ML030930470

Comments on Peach Bottom SER

ML030930470
Person / Time
Site:	Peach Bottom
Issue date:	03/18/2003
From:	Potel E Exelon Corp
To:	Dave Solorio NRC/NRR/DRIP/RLEP
References
Download: ML030930470 (18)

Text

3-18-03; 2:29PM;FueI s/Eng9 neer rIng a I/ t8 T CoJDepL. c-. Co. - Therefore, there is no need tC Phone # - Phone the requirements of 10 CFR 5i _a 301 F aul9 In 10 CFR 54.21, the Commission requires that each application for a renewed license for a nuclear facility must contain (a) an integrated plant assessment (IPA), (b) description of current licensing basis changes made during the NRC review of the application, (c) an evaluation of time-limited aging analyses (TLAAs), and (d) a final safety analysis report (FSAR) supplement.

On July 2, 2001, the applicant submitted the information required by 10 CFR 54.21 (a) and (c) in the Enclosure of its LRA.

In 10 CFR 54.22, the Commission states requirements regarding technical specifications. The applicant did not request any changes to the plant technical specification in its LRA.

The staff evaluated the technical information required by 10 CFR 54.21 and 54.22 in accordance I with the NRC's regulations and the guidance provided in the SRP. The staffs evaluation of this

>I; $ti information is documented in Chapters 2, 3, and 4 of this SER.

The staffj aluation of the environmental infornation required by 10 CFR 54.23 is documented L- g in the lant-specific supplement to the GEIS (NUREG-1437, Supplement 10), which states the consIerations related to renewing the licenses for Peach Bottom Atomic Power Station, Units 2-and 3.

1.3.1 Boiling Water Reactor Vessel Internals Project (BWRVIP) Topical Reports In accordance with 10 CFR 54.17(e), Exelon also incorporated by reference several BWRVIP topical reports into the Peach Bottom LRA. The purpose of the topical reports is to generically demonstrate that the aging effects for reactor coolant system components are adequately managed for the period of extended operation under a renewed license. Exelon incorporated the following BWRVIP topical reports into its application:

BWRVIP-05, '¶BWR RPV Shell Weld Inspection Recommendations," September 1995 M3WRVIP-18, "Core Spray Internals Inspection and Flaw Evaluation Guidelines,"

July 1996 BWRVIP-25, "BWR Core Plate Inspection and Flaw Evaluation Guidelines," October 1999 BWRVIP-26, "Top Guide Inspection and Flaw Evaluation Guidelines," December 1996 BWRVIP-27, "Standby Liquid Control System/Core PlateP Inspection and Flaw Evaluation Guidelines," April 1997

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3-18-03; 2:29PM;FueI s/Eng I fleert ng 2:29PM;Fue1S/En91neer1n9 ;6107655651 it Z/ 18 component and is used to identify the safety-related components in the plant. The UFSAR includes information on the plant, presents the design bases and the limits on the plant's operation, presents the safety analyses of the SSCs and of the facility as a whole, and identifies the intended functions of structures. .DBDs are comprehensive system-level documents that provide the design bases and include system functions, controlling parameters, and design features for various operating and accident conditions. In addition, DBDs discuss the regulatory requirements, commitments, codes and standards, and system configuration changes that are reflected in the design basis of the system. The evaluation against license renewal scoping criterion 54.4(a)(1) for mechanical and electrical systems is taken from the evaluation against the corresponding MR scoping criterion described in the LRA. The applicant then performed additional scoping activities to identify systems and structures within the scope of license renewal. For structure-level scoping, a comprehensive list of plant structures to be evaluated for license renewal scoping was produced from the MR bases documentation, the UFSAR and other plant design documentation. Seismic Class I structures were included within the scope of license renewal under scoping criterion 10 CFR 54.4(aXI). Structural component listings were downloaded from the CRL and added to the license renewal database. Certain types of structural components and commodity Items are not identified in the CRL (e.g., equipment pads and pedestals and equipment supports). Such components and commodity items were identified by review of design drawings and plant walkdowns and added to the license renewal database. Some structural components may also be listed as components of mechanical and electrical systems in the CRL.

