ML111170204

Request for Additional Information for the Review of the Davis-Besse Nuclear Power Station - Batch 3

ML111170204
Person / Time
Site:	Davis Besse
Issue date:	05/02/2011
From:	Harris B License Renewal Projects Branch 1
To:	Allen B FirstEnergy Nuclear Operating Co
Harris B
References
TAC ME4640
Download: ML111170204 (51)

Text

UNITED STATES NUCLEAR REGULATORY COMMISSION WASHINGTON, D.C. 20555-0001 May 2,2011 Barry S. Allen Vice President, Davis-Besse Nuclear Power Station FirstEnergy Nuclear Operating Company 5501 North State Route 2 Oak Harbor, OH 43449

SUBJECT:

REQUEST FOR ADDITIONAL INFORMATION FOR THE REVIEW OF THE DAVIS-BESSE NUCLEAR POWER STATION-BATCH 3 (TAC NO. ME4640)

Dear Mr. Allen:

By letter dated August 27,2010, FirstEnergy Nuclear Operating Company, submitted an application pursuant to Title 10 Code of the Federal Regulation Part 54 for renewal of Operating License NPF-3 for the Davis-Besse Nuclear Power Station. The staff of the U.S. Nuclear Regulatory Commission (NRC or the staff) is reviewing this application in accordance with the guidance in NUREG-1800, "Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants~' During its review, the staff has identified areas where additional information is needed to complete the review. The staffs requests for additional information are included in the Enclosure. Further requests for additional information may be issued in the future.

Items in the enclosure were discussed with Mr. Cliff Custer, of your staff, and a mutually agreeable date for the response is within 30 days from the date of this letter. If you have any questions, please contact me by telephone at 301-415-2277 or bye-mail at brian. harris2@nrc.gov.

Sincerely,

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'Srlan K. Harris, Project Manager Projects Branch 1 Division of License Renewal Office of Nuclear Reactor Regulation Docket No. 50-346

Enclosure:

As stated cc w/encl: Listserv

DAVIS-BESSE NUCLEAR POWER STATION LICENSE RENEWAL APPLICATION REQUEST FOR ADDITIONAL INFORMATION RAI B.2.3-1 In LRA Section B.2.3, "Air Quality Monitoring Program," under the "scope of program" program element, the applicant stated that this program includes periodic sampling of the air quality in the instrument air system piping and piping components to ensure that the compressed air environment remains dry and free of contaminants, thereby ensuring that there are no aging effects requiring management for this system. SRP-LR, Appendix A.1.2.1.5, states that an aging effect should be identified as applicable for license renewal even if there is a prevention or mitigation program associated with that aging effect.

The staff reviewed LRA Table 3.3.2-17, Instrument Air System, and noted that for steel components in dried air, the applicant cited plant-specific footnote 318, which states that the Air Quality Monitoring Program ensures that the instrument air system remains dry and free of contaminants, thereby sustaining the aging management review conclusion that there are no aging effects that require management. However, the program has not been credited.

Justify why the LRA does not identify an aging effect as applicable for license renewal and credit the Air Quality Monitoring Program as a preventive program that manages this aging effect.

RAI B.2.3-2 In LRA Section 8.2.3, "Air Quality Monitoring Program," under the "detection of aging effects" program element, the applicant stated that the presence of an environmental stressor (moisture), which could lead to corrosion of system components, is detected and moisture, if any, is removed to ensure air quality (and intended function) is maintained. SRP-LR Section A.1.2.3.4, states that this program element describes "when," "where," and "how,"

program data are collected, and that the method or technique and frequency may be linked to plant-specific or industry-wide operating experience, and to provide justification, including codes and standards referenced, that the frequency is adequate.

The staff reviewed LRA Section B.2.3 and noted that the applicant has not identified the frequency of periodic sampling nor provided any industry standards such as ISA or EPRI to confirm that the frequency is adequate.

Provide the frequency of periodic testing of contaminants and any industry standards used to determine the frequency.

RAI B.2.3-3 In LRA Section B.2.3, "Air Quality Monitoring Program," under the "acceptance criteria" program element, the applicant specified acceptance criteria for particulates, hydrocarbons and dew ENCLOSURE

2 point as necessary for sampling of the instrument air system. SRP-LR Section A.1.2.3.6 states that the acceptance criteria of the program and its basis should be described.

The staff reviewed LRA Section B.2.3 and noted that the applicant has not identified the basis for the acceptance criteria.

Provide the basis for the acceptance criteria, such as current licensing basis (CLB) or an industry standard, to ensure that the instrument air system remains dry and free of contaminants.

RAI8.2.3-4 In LRA Section B.2.3, "Air Quality Monitoring Program," under the "operating experience" program element, the applicant stated that in 2007, one out of nine air samples drawn for particulate testing exceeded the Preventive Maintenance limit that was established as a threshold for further investigation, and the work order system was used to investigate and characterize the system piping that produced the high particulate loading. The staff reviewed the applicant's "operating experience" program element against the criteria in SRP LR Section A.1.2.3.1, which states that operating experience with existing programs should be discussed. The operating experience of aging management programs, including past corrective actions resulting in program enhancements or additional programs, should be considered.

The staff reviewed LRA Section B.2.3 and noted that the applicant did not describe in detail the cause of the abnormal particulate testing and corrective actions taken.

With regard to the particular operating experience described above, were any corrective actions taken that resulted in program enhancements? If so, provide additional details on the cause of the variance and associated corrective actions. Since 2007, have there been any additional air samples that have exceeded the Preventive Maintenance limit?

RAI8.2.9-1 In license renewal application (LRA) Section B.2.9, "Collection, Drainage and Treatment Components Inspection Program," under the "detection of aging effects" program element, the applicant stated that inspections will be conducted using visual (VT-3 or equivalent) inspection methods performed by qualified personnel following procedures consistent with the American Society of Mechanical Engineers (ASME) Code and 10 Part CFR 50, Appendix B. ASME Section III, Subsection IWA-2213, states that VT-3 examinations are conducted to determine the general mechanical condition of components and their supports. ASME Section III, Subsection IWA-2211, states that VT-1 examinations are conducted to detect discontinuities and imperfections on the surface of components including such conditions as cracks, wear, corrosion and erosion. Also, the comparable aging management program (AMP) in the Generic Aging Lessons Learned (GALL) Report, XI.M32, "One-Time Inspection," in the "detection of aging effects" program element recommends VT-1 or equivalent for detecting crevice and pitting corrosion.

This plant-specific program is credited to manage loss of material due to general, pitting and crevice corrosion, and cracking. A VT-3 or equivalent method may be satisfactory to detect

3 general corrosion, but is not necessarily an acceptable method to detect crevice or pitting corrosion, and cracking.

Justify that VT-3 or equivalent inspectio~ method will detect pitting and crevice corrosion.

RAI8.2.9-2 In LRA Section 8.2.9, "Collection, Drainage and Treatment Components Inspection Program,"

under the "acceptance criteria" program element, the applicant stated that indications or relevant conditions of degradation detected during the inspections will be compared to pre-determined acceptance criteria. The applicant also stated that unacceptable inspection findings will include visible evidence of cracking, loss of material, or reduction in heat transfer due to fouling that could lead to loss of component intended function during the period of extended operation. Standard Review Plan for Reviewing of License Renewal Applications for Nuclear Power Plants (SRP-LR) Section A.1.2.3.6 states that the acceptance criteria of the program and its basis should be described.

The staff reviewed LRA Section 8.2.9 and noted that the applicant has not identified the basis for the acceptance criteria.

Provide the basis and the description, such as manufacturer's recommendations or industry standards, for the acceptance criteria associated with this program.

RAI 2.3.3.18-2 LRA Section 2.3.3.18, "Makeup and Purification System," states that the letdown coolers, designated as DB-E25-1 and 2, are replaced periodically, are evaluated as short-lived components (consumables), and, therefore, are not subject to aging management review (AMR).

According to SRP-LR Section 2.1.3.2.2, replacement programs may be based on vendor recommendations, plant experience, or any means that establish a specific replacement frequency under a controlled program. It also notes that component replacements based on performance or condition are not generically excluded from AMR and performance or condition monitoring may be evaluated as programs to ensure functionality during extended operation.

The staff noted that previous LRAs for other sites have acknowledged problems with these specific heat exchangers, and in one case cracking in the tubes was attributed to high cycle fatigue during infrequent events. However, the related problems at these sites had apparently been resolved and the heat exchangers were being age managed in a routine manner similar to other heat exchangers. The staff also noted that LRA Section 3.3.2.2.4.1, which addresses heat exchangers in the same system, states that cracking due to cyclic loading is not identified as an aging effect requiring management. The bases for Davis-Besse's determination regarding cyclic loading is the subject of the NRC's RAI 3.3.2.2.4-1; however, the industry experience associated with the heat exchanger cracking issue, and Davis-Besse's periodic replacement of the heat exchangers in conjunction with its determination that cracking due to cyclic loading does not require age management, all appear to be integrally related.

4 The LRA did not include information regarding the replacement frequency, the bases for the frequency, or any discussion regarding the reasons these normally long-lived components need to be replaced. In order to evaluate the adequacy of age managing of other components in this system, information is needed to understand the extent of the condition and the reason for periodic replacement of these heat exchangers.

The staff requests the following information:

1. State the basis for the replacement frequency of letdown coolers, DB-E25-1 and 2. If the frequency is based on qualified life, then provide information to demonstrate that the cooler's intended function is being maintained consistent with current licensing basis immediately prior to replacement. If the frequency is based on performance or condition monitoring, then provide the AMP that manages the monitoring.

2. State the circumstances surrounding the need to replace these coolers, and provide details for the extent of condition and cause (e.g., other heat exchangers in similar configurations, other components in the system) that was conducted.

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RA13.0 The NRC staff reviewed the AMPs described in Appendix A, "Updated Safety Analysis Report Supplement," and Appendix B, "Aging Management Programs," of the license renewal application. The purpose of the review was to assure that the aging management activities were consistent with the staff's guidance described in NUREG-1800, Section A.2, "Quality Assurance for Aging Management Programs (Branch Technical Position IQMB-1)," regarding quality assurance attributes of AMPs.

The staff determined that the AMP quality assurance attributes (Element 7 - Corrective Action, Element 8 - Confirmation Process, and Element 9 - Administrative Controls) described in Appendix B, Section B.1.3, "Quality Assurance Program and Administrative Controls," of the LRA for all programs credited for managing aging effects, were consistent with Branch Technical Position IQMB-1. Section B.1.3 states that the quality attributes would be implemented in accordance with the applicant's 10 CFR Part 50, Appendix B, quality assurance program and be applied to both safety-related and nonsafety-related structures and components (SCs) subject to the aging management programs during the period of extended operation.

However, the applicant has not specifically addressed the application of the AMP quality attributes in Appendix A, "Updated Safety Analysis Report Supplement," to nonsafety-related SCs. Appendix A does not contain a specific statement that the quality attributes, implemented in accordance with the applicant's 10 CFR Part 50, Appendix B, quality assurance program, would be applied to both safety-related and nonsafety-related SCs subject to the AMPs during the period of extended operation.

The staff requests that the applicant supplement the information provided in Appendix A to state that the AMP quality attributes, implemented in accordance with the applicant's 10 CFR Part 50, Appendix B, quality assurance program, will be applied to both safety-related and nonsafety-related SCs subject to the AMPs during the period of extended operation.

5 RAI3.1.1.70-1 GALL Report Rev. 1, item IV.C2-1 addresses Class 1 piping, fitting and branch connections less than nominal pipe size (NPS) 4, which are exposed to reactor coolant and subject to cracking due to stress corrosion cracking (SCC) and thermal and mechanical loading. It also recommends the ASME Section XI Inservice Inspection Subsections, IWB, IWC and IWD Program, Water Chemistry Program, and One-time Inspection of ASME Code Class 1 Small-bore Piping Program to manage the aging effect.

LRA Table 3.1.2-3, in Row Nos. 230 to 232 and 237 to 239, indicates that valve bodies less than 4 inches, made of cast austenitic stainless steel (CASS) and stainless steel respectively, are subject to cracking due to flaw growth, SCC and intergranular attack (lGA) in a borated reactor coolant environment. LRA Table 3.1.2-3 also indicates that the applicant will use the Inservice Inspection Program, pressure water reactor (PWR) Water Chemistry Program, and Small Bore Class 1 Piping Inspection Program to manage the aging effect. The LRA table further indicates that the valve bodies less than 4 inches are related to LRA Table 1 item 3.1.1-70 and consistent with GALL Report Rev. 1, item IV.C2-1.

LRA Section B.2.37 states that the Small Bore Class 1 Piping Inspection Program will detect and characterize cracking of small bore ASME Code Class 1 piping less than 4 inches NPS, which includes pipe, fitting, and branch connections.

LRA Section B.2.37 indicates that the scope of the Small Bore Class 1 Piping Inspection Program includes small-bore pipe, fitting and branch connections; however it does not discuss valve bodies. The staff noted that scope of components for the applicant's Small Bore Class 1 Piping Inspection Program does not include valve bodies and conflicts with the aging management review result to manage cracking in the CASS and stainless steel valve bodies less than 4 inches.

Clarify why the Small Bore Class 1 Piping Inspection Program is credited to manage cracking due to flaw growth, SCC and IGA of the stainless steel and CASS valve bodies less than 4 inches, when this program only includes small-bore pipe, fitting and branch connections. In addition, clarify how this program will manage this aging effect specific to stainless steel and CASS valve bodies less than 4 inches.

RAI 3.1.2.1.58-1 In LRA Table 3.1.2-1, item 99, the applicant states that it will manage loss of material of the upper reactor vessel head with the Boric Acid Corrosion Program. Consistent with this, in LRA Section 8.2.29, "Nickel-Alloy Reactor Vessel Closure Head Nozzle Program," the applicant stated that the Boric Acid Corrosion Program will be used to manage wastage of the reactor vessel closure head surfaces, but also states that inservice inspections of the vessel closure head surfaces will be performed in accordance with ASME Code Case N-729-1. In addition to inspection requirements, ASME Code Case N-729-1 specifies the performance of evaluations for relevant conditions and prescribes methods for repair activities.

