ML030020228

Response to Open Items & Confirmatory Items & Verification of Accuracy for Safety Evaluation Report Related to License Renewal of Peach Bottom Atomic Power Station, Units 2 & 3, Attachments 1, 2 and 3

ML030020228
Person / Time
Site:	Peach Bottom
Issue date:	11/26/2002
From:	Gallagher M Exelon Nuclear
To:	Document Control Desk, Office of Nuclear Reactor Regulation
References
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Download: ML030020228 (75)

Text

3.4.2.1.1 Aging Effects Table 3.4-2 of the LRA identified the following components of the main condenser as subject to AMR: main condenser shell, tubesheet, tubes, waterbox, feedwater heater shell, drain cooler shell, nozzles, and expansion joints. No aging effects requiring aging management during the period of extended operation were identified for these components. The applicant identified stainless steel, carbon steel, and titanium as the materials of construction for the main condenser components.

3.4.2.1.2 Aging Management Programs The LRA identified no aging management programs to manage the aging effects for the main condenser during the extended period of operation.

3.4.2.2 Staff Evaluation The staff has reviewed the Information included in Section 3.4 of the LRA. The purpose of the review was to ascertain whether the applicant has adequately demonstrated that the effects of aging associated with the main condenser will be adequately managed so that the intended function of the main condenser will be maintained consistent with the CLB throughout the period of extended operation as required by 10 CFR 54.21 (a)(3).

3.4.2.2.1 Aging Effects The LRA included a summary of the results of the aging management review for the main condenser. The results are listed in Table 3.4-2 of the LRA. The materials of construction, applicable environments and aging effects for the main condenser are as follows:

carbon and stainless steel in a steam environment-no aging effects carbon =WONe.

steel in reactor coolant and raw water environments-no aging effects titanium tubes in steam and raw water environments-no aging effects No aging effects were identified by the AMR for the main condenser components made of carbon steel, stainless steel, or titanium in steam, reactor coolant, or raw water environments.

These materials have successfully performed as main condenser materials at other plants.

Further, the applicant has concluded that aging management of the main condenser is not r-44tIrd.,

based on analysis of materials, environments, and aging effects. Condenser integrity required to perform the post-accident Intended function (holdup and plateout of MSIV leakage) is continuously confirmed by normal plant operation. The main condenser must perform a significant pressure boundary function (maintain vacuum) to allow continued plant operation.

For these reasons, the applicant has not identified any applicable aging effects for the main condenser. The staff concurs with the applicant's conclusion because the main condenser integrity is continuously confirmed during normal plant operation and thus the condenser post accident function will be ensured.

3.4.2.2.2 Aging Management Programs The applicant did not identify any management programs to manage aging effects for the main 3-201

3.4.3.2 Staff Evaluation.

The staff has reviewed the information included in Section 3.4 of the LRA. The purpose of the review was to ascertain whether the applicant has adequately demonstrated that the effects of aging associated with the feedwater system will be adequately managed so that the intended function of the system will be maintained consistent with the CLB throughout the period of extended operation as required by 10 CFR 54.21 (a)(3).

3.4.3.2.1 Aging Effects The LRA included a summary of the results of the aging management review for the feedwater system. The results are listed in Table 3.4-3 of the LRA. The materials of construction, applicable environments, and aging effects for the feedwater system are as follows:

carborand inless steel in a sheltered environment-no aging effects carbo tee in a reactor coolant environment-loss of material stainless steel in a reactor coolant environment-cracking No aging effects were identified by the AMR for piping, piping specialties, tubing, and valve bodies made of stainless steel or carbon steel in a sheltered environment. These materials are corrosion resistant in sheltered environments. The applicant, therefore, has not identified any applicable aging effects for the surfaces of stainless steel or carbon steel feedwater system components exposed to this environment.

Loss of material was identified for the carborlsteel piping, pi inp soecialties and valve bodies in a reactor coolant environment. Loss of material of carbon.

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• ,ron may occur in reactor coolant environment, and therefore may be an applicable aging effect for the carbon 4aa, s/'fdg-s.=

steel surfaces 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 speciaes, dvave bo1ie

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'J, 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 eea-ef

,mateiel. associated with stainless steel pipe, tubing, and valve bodies in a reactor coolant environment.

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 piping, piping specialties, and valve bodies. The RCS chemistry program will be used to manage the loss of material &,WL.v.Ack associated 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 staff's detailed review of the different aging management activities and their ability to adequately manage the applicable aging effects is provided in Appendix B of this SER. As a result of its review, the staff did not identify any 3-203

addition, the staff has evaluated the applicability of the aging management programs that are credited for managing the identified aging effects for the containment components.

3.5.1.2.1 Aging Effects Concrete: No aging effects are identified in Table 3.5-1 for the concrete containment components. These concrete containment components are the (1) reinforced concrete reactor pedestal, foundation, and floor slab and (2) the unreinforced concrete sacrificial shield wall. All of these concrete containment components are exposed to a sheltered environment.

The staff considers cracking, change in material properties, and loss of material to be applicable aging effects for concrete containment components that are exposed to sheltered or outdoor environments. The NRC staff position regarding the aging management of in-scope concrete structures and components (SCs) is that they need to be periodically inspected in order to adequately monitor their performance or condition in a manner that allows for the timely identification and correction of degraded conditions. Concrete SCs in nuclear power plants are prone to various types of age-related degradation, depending on the stresses and strains due to normal and incidental loadings and the environment to which they are subjected.

Concrete SCs subjected to sustained loading, such as crane or monorail operation, and/or sustained adverse environmental conditions, such as high temperatures, humidity, or chlorides, will degrade, thereby potentially affecting the intended functions of the SCs. These degradations to concrete SCs are manifested through aging effects such as cracking, loss of material, and change in material properties. As concrete SCs age, such aging effects accentuate. On the basis of industry-wide evidence, the American Concrete Institute (ACI) has published a number of documents (e.g., ACI 201.1 R, "Guide for Making a Condition Survey of Concrete,* ACI 224.1 R, "Causes, Evaluation and Repairs of Cracks in Concrete Structures,"

and ACI 349.3R, "Evaluation of Existing Nuclear Safety-Related Concrete Structures") that identify the need to manage the aging of concrete structures. These reports and standards confirm the inherent tendency of concrete structures to degrade over time if not pro~d.d.y..,

managed. Similar observations of concrete aging made by NRC staff are detailedAUUREG 1522, "Assessment of In-Service Conditions of Safety-Related Nuclear Power Plant Structures."

Accordingly, in RAI 3.5-1 the staff requested that the applicant identify the aging management program(s) that will be used to manage the aging effects for the concrete containment components listed in Table 3.5-1 of the LRA.

In response, the applicant stated:

PBAPS aging management reviews (AMRs) concluded that concrete and block wall aging effects are non-significant, will not result in a loss of intended function, and thus require no aging management. The AMRs are based on guidelines for implementing the requirements of 10 CFR Part 54, developed jointly by the NRC and the industry, that are documented in NEI 95-10. The AMR results are also confirmed by PBAPS operating experience.

Exelon therefore is not in agreement with the staff's position, that PBAPS concrete and block wall aging effects require aging management. However, we recognize that, contrary to our experience, the staff is concemed that unless concrete and block wall aging effects are monitored they may lead to a loss of intended function. As a result, we will monitor concrete and block wall structures 3-206

in accessible areas, for loss of material, cracking and change in material properties. The PBAPS Maintenance Rule Structural Monitoring Program (B.1.16) will be used to monitor the structures.

The applicant's commitment to monitor concrete and block wall aging effects in accessible areas is acceptable to the staff. The applicant has decided to use the Maintenance Rule Structural Monitoring Program to manage concrete aging. This program is reviewed in Section 3.0.3.11 of this SER.

For bconcrete components, the staff hasdetingdJhat aging management is unnecessary if applicants are able to show that the

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o soil/groundwater environment is nonaggressive. In response to RAI 3.5-1, the applicant provided water chemistry results that show that the Peach Bottom soil/groundwater environment is nonaggressive (pH = 7.2, sulfates

= 38 ppm, and chlorides = 24 ppm). Consequently, the applicant concluded that the aging management of below-grade concrete is not required. Since the groundwater chemistry at the Peach Bottom site is well above the limit for pH (5.5) and below the limits for sulfates (1500 ppm) and chlorides (500 ppm), the staff concurs with the applicant's conclusion that the groundwater is nonaggressive with respect to concrete. Therefore, below-grade concrete does not need to be managed by the applicant.

The staff considers the applicant's response to RAI 3.5-1 to be adequate with respect to managing the aging of concrete and masonry block walls during the period of extended operation.

Steel: The applicant identified (1) loss of material of carbon and stainless steel components in sheltered or torus water environments and (2) cumulative fatigue damage of carbon and stainless steel components in sheltered or torus water environments as applicable aging effects for steel components in the containment structure.

The staff concurs with the aging effects identified above by the applicant for the carbon steel and stainless steel components in the containment structure. However, the staff noted in Part 1 of RAI 3.5-2, that no aging effects are identified in Table 3.5-1 for the carbon steel structural supports, pipe whip restraints, missile barriers, and radiation shields in the containment structure. In response to Part 1 of RAI 3.5-2, the applicant stated:

PBAPS aging management reviews (AMRs) concluded that carbon steel exposed to a sheltered environment would be subjected to non-significant loss of material due to atmospheric corrosion. The estimated reduction in material thickness will not significantly degrade the load bearing capacity of structural members and thus will not adversely impact their intended function. The AMRs are based on guidelines for implementing the requirements of 10 CFR Part 54, developed jointly by the NRC and the Industry, and are documented in NEI 95-10. The AMR results are also confirmed by PBAPS operating experience.

Exelon's position is that loss of material for carbon steel in PBAPS sheltered environment is non-significant and requires no aging management. The position is supported by AMRs performed in accordance with industry guidelines for implementing the requirements of 10 CFR Part 54, and PBAPS operating experience. The position and its justification were discussed with NRC staff on 3-207

This section of this SER provides the staff's evaluation of the applicant's aging management review for the aging effects and the applicant's programs credited for the aging management of the reactor building structure at each Peach Bottom unit. The staff's evaluation includes a review of the aging effects considered and the basis for the applicant's elimination of certain aging effects. In addition, the staff has evaluated the applicability of the aging management programs that are credited for managing the identified aging effects for the reactor building components.

3.5.2.2.1 Aging Effects Concrete: The applicant did not identify any applicable aging effects for the reinforced concrete walls, slabs, columns, beams, and foundation that make up the reactor building structure. In addition, the applicant did not identify any aging effects for the reinforced concrete block walls within the reactor building structure.

As noted above in Section 3.5.1.2.1 of-this SER, the staff considers loss of material, cracking, and change in material properties to be both plausible and applicable aging effects for all concrete components, including masonry block walls, in all of the environments listed by the applicant. The NRC staff position regarding the aging management of in-scope concrete structures and components (SCs) is that they need to be periodically inspected in order to adequately monitor their performance or condition in a manner that allows for the timely identification and correction of degraded conditions. In RAI 3.5-1, the staff requested further information regarding the applicant's AMR of concrete components and specifically, the applicant's determination that management of concrete aging is not required. In response to RAI 3.5-1, the applicant stated that it is not in agreement with the staff's position regarding the aging management of concrete structures; however, the applicant has decided that it will manage concrete and masonry block wall aging during the period of extended operation. The applicant specifically stated that it will monitor concrete and masonry block wall structures for loss of material, cracking, and change in material properties through the Maintenance Rule Structural Monitoring Program. Since this commitment from the applicant covers the outdoor and sheltered reactor building structure concrete components, this response is considered acceptable by the staff. RAI 3.5-1 is considered closed with respect to the outdoor and sheltered reactor building concrete components.

For the *biee reactor building concrete components, the staff has determined that aging management is unnecessary if applicants are able to show that the be--"

grade soil/groundwater environment is nonaggressive. In response to RAI 3.5-1, the applicant provided water chemistry results that show that the Peach Bottom soil/groundwater environment is nonaggressive (pH = 7.2, sulfates = 38 ppm, and chlorides = 24 ppn.

n Oees Consequently, the applicant concluded that the aging management of J

,owgradewoncrete/s not required. Since the groundwater chemistry at the Peach Bottom site is well above the limit for pH (5.5) and below the limits for sulfates (1500 ppm) and chlorides (500 ppm), the staff concurs with the applicant's conclusion that~th onqte/

snaggressive with respect to concrete. Therefore,.be.o gi'p concretejiOenes-cn-o Hee to Pe managed by the applicant.

Steel: The applicant identified (1) loss of material of carbon steel components in an outdoor environment and (2) loss of material of stainless steel components in a fuel pool water environment as applicable aging effects for steel components in the reactor building structure.

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attenuation capability. The staff found the monitoring of the parameters following EPRI guidelines to be adequate to mitigate aging degradation for the spent fuel rack neutron poison material.

Detection of Aging Effects: The applicant stated that Boraflex degradation from change in material properties will result in release of silica boron carbide from Boraflex and result in increased levels of silica in fuel pool water and loss of boron-10 areal density. The applicant further stated that these parameters are monitored in accordance with EPRI guidelines at a frequency that assures identification of unacceptable aging effects before loss of intended function. The staff indicated that the amount of boron carbide released from the Boraflex panel is determined through direct measurement of boron areal density and the levels of silica determined by the use of a predictive code such as RACKLIFE or other similar codes.

Therefore, the staff requested additional information on the applicant's use of the data on silica levels and the loss of boron areal density.

The applicant responded, in a letter to the NRC dated May 14, 2002, that the data on silica levels are monitored for the prediction of loss of boron carbide and would signal potential degradation of Boraflex. The applicant further stated that silica is also used as an input to the EPRI RACKLIFE computer code. The staff found this program attribute acceptable because the applicant follows EPRI guidelines which have long-been, accepted for industry use. The staff also found that the program activities may be relied upon to provide reasonable assurance that aging effects will be detected before there is loss of intended function.

Monitoring and Trending: The applicant stated that monitoring of change in material properties is accomplished through the periodic measurements of boron-1 0 areal density of in-service spent fuel storage rack panels and sampling of silica levels in fuel pool water. This data is used to trend and predict performance of Boraflex. The staff found the applicant's approach to monitoring and trending activities to be acceptable because it is based on methods that are sufficient to predict the extent of degradation so that timely corrective or mitigative actions are possible.

Acceptance Criteria: The applicant stated that analysis has shown that Boraflex will perform its intended function if degradation is maintained at less than a 10% uniform loss and at less than 10-cm randomly distributed gaps. The applicant described these parameter limits as ensuring that CLB fuel pool reactMty limits (keff > 0.95 or 5% margin) are not exceeded. The applicant further stated that spent fuel pool silica data are trended and compared to an industry-wide EPRI database. A sustained increasing trend in spent fuel pool silica concentration, inconsistent with previous seasonaVrefueling changes, requires an engineering evaluation to determine the need for corrective action.

The staff requested additional information on the trending and comparison to an industry-wide database. The applicant responded, in a letter to the NRC dated May 14, 2002, that silica data is transmitted to EPRI periodically for analysis and trending and that the results are compared with data from other licensees who participate in the collaborative Boraflex research agreement with EPRI. The staff found the acceptance criteria specified by the applicant and the participation in an industry-wide data comparison agreement to be adequate to ensure the intended functions of the systems, structures, and components that may be served by the Boraflex management activities.

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Operating Experience: The applicant stated that NRC Information Notices IN 87-43, IN 93-70, and IN 95-38 address several cases of significant degradation of Boraflex in spent fuel pools.

In response to these findings, NRC issued Generic Letter 96- 04. The applicant 4urther stated that the industry formed a Boraflex Working Group with EPRi and developed a strategy for tracking Boraflex performance in spent fuel racks, detecting the onset of material degradation, and mitigating its effects. The applicant described the Peach Bottom spent fuel racks and Boraflex as having been in service since 1986, and that in situ testing of representative Boraflex panels was conducted in 1996 for Unit 2 and 2001 for Unit 3. Test results identified Boraflex degradation; however, the degradation is less severe than experienced in the industry. The applicant indicated that continued testing would identify unacceptable degradation prior to loss of intended function. The staff found that the aging management activities described above are based on plant and industry experience and EPRI/industry working group participation.

Therefore, the staff agreed that these activities are effective at maintaining the intended function of the systems, structures, and components that may be served by the Boraflex management activities, and can reasonably be expected to do so for the period of extended operation.

UFSAR Supplement The staff reviewed Section A.2.2 of the UFSAR Supplement (Appendix A of the LRA) to verify 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 has reviewed the information provided in Section 62.2 of the LRA and the summary description of the Boraflex management activities in SectiorAA.2.2 of the UFSAR Supplement (Appendix A of the LRA). In addition, the staff considered the applicant's response to the staff's RAIs provided in a letter to the NRC dated May 14, 2002. On the basis of this review and the above evaluation, the staff found that there is reasonable assurance that the applicant has demonstrated that the effect of aging within the scope of this evaluation will be adequately managed with the Boraflex management activities so that the intended functions will be maintained consistent with the CLB for the period of extended operation as required by 10 CFR 54.21(a)(3). 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).

Fuel Pool Chemistry Program Fuel Pool Chemistry Activities The applicant described the fuel pool chemistry activities AMP in Section.1.6 of Appendix B of the LRA. The staff reviewed the applicant's description of the AMP in the CRA to determine whether the applicant has demonstrated that the fuel pool chemistry activities AMP will adequately manage the applicable effects of aging of components exposed to fuel pool water during the period of extended operation as required by 10 CFR 54.21 (a)(3).

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Technical Information in the Application In Section T1.6 of the LRA, the applicant identified the fuel pool chemistry activities AMP as an existing agilig manageme t r g that will be used by the applicant to manage loss of material of carbon stee..strainr ess steel components and cracking of stainless steel components exposed to fuel pool water in the fuel pool cooling and cleanup system. In addition, the applicant gill use the fuel pool chemistry AMP to manage loss of material of the carbon stee

• 'a s steel components of the fuel pool gates, fuel storage racks, fuel pool liner, component supports, fuel preparation machines, and refueling platform mast. The fuel pool water is demineralized. Fuel pool water quality is monitored periodically and maintained in accordance with station procedures that include recommendations from EPRI TR-103515, "BWR Water Chemistry Guidelines."

Staff Evaluation The staff's evaluation of the fuel pool chemistry activities focused on how the program manages aging effects through the effective incorporation of the following 10 elements: program scope, preventive actions, parameters monitored or inspected, detection of aging effects, monitoring and trending, acceptance criteria, corrective actions, confirmation process, administrative controls, and operating experience. The applicant indicates that the corrective actions, confirmation process, and administrative controls are part of the site-controlled quality assurance program. The staff's evaluation of the quality assurance program is provided separately in Section 3.0.4 of this SER. The remaining seven elements are discussed below.

Program Scope: The applicant stated that the fuel pool chemistry activities AMP manages loss of material and cracking of components exposed to fuel pool water in the fuel pool cooling and cleanup system. The fuel pool chemistry AMP also manages loss of material of carbon steel, a. 61,ftafa, and stainless steel components of the fuel pool gates, fuel storage racks, fuel pool liner, component supports, fuel preparation machines, and refueling platform mast. The AMP provides monitoring and controlling of detrimental contamination in the fuel pool water using the PBAPS procedures and processes based on EPRI TR-103515, "BWR Water Chemistry Guidelines" (the 2000 version). The staff found the scope of the program to be acceptable because it includes a comprehensive list of systems and components exposed to a fuel pool water environment.

Preventive or Mitigative Actions: The applicant indicated that the fuel pool chemistry activities AMP includes periodic monitoring and controlling of fuel pool water chemistry to maintain the contaminants within preestablished limits specified in EPRI TR-103515. The staff found that these procedures are adequate because they include all of the activities needed to mitigate age-related effects that are within the scope of license renewal.

Parameters Monitored or Inspected: The applicant identified the parameters to be monitored as conductivity, cllorides, and sulfates. The staff found these parameters acceptable because operating experience and the EPRI guidelines support the monitoring and control of these parameters to mitigate corrosion-related degradations and to ensure contaminants are not present in the fuel pool water.

Detection of Aging Effects: The applicant indicated that the fuel pool chemistry activities AMP mitigates the onset and propagation of loss of material and cracking aging effects; however, 3-216

detection of aging effects is not credited. The staff believes that there should be a one-time inspection program to verify the effectiveness of the fuel pool water chemistry control to mitigate loss of material of the carbon steel component exposed to fuel pool water. Therefore, in RAI B1.6-1, the applicant was requested to include a one-time inspection in this AMP or explain the basis for not including a one-time inspection.

In a letter dated May 14, 2002, the applicant stated that PBAPS operating experience verifies the effectiveness of the fuel pool chemistry activities. The carbon steel components in the fuel pool cooling system as listed in Table 3.3-2 of the LRA are in the line from the RHR system to the fuel pool. This line was opened up and visually inspected in 2001 for Unit 3 and the results were satisfactory. The inspection of the similar line for Unit 2 is expected to be performed in 2004. Based on the applicant's approach, the staff agrees that a one-time inspection program is not necessary to verify the effectiveness of the fuel pool water chemistry control to mitigate the loss of material of the carbon steel component exposed to fuel pool water.

The staff believes that there should be a one-time inspection to verify the absence of cracking of stainless steel components exposed to fuel pool water because the fuel pool water could contain contaminants. In RAI B1.6-2, the staff asked the basis for not including the one-time inspection program to manage cracking of stainless steel components exposed to fuel pool water. In the same letter dated May 14, 2002, the applicant state that the operating experience cited in the response to RAI B1.6-1 is also applicable;AI B1.6-2 for verifying the effectiveness of the fuel pool chemistry activities.

The applicant stated that EPRI TR-1 03840, "BWR Containment Ucense Renewal Industry Report," and NUREG-0313, "Technical Report on Material Selection and Processing Guidelines for BWR Coolant Pressure Boundary Piping," consider stainless steel susceptible to significant cracking only at operating temperatures above 200 OF. The fuel pool water normal operating temperature is 85 °F with a high limit of 130 OF. These temperatures are significantly lower than the 200 OF referenced in the EPRI report. Consequently, cracking is not considered to be a significant aging effect for the fuel pool liner and components requiring aging management beyond the fuel pool chemistry activities. The staff found the response acceptable and agrees thIat this AMP does not have aging detection capability and that Its use is to maintain a fuegarter chemistry environment that will minimize aging effects such as loss of material and cracking.

Monitoring and Trending: The applicant indicated that periodic sampling measurements are taken and analyzed, and the data are trended. The minimum frequency of sampling is once per day for conductivity and once per week for chlorides and sulfates based on EPRI TR-1 03515.