The scoping results are documented, reviewed, and approved on a license renewal scoping form and entered Inthe license renewal database. The format of the scoping form is defined in Exhibit LR-C-14-3 of PBAPS procedure LR-C-14, "License Renewal Process." A scoping form Is prepared for each system and structure and includes references to the applicable UFSAR sections, design drawings, and DBDs. The form also includes answers to several scoping questions related to system intended functions, applicable supporting systems, and whether any components were realigned into or out of the system (the system boundary realignment methodology is discussed in Section 2.1.2.1.4 of this report). The scoping form is generated as a report from the license renewal database into which the scoping data is entered during the review process. Boundary drawings for the various disciplines in the form of marked-up piping and instrumentation drawings (P&lDs), electrical single-line drawings, and site plan drawings were prepared to identify the major electrical systems and plant structures within the scope of license renewal. The documents a o reviewed and approved by both the license renewal team and PBAPS system managers. ts 2.1.2.1.2 Non-safety-related Systems, Structures, and Components With respect to the non-safety-related criteria in 10 CFR 54.4(a)(2), the applicant stated, that a review of the UFSAR and other CLB documents has been performed to identify the non-safety-related and non-safety-related quality SSCs whose failure could prevent satisfactory accomplishment of any of the functions identified in 54.4(a)(1 )(i), (ii), or (iii). Component listings for non-safety-related systems were downloaded from the CRL and reviewed to check for any safety-related components. This review assured that safety-related components associated with system interfaces are captured regardless of which system they were assigned to in the CRL.

Any safety-related components found in non-safety-related systems were included in the license renewal database. The specific functions of such components were determined by review against the plant CLB on a case-by-case basis to identify the appropriate system and system

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6107655651 # 3/ is 3-18-03; 2:29PM; Fuels -- nn l nsPr no3 safety analyses or plant evaluations to perform a function that demonstrates compliance with the Commission's reguae r Isi Systems and structures that are in the scope of license renewal scoping criterion 10 CFR 54.4(aX3) are identified by review of appropriate plant documentation. For 10 CFR 50.48 and 10 CFR 50.63, the review isdocumented in license renewal position papers.

The reviewer uses the position papers and the CRL to answer the questions on the scoping and screening form. For 10 CFR 50.62, the required components are identified in the controlled CRL database. The equipment within the scope of 10 CFR 50.49 is identified by a controlled data field In the CRL and is addressed in LRA Section 4.4 under the time-limited aging analysis (TLAA) evaluations. For 10 CFR 50.61, no review is performed since it is not applicable to boiling water reactors.

2.1.2.1.4 System Boundary Realignment A significant aspect of the licensee's scoping and screening methodology involved the use of system boundary realignment Interfaces between systems were examined and realigned, as necessary, to ensure that interfacing components were associated with the appropriate system for license renewal. For example, a valve in an out-of-scope system that provides an isolation boundary interface with an in-scope system would be considered in the scope of license renewal. The valve is "realigned to the in-scope system and the remainder of the out-of-scope system remains out-of-scope. Similar realignments are used to address out-of-scope systems that interface with the primary containment boundary. Electrical distribution systems interface with many systems, including many mechanical systems, and the interface point is often an electrical isolation device such as a fuse or circuit breaker. These electrical isolation devices are typically considered part of the mechanical system because their function is to provide electrical isolation of these systems. The applicant examined these interfaces to confirm interfacing components had been identified in the correct system for license renewal. For example, a fuse in an out-of-scope mechanical system that has an isolation boundary interface with an in-scope electrical system was considered in the scope of license renewal. The fuse was realigned to the in-scope electrical system, and the out-of-scope mechanical system remained out-of-scope.

In some cases, components were realigned to support specific intended functions. For example.

at PBAPS the main steam isolation valves (MSIVs) are air-operated and require compressed gas to perform their intended function. These valves do not rely on the instrument air distribution system but instead utilize a dedicated instrument air accumulator. Accordingly, the MSIVs instrument air accumulators are required to support the intended function of the MSIVs. For purposes of system scoping, these instrument air accumulators were realigned from the instrument air system to the main steam system. System boundary realignment is described on page 2-5 of the LRA.