6 In LRA Section B.2.6, "Boric Acid Corrosion Program," the applicant did not state that the appropriate requirements from ASME Code Case N-729-1 are included in the program for loss of material of the upper vessel head.

Clarify whether the Boric Acid Corrosion Program includes consideration of evaluations and repair activities associated with ASME Code Case N-729-1, and if not, provide information on how the loss of material consideration for the reactor vessel closure head associated with this code case is incorporated into another aging management program.

LRA Table 3.1.2-2, Row No. 204, addresses CASS reactor vessel internal plenum cylinder reinforcing plates exposed to borated reactor coolant with neutron fluence. The applicant related referenced LRA Table 1 item 3.1.1-80 and GALL Report item IV. B4-4 for this component, which indicates that the component is subject to reduction in fracture toughness due to thermal aging and neutron irradiation embrittlement. The applicant stated that this aging effect is managed by the PWR Reactor Vessel Internals Program.

LRA Section B.2.32 states that the PWR Reactor Vessel Internals Program is based on the examination requirements provided in EPRI Topical Report 1016596, "Materials Reliability Program: Pressurized Water Reactor Internals Inspection and Evaluation Guidelines (MRP-227, Rev. 0)," along with the implementation guidance described in NEI 03-08.

The staff reviewed MRP-227, Rev. 0, Table 3-1, which lists the reactor vessel internal components of B&W-designed PWRs that require further evaluation for categorization and aging management strategy development. MRP-227, Table 3-1 also lists the aging mechanisms applicable to the vessel internals of B&W plants. In addition, MRP-227, Tables 4-1 and 4-4 list the aging effects and examination methods to inspect the "Primary" and "Expansion" components, respectively, of B&W plants.

The staff noted that MRP-227, Rev. 0, Table 3-1,4-1 or 4-4 does not specifically address the reduction in fracture toughness of the CASS plenum cylinder reinforcing plate. Therefore, it is not clear to the staff how the applicant will manage the reduction in facture toughness due to thermal aging and neutron irradiation embrittlement of the CASS plenum cylinder reinforcing plate.

Describe and justify how the CASS plenum cylinder reinforcing plate will be managed for reduction in facture toughness by the PWR Reactor Vessel Internals Program.

RAI 3.1.2.2.1-1 The following AMR line items discussed in LRA Section 3.1 credit a time limited aging analysis (TLAA) to manage cumulative fatigue damage:

• LRA Table 3.1.2-4, Row No. 67 addresses the nickel alloy secondary side - auxiliary feedwater pumps (AFW) thermal sleeve and AFW header transition section for cracking due to fatigue.

7

• LRA Table 3.1.2-4, Row No. 92 addresses the nickel alloy secondary side - main feedwater (MFW) spray head for cracking due to fatigue.

• LRA Table 3.1.2-3, Row No. 164 addresses the steel pressurizer support plate assembly for cracking due to fatigue.

• LRA Table 3.1.2-4, Row No. 84 addresses the steel secondary side - MFW header support plate and gusset for cracking due to fatigue by crediting a TLAA.

• LRA Table 3.1.2-4, Row No. 86 addresses the steel secondary side - MFW header for cracking due to fatigue.

• LRA Table 3.1.2-4, Row No. 110 addresses the steel secondary side - pipe cap for cracking due to fatigue.

For the AMR line items listed above, the staff reviewed LRA Section 4.3 "Metal Fatigue," and it was not clear to the staff which specific TLAA is being credited to manage the cumulative fatigue damage. The staff was not able to confirm if there is a TLAA for components identified by the AMR line items listed above.

The staff requests the following information:

• Clarify the fatigue TLAA that is being credited to manage cumulative fatigue damage for the components identified by the AMR line items in LRA Table 3.1.2-4, Row No. 67, 84, 86,92 and 110; and LRA Table 3.1.2-3, Row No. 164.

• If the fatigue TLAA for these components are not discussed in LRA Section 4, justify why the TLAA was not identified and dispositioned in accordance with 10 CFR 54.21 (c}(1).

In lieu of a justification, amend LRA Section 4 to include these fatigue TLAAs, including the disposition in accordance with 10 CFR 54.21 (c}(1) and any information that supports this disposition (e.g. cumulative usage factor (CUF) values).

RAI 3.2.2.1.26-1 In LRA Table 3.2.2-1, Row Nos. 26 and 28; Table 3.2.2-2, Rows 20 and 35; Table 3.3.2-1, Rows 76,77,78,79,80,84,88, and 91; Table 3.3.2-4, Row 159; Table 3.3.2-5, Row 60; Table 3.3.2-8, Row 43; Table 3.3.2-12, Row 42; Table 3.3.2-14, Row 25; Table 3.3.2-26, Rows 76 and 83; Table 3.3.2-27, Row 38; Table 3.3.2-30, Row 31; and Table 3.4.2-2, Row 8, the applicant addressed a number of material, environment, aging effect/mechanism combinations as either Generic Note G or H, and assigned only the One-Time Inspection Program. The current staff position, in the GALL Report, is that a more in-depth, periodic inspection program such as the Inspection of Internal Surfaces in Miscellaneous Piping Program or the External Surfaces Monitoring of Mechanical Components Program should be used to manage the aging effect/mechanisms such as loss of material, cracking, or reduction in heat transfer for these component/material/environment combinations.

Consistent with the GALL Report, one-time inspections are appropriate for managing loss of material where environments are consistent with time such as the fuel oil, lube oil, and water chemistry programs. Where environments may not be consistent with time, such as indoor air or outdoor air, the GALL Report recommends the performance of periodic inspections since a

8 single inspection may not reflect, or predict, the existence of future degradation. Therefore, it is unclear why the applicant has selected the One-Time Inspection Program to manage the various aging effects instead of a program that conducts periodic inspections.

The staff requests the following information:

1. Given that the One-Time Inspection Program may not be an effective program for managing the aging effects associated with the Table 2 line items above, provide details as to how aging will be managed for these material and environment combinations.

2. Provide an assessment of those Table 2 AMR line items containing similar material, environment, and aging effect combinations that might be similarly affected, and revise these line items to ensure an appropriate aging management program.

RAI 3.2.2.2.1-1 LRA Sections 3.2.2.2.1, 3.3.2.2.1 and 3.4.2.2.1 state that fatigue is a TLAA as defined in 10 CFR 54.3. TLAAs are required to be evaluated in accordance with 10 CFR 54.21 (c)(1). The evaluations of the fatigue TLAAs are addressed in LRA, Section 4.

LRA Section 4.3.3.1 discusses the TLAAs associated with fatigue of non-Class 1 piping and in line components and states that these TLAAs will remain valid for the period of extended operation in accordance with 10 CFR 54.21 (c)(1)(i).

The staff reviewed AMR results in the associated LRA Tables (3.x.2-y) in LRA Sections 3.2, 3.3 and 3.4, and noted that they did not include the applicable AMR line items for the TLAAs associated with fatigue of non-Class 1 piping and in-line components. It is not clear to the staff why the components analyzed for cumulative fatigue damage by the TLAAs discussed in LRA Section 4.3.3.1 are not included as AMR line items in LRA Sections 3.2, 3.3 and 3.4.

Justify that AMR line items associated with the TLAAs for fatigue of non-Class 1 piping and in line components do not need to be included in LRA Section 3.2, 3.3 and 3.4, as applicable. In lieu of a justification, revise the applicable LRA Tables (3.x.2-y) in LRA Sections 3.2, 3.3 and 3.4, to include the AMR line items that address cumUlative fatigue damage for non-Class 1 piping and in-line components.

RAI 3.2.2.3.4-2 In LRA Tables 3.2.2-4,3.2.2-5,3.3.2-12,3.3.2-17, and 3.3.2-30, the applicant stated that for stainless steel piping, strainer bodies, strainer screens, tanks, tubing, and valve bodies exposed either externally or internally to air or air-outdoor, there is no aging effect and no AMP is proposed. In LRA Table 3.0-1, the applicant equated the environment of "air" to the GALL Report environments of "air-indoor (uncontrolled)" and "moist air or condensation (internal}."

The GALL Report, Revision 2, contains line items for stainless steel piping, piping components, piping elements, and tanks exposed to outdoor air (Tables V.D1, VII.D, and VII.H2), and stainless steel piping, piping components, piping elements internally exposed to condensation (Table VII.D). The GALL Report suggests that such components may be subject to cracking

9 and loss of material based on the environmental conditions applicable to the plant. If so, the GALL Report recommends periodic visual inspections to detect signs of aging.

Outdoor air environments (and associated indoor air environments) likely to cause loss of material and/or cracking include, but are not limited to, those within approximately 5 miles of a saltwater coastline, those within one-half mile of a highway which is treated with salt in the wintertime, those areas in which the soil contains more than trace chlorides, those plants having cooling towers where the water is treated with chlorine or chlorine compounds, and those areas subject to chloride contamination from other agricultural or industrial sources.

Provide justification as to why air or air-outdoor will not induce loss of material and/or cracking in stainless steel components at Davis-Besse. In addition, state how aging of stainless steel components will be managed if it is determined that loss of material and/or cracking cannot be ruled out as an aging effect requiring management for stainless steel components.

RAI 3.2.2.2.3.6-1 SRP-LR Table 3.2-1, item 8, states that loss of material from pitting and crevice corrosion could occur for stainless steel components exposed to internal condensation and a plant-specific AMP should be used to ensure that the aging effect is adequately managed. The current staff position is reflected in SRP-LR, Revision 2, Table 3.2-1, item 48, and the GALL Report Revision 2, items V.A.EP-81 and V.D1.EP-81, which recommend that aging in a condensate environment in the engineered safety features systems be managed by AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components." The GALL Report, Revision 2, Table IX.D, states that condensation is considered to be "raw water" due to the potential for surface contamination. In LRA Table 3.2.1, item 3.2.1-08, the applicant stated that this aging effect will be managed by the One-Time Inspection Program.

It is not clear to the staff how a one-time inspection will be adequate to manage pitting and crevice corrosion of stainless steel components exposed to internal condensation. A one-time inspection is typically used to confirm the insignificance of an aging effect when the aging effect is not expected to occur, the aging effect is expected to progress very slowly, or the characteristics of the aging effect include a long incubation period. The GALL Report Revision 2 recommends that aging in a condensation environment be managed in a manner consistent with a raw water environment, in which periodic inspections are used to ensure that loss of material is adequately managed.

State why a one-time inspection program is used rather than a program with periodic inspections to detect loss of material in stainless steel components exposed to internal condensation, or propose an AMP that includes periodic inspections for pitting and crevice corrosion.

RAI 3.2.2.2.6-1 SRP-LR, Section 3.2.2.2.6, is associated with Table 3.2-1, item 3.2.1-12, and addresses loss of material due to erosion for stainless steel miniflow orifices in high-pressure safety injection pump minimum flow lines. The SRP-LR references LER 50-275/94-023 which documents

10 operating experience where extended use of a centrifugal high pressure safety injection pump for normal charging caused erosion in the miniflow orifice and affected the ability of the pump to perform its intended function. The SRP-LR recommends that a plant-specific AMP be evaluated for erosion of the orifice, and SRP-LR Appendix A.1.2.3.4 states that for a plant-specific program detection of aging effects should occur before there is a loss of the structure's or component's intended function(s).

In LRA Table 3.2.1, item 3.2.1-12, the applicant stated that this item is not applicable, and provides justification by stating that the high-pressure injection pump is not used for normal charging and that normal charging is provided by the makeup pump. However, the discussion continues by stating that loss of material due to erosion in the high-pressure injection and makeup pump miniflow recirculation orifices is addressed in item 3.2.1-49. LRA Section 3.2.2.2.6 contains similar information as discussed in item 3.2.1-12, and adds that the high pressure injection pump is normally in standby. In this section, the applicant then stated that loss of material due to erosion in the makeup pump and high pressure injection pump miniflow recirculation orifices is managed by the PWR Water Chemistry Program through periodic monitoring and control of contaminants, and that the One-Time Inspection will provide verification of the effectiveness of the PWR Water Chemistry Program to manage loss of material.

LRA Table 3.2.1, item 3.2.1-49, which is cited in item 3.2.1-12, only addresses loss of material due to pitting and crevice corrosion and does not address loss of material due to erosion. It is not clear whether loss of material due to erosion is an aging effect applicable to the orifice in the minimum flow line for the high-pressure injection pump, or if this aging effect is not applicable to this component because the pump is normally in standby. If the aging effect is applicable, then it is not clear whether the One-Time Inspection proposed for managing the aging effect/mechanism of loss of material due to erosion would include a one-time examination of an orifice subject to normal flow and potential erosion (e.g., the high pressure makeup pump), or whether the orifices would be included as part of a sampling of a pipe component population (not orifices) where erosion would be a less likely mechanism to cause loss of material.

The staff requests the following information:

1. Clarify whether loss of material due to erosion is an aging effect expected to occur, and whether this aging effect is being managed for the high pressure injection pump that is normally in standby.

2. If this aging effect is expected to occur and is being managed, clarify whether the proposed One-Time Inspection to manage loss of material due to erosion will examine orifices of similar material and environments that routinely have flow through them.

RAI 3.2.2.3.4-1 In LRA Tables 3.2.2-4 and 3.3.2-12, the applicant stated that for aluminum valve bodies and flame arrestors exposed to air-outdoor (external), there is no aging effect and no AMP is proposed.

11 In the GALL Report, Revision 2, Tables V.E and VI 1.1 , the aging effect of loss of material due to pitting and crevice corrosion is identified for aluminum piping, piping components and piping elements externally exposed to outdoor air. GALL AMP XI.M36, "External Surfaces Monitoring of Mechanical Components," is recommended as a suitable program to manage the aging effect/mechanism (AEM) of loss of material due to pitting and crevice corrosion. In addition, the staff notes that corrosion of aluminum in the passive range is usually manifested by random formation of pits (Ref: Metals Handbook, Volume 13, Corrosion).

