, lack of fill, and other failure modes(IN 88-56, IN 94-28, and IN 97-70). Degradation of electrical racing way fire barrier such as small holes, cracking, and unfilled seals are found on routine walkdown (IN.91-47 and GL 92-08). Fire doors have.

experienced wear of the hinges and handles.

References 10 CFR Part 50, Appendix B, Qual#y Assurance Criteriafor NuclearPower Plants, Office of the Federal Register, National Archives and Records Administration, 2005.

NRC Generic Letter 92-08, Thermo-Lag 330-1 Fire Barrier,U.S. Nuclear Regulatory Commission, December 17, 1992.

NRC Information Notice 88-56, PotentialProblems with Silicone Foam Fire Barrier.Penetration Seals, U.S. Nuclear Regulatory Commission, August 14, 1988.

NRC Information Notice 91-47, Failureof Thermo-Lag Fire BarrierMaterialto PassFire Endurance Test, U.S. Nuclear Regulatory Commission, August 6, 1991.

NRC Information Notice 94-28, Potentialproblems with Fire-BarrierPenetrationSeals, U.S.

Nuclear Regulatory Commission, April 5, 1994.

NRC Information Notice 97-70, Potentialproblems with FireBarrierPenetrationSeals, U.S.

Nuclear Regulatory Commission, September 19, 1997.

.September 2005 AI M-91 NUREG-1801, Rev. 1

Xl. M27 FIRE WATER SYSTEM Program Description This aging management program (AMP) applies to water-based fire protection systems that consist of sprinklers, nozzles, fittings, valves, hydrants, hose stations, standpipes, water storage tanks, and aboveground and underground piping and components that are tested in accordance with the applicable National Fire Protection Association (NFPA) codes and standards. Such testing assures the minimum functionality of the systems. Also, these systems are normally maintained at required operating pressure and monitored such that loss of system pressure is immediately detected and corrective actions initiated.

A sample of sprinkler heads- is to be inspected by using the guidance of NFPA 25 "Inspection, Testing and Maintenance of Water-Based Fire Protection Systems" (1998 Edition), Section 2-3.1.1, or NFPA2.5 (2002 Edition), Section 5.3.1.1.1. This NFPA.section states "where sprinklers have been in place.for 50 years, they shall be replaced or representative samples-from one or more sample areas shallbe submitted to a recognized testing laboratory for field service testing." It also contain's guidance to. perform this sampling every 10 years after the initial field service testing.

The fire protection system piping is to be subjected to required flow testing in accordance with guidance in NFPA 25 to verify design pressure or evaluated for wall thickness (e.g., non-intrusive volumetric testing or plant maintenance visual inspections) to ensure that aging effects are managed and that wall thickness is within acceptable limits. These inspections are performed before the end of the current operating term and at plant-specific intervals thereafter during the period of extended operation. The plant-specific inspection intervals are to be determined by engineering evaluation of the fire protection piping to ensure that degradation will be detected before the loss of intended function. The purpose of the full flow testing and wall thickness evaluations is to ensure that corrosion, MIC, or biofouling is managed such that the system function is maintained..

Evaluation and Technical Basis

1. Scope of Program:The AMP focuses on managing loss of material due to corrosion, MIC, or biofouling of carbon steel and cast-iron components in fire protection systems exposed to water. Hose stations and standpipes are considered as piping .in the AMP.
2. PreventiveActions: To ensure no significant corrosion, MIC, or biofouling has occurred in water-based fire protection systems, periodic flushing, system performance testing, and inspections may be conducted.
3. ParametersMonitored/Inspected.:Loss of material due to corrosion and biofouling could reduce wall thickness of the fire protection piping system and result in system failure.

Therefore, the. parameters monitored are the system's ability to maintain pressure and internal system corrosion conditions. Periodic flow testing of the fire water system is performed using the guidelines-of NFPA 25, or wall thickness evaluations may be performed to ensure that the system maintains its intended.function.