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2 Non-Safety-related Systems Safety-Rela eiSystems With Components Realigne d~rNon-Safety- Related System Primary Containment Leak Test System Primary Containment Isolation System Reactor Building Ventilation System RHR System Core Spray System HPCI System RCIC System Reactor Building Closed Cooling Water System Primary Containment Isolation System Reactor Water Cleanup System Reactor Recirculation System Primary Containment Isolation System Chilled Water System Primary Containment Isolation System Instrument Nitrogen System Primary Containment Isolation System Main Steam System Instrument Air System Main Steam Safety-Grade Instrument Gas System Battery and Emergency Switchgear Ventilation System Service Air System Primary Containment Isolation System Plant Equipment and Floor Drain System Primary Containment Isolation System Process Sampling System Primary Containment Isolation System Torus Water Cleanup System Primary Containment Isolation System Post-accident Sampling System Primary Containment Isolation System Traversing In Core Probe System Primary Containment Isolation System As a result of the applicant's system boundary realignment, the staff was unable to adequately review the implementation of the boundary realignment using the information presented in the Peach Bottom LRA. Therefore, the staff issued RAts to the applicant on January 23 and March 12, 2002. The staffs RAI of January 23, 2002, asked the applicant to describe the realignment process and the rationale for its use. The staffs RAI of March 12, 2002, requested the applicant to provide (1) a brief description of each of these out-of-scope systems whose components were realigned to be in-scope, (2) a textual description of the types of components realigned, and (3) details regarding the intended function for each realigned component In the context of license renewal and how the realigned components met the criteria of 10 CFR 54.4(a)(1), (2), or (3). In addition, the RAI requested the applicant to provide a means to identify, in an unambiguous and traceable manner, the components realigned to systems within the scope of license renewal back to the out-of-scope systems. The applicant responded to this RAI by letter on May 22, 2002. The staff s RAI of January 23, 2002, questioned how the realignment was done and the March 12, 2002, RAt questioned the results of the realignment process as presented in the LRA in Sections 2.3 through 2.5. The applicant's response to the staff's RAI, dated February 28, 2002, described the following five cases for system boundary realignment:

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3-18-03; ;5107555651 $9 5/ 15 Z:29PM;Fue1S/Enlglneer ing ;17561#~'I grouping those SCs as a commoalny. I ne stairts evaluation of the primary containment isolation system is provided in Section 2.3.2.3 of this document.

Case 4 involves the realignment of shared components of the instrument air and instrument nitrogen systems, which are non-safety-related, to (1) the safety grade instrument gas, (2) the backup instrument nitrogen to ADS, and (3) the battery and emergency switchgear ventilation system (BESVS). In the February 28, 2002, RAI response, the applicant stated that the plant design includes a safety grade backup source of compressed gas for the safety-related systems which share components with the above-mentioned non-safety-related systems. As previously stated, the staffs evaluation of the BESVS is in Section 2.3.3.9 of this document Also, the staffs evaluations of other realignments involving the instrument air and nitrogen systems are in Section 2.3.3.12 (safety grade instrument gas), and 2.3.3.13 (backup instrument nitrogen to ADS), of this document Case 5 involves the realignment of piping and components of the reactor building ventilation system to the boundary of the RHR, core spray, high-pressure coolant injection, and RCIC systems. In the May 22, 2002, response to the staffs RAI 2.2-1.2, the applicant stated that the cooling intended function for all components cooled by the emergency service water (ESW) system is included under the ESW system intended function of component cooling. Further, the HPCI, RCIC, RHR, and core spray system room coolers are cooled by the ESW system. The applicant also stated that the ESW system performs the room cooling function by providing cooling water to the room coolers and therefore the function of room cooling is not included as an intended function of the HPCI, RCIC, RHR, and core spray systems.