The staff found the frequency of sampling to be adequate in providing data for trending and that the fuel pool chemistry AMP would provide early indication of chemistry deviations, allowing for timely corrective action.

Acceptance Criteria: The specific limits of fuel pool chemistry are conductivity (S 2 pS/cm),

chlorides (;. 100 ppb), and sulfates (,. 100 ppb). The minimum sampling frequency is once a week. These parameters and their maximum levels and minimum frequency of measurements are based on the values specified in EPRI TR-103515 for the fuel pool water. The staff found these values acceptable because they are consistent with the EPRI guideline, which is based on operating experience and has proven effective.

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Operating Experience: The fuel pool chemistry activities AMP is an existing program. The applicant stated that components within the scope of license renewal have not experienced any loss of function such as failure of pressure boundary due to exposure to fuel pool water. The staff found that the fuel pool chemistry activities program has been effective in managing the aging effects associated with the systems and components exposed to fuel pool water.

UFSAR Supplement The staff reviewed Section A.1.6 of the UFSAR Supplement (Appendix A of the LRA) to yerfy that the information provided in the UFSAR Supplement for the aging management of syems and components discussed above is equivalent to the information in NUREG-1800 and therefore provides an adequate summary of program activities as required by 10 CFR 54.21(d).

Conclusions The staff has reviewed the information provided in Section BK1.6 of the LRA and the summary description of the fuel pool chemistry activities in Section A.1.6 of the UFSAR Supplement. On the basis of this review and the above evaluation, the staff found that there is reasonable assurance that the applicant has demonstrated that the effects of aging associated with the systems and components exposed to fuel pool water in the fuel pool cooling and cleanup system will be adequately mniaged so that the intended functions will be maintained consistent with the CLB for the period of extended operation as required by 10 CFR 54.21(a)(3). The staff also concludes that the UFSAR Supplement contains an adequate summary description of the program activities for managing the effects of agirn-for the systems and components discussed above as required by 10 CFR 54.21(d).

3.5.2.3 Conclusions The staff has reviewed the information in Section 3.5.2 of the LRA as well as the applicable aging management program descriptions in Appendix B of the LRA. On the basis of this review, the staff concludes that the applicant has demonstrated that the aging effects associated with the components in the reactor building structure will be maintained consistent with the CLB during the period of extended operation as required by 10 CFR 54.21(a)(3). 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).

3.5.3 Other Structures 3.5.3.1 Technical Information in the Application The aging management review results for structures outside containment are presented in Tables 3.5-3 through 3.5-12 of the LRA. Each of these aging management review tables lists the (1) component groups, (2) intended functions, (3) environments, (4) materials of construction, (5) aging effects, and (6) aging management activities. The structural*

components listed in Tables 3.5-3 through 3.5-12 of the LRA are in the following structures:

radwaste building and reactor auxiliary bay turbine building and main control room complex 3-218

a emergency cooling tower and reservoir a

station blackout structure and foundation 0

yard structures a

stack a

nitrogen storage building diesel generator building circulating water pump structure recombiner building A brief descnptio of each of the above structures is provided in Section 2.4 of the LRA. In response to RA4

, the applicant, by letter dated May 22, 2002, supplemented its LRA to include additional station-blackout-related SSCs that should be included within the scope of license renewal and subject to an AMR. The materials of construction are concrete, masonry block, steel, carbon and galvanized carbon, cast iron, aluminum, and gravel and sand.

The components of the structures outside containment are exposed to sheltered, outdoor, raw water, and buried environments.

3.5.3.1.1 Aging Effects 2.5-(

Tables 3.5-3 through 3.5-12 of the LRA and Table 2 of the response to RAI

-144.identify the following applicable aging effects for components in structures outside the reactor building and containment:

0 loss of material of carbon steel components in an outdoor environment change in material properties for reinforced concrete walls in a raw water outdoor environment cracking, loss of material, and change in material properties for concrete foundation, walls, slabs, and precast panels of station blackout structures in outdoor and sheltered environments cracking, loss of material, and change in material properties for masonry block walls in station blackout structures loss of material for galvanized carbon steel in station blackout structures in an outdoor environment 3.5.3.1.2 Aging Management Programs Tables 3.5-3 through 3.5-12 of the LRA credit only the Mainter7_-ce Rule Structural Monitoring Program with managing the aging effects for the components fn structures outside the reactor building and containment. Table 2 of the response to RAI It credits the Maintenance Rule Structural Monitoring Program with managing the aging effects for components in station blackout structures. A description of the Maintenance Rule Structural Monitoring Program is provided in Appendix B of the LRA. The applicant concludes that the effects of aging associated with the components in structures outside containment will be adequately managed by this AMP such that there is reasonable assurance that the intended functions will be maintained consistent with the CLB during the period of extended operation.

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3.5.3.2 Staff Evaluation In addition to Section 3.5 of the LRA, the staff reviewed the pertinent information provided in Section 2.4, "Scoping and Screening Results: Structures and Component Supports," and the applicable aging management program descriptions provided in Appendix B of the LRA to determine whether the aging effects for the components in structures outside the reactor building and containment have been properly identified and will be adequately managed during the period of extended operation as required by 10 CFR 54.21 (a)(3).

This section of this SER provides the staff's evaluation of the applicant's aging management review for the aging effects and the applicant's programs credited for the aging management of the components in structures outside the reactor building and containment at each Peach Bottom unit. The staff's evaluation includes a review of the aging effects considered and the basis for the applicant's elimination of certain aging effects. In addition, the staff has evaluated the applicability of the aging management programs that are credited for managing the identified aging effects for components in structures outside the reactor building and containment.

3.5.3.2.1 Aging Effects

/

Concrete and Masonry Block walls:

ables 3.5-3 through 3.5-12 of the LRA identify change in material properties as an applicable ging effect for the reinforced concrete walls of the emergency cooling tower and rese oir. For other concrete components in outdoor, sheltered, or buried environments, Table 3.5-through 3.5-12 do not identify any applicable aging effects.

Table 2 of the response to RAI identifies cracking, loss of material, and change in material properties as aging effects for concrete foundations, walls, slabs, and precast panels of station blackout structures in outdoor and sheltered environments.

As noted above in Section 3.5.1.2.1 of this SER, the staff considers loss of material, cracking, and change in material properties to be both plausible and applicable aging effects for all concrete components, including masonry block walls, in all of the environments listed by the applicant. The NRC staff position regarding the aging management of in-scope concrete structures and components (SCs) is that they need to be periodically inspected in order to adequately monitor their performance or condition in a manner that allows for the timely identification and correction of degraded conditions. In RAI 3.5-1, the staff requested further information regarding the applicant's determination that management of concrete aging is not required. In response to RAI 3.5-1, the applicant stated that it disagrees with the staff's position regarding the aging management of concrete structures; however, the applicant has decided that it will manage concrete and masonry block wall aging during the period of extended operation. The applicant specifically stated that it will monitor concrete and masonry block wall structures for loss of material, cracking, and change in material properties through the Maintenance Rule Structural Monitoring Program. Since this commitment from the applicant covers the outdoor and sheltered concrete components in structures outside the reactor building, this response is considered to be acceptable to the staff. RAI 3.5-1 is considered closed with respect to the concrete components in structures outside the reactor building.

For the buried concrete components in structures outside the reactor building, the staff has determined that aging management is unnecessary if applicants are able to show that the S---'ow-=

e

,soil/groundwater environment is nonaggressive. In response to RAI 3.5-1, the 3-220

applicant provided water chemistry results that show that the Peach Bottom soil/groundwater environment is nonaggressive (pH = 7.2, sulfates = 38 ppm, and chlorides = 24 ppm).

,h ;1,CCQ5$;blý._

Consequently, the applicant concluded that the aging management of beiew-gadrlconcreteqs ae.

not required. Since the groundwater chemistry at the Peach Bottom site is well above the limit for pH (5.5) and below the limits for sulfates (1500 ppm) and chlorides (500 ppm), the staff concurs with the applicant's conclusion thathlgoundc' er is*nnpaggressive with respect to concrete. Therefore, belew-ael-concrete1 oes noE to emanaged by the applicant.

Steel: The applicant identified loss of material of carbon steel components in an outdoor environment as an applicable aging effect for steel components in structures outside the reactor building.

The staff concurs with the aging effects identified above by the applicant for carbon steel exposed to an outdoor environment. However, the staff noted in Part 2 of RAI 3.5-2, that no aging effects are identified In Tables 3.5-3 through 3.5-12 for the carbon steel components in sheltered environments. In response to Part 2 of RAI 3.5-2, the applicant stated that it disagrees with the staff's position that carbon steel components in a sheltered environment require aging management. However, in response to RAI 3.5-2, the applicant committed to monitor carbon steel components in a sheltered environment for loss of material. This commitment includes all of the carbon steel components in structures outside the reactor building exposed to a sheltered environment for which the applicant did not originally identify any aging effects. Accordingly, the staff considers the applicant's response to RAI 3.5-2 with respect to carbon steel components in sheltered environments to be adequate.

For carbon steel in a buried environment, the applicant stated in its response to RAI 3.5-2 that:

The only carbon steel structural components in a buried environment, which are within the scope of license renewal, are foundation piles for the diesel generator building (Table 3.5-10). As discussed in the PBAPS Updated Final Safety Report (UFSAR) Section 12.2.5, the building is founded on steel H piles and concrete shear walls, which are supported on rock. Selection of steel piles is based on the results of foundation studies considering field explorations and laboratory tests. The piles are driven to refusal and designed for a maximum load of 60 tons per pile. They support only gravity loads while the shear walls support lateral loads.

The piles were driven into the redimed area of Conowingo Pond or in the backfilled areas where the rockwas excavated during plant construction.

According to EPRI TR-103842, Class I Structures License Renewal Industry Report: Revision I," and NUREG 1557, "Summary of Technical Information and Agreements form Nuclear Management and Resources Council Industry Reports Addressing Ucense Renewal," steel piles driven in undisturbed soils have been unaffected by corrosion and those drivd'in disturbed soil experience minor to moderate corrosion to a small area of the metal. Thus, the loss of material aging effect, due to corrosion, is non-significant and will not impact the intended function of piles.

The applicant's response is consistent with the staff position stated in NUREG-1557 regarding steel piles and is based on industry operating experience. As such, the staff considers the 3-221

applicant's response to be acceptable.

R.5.-,

Galvanized carbon steel: the applicant listed that galvalized carbon steel used in sheltered and outdoor environments in Table 2 of its response to RAW%6.

F.1 for structures and support components related to station blackout. The applicant identified loss of material as an aging effect for galvanized carbon steel in the outdoor environment and credited the Maintenance Rule Structural Monitoring Program With managing the aging effect. The applicant identified no aging effect for galvanized carbon steel in the sheltered environment. The staff considers the applicant's response to be acceptable.

Cast Iron: Table 3.5-11 of the LRA does not identify any aging effects for the cast iron/carbon steel sluice gates of the circulating water pump structure, which are exposed to a raw water ct#4.

sheltered environment. In RAI 3.5-3, the staff requested further information concerning the applicant's AMR for the cast iron/carbon steel sluice gates of the circulating water pump structure. In response, the applicant committed to monitor loss of material of the sluice gates using the Outdoor, Buried, and Submerged Component Inspection Activities. The applicant's response to RAI 3.5-3 is acceptable to the staff.

1 Aluminum: Table 2 of the applicant's response to RA*5t

'I for structures and support components related to station blackout structures lists aluminum used for supporting members, sidings, electrical and instrumentation enclosures, and raceways. The applicant states that there are no aging effects for aluminum and therefore no aging management activities are required for aluminum materials. This is consistent with industry experience and the staff accepts the applicant's assessment.

3.5.3.2.2 Aging Management Programs Tables 3.5-3 through 3.5-12 of the LRA credit only the Maintenance Rule Structural Monitoring Program with managing the aging effects for the components in structures outside the reactor building and containment. However, in response to RAI 3.5-3, the applicant committed to monitor loss of material of the cast iron/carbon steel sluice gates using the Outdoor, Buried, and Submerged Component Inspection Activities. Both the Maintenance Rule Structural Monitoring Program and the Outdoor, Buried, and Submerged Component Inspection Activities are credited with managing the aging of several components in several different structures and systems and are, therefore, considered common aging management programs. The staff review of the common aging management programs Is in Section 3.0 of this SER.

3.5.3.3 Conclusions The staff has reviewed the information in Sections 3.5.3 through 3.5.12 of the LRA as well as the applicable aging management program descriptions in Appendix B of the LRA. On the basis of this review, the staff concludes that the applicant has demonstrated that the aging effects associated with the components in structures outside the reactor building and containment will be adequately managed so that there is reasonable assurance that these components will perform their intended functions in accordance with the CLB during the period of extended operation as required by 10 CFR 54.21 (a)(3).

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3.5.4 Component Supports 3.5.4.1 Technical Information in the Application The aging management review results for component supports are presented in Table 3.5-13 of the LRA. Table 3.5-13 of the LRA identifies the component s.pprt groups, intended functions, environments, materials of construction, aging effects, and aging management activities.

The component groups for the component supports, as listed in Table 3.5-13 of the LRA, are support members, anchors, and grout.

Section 2.4.13 of the LRA states that the support member component group includes supports for piping and components, HVAC ducts, conduits, cable trays, instrumentation tubing trays, electrical junction and terminal boxes, electrical and I&C devices, instrument tubing, and supports for major equipment, including pumps, transformers, and HVAC fans and filters.

The anchor component group is the part of the component support assembly used to attach electrical panels, cabinets, racks, switchgears, enclosures for electrical and instrumentation equipment, pipe hangers, pumps, transformers, and HVAC fans and filters to other components or structures. Welds are used for steel attachments, and undercut anchors, expansion anchors, cast-in-place anchors, and grouted-in anchors are used for concrete attachments.

The grout component group includes grouted sypport pads and grouted base plates. Grout is used for constructing equipment pads and for filing and leveling equipment bases,5Erto their respective foundations.

aq The materials of construction for the component supports which are subject to aging management review are carbon steel, stainless steel, alloy steel, galvanized steel, aluminum, bronze, graphite, and grout.

The component supports are exposed to intemal (sheltered), outdoor, raw water, and torus water environments.

3.5.4.1.1 Aging Effects Table 3.5-13 of the LRA identifies the following applicable aging effects for the component supports:

loss of material for the emergency cooling water carbon steel anchors and support members exposed to an outdoor environment loss of material for carbon, alloy, and stainless steel support members exposed to a raw or torus water environment cracking of stainless steel support members exposed to torus water 3-223

3.5.4.1.2 Aging Management Programs Table 3.5-13 of the LRA credits the following aging management programs with managing the aging effects for the component supports:

ISI Program Torus Water Chemistry Maintenance Rule Structural Monitoring Program A description of these aging management programs is provided in Appendix B of the LRA. The applicant concludes that the effects of aging associated with the component supports will be adequately managed by these aging management programs such that there is reasonable assurance that the intended functions will be maintained consistent with the CLB during the period of extended operation.

3.5.4.2 Staff Evaluation In addition to Section 3.5 of the LRA, the staff reviewed the pertinent information provided in Section 2.4, "Scoping and Screening Results: Structures and Component Supports" and the applicable aging management program descriptions provided in Appendix B of the LRA to determine whether the aging effects for the component supports have been properiy identified and will be adequately managed during the period of extended operation as required by 10 CFR 54.21 (a)(3).

This section of this SER provides the staffs evaluation of the applicant's aging management review for aging effects and the applicant's programs credited for the aging management of the component supports at Peach Bottom. The staff's evaluation includes a review of the aging effects considered and the basis for the applicant's elimination of certain aging effects. In addition, the staff has evaluated the applicability of the aging management programs that are credited for managing the identified aging effects for the component supports.

3.5.4.2.1 Aging Effects Steel: The applicant identified loss of material for carbon steel component supports exposed to outdoor, raw water, and torus water environments. The applicant also identified loss of material for alloy and stainless steel components exposed to raw water and torus water environments.

In addition, the applicant identified cracking as an aging effect for stainless steel support members exposed to torus water.

The staff concurs with each of the above aging effects that were identified for steel component supports. However, the staff also considers loss of material to be an applicable aging effect for carbon steel component supports in sheltered environments. As such, in RAI 3.5-2, the staff requested that the applicant justify its AMR results, which did not identify any aging effects, for

'th **

carbon steel components in sheltered environments. In response to RAI 3.5-2, the applicant a

"stated that itýwll use the Maintenance Rule Structural Monitoring Prograrnfo manage loss of material for carbon steel component supports in sheltered environments. These additional D%

A40"°)

components, whose aging effects will now be managed during the period of extended 3-224

operation, are carbon steel anchors and support members. Since the applicant committed to manage loss of material for carbon steel component supports in sheltered environments, the staff considers RAI 3.5-2 closed.

Grout: Grout is used in the construction of equipment pads, and for filing leveling equipment bases and setting them to their respective foundations. The applicant didnot identify any applicable aging effects for grout and as a result, the staff requested in RAI 3.5-3 further information regarding this determination. In response, the applicant stated:

As in concrete components, PBAPS AMRs did not identify any aging effects for grout that will result in loss of intended function. As a result, we concluded that an aging management activity is not required. However, considering the staff's position on concrete, we will monitor accessible grout for cracking using the PBAPS Maintenance Rule Structural Monitoring Program.

The applicant's commitment to monitor grout for cracking is acceptable to the staff. Thus, RAI 3.5-3, with respect to grout, is considered closed.

Bronze/Graphite: Table 3.5-13 of the LRA does not identify any aging effects for the bronze/graphite Lubrite plates used as component supports. In Part 1 of RAI 3.5-3, the staff requested further information regarding the applicant's AMR for Lubrite plates. In response, the applicant stated:

Lubrite Is the trade name for a low-friction lubricant material used in applications where relative motion (sliding) is desired. At PBAPS, Lubrite plates are incorporated in the design of limited component supports to reduce or release horizontal loads due to temperature transients and SRV discharges.

PBAPS AMRs determined that there are no known aging effects for the Lubrite material that would lead to a loss of intended function. As explained by previous applicants and concurred by the staff, Lubrite resists deformation, has a low coefficient of friction, resists softening at elevated temperatures, absorbs grit and abrasive particles, is not susceptible to corrosion, withstands high intensities of radiation, and will not score or mar. In addition, lubrite products are solid, permanent, completely self-lubricating, and require no maintenance as documented in NUREG-1759, "Safety Evaluation Report Related to the License Renewal of Turkey Point Nuclear Plant, Units 3 and 4." A search of PBAPS and industry operating experience found no reported instances of lubrite plate degradation or failure to perform their intended function. On this basis, Exelon maintains that lubrite plates require no aging management.

The staff concurs with the applicant's response to RAI 3.5-3 with respect to the need for managing the aging of lubrite plates. The applicant's AMR of lubrite material is consistent with industry experience. The staff considers Part 1 of RAI 3.5-3 to be closed.

Aluminum: Aluminum is used for some of the support members. The applicant does not identify any aging effects for aluminum because the aluminum support members are located in 3-225

3.5.5.2.1 Aging Effects Elastomers: The applicant identified cracking, change in material properties, separation and delamination, and loss of sealing as applicable aging effects for the elastomers listed in Table 3.5-14 of the LRA. However, for the neoprene reactor building blowout panel seals and the silicone reactor building metal siding gap seals, the applicant did not identify any applicable aging effects. Therefore, in RAI 3.5-3, the staff requested that the applicant justify its AMR results for these two components. Regarding the neoprene reactor building blowout panel seals, the applicant stated:

PBAPS AMRs determined that the neoprene seals are susceptible to change in material properties and cracking, due to thermal exposure and ionizing radiation, only if the operating temperature exceeds 1600 F or the radiation exceeds 106 rads. The seals for the reactor building blowout panels are located in an environment where the temperature does not exceed 1120 F and the maximum total integrated gamma dose is less than 3.5 x 106 rads for 60 years. On this basis, the AMRs concluded that change in material properties and cracking aging effects are not applicable to the reactor building blowout panel seals.

Regarding the silicone reactor building metal siding gap seals, the applicant stated:

The silicone seal specified for the reactor building metal siding is either Dow Coming product No. 732 or 790. According to the Dow Coming materials group, the products are capable of sustaining long-term temperatures greater than 1580 F. The lowest threshold radiation dose for silicone Is 106 rads. The silicone seals for the reactor building metal siding are located in an environment where the temperature does not exceed 1J20 F and the maximum total integrated gamma dose is less than 3.5 x 10*Tads for 60 years. On this basis, PBAPS AMRs concluded that change in material properties and cracking aging effects are not applicable to the reactor building metal siding silicone seals.

Since the temperature and radiation limits for the neoprene blowout panel seals and the silicone metal siding gap seals are well above the actual values for the reactor building, the staff concurs with the applicant's determination that there are no applicable aging effects for these two components. The staff finds that the applicant has properly identified the applicable aging effects for the elastomers.

Fire Proofing: For the fire proofing wraps, the applicant identified change in material properties and loss of material as applicable aging effects. The staff finds that the applicant has properly identified the applicable aging effects for the fire proofing wraps.

Steel: For the carbon steel hazard barrier doors, the applicant identified loss of material as an applicable aging effect for the doors that are exposed to an outdoor environment. For the carbon steel hazard barrier doors in a sheltered environment, the applicant did not identify loss of material as an applicable aging effect. In RAI 3.5-2, the staff requested that the applicant justify Its determination that loss of material is not an applicable aging effect for carbon steel hazard barrier doors in a sheltered environment. In response to RAI 3.5-2, the applicant committed to monitor loss of material due to corrosion for the carbon steel hazard barrier doors in a sheltered environment. The staff finds the applicant's commitment to be acceptable.

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3.5.5.2.2 Aging Management Programs Table 3.5-14 of the LRA credits the following aging management programs with managing the identified aging effects for the hazard barriers and elastomers:

Door Inspection Activities Fire Protection Activities Maintenance Rule Structural Monitoring Program Primary Containment ISI Program Each of the above programs is credited with managing the aging of several components in various different structures and systems and are, therefore, considered common aging management programs. The staff review of the common aging management programs is in Section 3.0 of this SER.

3.5.5.3 Conclusions The staff has reviewed the information in Section 3.5 of the LRA as well as the applicable aging management program descriptions in Appendix B of the LRA. On the basis of this review, the staff concludes that the applicant has demonstrated that the aging effects associated with the hazard barriers and elastomers will be adequately managed so that there is reasonable assurance that these components will perform their intended functions In accordance with the CLB during the period of extended operation as required by 10 CFR 54.21 (a)(3).

3.5.6 Miscellaneous Steel 3.5.6.1 Technical Information in the Application The aging management review results for miscellaneous steel components are presented in Table 3.5-15 of the LRA. Table 3.5-15 of the LRA identifiesithe compone-ntl roups, (2) intended functions, (3) environments, (4) materials of construction, (5) aging effects, and (6) aging management programs.