Provide justification as to why air-outdoor (external) will not induce loss of material in aluminum alloy components. If it is determined that loss of material due to pitting and crevice corrosion cannot be ruled out as an AEM, please state how aging of aluminum alloy components will be managed.

RAI 3.2.2.3.4-2 In LRA Tables 3.2.2-4,3.2.2-5,3.3.2-12,3.3.2-17, and 3.3.2-30, the applicant stated that for stainless steel piping, strainer bodies, strainer screens, tanks, tubing, and valve bodies exposed either externally or internally to air or air-outdoor, there is no aging effect and no AMP is proposed. In LRA Table 3.0-1, the applicant equated the environment of "air" to the GALL Report environments of "air-indoor (uncontrolled)" and "moist air or condensation (internal}."

The GALL Report, Revision 2, contains line items for stainless steel piping, piping components, piping elements, and tanks exposed to outdoor air (Tables V.D1, VII.D, and VII.H2), and stainless steel piping, piping components, piping elements internally exposed to condensation (Table VII.D). The GALL Report suggests that such components may be subject to cracking and loss of material based on the environmental conditions applicable to the plant. If so, the GALL Report recommends periodic visual inspections to detect signs of aging.

Outdoor air environments (and associated indoor air environments) likely to cause loss of material and/or cracking include, but are not limited to, those within approximately 5 miles of a saltwater coastline, those within one-half mile of a highway which is treated with salt in the wintertime, those areas in which the soil contains more than trace chlorides, those plants having cooling towers where the water is treated with chlorine or chlorine compounds, and those areas subject to chloride contamination from other agricultural or industrial sources.

Provide justification as to why air or air-outdoor will not induce loss of material and/or cracking in stainless steel components at Davis-Besse. In addition, please state how aging of stainless steel components will be managed if it is determined that loss of material and/or cracking cannot be ruled out as an aging effect requiring management for stainless steel components.

RAI 3.3.1.39-1 GALL Report Revision 1, Volume 1, Table 3, item 39 and GALL Report Revision 2, item VII.A2.A-97 states that stainless steel spent fuel storage racks exposed to treated water greater than 60°C (140°F) are susceptible to SCC and should be managed by the Water Chemistry Program. LRA Table 3.3.1 indicates that item 3.3.1-39 is not applicable because it only will

12 occur for BWR plants. LRA Table 3.5.2-2 also indicates that stainless steel spent fuel storage racks exposed to treated borated water is only susceptible to loss of material.

The applicant's aging management review result is not consistent with the GALL Report indicating that cracking due to SCC is an aging effect requiring management for the stainless steel spent fuel storage racks exposed to treated water greater than 60°C (140°F).

Justify why the cracking due to SCC is not an aging effect requiring management for the stainless steel spent fuel storage racks. If it is determined that the spent fuel storage racks are susceptible to SCC under their exposure conditions, provide additional information on how cracking due to SCC will be managed for the components during the period of extended operation.

RAI3.3.1.49-1 SRP-LR, Table 3.3-1, item 49, recommends that stainless steel and steel with stainless steel cladding heat exchanger components exposed to closed cycle cooling water be managed by the Closed-Cycle Cooling Water System Program for loss of material due to microbiologically influenced corrosion. LRA Table 3.3.1, item 3.3.1-49, states that this aging effect is not applicable because loss of material due to microbiologically influenced corrosion is not identified as an aging effect requiring management for stainless steel heat exchanger components that are exposed to closed cycle cooling water.

It is not clear to the staff why the applicant does not consider loss of material due to microbiologically influenced corrosion to be an applicable aging affect for stainless steel heat exchanger components exposed to closed cycle cooling water.

State why loss of material due to microbiologically influenced corrosion is not an applicable aging effect for stainless steel heat exchanger components exposed to closed cycle cooling water, or propose an AMP to manage this aging effect.

RAI 3.3.1.54-1 SRP-LR Table 3.3-1, item 54 addresses stainless steel compressed air system piping, piping components, and piping elements exposed to internal condensation. The SRP-LR item recommends GALL AMP XI.M24, "Compressed Air Monitoring," to manage loss of material due to pitting and crevice corrosion. GALL AMP XI.M24 includes visual inspections, leakage testing, and air quality monitoring to manage loss of material for this component group.

LRA Table 3.3.1, item 3.3.1-54 addresses stainless steel tubing, piping, filter housings, pump casings, tanks, orifices and valve bodies exposed to internal condensation which are being managed for loss of material due to pitting and crevice corrosion. The LRA credits the One-Time Inspection Program to manage aging for stainless steel tubing in the instrument air system and cites generic note E. The applicant's One-Time Inspection Program includes one-time inspections of a sample of components in the program.

13 It is not clear to the staff how the applicant's One-Time Inspection Program, which does not include periodic inspections or preventive measures, is adequate to manage loss of material for stainless steel components exposed to internal condensation in the instrument air system, given that the GALL Report recommends periodic inspections, leakage testing, and air quality monitoring to manage the aging effect.

Explain why a one-time inspection is an acceptable alternative to periodic inspections and air quality monitoring to manage loss of material due to pitting and crevice corrosion for these components.

RAI 3.3.1.68-1 SRP-LR Table 3.3-1, items 3.3.1-68,3.3.1-69, and 3.3.1-70, address steel, stainless steel, and copper alloy piping, piping components, and piping elements exposed to raw water and recommend GALL AMP XI.M27, "Fire Water System," to manage loss of material. GALL AMP XI.M27 includes flow testing and wall thickness evaluations using either non-intrusive or visual examination techniques to manage loss of material. GALL AMP XI.M27 recommends that the visual inspections be performed on a representative number of locations on a reasonable basis, and be capable of evaluating (1) wall thickness to ensure against catastrophic failure and (2) the inner diameter of the pipe as it applies to design flow.

LRA Table 3.3.1, items 3.3.1-68, 3.3.1-69, and 3.3.1-70, state that the Collection, Drainage, and Treatment Components Inspection Program will be used to manage loss of material for steel, stainless steel, and copper alloy components exposed to raw water in the fire protection (diesel) and station plumbing, drains, and sumps systems. The Collection, Drainage, and Treatment Components Inspection Program includes opportunistic visual inspections for loss of material, cracking, and reduction of heat transfer. The visual inspections in the Collection, Drainage, and Treatment Components Inspection Program are not required to be performed on a representative number of locations on a reasonable basis, and do not state that they are capable of detecting wall thickness to ensure against catastrophic failure or the inner diameter of the pipe as it applies to design flow.

It is not clear to the staff how the Collection, Drainage, and Treatment Components Inspection Program is sufficient to manage loss of material for these components given that the program only includes opportunistic visual inspections.

Provide technical justification for using the Collection, Drainage, and Treatment Components Inspection Program to manage loss of material for the AMR items associated with LRA Table 3.3.1, items 3.3.1-68,3.3.1-69, and 3.3.1-70.

RAJ 3.3.1.74-1 The SRP-LR, Revision 2, Table 3.3-1, items 52 and 53, state that for steel cranes - rails exposed to air-indoor uncontrolled (external) the GALL AMP XI.M23, "Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems," should be used to manage the aging effects/mechanisms of loss of material due to general corrosion and loss of

14 material due to wear. In addition, GALL AMP XI.M23 states that the program manages the effects of wear on the rails in the rail system.

In LRA Table 3.3.1, item 3.3.1-74, the applicant addressed steel cranes - rails exposed to air-indoor uncontrolled (external) that are subject to loss of material due to wear, and stated that this aging concern is not applicable because loss of material due to wear is not identified as an aging effect requiring management. LRA Table 3.5.2-1, Row 9, Table 3.5.2-2, Row 10, and Table 3.5.2-3, Row 2, state that steel cranes - rails components exposed to air-indoor uncontrolled (external) are being managed for loss of material due to general corrosion, but are not managed for loss of material due to wear.

LRA Section B.2.1 0, "Cranes and Hoists Inspection Program," is stated to be an existing Davis-Besse program that is consistent with GALL AMP XI.M23, "Inspection of Overhead Heavy Load and Light Load (Related to Refueling) Handling Systems." In this same section, the applicant stated, "[t]he inspections monitor structural members for signs of corrosion and wear.

The LRA appears to provide contradictory information in regard to its consideration of loss of material due to wear as an applicable aging mechanism for steel cranes - rails exposed to air-indoor uncontrolled (external). In addition, the LRA does not provide sufficient information to justify why loss of material due to wear is not an applicable aging mechanism for steel cranes - rails.

Clarify whether the steel cranes - rails exposed to air-indoor uncontrolled (external) are being managed for loss of material due to wear. If this aging mechanism is being managed, provide additional information on how it will be managed during the period of extended operation. If loss of material due to wear is not being managed for these components, provide justification for not managing this aging mechanism. Additionally, if loss of material due to wear is not being managed for these components, the staff would consider this to be an Exception to the recommendations of GALL AMP XI.M23 requiring an appropriate justification as to why loss of material due to wear would not be of concern.

RAI 3.3.1.75*1 The SRP-LR Table 3.3-1, item 3.3.1-75, states that elastomer seals and components exposed to raw water are affected by hardening and loss of strength due to elastomer degradation, and loss of material due to erosion. The GALL Report recommends the use of the Open-Cycle Cooling Water System to manage this aging effect. In the LRA, the applicant stated that this aging effect will be managed by the One-Time Inspection Program. A one-time inspection is typically used to provide assurance that aging has either not manifested or that the aging is sufficiently slow that it does not require management.

It is not clear to the staff how a one-time inspection will be adequate to detect hardening and loss of strength due to elastomer degradation, and loss of material due to erosion of elastomer seals and components exposed to raw water.

Provide justi"fication for using a One-Time Inspection Program rather than a program such as the Open-Cycle Cooling Water System program, which conducts periodic inspections to manage the aging of the elastomer materials exposed to raw water.

15 RAI 3.3.1.80-1 For LRA Table 3.3.1, item 3.3.1-80, which addresses stainless steel and copper alloy piping components exposed to raw water that are being managed for loss of material due to pitting, crevice, and microbiologically influenced corrosion, the applicant stated that this item is not applicable. Instead, the applicant referred to LRA Table 3.3.1, items 3.3.1-78 or 3.3.1-79.

Item 3.3.1-78 addresses the same components made of comparable materials exposed raw water that are being managed for loss of material due to pitting and crevice corrosion. Item 3.3.1-79 addresses the same components made of the same material that are being managed for loss of material due to pitting and crevice corrosion, and fouling of stainless steel components exposed to raw water. However, neither of these referenced items address loss of material due to microbiologically influenced corrosion.

The applicant did not appear to consider loss of material due to microbiologically influenced corrosion as an aging mechanism in the auxiliary systems for stainless steel and copper alloy piping components exposed to raw water. However, the applicant did not provide sufficient information in the LRA to justify its position.

Clarify whether the stainless steel and copper alloy piping, piping components, and piping elements exposed to raw water are being managed for loss of material due to microbiologically influenced corrosion. If microbiologically influenced corrosion is not being managed for these components, provide justification for not needing to manage this aging mechanism. If this aging mechanism is being managed, provide the additional information on how it will be managed during the period of extended operation.

RAI 3.3.1.85-1 SRP-LR, Table 3.3-1, item 85, recommends that gray cast iron piping, piping components, and piping elements exposed to soil, raw water, treated water, or closed-cycle cooling water be managed by the Selective Leaching of Materials Program for loss of material due to selective leaching. In LRA Table 3.3.2-32, the applicant did not include loss of material due to selective leaching as an applicable aging effect for the gray cast iron heat exchanger shell in the startup feed pump lube oil cooler (DBE30) exposed to closed-cycle cooling water in the turbine plant cooling water system. For the gray cast iron heat exchanger channel in the same cooler, the applicant manages for loss of material due to selective leaching, citing LRA Table 3.3.1, item 3.3.1-85.

It is not clear to the staff why the applicant does not include selective leaching as an aging effect for the gray cast iron heat exchanger shell in the startup feed pump lube oil cooler (DBE30) exposed to closed-cycle cooling water in the turbine plant cooling water system.

State why loss of material due to selective leaching is not an applicable aging effect for the gray cast iron heat exchanger shell in the startup feed pump lube oil cooler (DBE30), or propose an AMP to manage this aging effect.

16 RAI3.3.2.-1 In LRA Table 3.3.2-3, the applicant stated that for copper alloy bolting exposed to air with steam or water leakage (external), there is no aging effect requiring management and no AMP is proposed.

The staff reviewed the associated items in the LRA and noticed that there could be a potential for loss of material due to pitting and crevice corrosion and cracking depending on the potential contaminants because the GALL Report states that copper-zinc alloys greater than 15 percent zinc are susceptible to SCC, selective leaching (except for inhibited brass), pitting and crevice corrosion. Additional copper alloys, such as aluminum bronze, greater than 8 percent aluminum, also may be susceptible to SCC or selective leaching.

Provide justification as to why the specific environment, air with steam or water leakage (external) will not induce loss of material or cracking in copper alloy bolting.

RAI 3.3.2.-2 In LRA Tables 3.3.2-1,3.3.2-12,3.3.2-14, and 3.3.2-30, the applicant stated that copper alloy and copper alloy (Zn greater than 15 percent) and copper alloy heat exchanger tubes - aftercooler and radiator, piping, tubing, valve bodies, spray nozzles exposed to air-outdoor (external/internal) there is no aging effect and no AMP is proposed.

The staff reviewed the associated items in the LRA and found that loss of material due to cracking could occur in copper alloy components exposed to air-outdoor (external/internal) depending on atmospheric contaminants in the environment. The GALL Report states that condensation on the surfaces of systems at temperatures below the dew pOint is considered "raw water" due to the potential for internal or external surface contamination. Copper alloys with greater than 15 percent zinc or greater than 8 percent aluminum exposed to a raw water environment may be susceptible to SCC or selective leaching.

Provide justification as to why the specific environment, air-outdoor (external/internal) will not induce loss of material due to cracking or selective leaching in copper alloys.