Because the components responsible for cooling were realigned to the HPCI, RCIC, RHR. and core spray systems, the system intended function of room cooling is removed from the scope of license renewal. The system intended function of room cooling meet§.bes eJi

§54.4(aX2). However, realignment of SCs to extend the boundaryoklRCLBIRR and core spray obscures the room cooling function since the supported syste te room coolers to remain functional before and after a design basis event but do not include room C I cdv cooling as a system level intended function. The staffs evaluations of the system boundary z l XF realignment of SCs are In Sections 2.3.2.5 (RHR), 2.3.2.1 (HPCI), 2.3.2.2 (core spray), and 2.3.2.4 (RCIC) of this document.

Non-Safety-related Systems Affecting Safety-Related Systems The staff evaluated the applicant's methodology for scoping SSCs meeting the requirements of 10 CFR 54.4 and 10 CFR 54.21 (a)(2). The implementation of the methodology for the potential spatial interaction between non-safety and safety-related systems resulted in the expansion of systems boundaries for the following systems:

reactor pressure vessel instrumentation system core spray system residual heat removal system fuel pool cooling and cleanup system control rod drive system radiation monitoring system tas _ Tv sey t.:W-M,EUe~ I/t~ng l neer l rag  ; 61*07655651* # 2/ *8 exposed to reactor coolant water. The applicant will use the RCS chemistry program, ISi program, and FAC program to manage loss of material for carbon steel piping, piping specialties, and valve bodies. The applicant will use the RCS chemistry program to manage loss of material for stainless steel or low alloy steel piping (tubing) and valve bodies.

Cracking was identified for the stainless steel pipe, tubing, and valve bodies in a reactor coolant environment. Cracking of stainless steel materials may occur in reactor coolant environment, and therefore may be an applicable aging effect for the stainless steel surfaces exposed to reactor coolant. The applicant will use the RCS chemistry program to manage the

-emael associated wih stainless steel pipe, tubing, and valve bodies in a reactor coolant environment yef -

I 3.4.3.2.2 Aging Management Programs The applicant stated that the RCS chemistry program, ISI program, and FAC program will be used to manage the loss of material associated with carbon steel or low alloy steel piping, piping specialties, and valve bodies. The RCS chemistry program will be used to manage the ssociated with stainless steel pipe, tubing, and valve bodies in a reactor coolant environment A detailed description of each of the programs identified above is included in Appendix B to the LRA, along with a demonstration that the identified aging effects will be effectively managed for the period of extended operation. The staffs detailed review of the different aging management activities and their ability to adequately manage the applicable aging effects is provided in Sections 3.0.3.1, 3.0.3.2, and 3.0.3.6 of this SER. As a result of its review, the staff did not identify any concerns or omissions in the aging management activities used to manage the feedwater system.

3.4.3.3 Conclusions The staff has reviewed the information in Section 3.4, "Aging Management of Steam and Power Conversion Systems," of the LRA. The staff considered both industry and plant-specific experience. On the basis of its review, the staff concludes that the applicant's identification of the aging effects associated with the feedwater system is consistent with published literature and industry experience. The staff further concludes that the applicant has adequate aging management programs to effectively manage the aging effects of the feedwater system and that there is reasonable assurance that the Intended functions of the system will remain consistent with the CLB during the period of extended operation as required by 10 CFR 54.21(aX3).

3.5 Aging Management of Structures and Component Supports 3.5.1 Containment Structure 3.5.1.1 Technical Information in the Application The aging management review results for the containment structure, which consists of the 3-219

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6107655651 3-18-03; 2 ;5107555851 V 13/ IS 3-iS-03; 2 1.5 to obtain the 60-year value All other cable insulation types were bounded by this analysis cab ng aging management as a result of radiation effects were Identified.

A review of cable insulation aging effects from temperature required a more detailed elimination process. Cable populations were grouped according to their common cable insulation material type and voltage application (power, control, or instrumentation). For each cable insulation material type, a 60-year limiting service temperature was established. This value was compared to the bounding cable service temperature to determine if it was below the 60-year limiting service temperature. Ohmic heating was considered for power cables and for control cables that are routed with power cables, where applicable to determine the bounding service temperature. A summary of each cable group review follows:

• Comruter Cable Groups Computer cable groups are not in the scope of license renewal and were eliminated from the temperature review.