Section 2.4.15 of the LRA states that the miscellaneous steel group includes platforms, grating, stairs, ladders, steel curbs, handrails, kick plates, decking, instrument tubing trays, and manhole covers. Each of the miscellaneous steel components listed in Table 3.5-15 of the LRA is constructed of carbon steel and exposed to either a sheltered or an outdoor environment.

3.5.6.1.1 Aging Effects Table 3.5-15 of the LRA does not identify any applicable aging effects for the miscellaneous steel components.

3.5.6.1.2 Aging Management Programs Since there are no aging effects identified for the miscellaneous carbon steel components in Table 3.5-15 of the LRA, the applicant does not credit any aging management programs.

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result, aging management of manhole covers is not required.

The staff concurs with the applicant's determination that the manhole covers are rugged, heavy-duty materials that have withstood severe environments with little degradation for long periods of time. Therefore, aging management of the manhole covers is unnecessary.

3.5.6.2.2 Aging Management Programs Table 3.5-15 of the LRA does not list any aging management programs for the miscellaneous steel components; however, in response to RAI 3.5-2 the applicant has committed to using the Maintenance Rule Structural Monitoring Program to manage the aging effects for the miscellaneous steel components in sheltered environments. The Maintenance Rule Structural Monitoring Program is credited with managing the aging of several components in various different structures and systems and is, therefore, considered a common aging management program. The staff review of the common aging management programs is in Section 3.0 of this SER.

3.5.6.3 Conclusions The staff has reviewed the information in Section 3.5 of the LRA as well as the applicable aging management program descriptions in Appendix B of the LRA. On the basis of this review, the staff concludes that the applicant has demonstrated that the aging effects associated with the miscellaneous steel components will be adequately managed so that there is reasonable assurance that these components will perform their intended functions in accordance with the CLB during the period of extended operation as required by 10 CFR 54.21 (a)(3).

3.5.7 Electrical and Instrumentation Enclosures and Raceways 3.5.7.1 Technical Information in the Application The aging management review results for electrical and Instrumentation enclosure and raceway component group are presented in Table 3.5-16 of the LRA. Table 3.5-16 of the LRA identifies the component 1 groups, (2) intended functions, (3) environments, (4) materials of construction, (5) aging effects, and (6) aging management programs.

Section 2.4.16 of the LRA states that the electrical and instrumentation enclosures and raceways group includes cable trays, cable tray covers, drip shields, rigid and flexible electrical conduits and fittings, wireway gutters, panels, cabinets, and boxes.

The materials of construction for the electrical and instrumentation enclosures and raceways are carbon steel, aluminum, and galvanized carbon steel.

The electrical and instrumentation enclosures and raceways are exposed to both sheltered and outdoor environments.

3.5.7.1.1 Aging Effects Table 3.5-16 of the LRA does not identify any applicable aging effects for the electrical and instrumentation enclosures and raceways.

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electrical and instrumentation enclosures and raceways should be minimiaI.Therefore, the staff considers RAI 3.5-2 to be closed with respect to the electrical and instrumentation enclosures and raceways.

Aluminum: Aluminum is used for some of the electrical and instrumentation enclosures and raceways. The applicant states that there are no aging effects for aluminum and therefore no aging management activities are required for aluminum materials. This is consistent with industry experience and the staff accepts the applicant's assessment.

3.5.7.2.2 Aging Management Programs Since no aging effects are identified in Table 3.5-16 of the LRA, no aging management programs are listed for the electrical and instrumentation enclosures and raceways.

3.5.7.3 Conclusions The staff has reviewed the information in Section 3.5 of the LRA. On the basis of this review, the staff concludes that the applicant has demonstrated that there are no aging effects for the electrical and instrumentation enclosures and raceways.

3.5.8 Insulation 3.5.8.1 Technical Information in the Application The aging management review results for the insulation commodity group are presented in Table 3.5-17 of the LRA. Table 3.5-17 of the LRA identifieshe component 1 groups, (2) intended functions, (3) environments, (4) materials of construction, (5) aging effects, and (6) aging management programs.

.4 Section 2.,V17 of the LRA states that the insulation commodity group includes all insulating materials within the scope of license renewal that are used in plant areas where temperature control is considered critical for system and component operation or where high room temperatures could impact environmental qualification. The plant areas that require temperature control are the interiors of drywall, the HPCI and RCIC pump rooms, and the outboard MSIV rooms. Outdoor piping and components also require heat tracing for freeze protection.

The insulation materials include stainless steel and aluminum mirror insulation and fiberglass blanket insulation with either stainless steel or aluminum jacketing. Other insulation materials are calcium silicate or fiberglass blankets covered by an aluminum jacket. Equipment insulation consists of either calcium silicate blocks or removable ceramic-fiber blankets.

Insulation at Peach Bottom is found in both sheltered and outdoor environments.

3.5.8.1.1 Aging Effects Table 3.5-17 of the LRA identifies insulation degradation as an applicable aging effect for the aluminum insulation jacketing with stainless steel straps that is exposed to an outdoor environment 3-233

staff concludes that the -applicant has demonstrated that the aging effects associated with the insulation will be adequately managed so that there is reasonable assurance that this component~will perform its intended function in accordance with the CLB during the period of extended operation as required by 10 CFR 54.21(a)(3).

3.6 Aging Management of Electrical and Instrumentation and Controls The applicant described its AMR results for the Peach Bottom electrical/i&C components requiring AMR in Section 3.6 of the LRA. The applicant stated that Tables 3.6-;1, 3.6&, and 3.6xS provided the results of the aging management reviews for the electrical commodities and station blackout system components within the scope of license renewal and that are subject to an aging management review. Because the commodities are not associated with one particular system but could be in any in-scope system, they were evaluated using a "spaces" approach.

The spaces evaluation was based on areas where bounding service environmental parameters were identified. For example, the temperature bounding service environmental parameter is the highest average service temperature present in the defined space, taking into account the ambient temperature (and ohmic heating where applicable). This bounding value is then

.compared to the 60-year limiting service temperature. The 60-year limiting service temperature is the temperature at which the insulation material experiences no aging effect which would cause the insulation material to lose its intended function for the period of extended operation.

The process used to perform an aging management review of a commodity or component group for a specific environmental stressor is as follows:

0 Identify the component group materials of construction.

Identify the aging effects for the component group when exposed to the environmental stressor.

0 Determine the value of the bounding service environmental parameter to which the.

component groups in the area to be reviewed are exposed.

a Compare the aging characteristics of the identified materials in the bounding service environmental parameter against the 60-year limiting service environmental parameter, and determine If the component groups are able to maintain their intended function during the period of extended operation.

The staff reviewed this section of the application to determine whether the applicant has demonstrated that the effect of aging on the electricaVl&C components will be adequately managed during the period of extended operation as required by 10 CFR 54.21 (a)(3).

3.6.1 Cables 3.6.1.1 Technical Information in the Application In Section 2.5.1 of the LRA, the applicant stated that there are approximately 39,000 installed cables at PBAPS. Electrical cables were treated as a commodity group during the aging management review process. This group includes all documented cables within the scope of 3-235

license renewal that are used for power, control, and instrumentation applications. The intended function of electrical cables is to provide electrical connections to specified sections of an electrical circuit to deliver voltage, current, or signals. Electrical cables are located in sheltered environment. Although EQ cables are reviewed as TLLAs, all documented cables, whether EQ or Non-EQ, were assumed to be in scope and to require aging management review.

The applicant indicated that cable insulation material groups for both safety-related and non safety-related cables were assessed on the basis of common materials and their respective material aging characteristics.

The applicant used the plant database as the primary tool to identify cable insulation groups and to screen electrical cables for the cable aging management review. The database contains a cable code. The cable code identifies a unique cable size, application (power, control, or instrumentation), and insulation. Cable insulation groups and their applications were the determining factors in performing the assessment against bounding parameters.

The electrical cable aging management review for radiation and temperature utilized a plant "spacese approach, whereby aging effects were identified and bounding environmental parameters were used to evaluate the identified aging effects with respect to component intended function.

3.6.1.1.1 Aging Effects The applicant states that the stressors potentially affecting loss of material properties for cables at PBAPS are moisture, temperature, and radiation.

Moisture is of concern because of a phenomenon called "water treeing." To be identified as being susceptible to aging effects caused by water treeing, a Non-EQ cable must be exposed 3 4..!

to long-term standing water, be energized more than 25% of the time, carry medium voltage WkV for PBAPS), and be constructed of insulation material containing a void or impurity (inclusion, flaw).

The industry and manufacturers recognized this Issue in the late 70s. Improved formulations (more resistant to water treeing) have been available and used since 1980. PBAPS recognized this issue and initiated a cable replacement program in 1995 to replace "suspected" cables that met the water treeing criteria described above. No cable failures have occurred at PBAPS since the cable replacement program was initiated. The applicant concluded that moisture is not an aging effect requiring management at PBAPS.

The remaining stressors affecting loss of material properties of cable insulation at PBAPS are temperature and radiation. Applying the =spaces" approach to the identification of the temperature and radiation stressors was a primary focus for the aging management review of cables. Maintaining adequate dielectric properties of the cable insulation is essential for ensuring that the electrical cables perform their intended function.

A review of cable insulation aging effects from radiation was performed by comparing the lowest radiation cable insulation with the highest radiation area where cables that support components within the scope of license renewal may be present in the plant. The value used 3-236

for the highest radiation area was obtained by multiplying the existing radiation design value by 0

1.5 to obtain the 60-year value, an hen adding the accident VosT

-Alf other cable insulation types were bounded by this analysis. No cables requiring 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:

Computer 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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0 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 Groups 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 "suspected" 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 maximum operatin doses of insulation material (1.5 times the existing radiation design va luls t*e*ent dos) will -

v not exceed the 60-year service limiting radiation dose. The maximum operating temperature 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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3.6.1.2 Staff Evaluation The staff evaluated the information on aging management presented in LRA, Sections 2.5.1and 3.6 and in the applicant's response to the staff RAIs dated January 2 and April 29, 2002. The staff evaluation was conducted to determine if there is a reasonable assurance that the applicant has demonstrated that the effects of aging will be adequately managed, consistent with its CLB throughout the period of extended operation, in accordance with 10 CFR 54.21 (a)(3). This section of this SER provides the staff's evaluation of the applicant's aging management review of aging effects and the applicant's program credited for the aging management of insulated cables at Peach Bottom. The staff's evaluation includes a review of the aging effects considered. In addition, the staff has evaluated the applicability for the aging management program that is credited for managing the identified aging effects for the insulated cables.

3.6.1.2.1 Aging Effects A cable replacement program was initiated in 1995 to replace "suspected" cables that met the water treeing criteria. Water treeing is moisture intrusion to the cable insulation that results in a decrease In the dielectric strength of the conductor insulation, which in turn results in cable failure. The applicant concluded that moisture is not an aging affect requiring management at PBAPS. It was not clear to the staff why moisture has not been an aging effect requiring management at Peach Bottom since the cables were replaced. The staff requested that the applicant provide details about the cable replacement program and explain why moisture is not an aging effect requiring management for these new cables. In a response dated January 2, 2002, the applicant stated that water treeing affects cable insulation materials having an ethylene polymer base. Water treeing has been shown to occur predominately in cables with cross-linked polyethylene (XLPE) insulation. The cable manufacturers and the utility industry recognized the water treeing phenomenon in the 1970s and improved formulations (resistant to water treeing) of XLPE cable insulation used in underground applications since 1980.

PBAPS experienced a series of nonsafety cable failures between 1984 and 1991, when XLPE insulated 5kV and 15kV cables failed with no cause Initially identified. Analyses attributed one failure, in 1991, to water treeing. Further analysis on the other cable samples was conducted, and evidence of water trees was found in six cases. The trees were found to be extensive in some cases. A cable replacement program was Initiated at PBAPS In 1995 and completed in 1999 on "suspected" cables subjected to the collective conditions listed above. The replacement cable was ethylene propylene rubber (EPR) insulated cable, pink in color, which has a low level of crystallinity with a poly-vinyl-chloride (PVC) jacket, suitable for use in wet or dry location in conduit, underground duct system, or direct buried, or aerial installations. The cables are rated for a minimum of 90 °C for normal operation, 130 0C for emergency loading operation, and 250 °C for short circuit conditions. The basic construction of the cable is either single-conductor Class B stranded base copper or aluminum, with extruded semiconducting strand screen, EPR insulation, extruded semiconducting insulation screen, bare copper shielding tape, and PVC jacket. A review of the PBAPS operating history has determined that no additional cable failures, caused by the effects of water treeing, have occurred at PBAPS since the cable replacement program was completed.

The applicant also provided a summary of a paper, "An Ossessment of Field Aged 15kV and 35kV ¶Wylene Propylene Rubber Insulation Cables," published in the 1994 T&D Conference 3-239

Proceedings in support of not having an aging management program for medium-voltage cables exposed to an adverse localized environment caused by moisture-produced water trees and voltage stress. It was not clear to the staff that the information in the paper is adequate for not having an AMP for medium-voltage cables exposed to an adverse localized environment caused by moisture-produced water trees and voltage stress. The staff requested the applicant to provide an aging management program for accessible and inaccessible medium-voltage (2kV-15kV) cables (e.g., installed in conduit or direct buried) exposed to an adverse localized environmental caused by moisture-produced water trees and voltage stress. In a response dated April 29, 2002, the applicant reiterated its view and stated that PBAPS elected to replace cables suspected to be susceptible to water treeing. Since the replacement cables were suitable for use in wet environment, the applicant believes that moisture is not an aging effect requiring management at PBAPS.

The applicant also stated that a review of the manufacturer's Product Data Sheet, Section 2, Sheet 9, for Okoguard-Okoseal Type MV-90 cable. The paragraph under the heading Applications states: "Type MV cables may be installed in wet or dry environments, indoors or outdoors (exposed to sunlight), in any raceway or underground duct." The paragraph headed "Product Features" additionally states that "triple tandem extruded, all EPR system, Okoguard cables meet or exceed all recognized industry standards (UL, AEIC, NEMANICEA, IEEE),

moisture resistant, exceptional resistance to water treeing." The above information is repeated in the manufacturer's specification, and provides a warrantee for cable failure due to defects in material or workmanship for 40 years.

The applicant believed that choosing cable capable of being installed in a wet location removes the potential for water treeing to occur. In addition, the applicant stated that a review of the PBAPS operating history has discovered no additional cable failures caused by the effects of water treeing have occurred at PBAPS since the cable replacement program was completed.

The staff acknowledges that the EPR-insulated replacement cable is more resistant to water treeing. However, the staff still does not accept the applicant's positions that moisture is not an aging effect requiring aging management for these cables. The staff believes that the discussion and conclusion of the paper, "Assessment of Field Aged 15kV and 35kV Ethylene Propylene Rubber Insulated Cables," do not support the applicant's position that moisture is not an aging effect requiring management at PBAPS. For example, the paper concludes that aging of the EPR-insulated cables can be characterized by an increase in moisture content, growth of water trees, drop in Insulation elongation, increase in dissipation factor, and decrease in AC and impulse voltage breakdown strength. Further, the data for water trees, elongation, dissipation factor, and AC and impulse strength indicate that EPR insulated cable deterioration appears to result from moisture permeating the insulation of the cable. Therefore, the applicant has not provided a sufficient technical justification for not requiring an aging management program for inaccessible medium-voltage cables and has not proposed to prevent such cables from being exposed to significant moisture, such as inspecting for water collection in cable manholes and conduit and draining water, as needed. This Is part of Open Item 3.6.1.2.1-1.

The additional part of this open item is discussed in Section 3.6.3.2.1 of this SER.

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 maximum g rtirm doses of insulation material (1.5 times the existing radiation design valueP-us the accident dos w

"-no 3-240

The applicant further states that as discussed in LRA Section 2.5M and Exhibit 2.5-1, Non-EQ cables in the steam tunnel were reviewed to identify if they supported any in-scope license renewal loads. None were identified. Non-EQ cables in the drywell were reviewed to identify if they support any in-scope license renewal loads. An adverse localized equipment environment was identified in the drywell for certain PVC cables. Through cable aging management review, the drywell was found to be the only adverse localized equipment environment at PBAPS for in scope, Non-EQ cables. These cables in the drywell are PVC-insulated cables, and are used to provide safety relief valve discharge temperatures to control room temperature recorders in support of FSSD. The FSSD cables have their own aging management program, as described in LRA Section B.3.2.

Although the applicant believes a thorough review of cable insulation types was performed against the PBAPS design parameters for temperature and radiation in the presence of oxygen, and a plant walkdown did not identify any adverse localized equipment environments outside the drywell or steam tunnel, the applicant agrees to implement a Non-EQ accessible cable inspection program consistent with GALL Program XI.E1.

Table 3.6-1 of the LRA will be revised to reflect this new activity. Since all accessible cables installed in an adverse environment, including power, control, and instrumentation cables will be inspected, Table 3.6-1will not differentiate between insulation types as is shown in the original application.

Table 3.6-1 Aging Management Review Results for Cable Component Component Environment Material of Aging Effect Aging Group Intended Construction Management Function Activity Electrical Electrical Sheltered Metallic Loss of Non-EQ Cables Continuity conductor material Accessible with various properties Cable Aging types of Management organic Activity insulation (B.3.3)

(XLPE, EPR, EP, SR, etc.)

Electrical Electrical Sheltered Metallic Loss of FSSD Cable Cables Continuity conductor material Inspection with polyvinyl properties Activity chloride (B.3.2)

(PVC) insulation Appendix B.3, "New Aging Management Activities," will be revised to reflect this new activity.

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The staff finds the applicant's response acceptable because it will implement an aging management program for Non-EQ accessible cable to manage aging effects for cables in adverse localized environment caused by heat or radiation that has been reviewed by the NRC staff in GALL and found to be acceptable.K 3.6.1.2.2 Aging Management Program FSSD Cable Inspection Activities The staff evaluated the information on aging effects caused by significant moisture and significant voltage, heat, and radiation, as presented in Section 2.5.1 of the LRA, to determine if there is a reasonable assurance that the applicant has demonstrated that the aging effects for accessible and inaccessible Non-EQ cables will be adequately managed, consistent with the applicant's CLB for the period of extended operation.

The staff asked the applicant (NRC question 22 of September 24-25, 2001 meeting) if the FSSD cable inspection activities are for instrumentation circuits. In response the applicant stated in a letter dated January 2, 2002, that the cable inspection activity for the FSSD cables do not apply to instrumentation circuits. The FSSD cables are connected to thermocouples on the discharge of the steam relief valves (SRVs) in the drywell, and provide temperature information to a recorder in the control room. The recorder provides both annunciation and input to the plant computer when an input signal Is outside a preset allowable range. Although this arrangement may be considered a type of instrument circuit, it is not "loop checked" like a true instrument circuit, but provides direct readings to the recorder. The primary concern is with the PVC insulation surrounding the thermocouple metallic conductors, not with the metallic conductors themselves. With that in mind, It was considered that the most adequate inspection activity would be a visual inspection of PVC insulation consistent with GALL Report Program XI.E1, "Electrical Cables and Connections Not Subject to 10 CFR 50.49 Environmental Qualification Requirements." Program XI.E2, "Electrical Cables Not Subject to 10 CFR 50.49 Environmental Requirements Used in Instrument Circuits," uses a combination of routine calibration and surveillance tests to identify the potential existence of aging degradation. This was considered to be an Inadequate activity to identify the potential aging degradation of the PVC insulation of FSSD cables. The staff agrees with the applicant because FSSD cables are not for Instrumentation circuits and visual inspection program is adequate for FSSD cable.

Staff Evaluation The staff reviewed the FSSD cable inspection activity to determine whether it will ensure that all FSSD cables will continue to perform their Intended function consistent with the CLB for the period of extended operation. The staff's evaluation of the FSSD cable Inspection activity focused on how the program manages the aging effect through effective incorporation of the following 10 elements: program scope, preventive action, parameters monitored or inspected, detection of aging effects, monitoring and trending, acceptance criteria, corrective actions, confirmation process, administrative controls, and operating experience.

The application indicated that the corrective action elements, which includes the confirmation process to assure that the cause of the condition is detenin pand corrective action taken to preclude repetition, was credited for license renewal. &

=

procedure AD-AA-1 01, "Processing of Procedures and T&RMs" governs creation and revision of site procedures and 3-243

was the basis for the administrative control element in all PBAPS LRA Appendix B programs.

The corrective action program and procedure AD-AA-101 are in accordance with the PBAPS Quality Assurance Program, which complies with 10 CFR Part 50, Appendix B. The staff's evaluation of the applicant's corrective action, corifirmation process, and administrative controls is provided separately in Section 3.0.4 of safety evaluation report. The remaining seven elements are discussed below.

C Program Scope: The scope of the activity includes evaluation of PVinsulated fire safe shutdown cables in the drywell that are within the scope of license renewal. The staff found the scope of the program acceptable because the program includes all insulated fire safe shutdown cables that are subject to potentially adverse localized environments.

Preventive Actions: FSSD cable inspection activities will be conducted for condition monitoring purposes. No preventive or mitigating attributes will be associated with FSSD cable inspection activities and the staff did not identify the need for such actions.

Parameter Monitored/Inspected: The PVC insulation will be visually inspected for surface anomalies such as embrittlement, discoloration, or cracking. The staff found this approach to be acceptable because it provides means for monitoring the applicable aging effects of FSSD cables.

Detection of Aging Effects: FSSD cable inspection activities will identify anomalies in the PVC insulation surface that are precursor indications of a loss of material properties for PVC insulated cables. The staff found this activity to be acceptable on the basis that cable inspection activity is focused on detecting change in material properties of the conductor insulation, which is the applicable aging effect when cables are exposed to higher temperature.

Monitoring and Trending: Sample size of the inspection will be identified in the inspection activity. The PVC-insulated FSSD cables will be inspected once every 10 years. The applicant clarified that the first inspection will be performed before the end of the initial 40-year license term. Trending actions are not included as part of this program because the ability to trend inspection results is limited. The staff found that the 10-year inspection frequency will adequately preclude failures of the conductor insulation since aging degradation is a slow process. A 1 0-year inspection frequency will provide two data points during a 20-year period, which can be used to characterize the degradation rate. The visual technique is acceptable because it provides indication that can be visually monitored to preclude aging effects of FSSD cables. The staff also found that the absence of a trending acceptable.

Acceptance Criteria: Acceptance will require that no unacceptable visual indications of insulation surface anomalies exist that would suggest that the insulation has degraded, as determined by engineering evaluation. An unacceptable indication will be defined as a noted condition or situation that, if left unmanaged, could lead to a loss of the intended function. The staff found this acceptance criterion to be acceptable because it should ensure that the intended function of the cables is maintained under all CLB design conditions during the period of extended operation.