RAI 3.3.2.-3 In LRA Tables 3.3.2-15, 3.3.2-17 and 3.3.2-30. the applicant stated that copper alloy (Zn greater than 15 percent) and copper alloy tubing and valve bodies exposed to air-indoor uncontrolled (external) and/or air (internal) there is no aging effect and no AMP is proposed.

The staff noted that in LRA Table 3.0-1. Process Environments, air is defined to be an air environment containing some amount of moisture or contaminants, this includes air - indoor uncontrolled. The staff reviewed the associated items in the LRA and found that loss of material and cracking could occur in copper alloy components exposed to air (internal/external) depending on the contaminants and moisture. The GALL Report states that condensation on the surfaces of systems at temperatures below the dew point is considered "raw water" due to the potential for internal or external surface contamination. Copper alloys with greater than

17 15 percent zinc or greater than 8 percent aluminum exposed to a raw water environment may be susceptible to SCC or selective leaching.

Provide justification as to why the specific environments, air indoor-uncontrolled (external) and/or air (internal) will not induce loss of material due to selective leaching or cracking in copper alloys.

RAJ 3.3.2.1-1 The GALL Report indicates that copper alloys greater than 15 percent zinc exposed to raw waster are susceptible to selective leaching. In LRA Table 3.3.2-1, the applicant stated that copper alloy greater than 15 percent zinc heat exchanger tubes exposed to raw water are being managed for cracking by the Open-Cycle Cooling Water Program. However, the applicant did not indicate that this component is being managed for selective leaching.

It is not clear to the staff why copper alloy greater than 15 percent zinc heat exchanger tubes exposed to raw water are not being managed for selective leaching.

Provide technical justification for not managing copper alloys greater than 15 percent zinc exposed to raw water for selective leaching. If it is determined that selective leaching is an applicable aging effect, indicate what program will be used to manage this aging effect.

RAI 3.3.2.18-1 SRP-LR Section A.1.2.1, item 7 states the determination of applicable aging effects is based on degradations that have occurred and those that potentially could cause structure and component degradation. The SRP-LR also states that the materials, environment, stresses, service conditions, operating experience, and other relevant information should be considered in identifying applicable aging effects.

LRA Table 3.3.2-18, Row Nos. 137 and 138, state that stainless steel 'Tank - Purification demineralizers (DB-T5-1, 2, & 3)" exposed to treated borated water, is subject to loss of material. These components will be managed by the PWR Water Chemistry Program and One-Time Inspection Program. LRA Table 3.3.2-18, Row Nos. 79-80 and 81-82, state that stainless steel piping exposed to treated borated water> 60°C (> 140 OF) is subject to cracking and loss of material, respectively. These components are managed by the PWR Water Chemistry Program and One-Time Inspection Program. Similarly, there are other stainless steel components in LRA Table 3.3.2-18 that are only being managed for loss of material.

Licensee Event Report (LER) 1998-002-01 dated November 7,2003, addresses an event associated with demineralizer resin blockage of the let down line in the makeup and purification system. Due to corrosion in the Purification Demineralizer #3 internal screen, resin was released into the downstream piping. Subsequent inspections of the demineralizer revealed that its internals had degraded, which resulted in demineralizer resin being transported into the filter housings. The screen mesh at the bottom of the demineralizer failed due to extensive pitting corrosion and material deficiencies which allowed the resin breakthrough. A metallurgical analysis indicated that sulfur compounds, which caused a low pH, were likely the cause of the

18 pitting. The likely source of the sulfur compounds was attributed to the degradation of the cation resin beads due to the partially spent condition and extended radiation exposure of the resin.

LER 1998-002-01 indicates that the degradation of the resin beads in Purification Demineralizer

1. 3 resulted in releases of sulfur compounds that caused the extensive pitting of the demineralizer internal screen and the breakthrough of the resin beads to the downstream piping. The staff noted that that a release of sulfur compounds can facilitate stress corrosion cracking. Therefore the staff needs clarification as to whether this operating experience has been adequately evaluated and whether stress corrosion cracking in the demineralizer tanks and their downstream piping needs to be managed.

The staff requests the following information:

1. Describe whether or not the stainless steel components in the makeup and purification system that were previously exposed to sulfur compounds have experienced stress corrosion cracking. In addition, justify why cracking due to stress corrosion cracking is not an aging effect requiring management for the stainless steel demineralizer tanks, including internal screens, and filter housing.

2. If the piping has experienced stress corrosion cracking, justify why the One-Time Inspection Program is adequate to manage cracking due to stress corrosion cracking of the piping rather than a program that includes periodic inspections.

RAJ 3.3.2.2.3.3-1 The GALL Report, Revision 1, Table 3, item 6, states that cracking due to stress corrosion cracking could occur in stainless steel diesel engine exhaust piping, piping components, and piping elements exposed to diesel exhaust. In addition, item VII.H2.AP-128 of the GALL Report, Revision 2, recommends the use of GALL AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components," to manage cracking due to stress corrosion cracking of stainless steel diesel engine exhaust piping, piping components and piping elements.

In LRA Section 3.3.2.2.3.3, the applicant stated that cracking due to stress corrosion cracking could occur in stainless steel diesel engine exhaust piping, piping components, and piping elements exposed to diesel exhaust. The applicant further stated that flexible connections and tubing of the diesel exhaust piping are stainless steel, and other piping components are steel, and cracking due to stress corrosion cracking for stainless steel diesel engine exhaust piping components, though it is not expected to occur, will be managed by the One-Time Inspection Program.

Stress corrosion cracking is a potential aging effect for stainless steel diesel engine exhaust piping, piping components, and piping elements exposed to diesel exhaust as indicated in the GALL Report, Revision 1 and Revision 2. In addition, GALL Report Revision 2 specifies the use of XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components,"

program which is a periodic inspection program to manage the aging effect. However, the applicant credits the One-Time Inspection program to manage the aging effect.

19 Provide technical justification to describe why the One-Time Inspection Program is adequate to monitor the cracking due to stress corrosion cracking aging effect on diesel engine exhaust piping, piping components, and piping elements exposed to diesel exhaust during the period of extended operation.

RAI 3.3.2.2.7.3 -1 The GALL Report, Revision 1, Table 3, item 18, states that loss of material due to general (steel only), pitting, and crevice corrosion could occur for steel and stainless steel diesel engine exhaust piping, piping components, and piping elements exposed to diesel exhaust. In addition, item VII.H2.AP-104 of the GALL Report, Rev. 2, recommends the use of GALL AMP XI.M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components," for steel and stainless steel diesel exhaust piping, piping components, and piping elements.

In LRA Section 3.3.2.2.7.3, the applicant stated that loss of material due to general (steel only),

pitting, and crevice corrosion could occur for steel and stainless steel diesel exhaust piping, piping components, and piping elements exposed to diesel exhaust. The applicant further stated that at Davis-Besse, loss of material due to general (steel only), pitting, and crevice corrosion for steel and stainless steel diesel exhaust piping, piping components, and piping elements that are exposed to diesel exhaust will be managed by the One-Time Inspection program.

Loss of material due to general (steel only), pitting, and crevice corrosion is a potential aging effect for steel and stainless steel diesel engine exhaust piping, piping components, and piping elements exposed to diesel exhaust as indicated in the GALL Report, Rev 1 and Rev 2. In addition, GALL Report, Rev. 2, specifies the use of XI,M38, "Inspection of Internal Surfaces in Miscellaneous Piping and Ducting Components," program which is a periodic inspection program to manage the aging effect. However, the LRA credits the One-Time Inspection program to manage the aging effect.

Provide technical justification to describe why the One-Time Inspection Program is adequate to manage the loss of material due to general (steel only), pitting, and crevice corrosion aging effect on diesel exhaust piping, piping components, and piping elements exposed to diesel exhaust during the period of extended operation.

RAt 3.3.2.2.13-1 In LRA Section 3.3.2.2.13, the applicant stated that wear of elastomer seals and components exposed to air is not identified as an aging effect requiring management at Davis-Besse. It also stated that loss of material due to wear is the result of relative motion between two surfaces in contact. However, wear occurs during the performance of an active function; as a result of improper design, application, or operation; or to a very small degree with insignificant consequences. GALL Report Section IX.F defines wear as the removal of surface layers due to relative motion between two surfaces or under the influence of hard abrasive powder. The GALL Report further states that wear occurs in parts that experience intermittent relative motion or frequent manipulation.

20 The applicant based its conclusion that loss of material due to wear was not an aging effect requiring management (AERM) on the fact that wear is an active loss of material mechanism and not on the fact that the elastomeric HVAC seals and components for which wear is plausible are active components or components that are replaced on a qualified or specified frequency. Within the definition of the term "wear" in GALL Report Section IX.F, there are three factors to consider that could cause age-related wear due to the design of the joint, including (a) relative motion between two surfaces, under the influence of hard abrasive particles, (b) frequent manipulation, or (c) in clamped joints where relative motion is not intended but may occur due to a loss of the clamping force.

It is unclear to the staff whether there are any in-scope components that are designed in such a way that they could be impacted by the three age-related factors considered in the definition of wear.

The staff requests the following information:

1. State whether any in-scope elastomeric components which are designed with relative motion that are exposed to an internal or external environment that includes hard abrasive particles.

2. State whether any in-scope elastomeric components that are susceptible to wear that over time, due to their frequent manipulation could challenge the CLB function(s) of the component.

3. State whether any in-scope elastomeric components that have clamped joints where relative motion is not intended but may occur due to a loss of the clamping force over time causing wear that could challenge the CLB function(s) of the component.

4. If an AERM is applicable based on the configurations or aging mechanisms described in items (1) through (3), discuss how the AERM will be managed.

RAI 3.3.2.2.4-1 In LRA Section 3.3.2.2.4.1, the applicant stated that cracking due to SCC and cyclic loading in stainless steel non-regenerative heat exchanger components is managed by the Water Chemistry Program, and the effectiveness of the Water Chemistry Program will be confirmed by the One-Time Inspection Program. The applicant also stated that the One-Time Inspection Program is selected in lieu of eddy current testing of tubes and that temperature and radioactivity monitoring of shell side water is performed by installed instrumentation. The applicant further stated that cracking due to cyclic loading is not identified as an aging effect requiring management for stainless steel heat exchanger components in the associated environment.

The acceptance criteria in SRP-LR Section 3.3.2.2.4, item 1, states that cracking due to SCC and cyclic loading in stainless steel non-regenerative heat exchangers is managed by monitoring and controlling primary water chemistry. The SRP-LR also states that the effectiveness of water chemistry control programs should be verified, because water chemistry

21 controls do not preclude this aging effect. The GALL Report recommends that a plant-specific AMP be evaluated to ensure these aging effects are adequately managed and an acceptable verification program includes temperature and radioactivity monitoring of the shell side water and eddy current testing of tubes.

In LRA Section B.2.30, "One-Time Inspection Program," the applicant stated that a representative sample of the system and component population will be inspected using a variety of nondestructive examination methods, including visual inspection, volumetric inspection, and surface inspection techniques. It further stated that the sample population will be determined by engineering evaluation, and where practical, will be focused on the components considered most susceptible to aging degradation due to time in service, the severity of the operating conditions, and the lowest design margin. However, it is not clear whether the non-regenerative heat exchangers will be included in the sample of components to be inspected, and since eddy current testing of tubes is not used, what inspection techniques will be used.

In addition, the LRA did not provide the bases for the statement that cyclic loading is not identified as an aging effect requiring management for stainless steel heat exchanger components exposed to treated borated water greater than 60°C.

The staff requests the following information:

1. Clarify whether the non-regenerative heat exchangers will be included in the sample of components to be inspected by the One-Time Inspection Program.

2. Describe the nondestructive examination technique that will be used in lieu of eddy current testing of tubes, which will provide verification of the effectiveness of PWR water chemistry to manage cracking due to SCC in stainless steel non-regenerative heat exchanger components.

3. Provide the bases for the statement that cracking due to cyclic loading is not identified as an aging effect requiring management for stainless steel heat exchanger components exposed to treated borated water greater than 60°C.

RAI 3.3.2.3.12-2 In LRA Tables 3.3.2-12, 3.3.2-14, and 3.3.2-15, the applicant stated that for elastomer flexible connections exposed to fuel oil and lubricating oil internal environments, there is no aging effect and no AMP is proposed. The AMR line items cite generic note F. The GALL Report does not address elastomeric materials exposed to fuel oil or lubricating oil.

Given that certain elastomers such as natural rubbers and ethylene-propylene-diene (EPDM) are not resistant to fuel oil or lubricating oil, the staff needs to know the material of construction of the flexible connections to determine if there are no aging effects.

State the materials of construction of the flexible connections exposed to fuel oil and lubricating oil as listed in LRA Tables 3.3.2-12, 3.3.2-14, and 3.3.2-15.

22 RAI 3.3.2.3.14-1 In LRA Table 3.3.2-14, the applicant identified loss of material and cracking as aging effects for steel bolting exposed to an external environment of raw water. As identified in EPRI NP-5769 and NUREG-1833, loss of pre-load for bolting can occur in any environment.

In LRA Table 3.3.2-14, the applicant did not identify loss of pre-load for steel bolting exposed to an external environment of raw water.

Justify why loss of pre-load is not identified as an aging effect for steel bolting in an environment of raw water.

RAI 3.3.2.3.14-2 In LRA Table 3.3.2-14, the applicant identified cracking as an aging effect for steel bolting and copper alloy greater than 15 percent Zn heat exchanger tubes in an external environment of raw water and credits LRA Section B.2.9, "Collection, Drainage, and Treatment Components Inspection Program," to manage the aging effect using enhanced visual inspections to detect cracking.

It is not clear how the applicant proposes to perform enhanced visual inspections of the bolting and heat exchanger tubes in an external environment of raw water to detect cracking. An external environment of raw water implies that these components will be under water.

Justify how enhanced visual inspections will detect cracking of components under water in an external environment of raw water.