• Fibre Optic & Bare Ground Cable Groups Fibre optic cable Insulation material is unaffected by thermal aging. Bare ground cables have no insulation and were determined not to be within the scope of license renewal.

• Instrumentation Cable Groups Instrumentation cable groups with cross-linked polyethylene (XLPE), polyethylene, cross-linked polyolefin (XLPO), hypalon, Teflon-based, and polypropylene insulation were determined to have 60-year limiting service temperature greater than the bounding ambient temperature of PBAPS. Two bounding ambient temperatures were determined:

one bounding ambient temperature for containment and another bounding ambient temperature for all other plant areas.

• XLPE Power & Control Cable Groups XLPE insulated cable groups can operate continuously at their bounding service temperature for greater than 60-years. The 60-year limiting service temperature is greater than bounding ambient temperature and its associated ohmic heating temperature rise.

EPR Power & Control Cable Groups EPR (ethylene polymer rubber) cable groups supplying loads not in the scope of license renewal were eliminated from review. The remaining EPR cable groups were determined to be routed in areas outside containment and have 60-year limiting service temperature greater than the bounding ambient temperature and its associated ohmic heating temperature rise.

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3-ia-o3; Z:.Y M;1-ue I t . u, 1 t a PE Power and Control Cable Groups The routing of PE (polyethylene) power and control cable groups was determined and local ambient temperature field measurements were conducted In bounding cases. The 60-year limiting service temperature for PE insulation groups was greater than the bounding ambient temperature and its associated ohmic heating temperature rise.

• • PVC Cable Grougs Poly-vinyl-chloride (PVC) cables groups and individual cables from the remaining PVC cable groups supplying loads not in the scope of license renewal were eliminated from review. The remaining PVC cables were reviewed to identify cables with 60-year limiting service temperatures greater than the bounding service temperature. Thirty cables relied upon for fire safe shutdown (FSSD) were determined to require aging management.

• Miscellaneous Cable Groups Miscellaneous cables groups not In the scope of license renewal loads were eliminated from review. Miscellaneous cable groups were also reviewed to eliminate cables with a 60-year limiting service temperature greater than the bounding ambient temperature.

Individual cables within the remaining group were reviewed to identify cables within the scope of the environmental qualification aging management activity or cables supplying loads not within the scope of license renewal. None of the miscellaneous cables were identified as requiring management.

3.6.1.1.2 Aging Management Program Table 3.6-1 of the LRA provides the aging management review results for cables. In this table, no aging management activity is identified except for PVC insulated fire safe shutdown cables.

The applicant states that a cable replacement program was initiated in 1995 to replace "suspectedw cables subject to the water-treeing. No cable failures have occurred at PBAPS since the cable replacement program was initiated. Therefore, moisture is not an aging effect requiring management at PBAPS. The applicant also states that the m doses of insulation material (1.5 times the existing radiation design valu us e accident doseill not exceed the 60-year service limiting radiation dose. The maxim ii_ erature of insulation material will also not exceed the maximum temperature for 60-year life. The applicant concludes that no aging management programs are required for cables due to heat or radiation.

The fire safe shutdown (FSSD) inspection activity is a new aging management program. The applicant reviewed the PVC cable groups and determined that 30 cables relied upon for fire safe shutdown require aging management. These cables have a 60-year service temperature greater than the bounding service temperature. These cables are located in the drywell and are all MSRV discharge line thermocouple wires. The inspection will manage change in material properties of the PVC insulation.

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• 2: 29PM;Fue H ;6107655651 3-18-03, 2: 29PM; FuelI It 15/ 18 moisture simultaneously wth significant voltage are tesed to provide an indication of the condition of the conductor insulation. The specific test of test performed will be determined prior to the initial test. Each test performed for a cable may be a different type of test. This activity will provide reasonable assurance that aging effects on the conductor insulation are detected and addressed such that the intended function of these cable will be maintained for the period of extended operation. This activity will be implemented prior to the end of the initial operating license term for PBAPS.