Operating Experience: No age-related PVC-insulated FSSD cable failures have occurred at PBAPS. The staff found that the pro0posed inspection program will detect the adverse localized environment of FSSD cables.

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for monitoring the applicable aging affects for accessible in-scope Non-EQ insulated cables and connections.

Detection of Aging Effects: Conductor insulation aging degradation from heat, radiation, or moisture in the presence of oxygen causes cable and connection jacket surface anomalies.

Accessible electrical cables and connections installed in adverse localized environments are visually inspected at least once every 10 years. This is an adequate frequency to preclude failures of the conductor insulation since experience has shown that aging degradation is a slow process. A 1 0-year inspection frequency will provide two data points during a 20-year period, which can be used to characterize the degradation rate. The first inspection for license renewal is to be completed before the period of extended operation. The staff found that a 10-year inspection frequency is an adequate period to preclude failures of the conductor insulation since aging degradation is a slow process. The visual technique is acceptable because it provides indication that can be visually monitored to preclude aging effects of accessible cables and connections.

Monitoracand Trending: Trending actions are not included as part of this program because the ability to trend inspection results is limited. The staff found the absence of trending acceptable because this Inspection program is a new program.

Acceptance Criteria: The accessible cables and connections are to be free from unacceptable, visual indication of surface anomalies which suggest that conductor insulation or connection degradation exists. An unacceptable indication is defined as a noted condition or situation that, if left unmanaged, could lead to a loss of the intended function. The staff found the acceptance criterion acceptable because it should ensure that the intended functions of the cables and connections are maintained under all CLB design conditions during the period of extended operation.

Operat§lk Experience: Industry operating experience has shown that adverse localized environments caused by heat or radiation may exist for electrical cables and connections next to or above (within 3 feet of) steam generators, pressurizers, or hot process pipes such as feedwater lines. These adverse localized environments have been found to cause visually observable degradation (e.g. color changes or surface cracking) of the insulating materials on electrical cables and connections. These visual indications can be used as indicators of degradation. No age-related insulated Non-EQ cable failures due to adverse localized equipment environments have occurred at PBAPS. The staff found that the proposed inspection program will detect the adverse localized environments caused by heat or radiation of electrical cables and connections.

UFSAR Supplement The staff reviewed the proposed Section A.3.3 of the UFSAR Supplement (Appendix B of the LRA) to verify 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-1800 and therefore provides an adequate summary of program activities as required by 10 CFR 54.21(d). However, to be consistent with the commitment made in response to RAI 3.6-1, the applicant needs to provide a summary of description of the B.3.3, "Non-EQ 3-246

accessible cable aging management activity" in the UFSAR Supplement. This Is Confirmatory Item 3.6.1.2.2-1.

Conclusions The staff concludes that the applicant has demonstrated that the aging effects associated with Non-EQ accessible cable aging management activity 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 54.21 (a)(3). The staff also concludes that, with the exception of Confirmatory Item 3.6.1.2.2-1, 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).

In response to the staff's request for an aging management program (PAl 3.6-1) for accessible and inaccessible electrical cables used in instrumentation circuits that are sensitive to reduction in conductor insulation resistance and exposed to an adverse localized environment caused by heat or radiation, the applicant states that it understands that the staff is requesting a program similar to GALL Report Program XI.E2, "Electrical Cables Not Subject to 10 CFR 50.49 Environmental Qualification Requirements Used in Instrumentation Circuits," which uses routine calibration tests performed as part of the plant surveillance test program to identify the potential existence of aging degradation of cables and connections used in low-level-signal instrumentation that are sensitive to reduction in insulation resistance (IR) such as radiation monitoring and nuclear instrumentation.

The applicant stated that visual inspection can detect degradation early in the aging process whereas embrittlement and cracking must occur before significant electrical property changes, such as reduced resistance, would be detected through circuit calibration. Section 5.2.2, "Measurement of Component or Circuit Properties," of SAND96-0344, "Aging Management Guideline for'Commercial Nuclear Power Plants - Electrical Cable and Terminations," dated September 1996, states, Significant changes in mechanical and physical properties (such as elongation at-break and density) occur as a result of thermal-and radiation-induced aging.

For low-voltage cables, these changes precede changes to the electrical performance of the dielectric. Essentially, the mechanical properties must change to the point of embrittlement and cracking before significant electrical changes are observed...

The industry understands that these two GALL programs (XI.E1 and XI.E2) manage the same aging effects for the same cables in different ways. This is seen as providing an applicant with the b to pick the program that best fits the needs identified at the plant. Both programs are notbfrequired to adequately manage aging of plant cables. Calvet Cliffs committed to the calibration program (XI.E2) but not to the Inspection program, and Oconee committed to the inspection program (XI.E1) but not the calibration program. The industry saw this as a precedent and understood as being included in the GALL Report: the two programs cover the same cables using different methods to manage aging, and the applicant can choose a program that best fits the plant aging management requirements.

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The staff notes that purpose of GALL Program XI.E1 is to provide reasonable assurance that the intended function of Non-EQ electrical cables and connections that are exposed to adverse localized environments caused by heat or radiation will be maintained consistent with the CLB through the period of extended operation. The cables included in this program do not include sensitive, low-signal-level instrumentation circuits or medium-voltage power cables. In Program XI.E1 a representative sample of accessible electrical cable and connection in adverse localized environments is visually inspected for cable and connection jacket surface anomalies.

If an unacceptable condition or. situation is identified for a cable or connection in the inspection sample, a determination is made as to whether the same condition is applicable to other accessible or inaccessible cables or connections. The purpose of GALL Program XI.E2 is to provide reasonable assurance that the intended functions of Non-EQ electrical cables that are used in sensitive low-level-signal circuits exposed to adverse localized environments caused by heat, radiation, or moisture will be maintained consistent with the CLB through the period of extended operation. In this program routine calibration tests performed as part of the plant surveillance test program are used to identify the potential existence of aging degradation.

When an instrumentation loop is found to be out of calibration during routine surveillance testing, trouble shooting is performed on the loop, including the instrumentation cable. Thus, the two program cover different cables using different methods.

The aging management activity submitted by the applicant does not utilize the calibration approach for Non-EQ electrical cables used in circuits with low-level signals. Instead, these cables are simply combined with other Non-EQ cables under the visual inspection activity. The staff believes, however, that visual inspection alone may not necessarily detect reduced insulation resistance (IR) levels in cable insulation before the intended function is lost.

Exposure of electrical cables to adverse localized environments caused by heat or radiation can result in reduced IR. A reduction in IR will cause an increase in leakage current between conductors and from individual conductors to ground, and is a concern for circuits with sensitive low-level signals such as in radiation and nuclear instrumentation since reduced IR may contribute to inaccuracies in instrument loop. Because low-level-signal instrumert.ion circuits may operate with signals that are normally in the picoamp range or less, they canqaffected by extremely low levels of leakage current. Routine calibration tests performed as part of the plant surveillance test program can be used to identify the potential existence of this aging degradation.

The staff was not convinced that aging of these cables will initially occur on the outer casing, resulting in sufficient damage that visual inspection will be effective in detecting the degradation before IR losses lead to a loss in intended function, particularly if the cables are also exposed to moisture. The staff undertook its own review of several aging management references. Page 3-52 of the SAND96-0344 report referenced by the applicant identifies polyethylene-insulated instrumentation cables located in close proximity to fluorescent lighting that had developed spontaneous circumferential k inWsed portions of the insulation. For some of the affected cables, the cracking was enough to expose the underlying conductor; however, no operational failures were documented as a result of this degradation.

Section 5.2.2 of SAND 96-0344 only assumes dry conditions where cable cracking occurs.

"Aging and Life Extension of Major Light Water Reactor Components" edited by V.N Shaw and P.E. MacDonald on page 855 state that breaks in insulation systems that are dry and clean are normally not detectable with insulation resistance tests for 1000V or less. On the same page they also state that insulation resistance tests can detect some types of gross insulation 3-248

managed, consistent with its CLB throughout the period of extended operation, in accordance with 10 CFR 54.21(a)(3). This section of the SER provides the staff's evaluation of the applicant's aging management review for aging effects and the applicant's aging management program credited for the aging management of connectors, splices, and terminal blocks at Peach Bottom. The staff's evaluation includes a review of the aging effects considered. In addition, the staff has evaluated the applicability of the aging management program that is credited for managing the identified aging effects for the connectors, splices, and terminal blocks.

3.6.2.2.1 Aging Effects The staff noted that low-voltage Instrumentation circuits that are sensitive to small variations in impedance were determined to be potentially affected by oxidation of connectors and terminations that are used to terminate impedance-sensitive circuits (e.g., coaxial and triaxial connectors and terminations). Loss of materials caused by oxidation and corrosion of connector pins are aging concerns. The staff requested that the applicant provide an aging management program to manage these aging effects or provide technical justification for excluding it. In a response dated January 2, 2002, the applicant states that the connector materials subject to aging are metal and insulation. The metals used for low-voltage electrical connectors are copper, tinned copper, and aluminum. The connector insulation materials used are various elastomers and thermoplastics. Properly fitted and tight connections on uninsulated connectors protect the metallic contact surface area connection frofn environmental aging effects. Low-voltage (impedance-sensitive) instrumentation electrical connectors may experience failure when exposure to a wet environment induces corrosion or tarnishing of the metallic surface contact. The absence of a wet environment, with a properly fitted connection, ecldess~t~c.

~nnact A

nj.nirnqm#nt nd _ r~nF!* f!-h-nnnectior] preclude failure of an impedance-sensitive instrumentation connection through corrosion or tarnishing. Failures of electrical connectors that are not designed for wet environments are not age-related failures.

Electrical connector failures resulting from water unexpectedly introduced into a normally dry area of the plant are event-driven or due to human error and are not age-related. This is confirmed in the NRC letter from Grimes to Walters, dated June 5, 1998, "License Renewal Issue No. 98-0013, 'Degradation Induced Human Activities" which states that "the staff concludes that the issue of degradation induced by human activities need not be considered as a separate aging effect and should be excluded from aging management review." The applicant further stated in its response that a review of PBAPS operational history concluded that no age-related degradation due to oxidation of connectors has occurred at PBAPS.

Therefore, the applicant concluded that no aging management activity is required. The staff finds the applicant's response acceptable because failures of electrical connectors resulting from connectors that are not designed for wet environments ký-installed in a wet environment, are not age-related failures. Electrical connector failures, resulting from water unexpectedly introduced into a normally dry area of the plant are event-driven or due to human error and are not age-related.

Peach Bottom LRA Section B.1.13, "Standby Liquid Control System Surveillance Activities,"

covers standby liquid control system (SBLC) components, including the solution tank, piping and valves on the suction side of the SBLC pump. The staff requested the applicant to explain why the electrical cables, connectors, and terminations were not included in this program in order to manage the aging effects of electrical components located in boric acid environments.

In response to the staff's request, the applicant states that as a boiling water reactor (BWR),

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PBAPS has an SBLC system like that described in Section VII.E2 of NUREG-1801, "Generic Aging Lessons Lqmed (GALL) Report." The GALL report describes the components of the SBLC system

)in contact with a sodium pentaborate solution. The sodium pentaborate solution provides a relatively mild environment with a slightly basic pH. Peach Bottom does not have a borated water environment; therefore, GALL Report Program XI.M10, "Boric Acid Corrosion," does not apply to PBAPS. There is no boric acid corrosion of any external surfaces, including the surfaces of cables, connections, and terminations. Additionally, the connectors and cables in the SBLC system are within protected enclosures so that sodium pentaborate leakage cannot degrade conductivity. The staff find the applicant's response acceptable because boric acid corrosion does not apply to PBAPS.

Section 3.6.2 of the LRA does not identify any applicable aging effects for Non-EQ connectors, splices, and terminal blocks. Industry experience indicates that change in material properties is an aging effect for connections (connectors, spices, and terminal blocks) that require aging management. In a letter dated January 23, 2002, the staff requested the applicant to provide an aging management program to manage the aging effects of accessible and inaccessible electrical connections exposed to an adverse localized environment caused by heat or radiation (RAI 3.6-1). The applicant responded with aK proposed aging management activity to manage the aging effects for connections.

Table 3.6-2 of the LRA will be revised as shown below to reflect this new activity.

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Table 3.6-2 Aging Management Review Results for Connectors, Splices, and Terminal Blocks Component Component Environment Material of Aging Effect Aging Group Intended Construction Management Function Activity Electrical Electrical Sheltered Various Loss of Non-EQ Connectors Continuity organic Material Accessible Insulation insulation Properties Cable Aging types Management (discussed in Activity Section (B.3.3) 2.5.1)

Electrical Electrical Sheltered

Copper, None (2)

Not Connectors Continuity tinned Applicable Metallic copper, and Connector aluminum Electric Electrical Sheltered Modified Loss of Non-EQ Splices Continuity Polyolefin Material Accessible Insulation (XLPO, Properties Cable Aging XLPE)

Management Activity (B.3.3)

Electrical Electrical Sheltered Phenolic and Loss of Non-EQ Terminal Continuity nylon Material Accessible Blocks insulation Properties Cable Aging Insulation Management Activity (B.3.3)

Electrical Electrical Sheltered

Copper, None (2)

Not Terminal Continuity tinned Applicable Blocks

copper, Metallic

brass, bronze &

aluminum (2) No aging effects for PBAPS The revised Table 3.6-2 identifies oss of material properties as an aging effect of electrical connections. The staff finds jHthe applicant's response acceptable because loss of material properties is the aging effect of electrical connections.

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3.6.2.2.2 Aging Management Programs The applicant proposed an aging management program, "Non-EQ Accessible Cable Aging Management Activity," for connectors, splices, and terminal blocks in a letter dated April 29, 2002. This program applies to electrical connectors, splices, and terminal blocks within the scope of license renewal that are installed in adverse localized environments caused by heat or radiation in the presence of oxygen. The staff found that the submitted aging management activity is essentially a visual inspection that addresses age-related degradation of connections that can result from exposure to high values of heat or radiation. In addition, fuse holders/blocks are classified as specialized type of terminal block because of the similarity in design and construction. Terminal blocks are passive components subject to an AMR for license renewal and so are fuse holders. During a conference call on September 5, 2002, the applicant stated that it will include fuse holders in the scope of the proposed AMP, Non-EQ accessible Cable Aging Management Activity (B.3.3), and this AMP will manage the aging effects for fuse connectors, splices, and terminal blocks as well as fuse holders. This Is Confirmatory Item 3.6.2.2.2-1.

The acceptability of this AMP has been evaluated in Section 3.6.1.2.2 of this SER. The staff therefore finds the aging management activity acceptable for providing reasonable assurance that the intended functions of Non-EQ connectors, splices, terminal blocks, and fuse holders that are exposed to adverse localized environments caused by heat or radiation will be maintained consistent with the CLB through the period of extended operation.

3.6.2.3 Conclusions The staff concludes that, with the exception of Confirmatory Item 3.6.2.2.2-1, the applicant has demonstrated that the aging effects associated with connectors, splices, and terminal blocks will be adequately managed so there is reasonable assurance that the intended function of the systems and components will be maintained consistent with the CLB during the period of extended operation as required by 10 CFR 54.21 (a)(3). 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).

3.6.3 Station Blackout System 3.6.3.1 Technical Information in the Application In Section 2.5.3 of the LRA, the applicant states that the station blackout systerfrcomprisek of the alternate AC (AAC) power source as required per NUMARC 87-00, "Guidelines and Technical Bases for NUMARC Initiatives Addressing Station Blackout at Light Water Reactors.'

The station blackout (SBO) system for PBAPS is in compliance with 10 CFR 50.63. The AAC power source consists of the following components:

Conowingo Hydroelectric Plant (dam)

Susquehanna substation wooden takeoff pole manholes at Conowingo and Peach Bottom Submarine cable (transmission line) 3-254

station blackout substation at PBAPS Conwin-go Hydroelectric Plant (Dam)

The Conowingo Hydroelectric Plant (dam) is on the Susquehanna River approximately 10 miles north of the mouth of the river on the Chesapeak Bay, 5 miles south of the Pennsylvania border, and approximately 10 miles south of PBAPS. The Dam is the source of power to support the PBAPS SBO commitment. The Federal Energy Regulatory Commission (FERC) licenses the dam and associated power block. The dam is constructed primarily of concrete and steel. The associated power block consists of reinforce concrete and structural steel.

Susquehanna Substation The Susquehanna substation is adjacent to and receives power from the Conowingo Hydroelectric Plant. The substation delivers 34.5kV power to PBAPS to support the SBO requirements. The substation has the standard industry power distribution design and consists of aluminum bus bars, insulators, circuit breakers, transformers, and associated foundations.

Wooden Pole The takeoff tower for the transmission line from the Susquehanna substation is a wooden pole.

The pole is constructed of yellow pine and chemically treated before installation. The installed pole has been analyzed to be able to withstand the severe weather conditions associated with the SBO event.

Manholes Manholes exist at both the Conowingo Hydroelectric Plant and PBAPS locations to house the transition between the standard power cables from the substations at each location and the submarine cable. The manholes are constructed of reinforced concrete. AMRs of aging effects for concrete structures have concluded that no aging management activities are required, excert for change in matedalo properties due to leaching of calcium hydroxide s-H

+IW,

,*e.,./

Submarine Cable (Transmission Line)

A 35kV submarine cable exits the manhole at Conowingo and runs under the bed of the Susquehanna River from just north of the dam to a manhole just south of the SBO substation.

The submarine cable consists of copper phase conductors, ground conductors, EPR insulation, metallic shielding, and polyethylene (Okolene) jackets. The assembly of the submarine cable has three individually shielded and jacketed conductors cabled together with two ground conductors, and one fiber optic cable, with polypropylene fillers as necessary. A polypropylene bedding covers the entire cable and a layer of steel armor wires is applied over the bedding.

Each wire is jacketed with black polyethylene. A nylon serving is then applied and an asphaltic solution is applied both under and over the armor and nylon serving.

PBAPS SBO Substation PBAPS SBO substation consists of 34.5kV and 13.8kV metalclad outdoor walk-in switchgear, a 15/20 MVA oil-filled transformer, and associated breakers and controls. The SBO substation is 3-255

designed as a stand-alone facility with control power coming from within the switchgear. The switchgear is contained within a standard prefabricated metal enclosure. The enclosure and switchgear foundation is discussed in LRA Section 2.4.6.

3.6.3.1.1 Aging Effects Table 3.6-3, of the LRA identifies the following aging effects for the components of the wooden poles and Conowingo Hydroelectrical Plant:

loss of material change in material properties In Table 3.6-3, the applicant indicates that aging effects for concrete are evaluated in Section 3.5.6 of the LRA and that no aging effects are identified for aluminum, porcelain, and EPR insulation of the substation bus ba?, substation insulators, and submarine cable, respectively.

3.6.3.1.2 Aging Management Program Table 3.6-3 of the LRA credits the Wooden Pole Inspection and Conowingo Hydroelectric Plant Aging ManagemenProgram for managing the aging effects for the wooden pole and Conowingo HydrWEEP' 3.6.3.2 Staff Evaluation The staff evaluated the information on aging management presented in the Peach Bottom LRA Sections 2.5.3 and 3.6.3 and the applicant's January 2, April 2V May 22, June 10, and July ns.

2002, responses to the staff RAls. The staff evaluation was conducted to determine if there is a reasonable assurance that the applicant has demonstrated that the effects of aging will be adequately managed, consistent with its CLB throughout the period of extended operation, in accordance with 10 CFR 54.21 (a)(3).

3.6.3.2.1 Aging Effects Potential aging effects for insulators are surface contamination, cracking, and loss of material due to wear. Various airbome materials such as dust, salt, and industrial effluents can contaminate insulator surfaces. Porcelain Is essentially a hardened, opaque glass. Uke any glass, if subjected to enough force it will crack or break. The most common cause for cracking or breaking of an insulator is being struck by an object (e.g., a rock or bullet). Insulators also crack when the cement that binds the parts together expands enough to crack the porcelain.

This phenomenon, known as cement growth, is caused by an improper manufacturing process which makes the cement more susceptible to moisture penetration. Mechanical weyr is an aging effect for strain and suspension insulators because they move. An insulator can move when the wind blows the supported transmission conductor, swinging the conductor from side to side. If frequent enough, the swinging can cause wear in the metal contact points of the insulator string and between an insulator and the supporting hardware.

The staff requested the applicant to explain why no aging effects which require aging management was identified for bus bar insulators and the submarine cable. In response to the staff's concem regarding the aging management for bus bar insulators and submarine cables 3-256

phase bus (non-segregated-phase bus) transmission conductors The intended electrical function of the offsite power system within the scope of license renewal is to provide recovery after an SBO event. The AMR results for the electrical components are shown in Table 1 of the applicant's RAI response.

In Table 1 of the applicant's May 22, 2002, response to RAI 2.5-1 the applicant indicated that switchyard bus, outdoor/buried/sheltered insulated cables and connections, non-segregated phase bus, and transmission conductors have no aging effects and do not require aging management activity. In a telephone conference on June 18, 2002, the staff requested the applicant to explain why no aging effect was identified for these components. The staff also requested the applicant to identify any operating experiece of the offsite power system components associated SBO. In response dated JulM-2002, the applicant states that pure aluminum exposed to air may be susceptible to oxidation at connection points. However, no oxide grease, a consumable which is replaced as required during routine maintenance, prohibits oxidation. Therefore, no aging effects are applicable.

A sheltered environment Is defined on page 3-6 of the LRA. A sheltered environment consists of indoor ambient conditions where components are protected from outdoor moisture. No cables and connections associated with the SBO system and offsite power are in the drywell and steam tunnel. These cables experience temperatures of less than 105 'F and humidity between 10% and 90%. Radiation levels in this environment are less than 2.OE+06 inside the plant and normal background radiation levels outside the plant. No aging effects for cables and connections in this environment require management.

An outdoor environment is defined on page 3-7 of the LRA. An outdoor environment consists of air temperatures typically ranging from 0 OF to 100 OF, and an average annual precipitation of approximately 30 inches. Radiation levels are those of normal background levels. There are no aging effects for cables and connections in this environment.

A buried environment is defined on page 3-7 of the LRA. The buried environment consists of granular bedding material of sand or rock fines, backfill of dirt or rock, and filler material of gravel or crushed stone. A buried environment may include such items as ductbanks and conduits. The buried cables and connections associated with the offsite power sources, which may be susceptible to the phenomenon of water treeing, have been replaced. Direct buried cables exist in the substation. The cables are installed in a trench constructed of bar sand or stone screening both above and below the cables, with treated planking above the covered cables. As a result the cables in the trench experience normal "rain and drain" moisture and not standing water, therefore, they are not susceptible to water treeing.