4. Detection of Aging Effects: Fire protection system .testing is performed to assure that the system functions by maintaining required operating pressures. Wall thickness evaluations of fire protection piping are performed on system components using non-NUREG-1801, Rev. 1 XI M-92 September 2005

intrusive techniques (e.g., volumetric testing) to identify evidence of loss of material due to corrosion. These inspections are performed before the end of the current operating term and at plant-specific intervals thereafter during the. period of extended operation. As an alternative to non-intrusive testing, the plant maintenance process may include a visual inspection of the internal surface of the fire protection piping upon each entry to the system for routine or corrective maintenance, as long as it can be demonstrated that inspections are performed (based on past maintenance history) on a representative number of locations on a reasonable basis. These inspections must be capable of evaluating (1) wall thickness to ensure against catastrophic failure and (2) the inner diameter of the piping as it applies to the design flow of the fire protection system. If the environmental and material conditions that exist on the interior surface of the below grade.

fire protection piping are similar to the conditions that exist within the above grade fire protection piping,, the results of the inspections of the above grade fire protection piping can be extrapolated to evaluate the condition of below grade fire protection. piping. If not, additional inspection activities are needed to ensure that the intended function of below grade fire protection piping will be maintained consistent with the current licensing basis for the period of extended operation. Continuous system pressure monitoring, system flow testing, and wall thickness evaluations of piping are effective means to ensure that corrosion and. biofouling are not occurring and the system's intended function is maintained.

General requirements of existing fire protection programs include testing and maintenance of fire detection and protection systems and surveillance procedures to. ensure that fire detectors, as well as fire protection systems and components are operable.

Visual inspection of yard fire hydrants performed annually in accordance with NFPA 25 ensurestimely detection of signs of degradation, such as corrosion. Fire hydrant hose hydrostatic tests, gasket inspections, and fire hydrant flow tests, performed annually, ensure that fire hydrants can perform their intended function-and provide opportunities for degradation to be detected before a loss of intendedfunction can occur.

Sprinkler heads are inspected before the.end of the 50-year sprinklerhead service life and at10-year intervals thereafter during the extended period of operation to ensure that signs of degradation, such as corrosion, are detected in a timely manner.

5. Monitoring.and Trending: System discharge pressure is monitored continuously.

Results of system performance testing are monitored and trended as specified by the associated plant commitments pertaining to NFPA codes and standards. Degradation identified by non-intrusive or internal inspection is evaluated.

S. Acceptance Criteria:The acceptance criteria are (a) the ability of a fire protection system to maintain required pressure, (b) no unacceptable signs of degradation observed during non-intrusive or visual assessment of internal system conditions, and (c) that no biofouling exists in the sprinkler systems that could cause corrosion in the sprinkler heads.

7. CorrectiveActions: Repair and replacement actions are initiated as necessary. For fire water systems and components identified within scope that are subject to an. AMR for license renewal, the applicant's 10 CFR Part 50, Appendix B, programnis used for corrective actions, confirmation process, and administrative controls for aging management during the period of extended operation. As discussed in the appendix to September 2005 X1 M-93 NUREG-1801, Rev. 1

this report, the staff finds the requirements of 10 CFR Part 50, Appendix 8, acceptable to address the corrective actions, confirmation process, and administrativecontrols.

8. Confirmation Process: See Item 7, above.
9. Administrative Controls: See Item 7, above.
10. OperatingExperience: Water-based fire protection systems designed, inspected, tested and maintained in accordance with the NFPA minimum standards have demonstrated reliable performance.

References 10 CFR Part 50, Appendix B, Qualify Assurance Criteriafor Nuclear PowerPlants*, Office of the Federal Register, National Archives and Records Administration, 2005.

NFPA 25: Inspection, Testing and Maintenance of Water-Based Fire Protection Systems, 1998 Edition.