The staff reviewed proposed Section B.3.5 of the UFSAR Supplement (Appendix B of the LRA) and verified that the information provided in the UFSAR Supplement for the aging management of systems and components discussed above Is equivalent to the information in NUREG-1 800 and therefore provides an adequate summary of program activities as required by 10 CFR 54.21(d).

Conclusions The staff concludes that the applicant has demonstrated that the aging effects associated with inaccessible medium-voltage cables not subject to 10 CFR 50.49 environmental qualification requirements will be adequately managed so there is reasonable assurance that the intended functions of the systems and components will be maintained consistent with the CLB during the period of extended operation as required by 10 CFR 54.2(aX3). The staff also concludes that the UFSAR Supplement contains an adequate summary description of the program activities for managing the effects of aging for the systems and components discussed above as required by 10 CFR 54.21(d).

For accessible Non-EQ cables installed in adverse localized environments due to heat or radiation, in Section 2.5.1 of the LRA, the applicant states that the m mopefati das of insulation material (1.5 times the existing radiation design valu us the accide will not exceed the 60 year-service limiting radiation dose. The applica so stes thamaximum operating temperature of insulation material will not exceed the maximum temperature for 60-year life. Therefore, It concludes that no aging management is required for aging effects due heat or radiation. Additionally, on January 2, 2002, the applicant stated that a plant walk down was conducted outside containment (i.e., excluding the drywell and steam tunnel) to identify any adverse localized equipment environments. It was concluded that only the drywell PVC cables credited for fire safe shutdown required an aging management activity. The staff finds that this conclusion is not consistent with the aging management program and activities for electrical cables and connections exposed to adverse localized environments caused by heat or radiation, because conductor insulation material used in cables may degrade more rapidly than expected.

The radiation levels most equipment experience during normal service have little degrading effect on most materials. However, some localized areas may experience higher-than-expected radiation conditions. Areas prone to elevated radiation levels include areas near primary reactor coolant system piping or the reactor-pressure-vessel; areas near waste processing systems and equipment (e.g., gaseous waste system, reactor purification system, reactor water cleanup system, and spent fuel pool cooling and cleanup system); and areas subject to radiation streaming. The most common adverse localized equipment are those 3-257

3-18-03; 2:29PM;FueIs/Engineerlng ;6107555551 # 16/ 18 The applicant discussed the piping and component fatigue analyses in Section 4.3.3 of the LRA.

The applicant designates reactor coolant pressure boundary piping as Group I piping. The applicant indicated that all Group I piping was originally designed to United States of America Standards (USAS) B31.1. 1967. This code did not require an explicit fatigue analysis of piping components. The applicant indicated that the Group I recirculation piping and RHR piping were replaced because of IGSCC concerns and that the replaced piping was analyzed to ASME Section III Class 1 requirements, which include an explicit fatigue analysis. The applicant indicated that a simplified fatigue analysis was developed for the remainder of the Group I piping to estimate CUFs from the operating data. The applicant indicated that fatigue of the Group I piping will be managed by the FMP in accordance with 10 CFR 54.21(cX1Xiii).

The applicant designates the remainder of the safety-related piping as Group II and Ill. This piping was designed to the requirements of USAS B31.1. USAS B31.1 requires a reduction in the allowable bending loads If the number of full range thermal bending cycles exceeds 7,000.

The applicant's evaluation indicated that the expected number of thermal bending cycles will not exceed the 7,000 limit during the period of extended operation and that the analyses remain valid for the period of extended operation in accordance with 54.21(cX1Xi).

The applicant discussed the evaluation of the effects of the reactor coolant environment on the fatigue life of components in Section 4.3.4 of the LRA. The applicant relied on industry generic studies to address this Issue.

4.3.2 Staff Evaluation The components of the RCS were designed to codes that contained explicit criteria for fatigue analysis. Consequently, the applicant identified fatigue analyses of these RCS components as TLAAs. The staff reviewed the applicant's evaluation of the identified RCS components for compliance with the provisions of 10 CFR 54.21(cX1).