With the exception of an oil fire several years ago in the substation, which was event driven, a review of PBAPS operating history indicates that PBAPS has not experienced any age-related degradation of the cables buried in the trench. The nonsegregated bus associated with the offsite power is in a sheltered environment and has no aging effects. The non-segregated bus duct that transitions from the #2SU startup and emergency auxiliary transformer to the #2 SU startup switchgear building is in an outdoor environment, discussed with structures, and is inspected by the Maintenance Rule Structural Monitoring Program. The overhead conductor is aluminum conductor steel reinforced (ACSR). Corrosion of ACSR is a very slow-acting aging 3-258

effect and is even slower for rural areas such as PBAPS with generally fewer suspended particles and SO2 concentrations in the air than urban areas. Therefore there are no applicable aging effects that require management.

The staff finds the applicant's response acceptable for switchyard bus, outdoor/sheltered insulated cables and connections, non-segregated-phase bus, and transmission conductors because it provides the rationale for why no aging effects are identified. The staff believes that water treeing can effect buried cables (other than 35kV submarine cables) associated with the offsite source and installed in ductbanks, conduits, and trenches. The staff acknowledges that the replacement cable is an improved formulation, which is more resistant to water-treeing.

However, as discussed in Section 3.6.1.2.1, the staff does not accept the applicant's position that moisture is not an aging effect requiring an aging management for these cables. The staff is concerned that the applicant has not provided a sufficient technical justification for not requiring an aging management program for buried cables, not specifically designed for a wet environment. This Is the other part of Open Item 3.6.1.2.1-1.

3.6.3.2.1 Aging Management Programs The aging management review results for the statjon blackout system are provided in Table 3.6-3 of the LRA. The Conowingo Hydroelectric lant (Dam) Aging Management Programe will manage reinforced concrete and steel used in the Conowingo Hydroelectric Plant, and the Susquahanna Substation Wooden Pole Inspection Activity will manage the loss of material and change in material properties of wood used in wooden pole.

Conowingo Hydroelectric Plant (Dam) Aging Management Program Section B.1.15 of the LRA describes the applicant's program for managing the potential aging of structures and components associated with the Conowingo Hydroelectric Plant dam. The staff reviewed Section B.1.15 of the LRA to determine whether the applicant has demonstrated that the inspection activities will adequately manage the applicable effects of aging during the period of extended operation as required by 10 CFR 54.21 (a)(3).

The Conowingo Hydroelectric Plant is the source of power to support the PBAPS station blackout system, which was installed to meet the requirements of 10 CFR 50.63. The Conowingo dam is located on the Susquehanna River approximately 10 miles north of the mouth of the river on the Chesapeake Bay and approximately 10 miles south of PBAPS. The dam is constructed primarily of concrete and steel, and is exposed to raw water and an outside environment. The Federal Energy Regulatory Commission (FERC) licenses the dam and associated power block. The applicant credits'the Conowingo Hydroelectric Plant (Dam) Aging Management Program with managing the potential loss of material of the dam.

Staff Evaluation The applicant stated that the Conowingo Hydroelectric Plant dam is subject to the FERC 5-year inspection program. This program consists of a visual inspection by a qualified independent consultant approved by FERC, and is in compliance with Title 18 of the Code of Federal Regulations (Conservation of Power and Water Resources), Part 12 (Safety of Water Power Projects and Project Works), Subpart D (Inspection by Independent Consultant).

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The applicant stated that the FERC licenses the dam and associated power block. By virtue of the FERC's authority and responsibility for ensuring that its regulated projects are constructed, operated, and maintained to protect life, health, and property, the staff finds that for earthen embankments, dams, appurtenances, and related structures subject to AMR, continued compliance with FERC requirements during the license renewal period will constitute an acceptable dam aging management program for the purposes of license renewal. Therefore, the staff finds the program acceptable.

UFSAR Supplement The staff reviewed Section A.1.15 of the UFSAR Supplement (Appendix B of the LRA) to verify 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-1800 and therefore provides an"'dequate 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 Conowingo Hydroelectric Plant (dam) AMP 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 54.21 (a)(3). 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).

Susauehanna Substation Wooden Pole Inspection Activity The applicant described the Susquehanna Substation Wooden Pole (SSWP) Inspection Activity AMP in Section B.2.11 of Appendix B of the LRA. The program is used to manage loss of material and change of material properties for the SSWP. The staff reviewed the applicant's description of the AMP in Section B.2.1 1 of Appendix B of the LRA to determine whether the applicant has demonstrated that the program will adequately manage the aging effects of the SSWP during the period of extended operation as required by 10 CFR 54.21 (a)(3).

The SSWP inspection activity AMP is used to manage loss of material and change of material properties for the SSWP, a wooden pole at the Susquehanna substation. The pole provides structural support for the conductors connecting tle Ostation to the cable that transmits the AC power to PBAPS from the Conowingo Hyd1-, 0ant for coping with station blackout. The wooden pole is subjected to outdoor and buried environments.

The AMP consists of inspection on a 10-year interval by a qualified inspector. The above ground wooden pole exposed to the outdoor environment is inspected for loss of material due to ant, insect, and moisture damage and for change in material properties due to moisture damage. The applicant concluded that the SSWP inspection activity AMP manage the aging effects of loss of material and change in material properties so that the component intended functions will be maintained consistent with the CLB during the period of extended operation.

In accordance to 10 CFR 54.21 (a)(3), the staff reviewed the information Included in Appendix B 3-260

of the LRA regarding the applicant's SSWP inspection activity AMP. Specifically, the LRA should demonstrate that the effects of aging due to the exposure of the wooden pole to outdoor and buried conditions will be adequately managed, allowing the intended functions to be maintained consistent with the CLB for the period of extended operation.

Staff Evaluation The staff's evaluation of the Susquehanna substation wooden pole inspection activity focused on how the program manages aging effects through the effective incorporation of the following 10 elements: program scope, preventive actions, parameters monitored or inspected, detection of aging effects, monitoring and trending, acceptance criteria, corrective actions, confirmation process, administrative controls, and operating experience. The applicant indicated that the corrective actions, confirmation process, and administrative controls are part of the site controlled quality assurance program. The staff's evaluation of the quality assurance program is provided separately in Section 3.0.4 of this SER. The remaining seven elements are discussed below.

Program Scope: The applicant stated that the program only applies to the SSWP. The staff finds the scope of the program acceptable.

Preventive Actions: The applicant described the AMP as a condition monitoring AMP. No preventive or mitigation actions are provided. The staff considers inspection activities a means of detecting, not preventing, aging and, therefore, agrees that no preventive actions are associated with the wooden pole inspection activity and none are required.

Parameters Monitored or Inspected: The applicant stated that the wooden pole is inspected for loss of material due to ant, insect, and moisture damage and for change in material properties due to moisture damage. In RAI B2.1 1-1, the staff requested information on what parameters and material properties are monitored/inspected and how the buried part of the wooden pole is monitoredfinspected. In a letter dated June 10, 2002, the applicant responded that aging management activities for wooden poles consist of visual inspections, sounding, and, if required, boring and excavation activities. Each inspection consists of a visual inspection of the entire pole from the ground up. Parameters inspected include shell rot, decay pockets, heart rot* rotten butt, cracked or broken arms or braces, mechanical damage, ground line decay, split tops, etc. Each pole Is sounded by striking each quadrant of the pole surface several times with a sounding hammer around the, circumference from the ground line to as high as the inspector can reach. If poles are found to have ground line decay they are excavated and inspected 18 inches below the ground line. If internal decay is suspected, the pole is bored to allow for further analysis. The staff finds the parameters monitored or inspected acceptable because they are capable of detecting the aging effects.

Detection of Aging Effects: The applicant stated that inspection of the wooden pole every 10 years by a qualified Inspector will assure that aging effects are detected prior to loss of intended function. In the RAI B2.11-2, the staff requested justification for the 10-year inspection interval of the wooden pole. In a letter dated June 10, 2002, the applicant explained that the typical life for a wooden pole, based on industry experience, is 30-40 years. If the pole is inspected and treated with a pesticide, furpi th or preservative solution every 10 years, as required, it should last 10 to 15 years longer. M texperience over several decades has indicated that a 10-year inspection interval is adequate. The Susquehanna wooden pole was installed in 1994. The 3-261

first inspection is scheduled for 2003. The pole will be inspected every 10 years thereafter.

The staff finds the 10-year inspection interval acceptable because it is based,1plant and industry experience.

Monitoring and Trending: The applicant stated tat pdition monitoring for loss of material and change in material properties is provided in the spf~WEecification for inspection of wooden poles. The wooden pole is inspected at 10-year intervals. The monitoring under this AMP involves a combination of visual, sounding, boring, and excavation activities to determine the condition of the pole. Any shell rot, decay pockets, heart rot, rotten butt, cracked or broken arms or braces, mechanical damage, ground line decay, split tops, etc., which may limit the life of the pole or which require immediate attention in the interest of safety are recorded, and reported. Therefore, the staff finds the applicant's approach to monitoring activities to be acceptable because it is based on methods that are sufficient to predict the extent of degradation so that timely corrective or mitigative actions are possible.

Acceptance Criteria:.De applicant stated that the acceptance criteria for the inspection are provided in the--tion specification for inspection of wooden poles. In RAI B.2.11-3, the staff requested a description of the acceptance criteria in terms of (1) assessing the severity of the observed degradations and (2) determining whether corrective action is necessary. In a letter dated June 10, 2002, the applicant explained that an approved wooden pole maintenance contractor experienced in the inspection, treatment, and reinforcement of wooden poles performs the pole inspection. Personnel handling treatment material are licensed pesticide applicators. The inspector, through a combination of visual, sounding, boring, and excavation activities, determines the condition of the pole. If sounding indicates internal decay, or a hollow pole, boring will determine the extent of the decayed area. Pesticide treatment will occur as required. If any poles (except poles requiring replacement) found to contain ants or termites, the cavities where the ants or termites are found are flooded with an effective preservative solution. Any pole determined to have internal decay will receive fumigant treatment. Each wooden pole that is inspected receives a condition tag describes the pole condition as found by the inspector and whether the pole has received treatment. Based on the remaining shell thickness (circumference) and pole loading, poles can be tagged as requiring either reinforcement or replacement. The staff finds the acceptance criteria acceptable.

Operating Experience: The first inspection of the pole is scheduled for 2003, so there is no experience with this specific pole; however, the applicant stated that corporate experience shows that inspection of wooden poles once every 10 yes isddevate to detect aging degradation prior to loss of intended function, based orin Mustry experience. The staff finds this reasonable and acceptable.

UFSAR Supplement The staff reviewed Section A.2.11 of the UFSAR Supplement (Appendix B of the LRA) to verify 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-1800 and therefore provides and adequate summary of program activities as required by 10 CFR 54.21(d).

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4 TIME-LIMITED AGING ANALYSES 4.1 Identification of Time-Limited Aging Analyses 4.1.1 Introduction The applicant describes its identification of time-limited aging analyses (TLAAs) in Section 4.1.1, "Identification of Time-Umited Aging Analyses," of the LRA. The staff reviewed this section of the LRA to determine whether the applicant has identified the TLAAs as required by 10 CFR 54.21(c) and described them in its UFSAR Supplement as required by 10 CFR 54.21(d).

In Section 4.1 of the application, the applicant described the requirements for the technical information to be reported in the application regarding time-limited aging analyses (TLAAs), as stated in 10 CFR 54.21 (c). These include a list of TLAAs, as defined in 10 CFR 54.3, "Definitions,* and a list of plant-specific exemptions granted pursuant to 10 CFR 50.12 that are based on TLAAs. The applicant also described the criteria used to identify TLAAs at Peach Bottom, Units 2 and 3. These criteria are the same as the six criteria stated in 10 CFR 54.3 for identifying TLAAs.

The identified TLAAs were evaluated and the results are described in Sections 4.1 through 4.7 of this SER. As required by 10 CFR 54.21(c), the applicant has provided a list of TLAAs in Table 4.1-1 of the LRA. The applicant also stated that no plant-specific exemptions based on TLAAs have been granted at Peach Bottom.

4.1.2 Summary of Technical Information in the Application The applicant evaluates calculations for Peach Bottom against the six criteria specified in 10 CFR 54.3 to identify the TLAAs. The applicant identifies the following TLAAs:

Reactor vessel neutron embrittlement 10 CFR Part 50 Appendix G reactor vessel rapid failure pr gation and brittle fracture considerations: Charpy upper shelf energy (USE) and RTNDT increase, reflood thermal shock analysis Reactor vessel thermal limit analysis: operating pressure-temperature limit (P-T limit) curves Reactor vessel circumferential weld examination relief Reactor vessel axial weld failure probability Metal fatigue Reactor vessel fatigue Reactor vessel internals fatigue and embrittlement Reactor vessel internals fatigue analyses Reactor vessel Internals embrittlement analyses 4-1

Effect of fatigue and embrittlement on end-of-life reflood thermal shock 0

analysis Piping and component fatigue and thermal cycles Fatigue analyses of Group I primary system piping S+rcss Assumed thermal cycle count for allowable secondarykange reduction in Group II and III piping and components Design of the RHR system for a finite number of cycles Effects of reactor coolant environment on fatigue life of components and piping (Generic Safety Issue 190)

Environmental qualification of electrical equipment Loss of prestress in concrete containment tendons not applicable Containment fatigue Fatigue analyses of containment boundaries: new loads analysis of torus, torus vents, and torus penetrations New loads fatigue analysis of SRV discharge lines and external tows-attached piping Expansion joint and bellows fatigue analyses (drywell-to-torus-vent bellows)

Expansion joint and bellows fatigue analyses (containment penetration bellows)

Other plant-specific TLAAs Reactor vessel corrosion allowances Generic Letter 81-11 crack growth analysis to demonstrate conformance to the intent of NUREG-0619 Fracture mechanics of ISI-reportable indications for Group I piping: as-forged laminar tear in a Unit 3 main steam elbow Pursuant to 10 CFR 50.21 (c)(2), the applicant stated that no exemptions granted under 10 CFR 50.12 on the basis of a TLAA were identified. The applicant states that a technical altemative (as defined in 10 CFR 50.55a(a)(3)(i)) to requirements to inspect circumferential welds on the reactor pressure vessel has been approved by NRC. This TLAA is discussed in Section 4.2.3 of this SER.

In a separate licensing action, the applicant has submitted a license amendment for a power uprate to increase the maximum allowed operating power level. This power uprate is based on the increased accuracy of feedwater flow monitors. The higher power level may result in higher reactor coolant temperatures, increased reactor coolant flow, and/or increased neutron fluence.

On July 23, 2002, the staff held a conference call with the applicant to ask if the the effects of the power uprate were considered during Its evaluation of the TLAAs or that the analysis results are bounding for the higher power level. The applicant stated that the effects of the power uprate were considered. This Is Confirmatory Item 4.1.2-1.

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By letter dated February6, 2002, the staff requested gdditional information, per RAI 3.3-3, as to why the crane load cycle limit was not included as aKTLAA. The applicant responded in a letter dated May, 6, 2002, in which it stated that it will update the UFSAR Supplement to include load cycles for the reactor building overhead bridge cranes, turbine hall cranes, emergency diesel generator bridges, and circulating water pump structure gantry crane as a TLAA in Section 4.7.4 of the LRA. In the response, the applicant stated that the cranes are predominantly used to lift loads which are significantly lower than the crane's rated load capacity. For example, the reactor building cranes will undergo less than 5000 load cycles in 60 years based on the projected number of lifts during refueling outages, handling of spent fuel storage casks, and testing. The other cranes are expected to experience significantly fewer load cycles than the reactor building cranes. Thus, the number of lifts at or near their rated load is low compared to the design limit of 20,000 load cycles. The applicant stated that the load cycles for these cranes were evaluated for the period of extended operation and it was determined that the analyses associated with crane design, including the load cycle limit, remain valid for the period of extended operation and, therefore, meet the requirements of 10 CFR 54.21 (c)(1)(i). The staff agrees with the applicant's conclusion that the cranes will continue to perform their intended function throughout the period of extended operation as required by 10 CFR 54.21 (c)(1) and finds the applicant's response acceptable. The update of the UFSAR Supplement is as required by 10 CFR 54.21 (c)(1) is Confirmatory Item 4.1.3-2.

4.1.4 Conclusions The staff has reviewed the information provided in Section 4.1 of the Peach Bottom LRA. With the exception of the confirmatory items 4.1.3-1 and 4.1.3-2, the NRC staff concludes that the applicant has adequately identified the TLAAs as required by 10 CFR 54.21(c), and that no 10 CFR 50.12 exemptions have been granted on the basis of the TLAA as defined in 10 CFR 54.3. The staff also concludes that the applicant has adequately evaluated the TLAAs related to pipe breaks and the crane load cycle limit as required by 10 CFR 54.21 (c).

4.2 Reactor Vessel Neutron Embrittlement 4.2.1 10 CFR Part 50 Appendix G Reactor Vessel Rapid Failure Propagation and Brittle Fracture Considerations: Charpy Upper Shelf Energy (USE) Reduction and RTNDT Increase, Reflood thermal shock analysis 4.2.1.1 Summary of Technical Information in the Application The applicant described Its evaluation of this TLAA in LRA Section 4.2, "Reactor Vessel Neutron Embrittlement."

Neutron Irradiation Embrittlement Neutron irradiation causes a decrease in the Charpy upper shelf energy (USE) and an increase in the adjusted reference temperature (ART) of the reactor pressure vessel (RPV) beltline materials. The ART impacts the plant's pressure-temperature (P-T) limit and RPV integrity evaluations. BWRVIP-74 report contains integrity evaluations of the BWR RPV circumferentially oriented welds and the BWR RPV axially oriented welds. Therefore, in order to demonstrate that neutron embrittlement does not significantly impact BWR RPV integrity 4-5

that was approved by the staff, the results are acceptable and may be utilized for the evaluations discussed in SER Sections 4.2.2.2, 4.2.3.2, and 4.2.4.2.

The ART is defined as the sum of the initial (unirradiated) reference temperature (initial RTNDT),

the mean value of the adjustment in reference temperature caused by irradiation (delta RTNDT),

and a margin (M) term. The delta RTNDT is a product of a chemistry factor and a fluence factor.

The chemistry factor is dependent upon the amount of copper and nickel in the material and may be determined from tables in RG 1.99, Rev. 2, or from surveillance data. The fluence factor is dependent upon the neutron fluence at the maximum postulated flaw depth. The margin term is dependent upon whether the initial RTNDT is a plant-specific or a generic value and whether the chemistry factor (CF) was determined using the tables in RG 1.99, Rev. 2, or surveillance data. The margin term is used to account for uncertainties in the values of the initial RTNT, the copper and nickel contents, the fluence, and the calculation methods. RG 1.99, Rev. 2, describes the methodology to be used in calculating the margin term.

-(Zt 4;- 3 The 54 EFPYs ART for the limiting beltline material foJ nit 2 (Shell # 2 Heat C2873-1) at 1/4T is 70 OF. The 54 EFPYs ART for the limiting matedaaShell # 2, Heat C2773-2) at 1/4T is 97 OF. These values for ARTs were confirmed by the staff using the neutron fluence value of 1.6E18 n/cm2, the initial RTNDT values, and the Cu and Ni contents for the limiting beltline materials from the Peach Bottom Updated Final Safety Analysis Report, Volume 1. The Cu and Ni contents for the limiting beltline material are 0.12 and 0.57 wt%, respectively, for Unit 2, and 0.15 and 0.49 wt%, respectively, for Unit 3. The initial RTNDTfor the limiting beitline material is 6 OF for Unit 2 and 10 OF for Unit 3. A margin value of 34 OF was used for confirming the ARTs.

The staff finds the ART consistent with RG 1.99, Revision 2, and acceptable.

Reflood Thermal Shock Analysis The applicant has reviewed the reflood thermal shock analysis for Peach Bottom. For the reflood thermal shock event, the peak stress intensity at 1/4 of vessel thickness from inside occurs about 300 seconds after the LOCA. At 300 seconds, the analysis shows that the temperature of the vessel wall at a depth of 38.1mm (1.5 inches) is approximately 204 °C (400 OF). The applicant states that the reflood thermal shock analysis for 40-years of operation (32 EFPYs) will be bounding and valid for the license renewal term because the vessel beltline material ART, even after 60 years of Irradiation, is expected to be low enough to ensure that the material is in the Charpy upper shelf region at 204 OC. In RAI 4.2-2, the staff requested the applicant to present the technical basis for expecting the vessel beltline material ART after 60 years of irradiation to be low enough so that the material is in the Charpy upper shelf region at 204 °C. In response, the applicant referred to its response to RAI 4.2-1, which indicated that the ART for the limiting plate material for Peach Bottom Unit 2 is 70 F and for Unit 3 is 97 OF, which is well below the 204 °C (400 OF) 1/4T temperature predicted for the thermal shock event at the time of peak stress intensity. The reflood thermal shock analysis is, therefore, bounding and valid for the license renewal term.

Chamv UDDer Shelf EnerM (USE)

Section IV.A.la of Appendix G to 10 CFR Part 50 requires, in part, that the RPV beltline materials have Charpy USE in the transverse direction for base metal and along the weld for weld material of no less than 50 ft-lb (68J), unless it is demonstrated in a manner approved by the Director, Office of Nuclear Reactor Regulation, that lower values of Charpy USE will ensure 4-8

margins of safety against fracture equivalent to those required by Appendix G of Section XI of the ASME Code.

By letter dated April 30,1993, the Boiling Water Reactor Owners Group (BWROG) submitted a topical report entitled "10 CFR Part 50 Appendix G Equivalent Margins Analysis for Low Upper Shelf Energy in BWRI2 Through BWR/6 Vessels," to demonstrate that BWR RPVs could meet margins of safety against fracture equivalent to those required by Appendix G of the ASME Code Section XI for Charpy USE values less than 50 ft-lb. In a letter dated December 8, 1993, the staff concluded that the topical report demonstrates that the evaluated materials have the margins of safety against fracture equivalent to Appendix G of ASME Code Section XI, in accordance with AppendiG 10 CFR Part 50. In this report, the BWROG derived through statistical analysislto-derivelt he unirradiated USE values for materials that originally did not have documented unirradiated Charpy USE values. Using these statistically derived Charpy USE values, the BWROG predicted the end-of life (40 years of operation) USE values in accordance with RG 1.99, Rev. 2. According to this RG, the decrease in USE is dependent upon the amount of copper in the material and the neutron fluence predicted for the material.

The BWROG analysis determined that the minimum allowable Charpy USE in the transverse direction for base metal and along the weld for weld metal was 35 ft-lb.