RAI3.3.2.3.14-3 SRP-LR Revision 2 Table 3.3-1, item 112, recommends that steel piping, piping components, and piping elements exposed to concrete do not need to be age managed, provided that the attributes of the concrete are consistent with ACI 318 or ACI 349 and that plant operating experience indicates no degradation of the concrete. LRA Table 3.3.2-14, item 54 (fire protection system), Table 3.3.2-26, item 56 (service water system). Table 3.3.2-31, item 48 (station plumbing, drains. and sumps system), and Table 3.5.2-12. item 7 (yard structures),

state that steel components exposed to concrete do not need to be age managed. LRA Section B.2.39, "Structures Monitoring Program," includes several incidents of operating experience where water leakage through the concrete has occurred. .

It is not clear to the staff whether concrete degradation has occurred in the vicinity of in-scope components described in the request such that the steel components would be exposed to water and thus be subject to corrosion.

The staff requests the following information:

1. State whether concrete degradation has occurred such that water may have intruded into the concrete that surrounds the steel components in the fire protection system.

service water system, station plumbing, drains, and sumps system, and yard structures.

23 If water intrusion has occurred, state how the aging of the steel components will be managed.

2. State how the Structures Monitoring Program, or other plant-specific program, will address water intrusion into concrete to ensure that resulting aging of embedded steel components will be effectively managed during the period of extended operation.

RAJ 3.3.2.2.4.3-1 SRP-LR Rev. 1 Section 3.3.2.2.4, item 3 states that cracking due to sec and cyclic loading could occur for stainless steel pump casing for the PWR high-pressure pumps in the chemical and volume control system.

GALL Report Revision 2, item VII.E1.AP-114 addresses cracking due to sce of the stainless steel high-pressure pump casing in the chemical and volume control system, which is exposed to treated borated water greater than 60°C. It also recommends the Water Chemistry Program and One-Time Inspection Program to manage cracking due to SCC.

GALL Report Revision 2, item VII.E1.AP-115 addresses cracking due to cyclic loading of the stainless steel high-pressure pump casing, which is exposed to treated borated water. It also recommends the ASME Section Xllnservice Inspection, Subsections IWB, IWC, and IWD Program to manage cracking due to cyclic loading.

By contrast, LRA Section 3.3.2.2.4.3 states that cracking due to stress corrosion cracking and cycling loading is not identified as an aging effect requiring management for the stainless steel pump casing for the high-pressure pumps and is not applicable.

It is not clear to the staff how the applicant concluded that cracking due to stress corrosion cracking and cracking due to cyclic loading are not aging effects requiring management for the stainless steel pump casings for the high pressure pumps. The applicant did not provide sufficient justification for its conclusion.

Justify why neither cracking due to stress corrosion cracking nor cracking due to cyclic loading is an aging effect requiring management for the stainless steel high-pressure pump casing in the makeup and purification system. If it is determined that the stainless steel high-pressure pump casing is susceptible to either cracking due to stress corrosion cracking or cracking due to cyclic loading under the exposure conditions, justify how the aging effect(s) will be managed for the component during the period of extended operation.

RAI 3.3.2.3.12-1 SRP-LR Table 3.3-1, item 14, recommends that steel piping, piping components, and piping elements exposed to lubricating oil be managed by the Lubricating Oil Analysis Program and the One-Time Inspection Program. The GALL Report AMP XI.M39, "Lubricating Oil Analysis Program," element 3 "parameters monitored/inspected" states that, for components with periodic oil changes in accordance with manufacturer's recommendations, a particle count and check for water are performed to detect evidence of abnormal wear rates, contamination by

24 moisture, or excessive corrosion. The updated staff position in the GALL Report, Revision 2 AMP XI.M39, element 4 "detection of aging effects" states that the program recommends sampling and testing of the old oil following periodic oil changes or on a schedule consistent with equipment manufacturer's recommendations or industry standards.

In LRA Table 3.3.2-12, item 21, and Table 3.3.2-14, item 167, the applicant stated that loss of material is not applicable to steel air intake filter bodies exposed to lubricating oil in the diesel generators system. The applicant cited Plant-Specific Note 0325, which states that the aging effects are not applicable due to the regular replacement of the lubricating oil. The staff noted that LRA Table 3.3.2-12, items 19 and 20 (adjacent to item 21 above), state that steel filter bodies exposed to lubricating oil in the emergency diesel generators system are managed for loss of material by the Lubricating Oil Analysis Program and One-Time Inspection Programs.

It is not clear to the staff why the applicant does not consider loss of material to be an applicable aging affect for the steel air intake filter bodies exposed to lubricating oil. The GALL Report AMP XI.M39, "Lubricating Oil Analysis Program," takes into account that periodic oil changes will occur and recommends that periodic checks for contamination be performed to ensure that the environment does not become conducive to loss of material. It is also not clear why adjacent steel filter body line items in the emergency diesel generators system are age managed in a different manner.

State why loss of material is not an applicable aging effect for the steel air intake filter bodies when components have regular replacements of lubricating oil, or propose an AMP(s) to manage the aging effect. Also, state why the steel air intake filter bodies are being age managed in a manner different than that of the adjacent steel filter body line items in the emergency diesel generators system.

RAI 3.4.2.3-1 The GALL Report describes condensation as an environment where there is enough moisture for corrosion to occur. It further recommends the External Surfaces Monitoring AMP to manage the aging effect of loss of material and leakage though periodic visual inspections of the external surfaces of in-scope mechanical components, and monitors external surfaces of metallic components in systems within the scope of license renewal.

In Plant-Specific Note 0408 in LRA Table 3.4.2-3, the applicant stated that, except for the motor-driven feedwater pump and startup feed pump portions of the main feedwater system, the control air supply components associated with the main and start-up control valves, and bolting exposed to air with steam or water leakage, loss of material due to general corrosion is not an aging effect requiring management for the external surfaces of steel components in the main feedwater system that are exposed to an air-indoor uncontrolled environment. In Plant-Specific Note 0408, the applicant further stated that the reason the specified components do not require aging management for loss of material due to general corrosion is because their surface temperatures are greater than 212°F (100°C) and are, therefore, expected to be dry.

Given the plant-specific experience of two extended outages in recent years, it is not clear to the staff how the specified components will remain above 212°F (1000 e) throughout their service life

25 in the period of extended operation, and therefore, not be considered susceptible to loss of material due to general corrosion from condensation on the surfaces of systems.

Provide justification that the temperatures of the external surfaces of the main feedwater system exposed to an "air-indoor uncontrolled" environment will not be below 212°F (100°C) during the period of extended operation. If the external surfaces of the main feedwater system may be exposed temperatures below 212°F (100°C), please state how loss of material due to general corrosion will be managed for the subject components.

RAJ 3.4.2.2.5-1 In LRA Sections 3.4.2.2.5.2 and 3.4.2.2.7.3, the applicant stated that loss of material due to pitting and crevice corrosion could occur in gray cast iron and copper alloy heat exchanger components exposed to lubricating oil. In addition, both LRA sections state that loss of material due to selective leaching in these materials is managed by the Lubricating Oil Analysis Program. The associated line items, 3.4.1-12 and 3.4.1-18, both cite Plant-Specific Note 0403 which states that selective leaching is managed by controlling water contamination in the lubricating oil. The staff notes that LRA Section 8.2.26, "Lubricating Oil Analysis Program,"

describes this program as consistent with GALL AMP XI.M39, with no exceptions or enhancements and includes periodic sampling and analysis of lubricating oil to maintain contaminants within acceptable limits. The LRA AMP discusses loss of material due to various mechanisms, but does not specifically cite selective leaching. GALL AMP XI.M33, "Selective Leaching of Materials," recommends visual inspection and hardness measurement or other mechanical examination techniques. Although the LRA shows that the effectiveness of the Lubricating Oil Analysis Program will be verified by the One-Time Inspection Program, the One-Time Inspection Program neither discusses hardness measurements as one of the inspection techniques nor specifically states loss of material due to selective leaching will be considered for the Lubricating Oil Analysis Program.

Since the description of the Lubricating Oil Analysis Program does not state that it manages selective leaching, it is not clear whether the One-Time Inspection Program will verify the effectiveness of the Lubricating Oil Analysis Program for managing loss of material due to selective leaching, for which it is being credited in LRA Sections 3.4.2.2.5.2 and 3.4.2.2.7.3.

Since the detection of selective leaching requires specific examinations such as material hardness measurements, chipping, scraping, etc., it was not clear whether these would be performed under the One-Time Inspection Program or under the Selective Leaching Program, which is also a one-time inspection program.

If loss of material due to selective leaching, for line items 3.4.1-12 and 3.4.1-18, is being managed by the Lubricating Oil AnalYSis Program, then clarify this aspect in the program's description. In addition, confirm that the One-Time Inspection Program, instead of the Selective Leaching Program, will verify the effectiveness of the Lubricating Oil Analysis Program for managing loss of material due to selective leaching.

26 RAI 3.5.2.1-1 The GALL Report (Revision 2) in Table IX.E lists the standardized aging effects due to associated aging mechanisms used in its AMR tables, Chapters II through VIII. GALL XI.M39 "External Surfaces Monitoring of Mechanical Components" and XI.S7 "Regulatory Guide 1.127, Inspection of Water-Control Structures Associated with Nuclear Power Plants," are the AMPs having de-facto provisions to identify changes in material properties. LRA Tables 3.5.2-1 through 3.5.2-13 show a number of concrete structures or components listing "change in material properties," as an aging effect requiring management and list the Structures Monitoring Program enhanced with ACI 349.3R-96 and ANSI/ASCE 11-90, and the included Water Control Structures Inspection Program, to support the detection of this aging effect. For these line items the applicant uses NEI Generic Note "A," which affirms consistency with NUREG-1801 for both the selected AMP and for each identified item for component, material, environment and aging effect.

It is not clear to the staff what material properties the applicant seeks to detect changes to. It is also not clear to the staff how the "change in material properties aging effect" will be detected, especially when some of the line items are difficult to access or below grade, as shown for example in Table(s):

• 3.5.2-1, Rows 61,62;

• 3.5.2-2, Rows 65, 66;

• 3.5.2-3, Rows 34, 25.

For structures or structural components, identification of changes in concrete material properties (e.g., compressive, tensile strengths, etc.) requires testing. For detection of aging effects, enhancement of the Structures Monitoring AMP with ACI 349.3R-96 and ANSIIASCE 11-90 provide guidelines for nondestructive and invasive testing. By contrast EPRI TR-1007933 is a visual examination guide.

The staff requests the following information:

1. For Davis-Besse, explain for the screened class of components and structures why the applicant is concerned with the "change in material properties" and defines this to be an aging effect requiring management.

2. What are the material properties of interest to the applicant and how (what detection techniques) will the applicant detect the anticipated changes?

3. Justify the adequacy of the selections for both properties and techniques.

RAI 3.5.2.2.1.7-1 SRP-LR Revision 1, Section 3.5.2.2.1.7 states that cracking due to stress corrosion cracking of stainless steel penetration sleeves, penetration bellows, and dissimilar metal welds could occur in all types of PWR and BWR containments. LRA Section 3.5.2.2.1.7 states that SCC requires a combination of a corrosive environment, susceptible materials, and high tensile stresses and

27 that; stainless steel must be subject to both high temperature (> 140°F) and an aggressive chemical environment. The applicant also stated that see is not an applicable [aging] effect for stainless steel penetration sleeves and bellows because these components are not subject to an aggressive chemical environment. LRA Table 3.5.2-1 for the containment further indicates that the penetration components are exposed to an air-indoor environment.

LRA Section 3.5.2.2.1.10 states that change in material properties due to leaching of calcium hydroxide is an aging effect requiring management for concrete components. This aging effect is applicable at Davis-Besse due to operating experience indicating water leakage (above and below grade). In view of the observed water leakage associated with concrete structures and components, the staff found a need to further clarify whether the applicant's aging management review adequately evaluated the operating experience with the water leakage in its determination that cracking due to see is not an applicable aging effect for the containment penetration components.

Justify why the water leakage addressed in LRA Section 3.5.2.2.1.10 is not conducive to stress corrosion cracking of the stainless steel penetration sleeves and bellows. As part of the justification, clarify whether the water leakage has been in contact with the containment penetration components and describe the applicant's operating experience in terms of the occurrence of stress corrosion cracking in the containment penetration components. If stress corrosion cracking has been observed, justify why this aging effect has been determined to be not applicable.

RAI 3.5.2.2.2-1 SRP Table 3.5.1, Item 3.5.1-33 recommends further evaluation for any concrete elements that exceed the specified temperature limits of 150°F general and 200°F local.

LRA Section 3.5.2.2.2.3 notes that several localized areas in the upper regions of the containment internal structures have maximum temperatures exceeding 150°F.

The staff is unclear how concrete, having temperatures above the limits in the SRP Table 3.5.1, Item 3.5.1-33, will be managed during the period of extended operation. The staff requests the following information:

1. Provide a listing of locations where concrete temperature exceeds SRP Table 3.5.1.

Item 3.5.1-33 limits for general or local areas.

2. For each of these locations, provide the extent of the region of concrete impacted and the maximum temperature experienced by the concrete.

3. Provide a description of how these locations will be managed during the period of extended operation or an assessment of the impact of the elevated temperature on concrete to demonstrate that the concrete properties have not been adversely impacted.

The staff needs the above information to confirm that the effects of aging such as noted above will be adequately managed so that the intended function of impacted structural members will

28 be maintained consistent with the current licensing basis for the period of extended operation as required by 10 CFR 54.21 (a)(3).

RAI 3.5.2.3.1-1 SRP-LR in Section 4.3, titled "Metal Fatigue," states that ASME Section III requires a fatigue analysis for Class 1 components unless allowed by the Code to be exempted under applicable ASME Section III provisions. The SRP-LR also states, in Section 4.6, titled "Containment Liner Plate Metal Containments, and Penetration Fatigue Analysis," subsection 4.6.1.1, titled

'Time-Limited Aging Analysis," that specific requirements for fatigue analysis are contained in the design code of reference for each plant. The applicant in the LRA stated that the containment vessel meets the requirements of ASME Section III, Paragraph N-415.1; thereby justifying the exclusion of cyclic or fatigue analyses in the design of the containment vessel.