The design criterion for ASME Class I components involves calculating the CUR. The fatigue damage In the component caused by each thermal or pressure transient depends on the magnitude of the stresses caused by the transient. The CUF sums the fatigue damage resulting from each transient. The design criterion is that the CUF not exceed 1.0. The applicant monitors limiting locations in the RPV, RVI, and RCS piping for fatigue usage through the FMP.

The applicant relies on the FMP to monitor the CUF and manage fatigue in accordance with the provisions of 10 CFR 54.21 (c)(1Xiii). The staffs evaluation of the FMP is in provided below.

The applicant indicated that all component locations where the 40-year CUFs are expected to exceed 0.4 are included in the FMP. Section 4.3.1 of this SE lists the component locations monitored by the FMP. These locations have been identified in the reactor vessel, vessel-intemals, reactor coolant system piping, and torus. The applicant indicated that the existing FMP maintains a count of cumulative reactor pressure vessel thermal and pressure cycles to ensure that licensing and design basis assumptions are not exceeded. The applicant also indicated that an improved program is being implemented which will use temperature, pressure, and flow data to calculate apd-re'ord accumulated usage factors for critical RPV locations and subcomponents. In RA1(4.2-2,Pth staff requested that the applicant describe how the monitored data will be used to calcuateu age factors and to indicate how the fatigue usage will be estimated prior to implement tion of the improved program.

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29PM;FUe1S/Eng1neer§ng ing ;6107655551 # 17/ IS 3-18-03; Z:28PM;FueIS/Englfleer concerns regarding the EPRI Although the letter dated August 6, 1999, identified the staff's the application of the procedure and its application to PWRs, the technical concerns regarding threshold values are also Argonne National Laboratory (ANL) statistical correlations and strain staff identified additional the relevant to BWRs. In addition to the concerns referenced above, BWR studies in its review of the Hatch LRA.

concerns regarding the applicability of the EPRI of Representative BWR EPRI topical report TR-1 07943, "Environmental Fatigue Evaluations "Evaluation of report TR-110356, Components," addressed a BWR-6 plant, and EPRI topical Water Reactor in a Boiling Environmental Thermal Fatigue Effects on Selected Components indicated Plant," used plant transient data from a newer vintage BWR-4 plant. The applicant that these issues were considered in the assessment of metal fatigue at Peach Bottom.

The applicant discussed the impact of the environmental correction factors for carbon and low-on Fatigue alloy steels contained in NUREG/CR-6583, 'Effects of LWR Coolant Environments correction factors for

,N Design Curves of Carbon and Low-Alloy Steels," and the environmental LWR Coolant "Effects of austenitic stainless steels contained in NUREG/CR-5704, the results of the EPRI on

\ Environments on Fatigue Design of Austenitic Stainless Steels," data was not new carbon steel

< studies. The applicant indicated that the impact of the study results to EPRI generic

'M significant. The applicant applied a correction factor of 2.0to the account for the new stainless steel data.

studies that are directly q The applicant indicated that EPRItopical report TR-110356 contained to the Peach a BWR-4 that is identical

- applicable to Peach Bottom because they Involved 10356 are the feedwater in TR-1 Bottom design. However, the only components evaluated The staff had previously expressed nozzle and the control rod drive penetration locations.

contained In EPRI topical report TR-concerns regarding the applicability of the measured data

110356 to another facility in its review of the Hatch LRA.

Bottom Units 2 and 3 at the The applicant provided the sixty-year CUFs projected for Peach "Application of NUREG/CR-l locations evaluated for an older vintage BWR in NUREG/CR-6260, Components'," dated March 5999, 'Interim Fatigue Curves to Selected Nuclear Power Plant locations are monitored

' 1995, in Table 4.3.4-3 of the LRA. The applicant indicated that these accounted for by the g by the FMP, and that the environmental factors have been adequately conservatism In the design basis transient definitions. The applicant Indicated that the vessel w support skirt is monitored in lieu of the shell region identified In NUREG/CR-6260 because it is the location is on the i a more limiting fatigue location. The applicant also indicated that, since The staff agrees with the vessel exterior, the environmental fatigue factors do not apply.

' applicant's statement.