General Electric (GE) performed an update to the USE equivalent margins analysis, which is documented in EPRI TR-1 13596, "BWR Vessel and Internals Project BWR Reactor Pressure Vessel Inspection and Flaw Evaluation Guidelines," BWRVIP-74, September 1999. The staff review and approval of EPRI TR-1 13596 Is documented in a letter from C. I. Grimes to C. Terry dated October 18, 2001. The analysis in EPRI TR-1 13596 determined the reduction in the unirradiated Charpy USE resulting from neutron radiation using the methodology in RG 1.99, Revision 2. Using this methodology and a correction factor of 65% for conversion of the longitudinal properties to transverse properties, the lowest irradiated Charpy USE at 54 EFPYs for all BWR/3-6 plates is projected to be 45 ft-lb. The correction factor for specimen orientation in plates is based on NRC Branch Technical position MTEB 5-2. Using the RG methodology, the lowest irradiated Charpy USE at 54 EFPY for BWR non-Linde 80 submerged arc welds is projected to be 43 ft-lb. EPRI TR-1 13596 indicates that the percent reduction in Charpy USE for the limiting BWR/3-6 beltline plates and BWR non-Unde 80 submerged arc welds are 23.5%

and 39%, respectively. Since this is a generic analysis, the staff issued RAI 4.2-3 requesting the applicant to submit plant-specific information to demonstrate that the beltline materials of the Peach Bottom Units 2 and 3 RPVs meet the criteria in the report at the end of the license renewal period. The applicant was specifically requested to submit the information specified in Tables B-4 and B-5 of EPRI TR-1 13596. In response to RAI 4.2-3, the applicant stated that the predicted percent decrease of the beltline material USE values at 1/4T and 54 EFPYs was estimated using BWRVIP-74 and RG 1.99, Revision 2. The equivalent margin analysis was performed using information presented in Tables B-4 and B-5 of EPRI TR-1 13596. RG 1.99, Revision 2, predicted percent decrease in USE for the limiting beitline plate material at the end of the license renewal period is 14% for Unit 2 and 16% for Unit 3; both predicted values of USE are less than the generic value of 23.5% reported in EPRI TR-1 13596. Similarly, the RG 1.99, Revision 2, predicted percent decrease in USE for limiting weld material (non-Unde 80 weld material at both units) at the end of license renewal period is 21% for both Unit 2 and Unit 3, which is less than the generic value of 39% reported in EPRI TR-1 13596. The predicted values for the decrease in USE for limiting beltline weld and plate materials for Units 2 and 3 were confirmed by the staff using the 54 EFPYs neutron fluence values at 1/4T provided by the applicant and the values of the Cu contents for the limiting materials from the Peach Bottom 4-9

Updated Final Safety Analysis Report, Volume 1. The 54 EFPYs neutron fluence at 1/4T for the limiting beltline plate and weld materials of both units is 1.6E18 n/cm 2. The Cu contents for the limiting beltline materials are 0.182 wt% for weld and 0.13 wt% for plate for Unit 2, and 0.182 wt% for weld and 0.15 wt%/ for plate for Unit 3. The staff finds the applicant response acceptable because the percent decrease in USE for plant-specific limiting plate and weld materials at Units 2 and 3 is bounded by the corresponding generic results obtained by the equivalent margin analysis presented in EPRI TR-1 13596 as mentioned above. Therefore, the Charpy USE values at 54 EFPYs for the limiting plate and weld materials at Units 2 and 3 are greater than the minimum allowable value of 35 ft-lb, which demonstrates that the evaluated materials have the margins of safety against fracture equivalent to Appendix G of Section XI of the ASME Code, in accordance with Appendix G of 10 CFR Part 50, throughout the license renewal period. The UFSAR Supplement needs to include the additional information contained in the applicant's response to RAI 4.2-3 regarding the evaluation of this TLAA. This Is Confirmatory Item 4.2.1.2-1.

4.2.1.3 Conclusions The staff has reviewed the information in LRA Section 4.2.1, U1 0 CFR PApTpendix G Reactor Vessel Rapid Failure Propagation and Brittle Fracture Considerations: Charpy Upper Shelf Energy (USE) Reduction and RTNDT Increase, Reflood Thermal Shock Analysis." On the basis of this review, the staff concludes that the applicant has adequately evaluated the TLAA related to 10 CFR Part 50 Appendix G reactor vessel rapid failure propagation and brittle fracture considerations (Charpy upper shelf energy (USE) reduction, RTNDT increase, and reflood thermal shock analysis), as required by 10 CFR 54.21(c)(1)(i). The staff has also reviewed the UFSAR Supplement and the staff concludes that, with the exception of Confirmatory Item 4.2.1.2-1, the applicant has provided an adequate description of its evaluation of this TLAA for the period of extended operation as required by 10 CFR 54.21 (d).

4.2.2 Reactor Vessel Thermal Analyses: Operating Pressure-Temperature Limit (P-T Limit)

Curves 4.2.2.1 Summary of Technical Information in the Application Peach Bottom Technical Specification 3.4.9 presents P-T limit curves for heatup and cooldown, and also limit the maximum rate of change of reactor coolant temperature. At Peach Bottom, the criticality curve presents limits for both heatup and criticality are calculated for a 40-year design (32 EFPY). The application indicates that the applicant will determine the P-T limits for 60 years (54 EFPY), in accordance with 10 CFR 54.21 (c)(1)(ii), after the GE fluence methodology has been approved by the NRC.

4.2.2.2 Staff Evaluation The P-T limit curves are based on the following NRC regulations and guidance: 10 CFR Part 50, Appendix G; Generic Letter (GL) 88-11, "NRC Position on Radiation Embrittlement of Reactor Vessel Materials and Its Impact on Plant Operations"; GL 92-01, "Reactor Vessel Structural Integrity,' Revision 1; GL 92-01, Revision 1, Supplement 1; RG 1.99, Revision 2; and Standard Review Plan (SRP) Section 5.3.2, "Pressure-Temperature Umits and Pressurized Thermal Shock." GL 88-11 advised applicants that the staff would use RG 1.99, Revision 2, to 4-10

review P-T limit curves. RG 1.99, Revision 2, contains methodologies for determining the increase in transition temperature and the decrease in upper shelf energy resulting from neutron radiation. GL 92-01, Revision 1, requested that applicants submit their RPV data for their plants to the staff for review. GL 92-01, Revision 1, Supplement 1, requested that applicants submit and assess data from other applicants that could affect their RPV integrity evaluations. These data are used by the staff as the basis for the staff's review of P-T limit curves. Appendix G to 10 CFR Part 50 requires that P-T limit curves for the RPV be at least as conservative as those obtained by the methodology of Appendix G Section XI of the ASME Code.

SRP Section 5.3.2 presents an acceptable method of determining the P-T limit curves for ferritic materials in the beltline of the RPV based on the linear elastic fracture mechanics (LEFM) methodology of Appendix G to Section XI of the ASME Code. The basic parameter of this methodology is the stress intensity factor K*, which is a function of the stress state and flaw configuration. Appendix G requires a safety factor of 2.0 on stress intensities resulting from reactor pressure during normal and transient operating conditions and a safety factor of 1.5 for hydrostatic testing curves. The methods of Appendix G postulate the existence of a sharp surface flaw in the RPV that is normal to the direction of the maximum stress. This flaw is postulated to have a depth that is equal to 1/4 the thickness (1/4T) of the RPV beltline thickness and a length equal to 1.5 times the RPV beltline thickness. The critical locations in the RPV beltline region for calculating cooldown and heatup P-T limit curves are the 1/4T and 3/4 thickness (3/4T) locations, which correspond to the maximum depth of the postulated inside surface and outside surface defects, respectively. The ASME Code Appendix G methodology requires that applicants determine the ART at the end of the operating period.

The applicant plans to calculate vessel P-T limit curves for 60 years (54 EFPYs) after the NRC has approved GE fluence calculation methodology. As discussed in Section 4.2.1.2 of the SE, the staff has approved the GE fluence calculation methodology that is documented in topical report NEDC-32983P, "General Electric Methodology for Reactor Pressure Vessel Fast Neutron Flux Evaluation.' This topical report was approved by the NRC in a letter dated September 14, 2001 from S.A. Richards (NRC) to J.F. Klapproth (GE). In RAI 4.2-5, the staff requested the applicant to submit P-T limit curves for a 60-year (54 EFPYs) design for Peach Bottom using the GE methodology. In response, the applicant stated that the vessel P-T limit curves for 54 EFPYs have been completed. The plant technical specifications will be modified to incorporate these P-T limit curves when the current curves reach their operational limits. The curves will be submitted to the NRC as a license amendment prior to the end of the initial operating license term for Peach Bottom. The staff finds the applicant's response acceptable because the change in P-T curves will be implemented by the license amendment process.

4.2.2.3 Conclusions The staff has reviewed the information In LRA Section 4.2.2, "Reactor Vessel Thermal L-iu-:+

Analyses: Operating Pressure-Temperature Umit (P-T Limit) Curves." On the basis of this review, the staff concludes that the applicant has adequately evaluated the reactor vessel operating pressure-temperature limit curves TLAA, as required by 10 CFR 54.21 (c)(1). The staff has also reviewed the UFSAR Supplement and the staff concludes the applicant has provided an adequate description of its evaluation of this TLAA for the period of extended operation as required by 10 CFR 54.21(d).

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welds during an additional 20-year license renewal period would be reassessed, on a plant specific basis, as part of any BWR LRA.

Section A.4.5 of report BWRVIPF-74 indicates that the staff's SER conservatively evaluated the BWR RPVs to 64 effective full Iwer years (EFPYs), which is 10 EFPYs greater than what is realistically expected for the end of the license renewal period. Since this was a generic analysis, the staff issued RAI 4.2-6 requesting the applicant to submit plant-specific information to demonstrate that the Peach Bottom beltline materials meet the criteria specified in the report.

To demonstrate that the vessel has not become embrittled beyond the basis for the technical alternative, the applicant must supply (1) a comparison of the neutron fluence, initial RTNDT, chemistry factor, amounts of copper and nickel, delta RTNOT and mean RTNDT of the limiting circumferential weld at the end of the renewal period to the 64 EFPYs reference case in Appendix E of the staff's SER, and (2) an estimate of conditional failure probability of the RPV at the end of the license renewal term based on the comparison of the mean RTNDofor the limiting circumferential weld and the reference case. Should the applicant request relief from augmented ISI requirements for volumetric examination of circumferential RPV welds during the period of extended operation, the applicant is requested to demonstrate that (1) at the expiration of the license, the circumferential welds satisfy the limiting conditional failure probability for circumferential welds in the evaluation, and (2) the applicant has implemented operator training and established procedures that limit the frequency of cold overpressure events to the frequency specified in the report. In response to the RAI, the applicant compared the limiting circumferential weld properties for Peach Bottom Units 2 and 3 to the information in Table 2.6-4 and Table 2.6-5 of the staff SER on BWRVIP-05 dated July 28, 1998.

The NRC staff used the mean RTNDT value for materials to evaluate failure probability of BWR circumferential welds at 32 and 64 EFPYs in the staff SER dated July 28, 1998. The mean RTNoT value is defined as the sum of the initial (unirradiated) reference temperature (initial RTNoT) and the mean value of the adjustment in reference temperature caused by irradiation (delta RTND-); it does not include a margin (M). The neutron fluence used in this evaluation was the neutron fluence clad-weld (inner) interface. The mean RTNDT for Peach Bottom Units 2 and 3 Is determined to provide a comparison with the values documented in the staff SER. The 54 EFPYs mean RTNOT values thus determined arel2 OF and 17 OF for Units 2 and 3, respectively.

The staff confirmed these values of mean RTNDT using the data for 54 EFPYs neutron fluence at the clad-weld interface provided by the applicant and the data for Ni and Cu contents in the girth welds from the Peach Bottom Updated Final Safety Analysis Report, Volume 1. For Unit 2, the 54 EFPYs fluence is 1.8E18 n/cm2, and Cu arg Ni contents are 0.056 and 0.96 wt%,

respectively. For Unit 3, the 54 EFPYs fluence is 1.!E18 n/cm2, and Cu and Ni contents are 0.102 and 0.942 wt%. These 54 EFPYs values mean that RTNDT values for Units 2 and 3 are bounded by the 64 EFPYs mean RTNDovalue of 70.6 OF used by NRC for determining the conditional failure probability of a circumferential girth weld. The 64 EFPYs mean RTNODTvalue from the staff SER dated July 28, 1998, is for a Chicago Bridge and Iron (CB&I) weld because CB&I welded the girth welds in the Peach Bottom vessels. Since the Peach Bottom 54 EFPYs value Is less than the 64 EFPYs value from the staff SER dated July 28, 1998, the staff concludes that the Peach Bottom RPV conditional failure probability is bounded by the NRC analysis.

The procedures and training used to limit cold overpressure events will be the same those approved by the NRC when Peach Bottom requested to use the BWRVIP-05 technical 4-13

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 (c)(1).

The design criterion for ASME Class 1 components involves calculating the CUF. 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)(1)(iii). The staff's 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 internals, 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 and record accumulated usage factors for critical RPV locations and subcomponents. In RAI 4.X*-2, the staff requested that the applicant describe how the monitored data will be used to calculate usage factors and to indicate how the fatigue usage will be estimated prior to implementation of the improved program.

The applicant's May, 1, 2002, response indicated that the FatiguePro monitoring system will be implemented to monitor selected component locations. FatiguePro uses measured temperature, pressure, and flow data to either monitor the number of cycles of design basis transients or to directly compute the stress history to determine the actual fatigue usage for each transienL The applicant indicated that most component locations will be monitored by an automated cycle counting module that will count each licensing basis transient experienced by the plant based on input from monitored plant instruments. The applicant will incorporate the cycle counts obtained since initial plant startup for these component locations. Monitoring of the RPV feedwater nozzles and the RPV support skirt will include a fatigue usage computation based on temperature, pressure, and flow data obtained from monitored plant instruments. The applicant will estimate that the prior fatigue usage for the feedwater nozzles and the RPV support skirt assuming a linear accumulation of fatigue based on the design fatigue values.

The applicant indicates that the future monitoring will be used to demonstrate the conservatism of the assumption of a linear accumulation of fatigue based on the design values. The staff considers the applicant's improved program an acceptable method to monitor fatigue of the critical components.

The applicant Indicated that the closure studs are projected to have a CUF > 1.0 during the current period of operation and that the studs are included in the FMP. In RAI 4.3-1, the staff requested the applicant to provide additional discussion regarding the projected CUF for the closure studs.

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Although the letter dated August 6, 1999, identified the staff's concerns regarding the EPRI procedure and its application to PWRs, the technical concerns regarding the application of the Argonne National Laboratory (ANL) statistical correlations and strain threshold values are also relevant to BWRs. In addition to the concerns referenced above, the staff identified additional concerns regarding the applicability of the EPRI BWR studies in its review of the Hatch LRA.

EPRI topical report TR-107943, "Environmental Fatigue Evaluations of Representative BWR Components," addressed a BWR-6 plant, and EPRI topical report TR-1 10356, "Evaluation of Environmental Thermal Fatigue Effects on Selected Components in a Boiling Water Reactor Plant," used plant transient data from a newer vintage BWR-4 plant. The applicant indicated 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 alloy steels contained in NUREG/CR-6583, uEffects of LWR Coolant Environments on Fatigue Design Curves of Carbon and Low-Alloy Steels," and the environmental correction factors for austenitic stainless steels contained in NUREG/CR-5704, "Effects of LWR Coolant Environments on Fatigue Design of Austenitic Stainless Steels," on the results of the EPRI studies. The applicant indicated that the impact of the new carbon steel data was not significant. The applicant applied a correction factor of 2.0 to the EPRI generic study results to account for the new stainless steel data.

The applicant indicated that EPRI topical report TR-1 10356 contained studies that are directly applicable to Peach Bottom because they Involved a BWR-4 that is identical to the Peach Bottom design. However, the only components evaluated in TR-1 10356 are the feedwater nozzle and the control rod drive penetration locations. The staff had previously expressed concerns regarding the applicability of the measured data contained in EPRI topical report TR 110356 to another facility In its review of the Hatch LRA.

The applicant provided the sixty-year CUFs projected for Peach Bottom Units 2 and 3 at the locations evaluated for an older vintage BWR in NUREG/CR-6260, "Application of NUREG/CR 5999, 'interim Fatigue Curves to Selected Nuclear Power Plant Components'," dated March 1995, in Table 4.3.4-3 of the LRA. The applicant indicated that these locations are monitored by the FMP, and that the environmental factors have been adequately accounted for by the conservatism In the design basis transient definitions. The applicant Indicated that the vessel support skirt Is monitored In lieu of the shell region Identified in NUREG/CR-6260 because it Is a more limiting fatigue location. The applicant also Indicated that, since the location is on the vessel exterior, the environmental fatigue factors do not apply. The staff agrees with the 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 environmental fatigue correlatons provided in NUREG/CR-6583 and NUREGICR-5704 reports for Peach Bottom Unitslrd

n.

In its May 1, 2002, response, the applicant committed to perform plant-specific calculations for the locations identified in NUREG/CR-6260 for an older vintage BWR plant considering the applicable environmental factors provided in NUREG/CR-6583 and NUREG/CR-5704. The applicant committed to complete these calculations prior to the period of extended operati0 n and take appropriate corrective actions if the resulting CUF values exceed 1.0.j 'he staff finds the applicant's commitment to complete the plant-specific calculations described above prior to

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the period of extended operation acceptable. However, in accordance with 10 CFR 54.21(d),

this information needs to be added to the UFSAR Supplement.

The applicant indicated that Group II. and III piping systems were designed to the requirements of USAS B31.1. The applicant performed an evaluation of the number of cycles expected for the period of extended operation. The applicant's evaluation indicated that the number of cycles is expected to be substantially less than the 7,000 cycle limit during the period of extended operation. Therefore, the existing analyses remain valid for the period of extended operation in accordance with 10 CFR 54.21 (c)(11)(i).

The applicant Indicated that the NSSS vendor specified a finite number of cycles for each of the elevated-temperature operating modes of the RHR system. The applicant also indicated that it found no description of these design operating cycles in the Peach Bottom licensing basis documents. The applicant indicated that the Group 1 RHR piping inside the drywell was analyzed to the ASME Section III Class 1 requirements. The applicant further indicated that an evaluation of the remaining Group I and Group II piping indicated that the number of thermal cycles would be substantially less the 7,000 cycle limit applicable to piping designed to USAS B31.1. In RAI 4.3-5, the staff requested the applicant to provide further clarification regarding the NSSS vendor specification.

In its May 1, 2002, response, the applicant indicated that the vendor specification contained a description of certain thermal cycles for the original system design. The applicant found no licensing basis requirements (other than design code cycle limits) like those contained in the USAS B31.1 piping design code. The applicant also stated that design to the vendor-specified cycles is not a TLAA, except as It may be included within the design code requirements. The applicant reviewed the design specifications and design codes for components such as pumps and heat exchangers to determine whether they incorporated thermal cycle design considerations. The applicant Indicated that no such requirements were identified. As a consequence, the applicant concluded that the only consideration for thermal cyclic loading that needed to be considered was the USAS B31.1 cycle limit. The staff considers the applicant's clarification of this issue satisfactory.

The applicant's UFSAR Supplement for metal fatigue is provided in Section A.4 of the LRA.

The applicant describes the FMP in Section A.4.2 and Its assessment of metal fatigue for the reactor vessel, reactor vessel intemals and piping and components in Section A.5.2. As discussed previously, the applicant indicated that corrective actions to address the fatigue of the reactor vessel closure studs would be initiated prior to the period of extended operation.

With the applicant's commitment to include in the UFSAR Supplement a description of the corrective actions to address closure studs as provided above in the response to RAI 4.3-1; and perform plant specific calculations for the locations identified in NUREG/CR-6260 for an older vintage BWR plant considering applicable environmental factors provided in NUREG/CR-6583 and NUREG/CR-5704 as provided above in response to RAI RAI 4.3-6; the staff concludes that the UFSAR Supplement will include ar~appropdate summary description of the programs and activities to manage aging as required by 10 CFR 54.21(d). The applicant needs to provide the revised UFSAR Supplement that includes these commitments. This Is Confirmatory Item 4.3.2-1.

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4.4 Environmental Qualification The 10 CFR 50.49 environmental qualification (EQ) program has been identified as a TLAA for the purposes of license renewal. The TLAA of EQ components includes all long-lived passive and active electrical and instrumentation and control (I&C) components and commodities that are located in a harsh environment and are Important to safety, including safety-related and Q list equipment, non-safety-related equipment whose failure could prevent satisfactory accomplishment of any safety-related function, and the necessary post-accident monitoring equipment.

4'I £1c-r;...

Erf4-The staff has reviewed LRA Section 4.4, "Environmental Qualificatior, to determine whether the applicant submitted adequate information to meet the requirements of 10 CFR 54.21 (c)(1) for evaluating the EQ TLAA. Paragraph (1) of 10 CFR 54.21 (c) requires that a list of EQ TLAA must be provided. The applicant must demonstrate that (i) the analyses remain valid for the period of extended operation, (ii) analyses have been projected to the end of the period of extended operation, or (iii) the effect of aging on the intended functions will be adequately managed for the period of extended operation. The staff also reviewed LRA Section 4.4.2, "GSI-1 68, 'Environmental Qualification of Low Voltage Instrumentation and Controls M 4&C) Cables."

On the basis of this review, the staff requested additional information in a letter to the applicant dated October 26, 2001. The applicant responded to this request for additional information (RAI) in a letter to the staff dated January 2, 2002.

4.4.1 Electrical Equipment Environmental Qualification Analyses 4.4.1.1 Summary of Technical Information in the Application The Peach Bottom EQ program complies with all applicable regulations and manages equipment thermal, radiation, and cyclic aging through the use of aging evaluations based on 10 CFR 50.49(f) qualification methods. Environmetally qualified equipment must be refurbished, replaced, or have its qualification extended prior to reaching the aging limits established In the aging evaluation. Aging evaluations for environmental qualified equipment that specify a qualified life of at least 40 years are considered TLLAs for license renewal. The following is a list of TLAAs for EQ of electrical equipment.