The LRA further states that the containment penetrations are excluded on the basis of N-415.1, Vessels not requiring Analysis for Cyclic Operation. The staff reviewed the USAR and verified that vibrational loads are treated in accordance with ASME Code Section III, paragraph N-415 which precludes fatigue analysis.

LRA Table 3.5.2-1 Aging Management Review Results - Containment, references the GALL Report AMR line item II.A3-4, for cumulative fatigue damage due to cyclic loading of penetration sleeves and bellows made of steel; stainless steel; and dissimilar metal welds for the Containment Vessel. The staff noted that the particular AMR line item is recommended for use only when there is a CLB fatigue analysis.

The staff requests the following information:

1. Does the applicant have a CLB fatigue analysis assessing damage incurred from cyclic loading of penetration sleeves and bellows made of steel; stainless steel; and dissimilar metal welds for the Containment Vessel?

2. If no CLB fatigue analysis exists, explain the apparent contradiction of the AMR Containment Vessel penetrations excluded from fatigue analysis with the II.A3-4, which is recommended only if there is a CLB fatigue analysis.

RAI 3.5.2.3.12-1 The GALL Report (e.g., Item III.B3-7) notes that for steel components providing an intended function of anchorage (e.g., hold down) in an air-indoor uncontrolled or air-outdoor environment loss of material/general and pitting corrosion is an AERM. LRA Table 3.5.2.3-12 states that the wire rope hold down restraints for the emergency diesel generator (EDG) fuel oil tanks subjected to a structural backfill environment do not have an AERM; however, the applicant stated that the Structures Monitoring Program would be used to confirm the absence of aging effects.

The staff is unclear why the wire rope hold down restraints for the EDG fuel oil tanks, subjected to a structural backfill environment, do not have an associated AERM. The staff is also unclear

29 how the Structures Monitoring Program, a visual inspection program can effectively monitor aging of a component in structural backfill.

The staff requests the following information:

1. Explain why loss of material is not an aging effect for the steel restraints in a backfill environment.

2. Explain how the Structures Monitoring Program can monitor aging of components in structural backfill.

RAI 3.5.2.3.12-2 LRA Table 3.5.2.3-12 states that the galvanized steel wave protection dike corrugated pipe casings and carbon steel wave protection dike piles exposed to structural backfill are managed for loss of material by the Structures Monitoring Program. The Wave Protection Dike corrugated pipe casings and Wave Protection Dike piles buried in the wave protection dikes can be exposed to groundwater since the corrugated pipe casings are located below the site groundwater elevation.

Since the Structures Monitoring Program in large measure is visual and the components are located below the site groundwater elevation, the staff is unclear how the Structures Monitoring Program will be utilized to manage loss of material during the period of extended operation.

Explain how the Structures Monitoring Program will be utilized to manage loss of material during the period of extended operation.

RAI 3.5.2.3.13-1 LRA Table 3.5.2-13, Aging Management Review Results - Bulk Commodities, includes lines for fiberglass containment penetration insulation and for calcium silicate or fiberglass piping and mechanical equipment insulation exposed to indoor or outdoor air. In the LRA, the applicant states that there are no aging effects for these material and environment combinations requiring age management and no aging management program is proposed. For the applicable AMR line items, the applicant cites generic note J, indicating that neither the component nor the material and environment combination is evaluated in the GALL Report. The staff noted that mechanical equipment insulation is not addressed in the GALL Report.

In LRA Section 2.1.2.6, the applicant states that thermal insulation may be credited with a specific function (such as in-room heat-up analyses and for structural fire barriers) or be affixed to mechanical components and have potential to fall on, block, or obstruct safety-related components. The applicant also states that insulating materials that function to limit heat transfer, perform a fire barrier function, or must maintain their integrity to prevent interactions with safety-related components are within the scope of license renewal. The LRA treats the fiberglass containment penetration insulation and calcium silicate or fiberglass piping and mechanical equipment insulation exposed to indoor or outdoor air as bulk commodities but does not identify specific locations or applications associated with in-scope insulation components.

30 The staff notes that in a dry environment of indoor or outdoor air, without potential for water leakage, spray, or condensation, fiberglass and calcium silicate are expected to be inert to environmental effects. However, in moist environments, calcium silicate has been found to degrade. In addition, both fiberglass and calcium silicate insulation have the potential for prolonged retention of any moisture to which they are exposed; prolonged retention of moisture may increase thermal conductivity, thereby degrading the insulating characteristics, and also could accelerate the aging of insulated components. The staff noted that the LRA's description of insulation materials includes aluminum jacketing which, if properly installed, provides protection from ambient moisture for the heat-resistant insulating materials.

For those insulation components in LRA Table 3.5.2-13 with a function to limit heat transfer, state how the configuration of the jacketing ensures that it is properly installed so as to prevent water intrusion into the insulation (e.g., seams on the bottom, overlapping seams) such that aging management is not required.

RAI3.6-1 In LRA Table 3.6-1, Item 3.6.1-09 metal enclosed bus - enclosure assemblies, the applicant stated that loss of material due to general corrosion is not applicable to Davis Besse because there is no metal enclosed bus within the scope of license renewal. During a plant walk down, the staff reviewed the station black out recovery path and noted that cable buses are used to connect bus tie transformers and the 4160 V essential switchgear buses. The applicant indicated to the staff that these cable buses were not subject to an AMP because they are not located in an adverse localized environment.

The staff agreed with the applicant that these cable buses are not required to have an AMP because GALL Report (NUREG-1801, Revison 2)Section VI does not recommend aging management for cable in air indoor or outdoor environment. However, the cable buses are protected by enclosure assemblies. These assemblies are made from galvanized steel material. Galvanized steel material in air outdoor or air indoor uncontrolled environment could be subject to loss of material due to general, pitting, and crevice corrosion.

Explain how aging of cable bus enclosure assemblies (including support structures) will be managed during the period of extended operation.

RAJ 3.6-2 In LRA Section 3.6.2.2.2, the applicant stated that industry experience has shown that transmission conductors do not normally swing unless subjected to a substantial wind, and they stop swinging shortly after the wind subsides. The applicant further stated that wind loading that can result in conductor sway is considered in the transmission system design. The applicant then concluded that loss of material due to mechanical wear is not an aging effect requiring management for the high voltage insulators and transmission conductors at Davis Besse.

SRP Section 3.6.2.22 states that loss of material due to mechanical wear caused by wind blowing on transmission conductors could occur in high-voltage insulators. The applicant did not

31 address plant specific operating experience with high-voltage insulator and transmission conductor loss of material due to wear.

Review plant specific operating experience to confirm that wear has not occurred in high-voltage insulators and transmission conductors installed at Davis Besse.

RAI3.6-3 In LRA Section 3.6.2.2.3, the applicant stated that galvanized and aluminum bolted connections are exposed to the same service conditions as the plant switchyard and do not experience any aging effects, except for minor oxidation of the exterior surfaces, which does not impact their ability to perform their intended function.

Aluminum and galvanized connections are highly conductive but do not make a good contact surface since aluminum and galvanized steel exposed to air forms oxides on the inside surface which is nonconductive and could increase the resistance of connections. SRP (NUREG-1800, Rev. 2) Section 3.6.2.2.3 states that increased resistance of connection due to oxidation in transmission conductors and connections, and switchyard bus and connections could occur.

The SRP recommends a plant specific program for management of increase resistance due to oxidation for transmission conductor and switchyard bus connections.

Explain why increase resistance of connections (galvanized and aluminum bolted connections) is not an aging effect requiring management and why an AMP is not needed.

RAI3.6-4 In LRA Table 3.6-1, Item 3.6.1-10 metal enclosed bus - enclosure assemblies, the applicant stated that hardening and loss of strength due to elastomer degradation is not applicable to Davis Besse because there is no metal enclosed bus within the scope of license renewal.

During a plant walk down, the staff reviewed the station black out recovery path and noted that cable buses are used to connect bus tie transformers and the 4160 V essential switchgear buses. The applicant indicated to the staff that these cable buses were not subject to an AMP because they are not located in an adverse localized environment. The staff agreed with the applicant that these cable buses are not required to have an AMP because GALL Report (NUREG-1801, Rev. 2)Section VI does not recommend aging management for cable in air indoor or outdoor environment. However, the cable buses are protected by enclosure assemblies.

It is unclear to the staff whether or not the enclosure assemblies contain elastomers and if so, how they are being managed for hardening and loss of strength.

The staff requests the following information:

1. Explain whether or not the cable bus enclosure assemblies have elastomer components.

2. If the enclosure assemblies have elastomer components explain how aging of the components will be properly managed during the period of extended operation. An

32 appropriate elastomer AMP should include manual manipulation or an explanation of why manual manipulation of elastomers is unnecessary.

RAI4.1-1 LRA Table 4.1-1 states that the CLS does not include any fatigue analysis for Class 1 valves, which is further discussed in LRA Section 4.3.2.3.2. LRA Section 4.3.2.3.2 states that a review of quality assurance records located the stress reports of record for each of the twelve Class 1 valves with four inch or greater diameter, but no associated fatigue analyses were identified.

LRA Section 4.3.2.3.2 also states that "valve bodies were considered robust compared to the piping system in which they were located and fatigue of the attached piping was understood to bound the fatigue of the valve bodies."

USAR Table 5.2-1 identifies that the following Codes are applicable to the design of its Class A or Class 1 valves in the reactor coolant system (RCS):

• Pressurizer safety valves and pressurizer relief valve - 1968 Draft ASME Pump and Valve Code

• Pressurizer Pilot-Operated Relief Pressure Valves -1974 ASME Section III inclusive of the Summer 1976 Addenda

• Pressurizer Spray line Isolation Valve - 1986 ASME Section 11\

• Loop Isolation Valves both 2 Yz inches and larger and 2 inches in diameter and smaller 1971 ASME Section III

• Other Class 1 or Class Valves both 2 Yz inches and larger and 2 inches in diameter and smaller -1971 ASME Section III or later NRC endorsed editions of this code USAR Table 5.1-1 b identifies the valves that are included in the reactor coolant pressure boundary (RCPS).

The staff noted that the terminology for valves in USAR Table 5.1-1 b does not correlate to the terminology of valves in USAR Table 5.2-1, therefore, it is difficult to confirm the statements in LRA Section 4.3.2.3 without clarifications of the specific valves, including the deSign code, in the RCS and RCPS.

The staff has the following issues associated with the Class 1 and Class A valves listed in USAR Table 5.2-1 and in USAR Table 5.1-1b.

Issue 1 - USAR Table 5.1-1 b identifies several valves that are in the RCPS. Specifically for the seal injection flow isolation valve, pump seal return isolation valve, letdown cooler inlet valve, HP injection valve, seal return isolation valve, makeup isolation valve, letdown cooler isolation valve, pressure spray control valve, low pressure injection valve and two DH removal outlet valves, the staff is unable to correlate the specific category these valves are classified under.

These categories include the following, which are identified in USAR Table 5.2-1: "2Yz inch and larger - Loop Isolation Valve," "2 inch and smaller - Loop Isolation Valve," "2Yz inch and larger Other Valves," or "2 inch and smaller - Other Valves." In addition, the staff is unable to determine whether the "pressurizer relief isolation valve" or "pressurizer pilot-operated relief valve (PORV)" in USAR Table 5.1-1 b correlates to the "pressurizer pilot-operated relief isolation valve" that is listed in USAR Table 5.2-1.

33 Without a clear correlation between USAR Table 5.1-1b and USAR Table 5.2-1 the staff is unable to verify the specific edition of ASME Section III used for the design of these valves and determine is a fatigue analysis was required by the design code.

Request 1 Part A:

1) Identify the edition of ASME Section III used for the design, procurement, and installation of the following valves in USAR Table 5.1-1b: (1) the seal injection flow isolation valve; (2) the pump seal return isolation valve; (3) the letdown cooler inlet valve; (4) the HP injection valve; (5) the seal return isolation valve; (6) the makeup isolation valve; (7) the letdown cooler isolation valve; (8) the pressure spray control valve; (9) pressurizer LP injection valve; and (10) each of the DH removal outlet valves.

2) For each of these valves, justify that an It fatigue analYSis was not required in accordance with NB-3545.3 and NB-3550 of the applicable ASME Code Section III edition and the provisions for performing It fatigue analysis in paragraph NB-3553.

3) If an It fatigue analysis was performed as part of the design basis for the specific valve, justify the conclusion that the It fatigue analysis does not need to be identified as a TLAA in accordance with 10 CFR 54.21(c)(1).

Part B:

1) Confirm the description for the "pressurizer relief isolation valve" in USAR Table 5.1-1 b correlates to the "relief valve" in USAR Table 5.2-1.

2) Confirm the description for the "pressurizer pilot-operated relief valve (PORV)" in USAR Table 5.1-1 b correlates to the "pressurizer pilot-operated relief isolation valve" in USAR Table 5.2-1.

3) If not, identify the design code that is applicable for the "pressurizer relief isolation valve" and "pressurizer pilot-operated relief valve" in USAR Table 5.1-1 b.

Issue 2 (Pressurizer Safety Valve and Relief Valve) - USAR Table 5.2-1 indicates that the pressurizer safety valve and relief valve were designed to the 1968 Draft ASME Pump and Valve Code. The staff noted that Sections 452 and 454 of this Code include applicable time dependent cyclic or fatigue assessment criteria for pumps and valves.

Specifically, Section 454 of the Code includes an It parameter metal fatigue analysis (cycling loading analysis). The staff verified that Section 142 of the 1968 Draft ASME Pump and Valve Code identifies that the requirements in Section 452 and 454 needs to be performed only if the inlet nozzle size for the Class 1 pump or valve was greater than 4 inches diameter nominal pipe size. Section 410 of this code states that Chapter 4 procedures and analyses (including those in Sections 452 and 454) need to be performed for small bore pumps or valves (i.e. for those pump or valves with inlet nozzles less than or equal to 4 inches in nominal pipe size) if specified

34 by the owner's design specification. The staff noted that it is possible that small bore pumps or valves could be subject to a time-dependent cyclic or fatigue assessment.