In RAI 4.3-6, the staff requested that the applicant provide an assessment of the six locations identified in NUREG/CR-6260 considering the applicable environmentalBottom fatigue correlat2 ns; reports for Peach Units/and ?I provided in NUREG/CR-65B3 and NUREG/CR-5704

%In its May 1, 2002, response, the applicant committed to perform plant-specific calculations for

1. the locations identified in NUREG/CR-6260 for an older vintage BWR plant applicable environmental factors provided in NUREG/CR-6583 considering the and NUREG/CR-5704. The period of extended o eration applicant committed to complete these calculations prior to the CUF yalues exceed I.O. he staff finds and take appropriate corrective actions if the resulting rto described abovebpve the Sp~caant's commitment to complete'the plant-specific calculations

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3-1 8-03; 2:29PM; Fue I sZEng I neer I ng ;6107655551 V IS/ 15 In Attachment 3 to a letter from M. P. Gallagfier to USNRC.dated January 14, 2003, the applicant provided a revised Reactor Pressure Vessel and Internals 1SI Program (B.2.7) which Indicates Peach Bottom will perform augmented inspections for the top guide similar to the inspections of Control Rod Drive Housing (CRDH) guide tubes. The sample size and frequency for CRDH guide tubes is a 10% sample of the total population within 12 years; one half (5%) to be completed within six years. The method of examination is an enhanced visual examination (EVT-1). EVT-1 are utilized to examine for cracks. The program will be implemented prior to the end of the initial operating license term for Peach Bottom. The applicant also stated that it might modify the above agreed-upon inspection program should the BWRVIP-26, *BWR Vessels and Internals Project, BWR Top Guide Inspection and Flaw Evaluation Guidelines (BWRVIP-26),w be revised in the future. This Is acceptable to the staff because any modifications to the BWRVIP-26 program through the BWRVIP are reviewed and approved by the staff. Since the aging effect is IASCC, the staff requested the applicant to clarify whether the inspection sample would be in top guide locations that receive the greatest amounts of neutron fluence. In a letter from M. P. Gallagher to USNRC dated January 29, 2003, the applicant concluded that future locations for the top guide inspections will be in the center or close to the center of the core in the high fluence region. The conclusion is based on the applicant's experiences with prior CRDH inspections: Since the applicant has proposed an inspection program which will be able to detect IASCC in locations which receive high neutron fluence, the staff considers the program acceptable; therefore, Open Item 4.5.2-1 is closed.

Effect of Fatigue and Embrittlement on End-of-Life Reflood Thermal Shock Analysis Radiation embrittlement and fatigue usage may affect the ability of certain reactor vessel intermals (RVI), particularly the core shroud support plate, to withstand an end-of-life reflood thermal shock following a recirculation line break. The applicant evaluated the effects of embrittlement and fatigue on the end-of-life reflood thermal shock analysis. The thermal shock analyses were validated for the 60-year extended operating term. The effects of embrittlement are not.

significant at higher usage factor locations, and the effects of fatigue are not significant at locations where embrittlement is significant. Based on the applicant's evaluation of the impact of fatigue and embrittlement on RVI components, the staff concludes that reflood thermal shock will not significantly affect the capability of RVI components to perform their intended functions during the 60-year extended operating term. The impact of reflood thermal shock on the reactor vessel Is discussed in Section 4.2.1 of this SER.

4.5.3 Conclusions The staff concludes that. with-4 tceetion-f lM-45.6 the reactor vessel internals embrittlement analyses have been evaluated and remain valid for the period of extended operation in accordance with 10 CFR 54.21(c)(lXi). Because of the above open item the staff cannot conclude that the UFSAR Supplement provides an adequate description of the evaluation of this TLAA for the period of extended operation as required by 10 CFR 54.21(d). Pending resolution of the open item, the staff will determine if the UFSAR Supplement contains an appropriate summary description.

The effect of fatigue and embrittlement on end-of-life reflood thermal shock analysis have been evaluated and remain valid for the period of extended operation in accordance with 10 CFR 54.21(cXl)(1). The staff has also reviewed the UFSAR Supplement and the staff concludes the 4-34