0 GE Co. 4kV pump motors and associated cable 0

EGS Grayboot connectors 0

Raychem insulated splices for class 1 E systems Bussman Co. and Gould Shawmut fuses and fuse holders EGS quick disconnect connectors 0

Limitorque motor-operated valve actuators 0

Namco position switches a

ASCO solenoid valves, trip coils, and pressure switches UCI splice tape a

Rosemount 1153 Series B transmitters a

GE Co. control station Agastat relays 0

static O-ring pressure switches 4-25

Cutler Hammer motor control centers NDT International accoustical monitors Target Rock solenoid valves PYCO Resistance Temperature Detectors (RTDs) and thermocouples ITT Barton differential pressure switches Atkomatic solenoid valves Reliance fan motors and SGTS auxiliaries Brown Boveri load centers Valcor solenoid valves GE Co. radiation elements Pyle National plug connectors General Atomic radiation monitors 0

GE electrical penetrations 9

Buchanan terminal blocks 0

GE terminal blocks Marathon terminal blocks 0

Weidmueller terminal blocks Amp Inc. terminal lugs Scotch insulating tape GE SIS cable Brand Rex cable ITT Suprenant 60O"ontrol cable Okonite 600wpower and control cable Rockbestoable Foxboro pressure transmitters Patel conduit seals Jefferson coaxial cable a

Anaconda cable 0

HPCI system equipment Masoneilan electropneumatic transducer Wesjinghouse Y panels and associated transformers 0

Barlflale pressure switches a

H2 and 02 analyzer Avco pilot solenoid valves Rosemout model no. 71 O-DU trip units Westinghouse manual transfer switch The applicant states that aging effects of the EQ equipment identified in this TLAA will be managed during the extended period of operation by the EQ program activities described in Section B.4.1 of the LRA 4.4.1.2 Staff Evaluation The staff reviewed Section 4.4.1 of the Peach Bottom LRA to determine whether the applicant submitted adequate information to meet the requirements of 10 CFR 54.21(c)(1).

In addition, the staff met with the applicant to obtain clarifications and reviewed the applicant's response to the staff's request for additional information.

4-26

acceptable since 10 CFR 50.49 does not require monitoring and trending of component condition or performance parameters of in-service components to manage the effects of aging.

Acceptance Criteria: 10 CFR 50.49 acceptance criteria is that an in-service EQ component is maintained within its qualification including (a) its established aging limits and (b) continued qualification for the projected accident conditions. 10 CFR 50.49 requires refurbishment, replacement, or requalification prior to exceeding the aging limits of each installed device.

When monitoring is used to modify a component aging limit, plant-specific acceptance criteria are established based on applicable 10 CFR 50.49(f) qualification methods. The staff considers this is acceptable since it is consistent with 10 CFR 50.49 requirements of refurbishment, replacement, or requalification prior to exceeding the qualified life of each installed device.

Corrective Actions, Confirmation Process, and Administrative Controls: If an EQ component is found to be outside Its qualification, corrective actions are implemented in accordance with the PBAPS corrective action process. When unexpected adverse conditions are identified during operational or maintenance activities that effect the environment of a qualified component, the affected EQ component is evaluated and appropriate corrective actions are taken, which may include changes to the qualification bases and conclusions. When emerging industry aging issues are identified that affect the qualification of an EQ component, the affected component is evaluated and appropriate corrective actions are taken, which may include changes to the qualification bases and conclusions. Confirmatory actions, as needed, are implemented as part of the PBAPS corrective actions. The PBAPS EQ program is subject to administrative controls, which require formal reviews and approvals. The PBAPS EQ program will continue to comply with 10 CFR 50.49 throughout the renewal period including development and maintenance of qualification documentation demonstrating a component will perform required functions during harsh accident conditions. The PBAPS EQ program documents identify the applicable environmental conditions for the component locations. The PBAPS EQ program qualification files are maintained in an auditable form for the duration of the install.d life of the component.

The PBAPS EQ program documentation is controlled under the qualifi6U assurance program.

The staff considers this acceptable because corrective actions, confirmation process, and administrative controls are implemented in accordance with the requirement of 10 CFR 50 Appendix B, Quality Assurance Criteria for Nuclear Power Plants and Fuel Reprocessing Plants, that will insure adequacy of corrective actions, confirmation process, and administrative

controls, Operating Experience: The Peach Bottom EQ program includes consideration of operating experience to modify qualification bases and conclusions. Including aging limits. Compliance with 10 CFR 50.49 provides evidence that the component will perform its intended functions during accident conditions after experiencing the detrimental effects of in-service aging. The staff finds that the applicant has adequately addressed operating experience.

The results of the environmental qualification of electrical equipment in Section 4.4. indicate that the aging effects of the EQ of electrical equipment identified in the TLAA will be managed during the extended period of operation under 10 CFR 54.21 (c)(1)(iii). However, no information is provided in the submittal on the attribute of a reanalysis of an aging evaluation to extend the qualification life of electrical equipment identified in the TLAA. The important attributes of a reanalysis are the analytical methods, the data collection and reduction methods, the underlying assumptions, the acceptance criteria, and corrective actions. The staff requested the applicant 4-28

Underlying Assumptions The Peach Bottom EQ Program EQ component aging evaluations contain sufficient conservatism to account for most environmental changes occurring due to plant modification and events. When unexpected adverse conditions are identified during operational or maintenance activities that affect the normal operating environment of a qualified component, the affected EQ component is evaluated and appropriate corrective actions are taken, which may include changes to the qualification bases and conclusions.

Acceptance Criteria and Corrective Actions Under Peach Bottom EQ Program, the reanalysis of an aging evaluation could extend the qualification of the component. If the qualification can not be extended by reanalysis, the component is be refurbished, replaced, or requalified prior to exceeding the period for which the current qualification remains valid. A reanalysis is to be performed in a timely manner (that is sufficient time is available to refurbish, replace, or requalify the component if the reanalysis is unsuccessful).

The staff finds that the above response acceptable because it now addresses the reanalysis attribute.

4.4.1.3 Conclusions The staff has reviewed the informatlon in LRA Section 4.4.1 "Electrical Equipment Environmental Qualification Analyo5 for the Peach Bottom Units 2 and 3 and concluded that the applicant has submitted adequate information to meet the requirements of 10 CFR 54.21 (c)(1) and that the applicant has adequately evaluated the time-limited aging analyses for EQ of electrical equipment consistent with 10 CFR 54.21 (c)(1). The staff has also reviewed the UFSAR Supplement and the staff concludes the applicant has provided an adequate description of its evaluation of this TLAA and the associated program for effectivley managing aging for the period of extended operation as required by 10 CFR 54.21(d).

4.4.2 GSI-1 68, Environmental Qualification of Low Voltage Instrumentation and Control (I&C)

Cables 4.4.2.1 Summary of Technical Information in the Application

51 The applicant states that NRC guidance fo addressing GSI-1 68 "Environmental Qualification of Low Voltage Instrumentation and Control,C)

Cables, for license renewal is contained in the June 2, 1998, NRC letter to NEI. In the letter, the NRC states: "With respect to addressing GSI-1 68 for license renewal, until completion of an ongoing research program and staff evaluations the potential issues associated with GSI-168 and their scope have not been defined to the point that a license renewal applicant can reasonably be expectql to address them at this time. Therefore, an acceptable approach described in the Statemenlof Consideratiorfs to provide a technical rationale demonstrating that the current licensingbasis for environmental qualification pursuant to 10 CFR 50.49 will be maintained in the period of extended operation.

Although the Statemenlof Consideration also indicated that an applicant should provide a brief description of one or more reasonable options that would be available to adequately manage the effects of aging, the staff does not expect an applicant to provide the options at this time.*

4-30

Environmental qualification evaluations of electrical equipment are identified as time-limited aging analyses for Peach Bottom. The Peach Bottom program (Section B.4.1) evaluates the qualified lifetime of equipment in the EQ program. The existing EQ program requires that equipment qualified for 40 years be reanalyzed prior to entering the period of extended operation. The EQ program requires inclusion of any changes managed by closure of GSI-1 68.

Consistent with the above NRC guidance, no additional information is required to address GSI 168 in a license renewal application at this time.

4.4.2.2 Evaluation GSI-168, NEnvironmental Qualification of Low Voltage Instrumentation and Control (£ZC)

Cables," was developed to address environmental qualification of electrical equipment. The staff guidance to the industry (letter dated June 2, 1998 from NRC (Grimes) to NEI (Walters) states:

GSI-168 issues have not been identified to a point that a license renewal applicant can be reasonably expected to address these issues, specifically at this time; and An acceptable approach is to provide a technical rationale demonstrating that the CLB for EQ will be maintained in the period of extended operation.

For the purpose of license renewal, as discussed in the statemenlf consideration (SOC) (60 FR22484, May 8, 1995), there are three options for addressing issues associated with a GSI:

If the issue is resolved before the renewal application is submitted, the applicant can incorporate)(the resolution in the LRA.

An applicant can submit a technical rationale that demonstrate the CLB will be maintained until some later point in the period of extended operation, at which time one or moreasonable options would be available to adequately manage the effects of aging.

An applicant can develop a plant-specific aging management program that incorporates the resolution of the aging issue.

For addressing Issues associated with GSI-1 68, the applicant continues to manage the effects of aging in accordance with the CLB and considers the evaluation of the EQ TLAA to be technical rationale that demonstrate that the CLB will be maintained during the period of extended operation. The staff finds that the applicant has addressed the issues associated with GSI-1168.

4.4.2.3 Conclusions The staff concludes that the applicant has adequately addressed the issues associated with GSI-168. The applicant will continue to manage the effects of aging in accordance with the CLB and considers the evaluation of the EQ TLAA to be the technical rationale that demonstrates that the CLB will be maintained during the period of extended operation in accordance withl64.21 (c)(1). The staff has also reviewed the UFSAR Supplement and the staff to C4F 4-31

concludes the applicant has provided an adequate description of its evaluation of this TLAA for the period of extended operation as required by 10 CFR 54.21(d).

4.5 Reactor Vessel Internals Fatigue and Embrittlement 4.5.1 Summary of Technical Information in the Application Core Shroud and Top Guide BWRVIP-26 [Ref.: EPRI topical report TR-107285, "BWR Vessel and Internals Project: BWR Top Guide Inspection and Flaw Evaluation Guidelines," December 1996] lists 5 x 1020 n/cm2 as the threshold fluence beyond which the components will be significantly affected. The expected 60-year fluence on the shroud, 2.7 x 1020 n/cm2 x 60/40 = 4.5 x 1020 n/cm 2, is below the 5 x 1020 n/cm2 damage threshold. Ucense Renewal Appendix C to BWRVIP-26 states that the generic fluence for 60 years on the top guide is 6 x 1020 n/cm2. The application indicates that although this 60-year fluence will be above the 5 x 1020 n/cm2 damage threshold, the tensile stresses in this component are very low. At these low stresses fracture is not a concern, and embrittlement is, therefore, not a threat to the intended function. These critical locations in the top guide are exempt from inspection under the approved BWRVIP-26 and no aging management activity is required.

Effect of Fatigue and Embrittlement on End-of-Life Reflood Thermal Shock Analysis Radiation embrittlement and fatigue usage may affect the ability of certain internals, particularly the core shroud support plate, to withstand an end-of-life reflood thermal shock following a recirculation line break. Thermal shock analyses assume end-of-life fatigue and embrittlement effects and are considered TLAAs.

The applicant evaluated the effects of embrittlement and fatigue on the end-of-life reflood thermal shock analyses. 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. The net effect in each analyzed location is acceptable. The applicant stated that the thermal shock analyses are, therefore, acceptable for the extended operating period.

4.5.2 Staff Evaluation Core Shroud and Top Guide The BWRVIP inspection program for the core shroud and top guide is discussed in topical report EPRI TR-107285, "BWR Vessel and Internals Project, BWR Top Guide Inspection and Flaw Evaluation Guidelines (BWRVIP-26)," December 1996. This report was approved by the staff in a letter from C.I. Grimes (NRC) to C. Terry (BWRVIP) dated December 7,2000. In its safety evaluation of this report, the staff concluded that due to susceptibility to irradiation assisted stress corrosion cracking (IASCC), applicants referencing the BWRVIP-26 report for license renewal should identify and evaluate the projected accumulated neutron fluence as a potential TLAA Issue, 4-32

BWRVIP-26 lists 5 x 1020 n/cm 2 as the threshold fluence beyond which components will be susceptible to IASCC. Since the expected 60-year fluence on the shroud, is below the 5 x 1020 n/cm2 damage threshold, the core shroud should-not be susceptible to IASCC.

The staff in a telephone call on June 17, 2002, with the applicant discussed the impact of neutron radiation on the integrity of top guide components. BWRVIP-26 states that the generic fluence on the top guide for 60 years is 6 x 1020 n/cm2, which exceeds the 5 x 1020 n/cm2 damage threshold. The applicant stated that the location on the top guide that will see this high fluence is the grid beam. This is location 1, as identified in BWRVIP-26, Table 3-2, "Matrix of Inspection Options." In its evaluation of the top guide assembly, including the grid beam, General Electric (GE) assumed a lower allowable stress value, acknowledging the high fluence value at this location. The conclusion of this analysis, and the fact that a single failure at this location has no safety consequence, was that no inspection was considered necessary.

The staff is concerned that multiple failures of top guide beams are possible when the threshold fluence for IASCC is exceeded. According to BWRVIP-26, multiple cracks have been observed in top guide beams at Oyster Creek. In addition, baffle-former bolts on PWRs that exceeded the threshold fluence have had multiple failures. In order to exclude the top guide beam from inspection when its fluence exceeds the threshold value, the applicant must denmionstrate that failures of multiple beams (all beams that exceed the threshold fluence) will not impact the safe shutdown of the reactor during normal, upset, emergency, and faulted conditions. If this can not be demonstrated, the applicant should propose an aging management program (AMP) for these components which contain the elements in Branch Technical Position RLSB-1 of NUREG-1 800, "Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants," July 2001. This Is Open Item 4.5.2-1.

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 internals (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 emlrittlement on RVI components, the staff concludes that reflood thermal shock will note 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 the exception of Open Item 4.5.2-1, 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)(1)(i). 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).

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transients. The applicant stated that during normal operation, only SRV load cases contribute to fatigue. As part of the FMP, the fatigue analyses will be revised to show that the SRV contribution will not exceed the Code CUF limit during the period of extended operation. This will be confirmed for the duration of the extended operating period by monitoring fatigue at the high-usage-factor locations in the tori, torus vents and penetrations with the FMP, and tracking the CUFs at these locations using the CUF modeling equations, based on the monitored plant transients. These equations will be updated as necessary, and transient events will be tracked to ensure that the CUF due to normal operating transients will remain less than 1.0. The FMP also permits fatigue reanalysis of the high-usage-factor locations. Conservatism in the original containment PUA may permit the reduction of the total calculated CUFs below the limiting value of 0.4, for which fatigue monitoring would be required. Most locations have been evaluated and remain valid for the period of extended operation In accordance with 10 CFR 54.21 (c)(1)(i).

Those that do not remain valid will require management of the aging effects, in accordance with 10 CFR 54.21 (c)(1)(iii).

4.6.1.2 Staff Evaluation The applicant has performed fatigue analyses of the tori, torus vents and torus penetrations that include new Peach Bottom loads. A limit of CUF =0.4 for 40 years as an acceptance criterion was selected to determine if the analyses will remain valid for the period of extended operation.

Those locations with CUF<0.4 will remain valid, pursuant to 10 CFR 54.21 (c)(

I. For those locations that exceed the threshold, the effects of fatigue will be managed Xg*'eRod of extended operation by the FMP cycle counting and fatigue CUF tracking program, pursuant to 10 CFR 54.21 (c)(1)(iii).

4.6.1.3 Conclusions Pursuant to 10 CFR 54.21(c), the staff finds the proposed acceptance limit CUF of 0.4 acceptable. The staff also finds the use of the FMP, to ensure that fatigue effects will be adequately managed and will be maintained within Code design limits for the period of extended operation, reasonable and acceptable. The applicant has also provided an adequate summary of the information related to the fatigue analysis of the tori, torus vents and

.it penetrations in Section A.5.4.1 of the UFSAR Supplement as required by 10 CFR-A;()

4.6.2 Fatigue Analysis of SRV Discharge Unes and Extemal Torus-Attached Piping 4.6.2.1 Summary of Technical Information in the Application The SRV discharge lines and external torus-attached piping were analyzed separately from the tori and the torus vents. The analysis included the SRV lines and all piping and branch lines, including small-bore piping attached to the tori, pipe supports, valves, flanges, equipment nozzles and equipment anchors. The applicant stated that the highest fatigue CUF, calculated in the PUA on the basis of 800 SRV actuations was 0.202. The applicant concludes that the fatigue analyses of this piping will remain valid for the period of extended operation.

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4.6.2.2 Staff Evaluation The applicant has described a conservative approach to determining the fatigue evaluation of the SRV discharge lines and external tows-attached piping. The staff finds this approach reasonable and acceptable.

4.6.2.3 Conclusions Pursuant to 10 CFR 54.21 (c)(1)(i), the staff finds that the applicant's evaluation of the fatigue analyses of the SRV discharge lines and external torus-attached piping demonstrate that these TLAAs will remain valid for the period of extended operation. The applicant has also provided an adequate summary of the information related to the fatigue analysis of the SRV discharge lines and external torus-attached piping in Section A.5.4.2 of the UFSAR Supplement as required by 10 CFR 54.21 (d).

4.6.3 Expansion Joints and Bellows Fatigue Analyses: Drywell-to-Torus Vent Bellows 4.6.3.1 Summary of Technical Information in the Application The applicant has stated that the PUA-calculated fatigue usage factors for the drywell to torus vent bellows are negligible.

4.6.3.2 Staff Evaluation The staff considers the results of the PUA for these components reasonable and acceptable.

4.6.3.3 Conclusions Pursuant to 10 CFR 54.21 (c)(1)(i), the staff finds that the applicant's evaluation of the fatigue analysis of the drywell-to-torus vent bellows demonstrates that these TLAAs will remain valid for the period of extended operation. The applicant has also provided an adequate summary of the information related to the fatigue analysis of the drywell-to-torus vent bellows in Section A.5.4.3 of thb UFSAR Supplement as required by 10 CFR 54.21(d).

4.6.4 Expansion Joint and Bellows Fatigue Analyses: Containment Process Penetration Bellows Expansion Joint and Bellows Fatigue Analyses: Containment Process Penetration Bellows has been identified as a TLAA for the purposes of license renewal. The staff reviewed LRA Section 4.6.4 to determine whether the applicant submitted adequate information to meet the requirements of 10 CFR 54.21(c)(1), F EQ TLA.

Paragraph (1) of

/'10 CFR 54.21(c) requires at a Ist of QTA must be provided. The applicant must demonstrate that (i) the analyses remain valid for the period of extended operation, (ii) analyses have been projected to the end of the period of extended operation, or (iii) the effect of aging on the intended functions will be adequately managed for the perod of extended operation.

4.6.4.1 Summary of Technical Information in the Application 4-36

In response to RAI 4.7-1, the applicant identified the basis for the corrosion rate and the sources for the data. Based on the average of the available data, corrosion rates were determined for high-and low-temperature operating conditions. Assuming 54 years at high temperature and 6 years at low temperature (90% availability for 60 years of operation), and doubling the average corrosion rate, the amount of corrosion for 60 years of operation was estimated to be 0.030 inch. The analysis is acceptable to the staff because the analysis used the average of all available data and conservatively doubled the average corrosion rate to estimate the amount of corrosion for 60 years of operation. Based on the applicant's conservative analysis of the predicted loss of material resulting from corrosion during 60 years of operation, the staff concludes that the corrosion allowance identified when the clad was removed from the main steam nozzles is valid for 60 years of operation.

4.7.1.3 Conclusions S"

The reactor vessel main am nozzle clad removal corrosion allowances have been evaluated and remain valid for the 5eri.od of extended operation in accordance with 10 CFR 54.21 (c)(1)(i).

The applicant has also I~rovided an adequate summary of the information related to the above analysis in Section A.5..1 of the UFSAR Supplement as required by 10 CFR 54.21 (d).

4.7.2 Generic Letter 81-11 "Crack Growth Analysis to Demonstrate Conformance to the Intent of NUREG-0619, BWR Feedwater Nozzle and Control Rod Drive Return Une Nozzle Cracking" 4.7.2.1 Summary of Technical Information in the Application The applicant describes its evaluation of the feedwater nozzle and control rod drive return line nozzle cracking TLAA in LRA Section 4.7.2, "Generic Lettr 81-11 Crack Growth Analysis to Demonstrate Conformance to the Intent of NUREG-0619*BWR Feedwater Nozzle and Control Rod Drive Return Une Nozzle Cracking," and in Section A.5.6, "Inservice Flaw Growth Analyses that Demonstrate Structural Integrity for 40 Years," of Appendix A, "Updated Final Safety Analysis Report (UFSAR) Supplement," of the LRA. The applicant proposes to manage crack growth associated with the TLAA by an NRC-approved BWR Owners Group (BWROG) inspection program.

By late 1970s, inservice inspections (ISIs) discovered cracking on the inside surface of feedwater and control rod drive return line (CRDRL) nozzles at several BWR plants in the United States. The cracking was attributed to thermal cycling due to turbulent mixing of relatively cooler CRDRL water and leaking feedwater with hot downcomer flow. The CRDRL nozzles have been capped at Peach Bottom Units 2 and 3 to eliminate cracking due to thermal cycling.

The applicant has taken the following three actions as recommended by NUREG-0619 and Generic Letter 81-11 to reduce or eliminate the causes of cracking of feedwater nozzles: (a) installation of improved triple thermal sleeves with dual piston ring seals, (b) removal of cladding from the nozzle bore and blend radii, and (c) improvement of the low-flow controller.

The applicant now uses the NRC-approved improved BWROG inspection and management methods in lieu of NUREG-0619 methods. The BWROG methods depend on a fracture mechanics analysis and ultrasonic inspection from the vessel and nozzle exterior. The fracture 4-38

mechanics analysis is used to determine the inspection interval. This analysis is not a TLAA because it does not involve time-limited assumptions defined by the current operating term.

The nozzle crack growth, however, must be acceptable for the period of extended operation to ensure the continued validity of the assumptions of fatigue analyses for the reactor pressure vessel, which are TLAAs.

The feedwater nozzle is subject to the combined effect of long-term, low-cycle thermal fatigue due to heatup, cooldown, and other operational transients (which affects the entire vessel, including the nozzle wall) and high-cycle thermal fatigue due to leaking feedwater (which only affects inner surface of the feedwater nozzle). The UFSAR description of this issue Includes an evaluation of this combined effect, which is a TLAA. However, these two fatigue effects are separable. Table 3.1-1 of the LRA includes both cumulative fatigue damage and cracking as aging effects due to fatigue for BWR feedwater nozzle. The applicant proposes the use of NRC-approved BWROG inspection methods, which no longer depend on this combined fatigue evaluation, to manage cracking due to rapid thermal cycling, in accordance with the requirements of 10 CFR 54.21 (c)(1)(iii).