Request 2:

• Justify why an It fatigue analysis was not required for the pressurizer safety and relief valves under the provisions of the 1968 Draft ASME Pump and Valve Code as part of the design basis.

• If an It analysis was performed as part of the design basis for these valves, justify why these analyses do not need to be identified as a TLAA in accordance with 10 CFR 54.21(c)(1).

Issue 3 (Pressurizer Pilot-Operated Relief Isolation Valve) - USAR Table 5.2-1 indicates that the pressurizer pilot-operated relief isolation valve (PPORIV) was designed to the 1974 edition of ASME Section III, inclusive of the 1976 Summer Addenda. The staff noted that Paragraph NB-3545.3 of this code edition required that the pressure retaining portions of these valves be analyzed for fatigue in accordance with the design rules in NB-3550. This includes the requirements for performing a time-dependent (cycle-dependent) It fatigue analysis described in NB-3553. It is not clear to the staff if an It fatigue analysis for the PPORIV was performed in accordance with the requirements of ASME Section 1/1, paragraph NB-3553.

Request 3:

• Justify why an It fatigue analysis was not required for the PPORIV in accordance with paragraphs NB-3545.3 and NB-3550 of the 1974 Edition of the ASME Code Section 1/1 and the provisions for performing It fatigue analyses in paragraph NB-3553.

• If an It analysis was performed as part of the design basis for the PPORIV, justify the conclusion that the It fatigue analysis for the PPORIV does not need to be identified as a TLAA in accordance with 10 CFR 54.21 (c)(1).

Issue 4 (Pressurizer Spray Line Isolation Valve) - USAR Table 5.2-1 indicates that the pressurizer spray line isolation valve (PSLlV) was designed to the 1986 edition of ASME Section III, with no applicable Addenda. The staff noted that Paragraph NB-3545.3 of the 1986 code edition required that the pressure retaining portion of this valve be analyzed for fatigue in accordance with the design rules in NB-3550. This includes the requirements for performing a time-dependent (cycle-dependent) "fatigue analysis in NB-3553. It is not clear to the staff if an It fatigue analysis for the PSLlV was performed in accordance with the requirements of ASME Section III, paragraph NB-3553 Request 4:

• Justify why an It fatigue analysis was not required for the PSLlV in accordance with paragraphs NB-3545.3 and NB-3550 of the 1986 Edition of the ASME Code Section III, and the provisions for performing It fatigue analyses in paragraph NB-3553.

35

• If an It analysis was performed as part of the design basis for the PSLlV, justify the conclusion that the It fatigue analysis for the PSLlV does not need to be identified as a TLAA in accordance with 10 CFR 54.21(c)(1).

RAI4.1-2 LRA Section 4.3.2.2.4 discusses the fatigue TLAA for the reactor coolant pump (RCP) casings and states that they were analyzed for fatigue by the OEM to meet the requirements of the ASME Code Section 111,1968 Edition through Winter-1968 Addenda. LRA Table 3.1.1 item 3.1.1-55 states that these pump casings will be managed by the applicant's Inservice Inspection Program.

The applicant's licensing basis includes a flaw tolerance analysis for the RCP casings that was used to support ASME Code Case N-481's alternate augmented visual inspection bases for the RCP casings. The staff noted that this flaw tolerance analysis is documented in Structural Integrity Associates (SIA) Topical Report No. SIR-99-040, Revision 1, "ASME Code Case N-481 of Davis Besse Reactor Coolant Pumps." (ADAMS Accession No. ML011200090, dated April 23,2001).

The staff noted that the evaluation in Report No. SIR-99-040 includes a cycle-dependent fatigue flaw growth analysis for the pump casings welds that is based on a 40-year design life; however, the applicant did not identify this analysis as a TLAA.

Justify why the fatigue flaw growth analysis for the RCP pump casing welds in SIA Topical Report No. SIR-99-040, Revision 1, does not need to be identified as a TLAA in accordance with 10 CFR 54.21(c)(1).

RAI4.1-3 The LRA Table 4.1-1 identifies "RCS Loop 1 Cold Leg drain line weld overlay repair," as a plant specific TLAA with its disposition discussed in the LRA Section 4.7.5.1. The Section 4.7.5.1 states that, even though there is no time dependency in the weld overlay design that is a full structural overlay assuming the as-found flaw to be 100% through-wall 360-degree, fatigue analysis for the repaired configuration was performed by conservatively estimating cycles for 60 years; as such the analysis is based on a specific number of cycles and so it is a TLAA.

The staff could not identify any other instances of similarly repaired piping and nozzle locations being considered in the LRA as plant-specific TLAAs. From the LRA, it is not clear to the staff if this item in Table 4.1-1 is the only weld overlay repair where fatigue analysis was performed.

Clarify if and why the RCS loop 1 cold-leg drain line weld overlay repair is the only one to include the cycle-based or time dependent flaw growth assumptions. If there are other instances of repairs with similar analyses justify their exclusion from TLAA identification.

36 RAI4.3-1 LRA Section 4.3.2.2 states that:

Cumulative usage factors for the Class 1 components are calculated based on normal and upset design transient definitions contained in the component design specifications. The design transients used to generate cumulative usage factors for Class 1 components are discussed in Section 4.3.1 above. In accordance with Davis-Besse Technical Specification 5.5.5, the Allowable Operating Transient Cycles Program (Fatigue Monitoring Program) provides controls to track the updated safety analysis report (USAR) Section 5 cyclic and transient occurrences to ensure that components are maintained within the design limits.

The staff noted that USAR Table 5.1-8 includes the classification for transients by the plant condition (e.g., normal, upset, emergency, faulted, or test). LRA Table 4.3-1, which is in LRA Section 4.3.1, includes additional transients that are not listed in USAR Table 5.1-8 and the transient classification is also not provided.

The aforementioned statement in LRA Section 4.3.2.2 implies that LRA table 4.3-1 lists only normal and upset design transients. However, the staff noted that Transient #9, "Rapid Depressurization" in LRA Table 4.3-1 is classified as an "Emergency" transient in USAR Table 5.1-8 and it is not clear to the staff if LRA Table 4.3-1 includes all emergency transients that were used in the fatigue analyses.

The staff requests the following information:

1. Clarify whether all fatigue significant transients, that have been included in the fatigue TLAAs, have been included in the LRA Table 4.3-1. Identify the plant condition (e.g.,

normal, upset, emergency, faulted, or test) for each transient listed in LRA Table 4.3-1.

2. Confirm whether the CUF analyses of record included emergency and test conditions in addition to the normal and upset condition. If necessary, clarify and revise the aforementioned statement in LRA Section 4.3.2.2.

RAI4.3-2 LRA Section 4.3.1.2, "Projected Cycles," states that the analysis of the high-pressure injection (HPI) nozzles determined thatthe elbowlets in HPI nozzles 1-1 and 1-2 were limited to 13 cycles for Transients 9A and 9B, respectively. The applicant stated that the current cycles are at 9 and 8 for HPI nozzles 1-1 and 1-2, respectively.

In LRA Table 4.3-1, Transients 9A to 90, labeled "Rapid RCS Depressurization" are listed in the USAR Table 5.1-8 as Transient #8. During its audit, the staff noted discrepancies in the cycle count for Transient #8 of USAR Table 5.1-8, as described in the applicant's existing Fatigue Monitoring Program (identified as "AOTC" by the applicant) logs. In the AOTC log, dated February 1990, it stated that a total of 11 cycles were recorded for this transient, out of the

37 design limit of 13. Furthermore, an AOTC log, dated May 2003, stated that the recorded cycle count for this transient was 9.

In addition, the staff noted, during its audit, that the cycle count from the AOTC log dated February 1990 for this transient exceeded the applicant's 75% action limit, which is based on the design cycle limit of 13 cycles. It is not clear to the staff if the applicant's procedures required corrective actions and the associated results for any corrective actions that may have been taken.

The staff noted, during its audit, that the elbowlets in HPI nozzles 1-1 and 1-2 have a design CUF of 0.981 (with the limit of 13 cycles of Transients 9A and 9B). It is not clear to the staff, if there were other transients that are a significant contributor to fatigue and the number of analyzed cycles in the design CUF calculation for these components.

The staff requests the following information:

1. Describe and justify the discrepancy between cycle counts for Transients 9A to 90, which are listed in LRA Table 4.3-1, and the cycles counts in the AOTC logs dated February 1990 and March 2003.

2. Based on the AOTC log dated February 1990, clarify whether corrective actions were taken, based on the cycle count exceeding the applicant's 75% action limit. If corrective actions were taken, describe the actions taken and the associated results of these actions. If corrective actions were not taken, explain why no action was required.

3. Identify the design transients and associated cycle limits that were used in the fatigue analysis of the HPJ nozzles and elbowlets.

RAI4.3-3 LRA Section 4.3.2.2.2.1 states that the applicant has not replaced the upper thermal shield bolts, flow distributor bolts, or guide block bolts. In addition, LRA Section 4.3.2.2.2.1 states that the reactor vessel internals are designed to meet the stress requirements of ASME Section III, they are not code components. Consequently, a fatigue analysis of the reactor vessel internals was not performed as part of the original design.

LRA Table 3.1.2-2, Row Nos. 42 and 110, for upper thermal shield bolts and flow distribution bolts, respectively, credit a TLAA to manage cumulative fatigue damage.

It is not clear to the staff what TLAA is being referenced by LRA Table 3.1.2-2 Row Nos. 42 and 110, when LRA Section 4.3.2.2.2.1 states that fatigue analyses were not performed for the reactor vessel internals.

Clarify the fatigue TLAA that is being credited to manage cumulative fatigue damage of the components identified by the AMR line items in LRA Table 3.1.2-2 Row Nos. 42 and 110.

38 RAI4.3-4 LRA Section 4.3.2.2.1 "Reactor Vessel" states that the design CUFs for the limiting reactor vessel assembly locations were calculated to be less than 1.0 based on the design transients.

The applicant also dispositioned these fatigue TLAAs in accordance with 10 CFR 54.21 (c)(1)(iii). The staff noted that the bottom head of the reactor vessel assembly is penetrated by the instrumentation nozzles which were analyzed for fatigue due to flow-induced vibrations and discussed in LRA Section 4.3.2.2.2.3. LRA Section 4.3.4.2 discusses the nickel-based incore instrument nozzle and addresses the effect of reactor coolant environment on component fatigue life.

During its audit, the staff noted that the applicant's basis documents, for metal fatigue TLAAs, lists CUF values for the instrument nozzle weld locations that vary from 0 to 0.323. LRA Section 4.3.2.2.2.3 states that the incore instrumentation nozzles were analyzed for fatigue due to flow-induced vibrations (FIV) with the resulting CUF of 0.59 for a 40-year life and was projected to have a CUF of 0.885 for a 60-year life. LRA Section 4.3.4.2 states that the maximum design CUF for nickel-based alloy incore instrument nozzle is 0.77.

The LRA does not indicate the locations that are considered to be limiting, the specific CUF values that are associated with these locations and the design transients used to determine the CUF values. In addition, it is not clear to the staff whether the generic reference of "Instrument Nozzles" in the applicant's basis documents and the LRA refer to the same locations.

The staff requests the following information:

1. Clarify the location(s) that are being referenced by the "Instrument Nozzle" CUFs in LRA Sections 4.3.2.2.1, 4.3.2.2.2.3, 4.3.4.2, and the applicant's basis documents for the metal fatigue TLAA.

2. Clarify which of these locations for the instrument nozzle of the reactor vessel assembly support the aforementioned statement in LRA Section 4.3.2.2.1 and is considered the limiting location. In addition, provide the corresponding limiting CUF values.

RAI4.3-5 LRA Section 4.3.2.2.2.2 discusses the fatigue of reactor vessel internals subject to the flow-induced vibrations. In addition, the fatigue TLAA discussion is based on the endurance limit approach, which establishes the allowable stress limit for infinite fatigue life. The staff noted that ASME Code Section III (Mandatory Appendix I) provides the design fatigue curves.

The applicant stated that the ASME Code fatigue curve was extended to 1E+12 cycles because the 60-year prOjection used in the vessel internals fatigue TLAA exceeds the Code design curves. The applicant stated that an extrapolation of the curve(s) was necessary to obtain the allowable stress limit. It is not clear to the staff which Appendix I design curve was used by the applicant and the method of extrapolation used to establish the endurance limit for the 40-year analysis and the 60-year projection.

39 The staff requests the following information:

1. Clarify and justify the ASME Code Section III (Mandatory Appendix I) design curves used in the extrapolation described in LRA Section 4.3.2.2.2.2 for all the vessel internal materials subject to the flow-induced vibration.

2. Describe and justify the method of extrapolation for the design fatigue curves used in establishing the endurance limits. Provide the allowable stresses and the calculated peak stress intensities for fatigue of the components/locations discussed in the LRA Section 4.3.2.2.2.2.

RAI4.3-6 LRA Section 4.3.2.2.4 states that the reactor coolant pumps (RCP) were analyzed for fatigue by the original equipment manufacturer. The applicant stated that the design CUF for the limiting coolant pump locations were calculated based on the design transients and are all less than 1.0.

The LRA also states that the fatigue TLAA for the reactor coolant pumps will be managed for the period of extended operation by the Fatigue Monitoring Program, in accordance with 10 CFR 54.21(c)(1)(iii).

During its audit, the staff reviewed the applicant's basis documents for the metal fatigue TLAAs and noted that the cooling hole ligament location of the pump cover has a CUF value of 0.56.

The staff also noted that the applicant's basis documents stated the CUF was calculated with an exception to the ASME Code rules. It is not clear to the staff what the exception was, and whether the exception affects the applicant's disposition for this TLAA. The staff noted that LRA Section 4.3.2.2.4 did not discuss the particular location.