NFPA 25: Inspection, Testing and Maintenance of Water-Based Fire Protection Systems, 2002 Edition.

NUREG-1801, Rev. 1 X1 M-94 September 2005 .

XI.M28 BURIED PIPING AND TANKS SURVEILLANCE Program Description The program includes surveillance and preventive measures to mitigate corrosion by protecting the external surface of buried carbon steel piping and tanks. Surveillance and preventive measures, are in accordance with standard industry practice, based on National Association of Corrosion Engineers (NACE) Standards RP-0285-95 and RP-0169-96, and include extemal coatings, wrappings, and cathodic protection systems.

Evaluation and Technical Basis

1. Scope of Program:The program relies on preventive measures, such as coating, wrapping, and cathodic protection, and surveillance, based on NACE Standard RP-0285-95 and NAC.E Standard RP-0169-96, to manage the effects of-corrosion on the intended function of buried tanks and piping, respectively.
2. Preventive Actions: In accordance with industry practice, underground piping and tanks are coated during installation with a protective coating system, such as coal tar enamel with a fiberglass wrap and a kraft, paper outer wrap, a polyolifin tape coating, or a fusion bonded epoxy coating to protect the piping from contacting the aggressive soil environment. A cathodic protection system is.used to mitigate corrosion where pinholes in the coating allow the piping or components to be in contact with the aggressive soil environment. The cathodic protection imposes a current from an anode onto the pipe or tank to stop corrosion from occurring at defects in the coating.
3. ParametersMonitored/inspected:The effectiveness of the coatings and cathodic protection system, per standard industry practice, is determined by measuring coating conductance, by surveying pipe-to-soil potential, and by conducting bell hole examinations to visually examine the condition of the coating.
4. Detection of Aging Effects: Coatings and wrapping can be damaged during installation or while in. service and the cathodic protection system is relied upon to avoid any corrosion at the damaged locations. Degradation of the coatings and wrapping. during service will result in the requirement for more current from the cathodic protection rectifier in order to maintain the proper cathodic protect potentials. Any increase in current requirements is an indication of coating and wrapping degradation. A close interval pipe-to-soil potential survey can be used to.locate the locations where degradation has occurred.
5. Monitoring and Trending: Monitoring the coating conductance versus time or the current requirement versus time provides an indication of the condition of the coating and cathodic protection.system when compared to predetermined values.
6. Acceptance Criteria:In accordance with accepted industry practice, per NACE Standard RP-0285-95 and NACE Standard RP-0169-96, the assessment of the condition of the coating and cathodic protection system is to be conducted on an annual basis and compared to predetermined values.

September 2005 Xl M-95 NUREG-1801, Rev. 1

7. CorrectiveActions: The site corrective actions program, quality assurance (QA) procedures, site review and approval process, and administrative controls are implemented in accordance, with the requirements of 10 CFR Part 50, Appendix B. As discussed in the appendix to this report, the staff finds the requirements of.10 CFR Part 50, Appendix B, acceptable to address the corrective actions, confirmation process, and administrative controls.
8. Confirmation Process:See Item 7, above.
9. Administrative Controls: See Item 7, above.
10. OperatingExperience: Corrosion pits from the outside diameter have been discovered in buried piping With farless than 60 years of operation. Buried pipe that is coated and
  • cathodically.protected is unaffected after 60 years of service. Accordingly, operating experience from application of the NACE standards on non-nuclear systems
  • demonstrates the effectiveness of this program.

References 10 CFR Part 50, Appendix B, QualityAssurance Criteria for NuclearPower Plants, Office of the Federal Register, National Archives and Records Administration, 2005.

NACE Standard RP-0169-96, Control of External Corrosionon Undergroundor Submerged Metallic Piping Systems, 1996.

NACE Standard RP-0285-95, Corrosion Controlof UndergroundStorage Tank Systems by CathodicProtection,Approved March 1985, revised February 1995.

NUREG-1801, Rev. I Al M-96 September 2005

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