4.7.2.2 Staff Evaluation The relatively cooler water leaking past the loosely fitted thermal sleeves installed inside the feedwater nozzles has caused cracking of these nozzles in a large number of BWR plants in the United States during 1970s. The cracks were discovered on the Inside surface of the nozzles at the bJend radius and bore. The leaking water (also called bypass leakage) turbulently mixiwith hot downcomer flow in the annulus between the nozzle and thermal sleeve and put high-cycle fatigue loads on the nozzle Inside wall. The cracks initiated by the high-cycle fatigue are arrested at a shallow depth (-6 mm) because the thermal stresses induced by the high-cycle fatigue have steep gradients and shallow depth. These cracks are further propagated by low-cycle fatigue due to plant heatup, cooldown, and feedwater on-off transients.

These transients produce large, throughwall, stress cycles on the nozzle wall and in time could drive the cracks to significant depth. Such cracking has been discovered in the feedwater nozzles at Peach Bottom Units 2 and 3.

Similarly, the relatively cooler water passing through the CRDRL nozzle turbulently mixes with hot downcomer flow and causes cracking on the Inside surface of the nozzle and also on the wall of the reactor pressure vessel beneath the nozzle. Such cracking has been discovered at the CRDRL nozzles at Peach Bottom Units 2 and 3. The applicant reports that these nozzles were> r-'capped after the cracks were repaired and are no longer susceptible to damage due to rapid thermal cycles. Therefore, the staff concludes that cracking of the CRI4RL nozi~es no longer requires aging management for license renewal at Peach Bottom Units X-and t2o-4he--.

NUREG-0619 recommended that the licensees take the following six actions to reduce the potential for initiation and growth of cracks in the inner nozzle areas: (1) remove the cladding from the inner radii; (2) replace loose-fitting or Interference-fitting sparger thermal sleeves; (3) evaluate the acceptability of the flow controllbr; (4) modify operating procedures to reduce thermal fluctuations; (5) reroute reactor water cleanup system (RWCU) discharge to both feedwater loops; and (6) conform to the inspection interval specified In Table 2 of NUREG 0619. In 1981, the NRC staff issued Generic Letter 81-11 to amend the recommendations in 4-39

NUREG-0619, thereby allowing plant-specific fracture mechanics analysis in lieu of hardware modifications.

The first three of the NUREG-0619 recommendations have been implemented at Peach Bottom Units 2 and 3: cladding has been removed from the nozzle bores and blend radii, improved triple thermal sleeves with dual piston ring seals have been installed, and the low-flow controllers have been improved. The implementation of these recommendations has been effective in preventing cracking of the feedwater nozzle. An industry report, GE-NE-523-A71 0594-A, Revision 1, "Altemate BWR Feedwater Nozzle Inspection Requirements," May 2000, states that no new cracking has been identified in the BWR feedwater nozzles since 1984.

The feedwater nozzle is susceptible to the combined effect of low-cycle thermal and mechanical fatigue due to heatup, cooldown, and feedwater on-off transients and high-cycle thermal fatigue due to bypass leakage. The evaluation of this combined effect is a TLAA. The applicant, however, states that these two fatigue effects are separable and proposes two different aging management programs to manage them. The aging effect of low-cycle fatigue is cumulative fatigue damage, whereas the aging effects of high-cycle thermal fatigue is cracking. Several of the NUREG-0619recommendations implemented at Peach Bottom Units 2 and 3 have reduced the potential for cd-cks due to rapid thermal cycling damage. Consequently, the susceptibility to crack initiation at the feedwater nozzle blend radius and bore has also been reduced. This reduced susceptibility to cracking is supported by the significant field experience with the successful prevention of cracks in feedwater nozzles since implementation of the NUREG-0619 recommendations, as mentioned earlier. So the remaining aging effect of high-cycle fatigue is the growth of an existing crack that was initiated earlier by rapid thermal cycling caused by bypass leakage. Therefore, the staff conclude that the separation of two fatigue effects, cumulative fatigue damage and crack growth, is justified.

NUREG-01 9 identified the inservice inspection requirements based on the state-of-the-art in the late 1970s. The required inservice inspection included both ultrasonic testing (UT) of the entire nozzle and dye-penetrant testing (PT) of various portions of blend radius and bore. Since the issuance of NUREG-0619, significant advances have been made in UT inspection technology, and significant field experience has been gained on the successful prevention of cracks in feedwater nozzles. As a result of these improvements, BWROG proposed that UT inspections replace the PT inspections specified in NUREG-061 9, and that UT inspection intervals be based on sparger-sleeve configurations and specific UT inspection methods as described in the report GE-NE-523-A71-0594-A, Revision 1. This report specifies UT of specific regions of the nozzle inner blend radius and bore. The nozzle inner blend radius region is more limiting from a fracture mechanics point of view than the bore region. The UT examination techniques and personnel qualifications are in accordance with the guidelines of GE-NE-523-A71-0594-A, Revision 1. The examination techniques include manual, automatic and phased-array UT methodologies. In a letter from SA. Richards to W. GLenn Warren, dated March 10, 2000, "Final Safety Evaluation of BWR Owners Group Alternative BWR Feedwater Nozzle Inspections," the NRC staff accepted the proposed BWROG inspection methods and fracture mechanics analysis. These NRC-approved BWROG inspection methods and inspection intervals are currently being used at Peach Bottom. The applicant proposes to continue the use of these inspection methods during the extended period of operation.

The BWROG inspection methods require fracture mechanics analysis to estimate the time required for an assumed crack (an initial crack depth of -6 mm [0.5 inch]) to reach the generic 4-40

allowable value (1 inch) or to reach an allowable value based on plant-specific analysis. Plant specific analysis must follow the recommendations of Section 5.6 of the report GE-NE-523 A71-0594-A, Revision 1. The BWROG method determines the inspection interval as a fraction of the time taken for this crack growth. The magnitude of the fraction and therefore the size of the inspection interval depend on the thermal sleeve-sparger design configuration, the UT inspection technique employed, and the specific region of the nozzle inspected. The maximum allowable inspection Interval for the nozzle inner blend radius is 10 years. This fracture mechanics analysis is not a TLAA because it Is used to determine the inspection interval and not to determine whether the crack growth at the end of the current 40-year licensed operating period is acceptable, and so does not involve time-limited assumptions for the current operating term. The GE generic fracture mechanics evaluation show that there is significant margin available to the allowable depth of 1 inch. The report recommends that the fatigue crack growth curves from Section XI of the ASME Code be utilized in the fracture mechanics analysis.

To predict crack growth, Peach Bottom performed the fracture mechanics analysis of feedwater nozzle subjected to thermal cycles expected during the extended period of operation. Analysis at Peach Bottom predicts that growth from the assumed initial flaw size to the allowable value will take about 60 years.

The NRC-approved BWROG inspection methods, along with acceptance criteria and corrective actions are included in the aging management program presented in LRA Section B.2.7, "RPV "o59 and Internals ISI Program." The evaluation of this program is presented in Section 38246 this SER. In addition to these inspections, the applicant proposes to do a periodic review of the fracture mechanics analysis, in conjunction with the fatigue management program presented in Section B.4.2 of the LRA, to ensure that the fracture mechanics evaluation remains bounding and applicable for its intended purpose_-The staff finds the applicant's commitments acceptable.

4.7.2.3 Conclusions The staff has reviewed the information presented in LRA Section 4.7.2, "Generic Letter 81-11 Crack Growth Analysis to Demonstrate Conformance to the Intent of NUREG-0619, BWR Feedwater Nozzle and Control Rod Drive Return Une Nozzle Cracking." On the basis of this review, the staff concludes that the applicant has adequately evaluated this TLAA, as required by 10 CFR 54.21 (c)(1). Specifically, the staff concludes that the RPV and Internals ISI program will ensure that any cracking in the feedwater nozzle will be adequately detected and managed, within the limits of the supporting fracture mechanics analyses, for the period of extended operation, in accordance with the requirements of 10 CFR 54.21 (c)(1)(iii). The applicant has also provided an adequate summary of the information related to the above analysis in Section A.5.r.

Iof the UFSAR Supplement as required by 10 CFR 54.21 (d).

4.7.3 Fracture Mqchanics of ISI-Reportable Indications for Group 1 Piping: As-forged Laminar Tear in a Unit 3 Main Steam Elbow Near Weld 1-B-3BC-LDO Discovered During Preservice UT 4.7.3.1 Summary of Technical Information in the Application The applicant reported that a preservice UT volumetric examination discovered an imbedded as-forged laminar tear in the Unit 3 main steam elbow material. The UT indication did not extend to the weld.

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4 TIME-LIMITED AGING ANALYSES.........................................

4-1 4.1 Identification of Time-Limited Aging Analyses..........................

4-1 4.1.1 Introduction.............................................

4-1 4.1.2 Summary of Technical Information in the Application..............

4-1 4.1.3 Staff Evaluation..........................................

4-3 4.1.4 Conclusion..............................................

4-5 4.2 Reactor Vessel Neutron Embrittlement................................

4-5 4.2.1 10 CFR Part 50 Appendix G Reactor Vessel Rapid Failure Propagation and Brittle Fracture Considerations: Charpy Upper Shelf Energy (USE)

Reduction and RTNmDT Increase, Reflood thermal shock analysis..... 4-5 4.2.2 Reactor Vessel Thermal Analyses: Operating Pressure-Temperature Limit (P-T Limit) Curves..................

..................... 4-10 4.2.3 Reactor Vessel Circumferential Weld Examination Relief.........

4-12 4.2.4 Reactor Vessel Axial Weld Failure Probability..................

4-14 4.3 Metal Fatigue..................................................

4-16 4.4 Environmental Qualification...................................

4-25 4.4.1 Electrical Equipment Environmental Qualification Analyses........

4-25 4.4.2 GSI-168, Environmental Qualification of Low Voltage Instrumentation and Control (l&C) Cables....................................

4-30 4.5 Reactor Vessel Internals Fatigue and Embrittlement....................

4-32 4.6 Containment Fatigue............................................

4-34 4.6.1 Fatigue Analysis of Containment Pressure Boundaries: Analysis of Tori, Torus Vents, and Torus Penetrations........................

4-34 4.6.2 Fatigue Analysis of SRV Discharge Unes and External Torus-Attached Piping................................................

4-35 4.6.3 Expansion Joints and Bellows Fatigue Analyses: Drywell-to-Torus Vent Bellows...............................................

4-36 4.6.4 Expansion Joint and Bellows Fatigue Analyses: Containment Process Penetration Bellows.....................................

4-36 4.7 Other Plant-Specific TLAAs.......................................

4-37 4.7.1 Reactor Vessel Main Steam Nozzle Cladding Removal Corrosion Allowance.............................................

4-37 4.7.2 Generic Letter 81-11 "Crack Growth Analysis to Demonstrate Conformance to the Intent of NUREG-0619, BWR Feedwater Nozzle and Control Rod Drive Return Line Nozzle Cracking3...

...................... 4-38 4.7.3 Fracture Mechanics of ISI-Reportable Indications for Group I Piping: As forged Laminar Tear In a Unit 3 Main Steam Elbow Near Weld 1 -B-3BC LDO Discovered During Preservice UT......................

4-41 4-43

5 REVIEW BY THE ADVISORY COMMITTEE ON REACTOR SAFEGUARDS The Advisory Committee on Reactor Safeguards (ACRS) will review the section of the license renewal application for the Peach Bottom Atomic Power Station, Units 2 and 3 that is required by 10 CFR Part 5f The ACRS Subcommittee on Peach Bottom Ucense Renewal will continue its detailed review of the LRA after this report is issued. Exelon and the staff will meet with the subcommittee and the full committee to discuss issues associated with the review of the LRA.

After the ACRS completes its review of the Peach Bottom LRA and the SER, the full committee will issue a report discussing the results of its review. This report will be included in an update to this SER. The staff will address any issues and concerns identified in that report.

5-1

November 5, 2001 November 16, 2001 November 16, 2001 December 14,2001 January 23, 2002 January 23, 2002 January 23, 2002 January 28, 2002 January 30, 2002

February, 2002 February 6, 2002 In a letter to Exelon signed by R. Anand, the NRC staff issued a summary of the public meeting held on October 22, 2001. In this meeting Exelon provided clarifications of the scoping and screening process discussed in the Peach Bottom LRA.

In a letter to Exelon signed by R. Anand, the NRC staff provided the schedule for the review of the Peach Bottom Atomic Power Station, Unit 2 and 3, LRA.

In a letter signed by M. Gallagher, Exelon submitted its response to the NRC staff's request for additional information (RAI) dated October 30, 2001, regarding Section 2.1-1 of the Peach Bottom LRA.

In a letter signed by R. Anand to Exelon, the NRC staff provided the findings of its audit of the scoping and screening methodology use in the Peach Bottom LRA.

In a letter to Exelon signed by R. Anand, the NRC staff requested additional information regarding the scoping and screening methodology discussed in Section 2.1.2 of the Peach Bottom LRA.

In a letter to Exelon signed by R. Anand, the NRC staff requested additional information regarding the aging management of electrical and instrument and control discussed in Section 3.6 of the Peach Bottom LRA.

In a letter signed by R. Anand, NRC issued a summary of a teleconference between the staff and Exelon representatives. This teleconference was held on December 26, 2001, to clarify information provided by Exelon in Section 3.2 of the Peach Bottom LRA.

In a letter signed by R. Anand, NRC issued a summary of a teleconference between the staff and Exelon representatives. This teleconference was held on January 16, 2002, to clarify information provided by Exelon in Section 3.5 of the Peach Bottom LRA.

In a letter signed by R. Anand, NRC issued a summary of a teleconference between the staff and Exelon representatives. This teleconference was held on January 3, 2002, to clarify information provided by Exelon in Section 4.3 of the Peach Bottom LRA.

In a letter signed by R. Anand, NRC issued a summary of a teleconference between the staff and Exelon representatives. This teleconference was held on February 4, 2002 to clarify information provided by Exelon In Section 2.3 of the Peach Bottom LRA.

In a letter to Exelon signed by R. Anand, the NRC staff requested additional information regarding the aging management of the reactor coolant system, the engineered safety feature systems, the auxiliary A-2

February 7, 2002 February 28, 2002 March 1, 2002 March 1,2002 March 6, 2002 March 12, 2002 March 12, 2002 March 12,2002 March 13, 2002 systems, and the steam and power conversion systems as discussed in Sections 3.1, 3.2, 3.3, and 3.4 of the Peach Bottom LRA.

In a letter to Exelon signed by R. Anand, the NRC staff requested additional information regarding time-limited aging analyses, identification of TLAAs, reactor vessel embrittlement, metal fatigue, and reactor vessel main steam nozzle cladding removal corrosion allowance as discussed in Sections 4.0, 4.1, 4.2, 4.3, and 4.7.1 of the Peach Bottom LRA.

In a letter signed by M. Gallagher, Exelon submitted its response to the NRC staff's RAI dated January 23, 2002, regarding Section 2.1.2 of the Peach Bottom LRA.

In a letter to Exelon signed by R. Anand, the NRC staff requested additional information regarding the aging management of containment, structure, and component supports as discussed in Section 3.5 of the Peach Bottom LRA.

In a letter to Exelon signed by R. Anand, the NRC staff requested additional information regarding the scoping and screening results for reactor coolant system, engineered safety features systems, and auxiliary systems as discussed in Sections 2.3.1, 2.3.2, and 2.3.3 of the Peach Bottom LRA.

In a letter to Exelon signed by R. Anand, the NRC staff requested additional information regarding the aging management activities as discussed in Appendix B of the Peach Bottom LRA.

In a letter to Exelon signed by R. Anand, the NRC staff requested additional information regarding the aging management activities as discussed in Appendix B of the Peach Bottom LRA.

In a letter to Exelon signed by R. Anand, the NRC staff requested additional information regarding the plant-level scoping, and screening results for mechanical, structures, component supports, and electrical and instrumentation and controls as discussed in the Sections 2.2, 2.3, 2.4, and 2.5 of the Peach Bottom LRA.

In a letter to Exelon signed by R. Anand, NRC issued a summary of a teleconference between the staff and Exelon representatives. This teleconference was held on January 22, 2002, to clarify information provided by Exelon in Sections 3.3 and 3.4 of the Peach Bottom LRA.

In a letter to Exelon signed by R. Anand, NRC issued a summary of a teleconference between the staff and Exelon representatives. This teleconference was held on January 22, 2002, to clarify information provided by Exelon in Sections 3.1and,32of the Peach Bottom LRA.

A-3

April 5, 2002 April 29, 2002 April 29, 2002 May 01, 2002 May 06, 2002 May 06, 2002 May 14, 2002 May 21, 2002 May 21, 2002 May 22, 2002 May 31, 2002 June 10, 2002 In a letter to Exelon signed by R. Anand, NRC issued a summary of a teleconference between the staff and Exelon representatives. This teleconference was held on February 20, 2002, to clarify information provided by Exelon in Section 2.0 of the Peach Bottom LRA.

In a letter signed by M. Gallagher, Exelon submitted its response to the NRC staff's RAIs dated January 23, 2002, regarding Section 3.6 of the Peach Bottom LRA.

In a letter signed by M. Gallagher, Exelon submitted its response to the NRC staff's RAIs dated March 12, 2002, regarding the Appendix B aging management activities discussed in the Peach Bottom LRA.

In a letter signed by M. Gallagher, Exelon submitted its response to the NRC staff's RAls dated February 7, 2002, regarding Section 4.0 of the Peach Bottom LRA.

In a letter signed by M. Gallagher, Exelon submitted its response to the NRC staff's RAIs dated March 1, 2002, regarding Section 2.3 of the Peach Bottom LRA.

In a letter signed by M. Gallagher, Exelon submitted its response to the NRC staff's RAIs dated February 6, 2002, regarding Sections 3.1, 3.2, 3.3, and 3.4 of the Peach Bottom LRA.

In a letter signed by M. Gallagher, Exelon submitted its response to the NRC staff's RAls dated March 6, 2002, regarding Appendix B aging management activities discussed in the Peach Bottom LRA.

In a letter signed by M. Gallagher, Exelon submitted its response to the NRC staff's RAIs dated March 1, 2002, regarding Section 3.5 of the Peach Bottom LRA.

In a letter signed by M. Gallagher, E 1on submitted its response to the NRC staffs RAls dated January 231February 6, 2002, regarding RAI 2.1.2-31 Sz...z.-4_

kc, 3.3-I.

In a letter signed by M. Gallagher, Exelon submitted its response to the NRC staff's RAIs dated March 12, 2002, regarding Section 2.0 of the Peach Bottom LRA.

In a NRC Region I letter to Exelon, signed by W. Lanning, the staff submitted Inspection Report 50-277/02-09, 50-278/02-09 conceming the scoping and screening of systems, structures, and components discussed in the Peach Bottom LRA.

In a letter signed by M. Gallagher, Exelon submitted its response to the NRC staff's RAls dated March 12, 2002, regarding Section 4.2-7 of the Peach Bottom LRA.

A-4

NRC IN 87-65, "Lesson Learned from Regional Inspection of Applicant Actions in Response to IE Bulletin 80-11, 'Masonry Wall Design" NRC IN 91-46, "Degradation of Emergency Diesel Generator Fuel Oil Deliver Systems," July 1991 NRC IN 92-20, "Inadequate Local Leak Rate Testing," March 1992 INSPECTION AND AUDIT REPORTS Peach Bottom Atomic Power Station-NRC Inspection Report Nos. 50-277/02-09, 50-278/02 09, May 31, 2002 Peach Bottom Atomic Power Station-NRC Inspection Report Nos. 50-277/02-09, 50-278/02 09, (In process of being Issued)

INSTITUTE OF ELECTRICAL AND ELECTRONICS ENGINEERS (IEEE)

ANS/IEEE Std. 450-1980, "IEEE Recommended Practice for Maintenance, Testing, and Replacement of Large Storage Batteries for Generating Stations and Substations" IEEE Std. 323-1974, "Qualifying Class I E Equipment for Nuclear Power Generating Stations,"

1974 IEEE 43-1974, "Recommended Practice for Testing Insulation Resistance of Rotating Machinery" IEEE 95-1977, "Recommended Practice for Insulation Testing of Large AC Rotating Machinery with High Direct Voltage" NATIONAL FIRE PROTECTION ASSOCIATION (NFPA)

NFPA-25, "Standard for the Inspection, Testing, and Maintenance of Water-Based Fire Protection Systems" NUCLEAR ENERGY INSTITUTE NEI 95-10, "Industry Guideline for Imprenting the Requirements of 10 CFR Part 54-The License Renewal Rule," Revision 3, 4

.11-2001 NEI/NRC License Renewal Work Shop, Reference Documents, October 29, 1997 NUREG REPORTS NUREG-1800, "Standard Review Plan for the Review of License Renewal Applications for Nuclear Power Plants," July 2001 B-6

NUREG-1 801, Generic Aging Lessons Learned Report, July 2001 NUREG-0588, "Interim Staff Position on Environmental Qualification of Safety-Related Electrical Equipment" NUREG-0612, "Control of Heavy Loads at Nuclear Power Plants" NUREG-0619, "BWR Feedwater Nozzle and Control Rod Drive Return Line Nozzle Cracking, Resolution of Generic Technical Activity A 10," November 1980 NUREG-0737, "Clarification of TMI Action Plan Requirements" NUREG-1275, Volume 3, "Operating Experience Feedback Report-Service Water System Failure and Degradations" NUREG-1339, "Resolution of Generic Safety Issue 29: Bolting Degradation or Failure in Nuclear Power Plants," 1990 NUREG-1 526, "Lessons Learned from Early Implementation of Maintenance Rule at Nine Nuclear Power Plants" NUREG-1568, "License Renewal Demonstration Program: NRC Observations and Lessons Learned," December 1996 NUREG/CR-5704, "Effects of LWR Coolant Environment on Fatigue Design Curves of Austenitic Stainless Steels," April 1999 NUREGICR-6260, "Application of NUREG/CR-5999, 'Interim Fatigue Curves to Selected Nuclear Power Plant Components'"

NUREG/CR-6335, "Fatigue Strain-Life Behavior of Carbon and Low-Alloy Steels, Austenitic Stainless Steels, and Alloy 600 in LRA Environments," August 1995 NUREG/CR-6384, "Literature Review of Environmental Qualification of Safety-Related Electric Cables," Vol. 1, April 1996, (Brookhaven National Laboratory, Prepared for U. S. Nuclear Regulatory Commission)

NUREG/CR-6583, "Effects of LWR Coolant Environments in Fatigue Design Curves of Carbon and Low-Alloy Steels" REGULATORY GUIDES (RGs)

NRC RG DG 1.188, "Standard Format and Content for Applications to Renew Nuclear Power Plant Operating Licenses" NRC RG 1.154, "Format and Content of Plant-Specific Pressurized Thermal Shock Safety Analysis Reports for Pressurized Water Reactors" B-7