Clarify the exception used for the fatigue analysis of cooling hole ligament of the RCP cover and justify that the exception does not affect the TLAA disposition of the reactor coolant pump casing fatigue evaluation.

RAI4.3-7 LRA Section 4.3.2.6.1 states that the steam generators were analyzed for fatigue by the original equipment manufacturer (OEM) and that the CUFs for limiting locations were calculated to be less than 1.0 based on the design transients.

LRA Section 4.3 states that the new design cycle limit for the remotely welded plugs was reduced to 33 cycles (Transient 32 in LRA Table 4.3-1). During its audit, the staff noted in the applicant's basis documents for the metal fatigue TLAA, that manually welded plugs may also be limited to 33 cycles although no specific analysis was performed at the time. The staff also noted that there were other once through steam generator (OTSG) tube plug types that did not need to be qualified to the OEM equipment specification requirements. Furthermore, the staff noted that by letter dated November 3, 2003, the applicant responded to the staff's request for additional information regarding the 2002 steam generator tube inspection (ADAMS Accession No. ML033100370) and stated that there are 36 construction-era welded plugs and two of them were repaired in 2003 with remote welded plugs.

40 It is not clear to the staff if other types of weld plugs, such as the 36 construction-era welded plugs and the two repaired welded plugs that were not discussed in the LRA Section 4.3.2.6.1, have applicable fatigue design analysis. It is also not clear to the staff whether these other types of plugs are bounded by the remotely welded plugs which have a limit of 33 cycles for Transient 32.

Clarify whether there are other types of plugs, other than remote welded plugs, for the steam generator. If so, clarify whether these other types of plugs have applicable fatigue design analysis and provide the applicable design transients and associated limits for these plugs.

RAI4.3-8 LRA Section 4.3.2.2.6.3 states that "The analysis of the auxiliary feedwater thermal sleeve stresses provided a basis for demonstrating that the auxiliary feedwater thermal sleeve is capable of withstanding 300 cycles of auxiliary feedwater injection transients." The applicant also stated that auxiliary feedwater (AFW) initiations (Transients 30A and 30B in LRA Table 4.3-1) are currently at 196.5 and 224.5 cycles, respectively. The staff noted that Transients 30A and 30B are projected to a maximum of 387 and 442 cycles, respectively, through the period of extended operation. These 60-year projections are less than the 875 design cycles for the riser flange attachment but exceed the 300 design cycles for the auxiliary feedwater thermal sleeve.

The staff noted that Transients 30A and 30B in LRA Table 4.3-1 are identified as "Auxiliary Feedwater Bolted Nozzle" (1-1 and 1-2). It is not clear to the staff whether these auxiliary feedwater injection transients refer to those transients identified in LRA Table 4.3-1.

During its audit, the staff noted that the applicant's basis documents for the metal fatigue TLAA indicated that the 3-inch auxiliary feedwater nozzles are limited to 1447 cycles of AFW initiation based on the CUF of 1.0 for the studs. It is not clear to the staff whether the design cycle limit of 1447 cycles for "AFW initiation" is tracked in the applicant's Fatigue Monitoring Program.

The staff requests the following information:

1. Clarify how the "auxiliary feedwater injection transient" for the modified AFW thermal sleeve design is related to the "Auxiliary Feedwater Bolted Nozzle 1-1," Transient 30A in LRA Table 4.3-1, and "Auxiliary Feedwater Bolted Nozzle 1-2,"

Transient 30B in LRA Table 4.3-1.

2. Clarify the cycle limit of 1447 for the "AFW initiations" transient discussed in the basis document for the metal fatigue TLAA and whether this "AFW initiation" transient is monitored by the Fatigue Monitoring Program during the period of extended operation. If not, justify why the "AFW initiations" transient does not need to be monitored by the Fatigue Monitoring Program during the period of extended operation.

41 RAI4.3-9 LRA Section 4.3.1.2 indicates that the number of cycles accrued as of February 2008 were compiled and linearly extrapolated to the 60 years of operation to determine whether the incurred cycles would remain below the number of design cycles.

The applicant did not justify the use of a linear extrapolation to determine the number of cycles for 60 years and whether it is conservative, based on its plant-specific operating history.

Explain the methodology used for the linear extrapolation of design transients and justify that the use of a linear extrapolation to determine the number of cycles for 60 years is valid and conservative, based on the plant-specific operating history.

RAI4.3-10 LRA Table 4.3-1 states that Transients #19, #20A, #208, #20C, #23A, #238, #23C, and #23D are not fatigue significant events. LRA Table 4.3-1 also states that Transients #25A and #258 are not fatigue events. Therefore, the applicant concluded that the monitoring of these transients is not needed The applicant did not provide a discussion to explain and justify why these transients are not fatigue significant events or fatigue events.

Justify why these transients are not considered fatigue significant events or fatigue events. In addition, justify why these transients do not need to be monitored by the Fatigue Monitoring Program during the period of extended operation.

RAI4.3-11 LRA Table 4.3-1 indicates that Transient 22A "Test-High Pressure Injection System" corresponds to Transient 12 in USAR Table 5.1-8. The applicant indicated that Transient 3 "Power change 8-100%" and Transient 4 "Power change 100-8%" correspond to Transient #3 in USAR Table 5.1-8. The applicant stated that these transients are not monitored and provided technical justifications in LRA Table 4.3-1.

The staff noted that cycle counting of the applicant's design basis transients in USAR Table 5.1-8 is required by its Technical Specification (TS) 5.5.5, unless the USAR specifically explains why the design basis transient is not monitored. The staff noted that the Revision 26 of USAR Table 5.1-8 indicates that these transients are applicable to TS 5.5.5 and the USAR does not identify the transients listed above as not requiring cycle counting.

The staff requests the following information:

1. Confirm that the 'Test-High Pressure Injection System", "Power change 8-100%", and "Power change 100-8%" transients are the only transients, listed both in LRA Table 4.3-1 and USAR Table 5.1-8 that require counting per TS 5.5.5, but are not counted by the Fatigue Monitoring Program. If not, identify any additional transients that require

42 counting per TS 5.5.5, but are not counted by the Fatigue Monitoring Program.

2. Clarify whether USAR Table 5.1-8 currently does not require the "Test-High Pressure Injection System", "Power change 8-100%", and "Power change 100-8%" transients from the cycle monitoring requirements of TS 5.5.5.

3. Explain and justify why the monitoring of transients can be omitted without justification in USAR Section 5.2, USAR Table 5.1-8 and the applicant's cycle counting procedure.

RAI4.3-12 The LRA does not provide the CUF values for ASME Code Section III Class 1 components described in LRA Section 4.3.2.

Without these values, the staff is not able to ascertain whether the CUF value for these locations exceeded the allowable limit or evaluate the applicant's dispOSitions of these TLAAs in accordance with 10 CFR 54.21(c).

Provide the design-basis 40-year CUF values for all components and/or critical locations that are applicable to the dispositions discussed in LRA Sections 4.3.2.

RAI4.3-13 LRA Section 4.3.2.3.3 states that the CUF analyses for Class 1 High Energy Line Break (HELB) locations TLAA is dispositioned in accordance with 10 CFR 54.21 (c)(1)(iii). The applicant also stated that the effect of fatigue on the HELB location selection will be managed by the Fatigue Monitoring Program during the period of extended operation.

The staff noted that a CUF value less than 0.1 is one of the HELB location selection criteria discussed in the Standard Review Plan (NUREG-0800) Sections 3.6.1 and 3.6.2, including Branch Technical Position MEB 3-1. The staff also noted that a CUF value less than 1.0 is one of the cumUlative fatigue damage design criteria in ASME Code Section III.

The staff noted that it may be possible that the design cycle limit applicable to HELB piping locations can be less than the "Design Cycles" identified in LRA Table 4.3-1. In addition, the "acceptance criteria" program element in the Fatigue Monitoring Program did not address how the acceptance criteria will be different for HELB and cumulative fatigue damage. The staff noted that the Fatigue Monitoring Program indicates that when the accumulated cycles approach the design cycles, corrective actions will be taken to ensure the analyzed number of cycles is not exceeded. However, the Fatigue Monitoring Program does not discuss the situation when the accumulated cycles approach the limit in the HELB analyses.

The staff requests the following information:

1. Identify the ASME Code Class 1 piping locations discussed in USAR Section 3.6.2 that are within the scope of LRA Section 4.3.2.3.3. Provide the design-basis transients and associated cycle limits that are applicable to each HELB piping location that are within

43 the scope of LRA Section 4.3.2.3.3.

2. Justify that the Fatigue Monitoring Program can adequately ensure the CUF for HELB locations remain below 0.1 by using systematic counting of plant transient cycles associated with HELB analysis. Provide any appropriate revisions to the program elements of the Fatigue Monitoring Program, as needed, to incorporate activities for ensuring that the CUF for HELB locations remain below 0.1.

RAI4.3-14 In LRA Section 4.3.4, the applicant discussed the methodology to determine the locations that require environmentally assisted fatigue (EAF) analyses consistent with NUREG/CR-6260 "Application of NUREG/CR-5999 Interim Fatigue Curves to Selected Nuclear Power Plant Components." The staff recognized that, in LRA Table 4.3-2, there are fifteen plant-specific locations listed, based on the six generic components identified in NUREG/CR-6260.

The GALL Report AMP X.M1, "Metal Fatigue of Reactor Coolant Pressure Boundary" states that the impact of the reactor coolant environment on a sample of critical components should include the locations identified in NUREG/CR-6260 as a minimum, and that additional locations may be needed. It was not clear to the staff whether the applicant verified that the plant-specific locations listed in the LRA Table 4.3-2 were bounding for the generic NUREG/CR-6260 components. Furthermore, the staff noted that the applicant's plant-specific configuration may contain locations that should be analyzed for the effects of the reactor coolant environment other than those identified in NUREG/CR-6260.

The staff requests the following information:

1. Confirm and justify that the plant-specific locations listed in LRA Table 4.3-2 are bounding for the generic NUREG/CR-6260 components.

2. Confirm and justify that the LRA Table 4.3-2 locations selected for environmentally assisted fatigue analyses consists of the most limiting locations for the plant (beyond the generic locations identified in the NUREG/CR-6260 guidance). If these locations are not bounding, clarify the locations that require an environmentally assisted fatigue analysis and the actions that will be taken for these additional locations.

RAI4.3-15 LRA Section 4.3.1.2 states that "Transients 9C, 90, and 32 are the only transients affecting Class 1 components where the 60-year projected cycles exceed the design cycles".

The applicant stated that HPI nozzles 2-1 and 2-2 are limited to 40 cycles for Transients 9C and 90, respectively, and it will manage cumulative fatigue damage of these nozzles for the period of extended operation. However, it is not clear to the staff if there are other components that have Transient 9C or 90 in the design-basis fatigue calculation and whether these components will be affected if the 60-year projected cycles are exceeded.

44 Clarify whether there are other components that include Transients 9C or 9D in their design basis fatigue calculation. If there are other components that use Transient 9C or 9D in their design-basis fatigue calculations, identify the number of design cycles in those fatigue calculations. Discuss and justify the fatigue TLAA disposition of these components.

RAI4.3-16 LRA Section 4.3.4.2 and LRA Table 4.3-2 states that the in-air design CUFs were adjusted by reducing conservatism in the original design calculations and/or by refining the material specific Fen factor. LRA Table 4.3-2 provided a summary of the adjusted CUFs and environmentally adjusted Uen factors.

Specific to the reactor vessel inlet and outlet nozzles and the pressurizer surge nozzle safe-end, the applicant stated that incremental fatigue contributions were identified and reduced based on the 60-year projected cycles. Specific to the high pressure injection/makeup nozzle and stainless steel safe-end, the applicant stated that although conservatism in the design analysis was removed and it still maintained the full-set of 40-year NSSS design transients.

It is not clear to the staff which incremental contributions were reduced based on the 60-year projected cycles, which transients were used and the number of cycles that were used in the analysis. Furthermore, it is not clear to the staff which variables in the original design calculations were adjusted, what elements of conservatism were reduced and the basis for these adjustments and reductions.

The staff requests the following information:

1. For each location in which the incremental fatigue contributions were reduced based on the 60-year projected cycles, provide the following:

a. Identification of the transients used in the original design CUF calculation.

b. The analyzed number of cycles used for the transients identified above in the CUF calculation.

c. Clarification on how the incremental fatigue contribution was adjusted.

2. Clarify if there are other variables and elements of the original design calculations that were used to reduce the conservatism in the original CUFs of record. Describe and justify the reduction of conservatism for each variable and element in the original CUFs of record.

RAI4.3-17 LRA Section 4.3.4.2 states that the surge line piping and high pressure injection/makeup (HPIIMU) nozzle and safe end were evaluated using an integrated Fen approach consistent with EPRI Technical Report MRP-47, "Guidelines for Addressing Fatigue Environmental Effects in a License Renewal Application," Revision 1, Section 4.2.

45 The staff noted that consistent with MRP-47. Section 4.2, the CUF and Uen are computed for each load pair and an effective Fen is calculated by dividing the Uen by the CUF. LRA Section 4.3.4 states that the maximum Uen is calculated with a global Fen and the adjusted CUF is then obtained by dividing the Uen by the global Fen.

The staff noted that EPRI Technical Report MRP-47 has not been reviewed and approved by the NRC. Furthermore, the applicant stated that in footnote 2 of LRA Table 4.3-2 the global Fen is calculated using the method from Section 4.2 of MRP-47. However, the term "global Fen" is not discussed in MRP-47. The staff further noted that the process of calculating global Fen is not discussed in the LRA.

Therefore. it is not clear to staff how the applicant determined the environmentally adjusted CUF for the surge line piping and HPIIMU nozzle and safe end.

The staff requests the following information:

1. Justify that use of the integrated Fen approach in the EPRI MRP-47 is applicable and adequately conservative to calculate Uen for the period of extended operation.

2. Clarify the term "global Fen" and how it is calculated for each component. Provide its relationship with Uen calculation methodology discussed in MRP-47.

RAI4.3-18 In LRA Appendix A. Table A-1. Commitment No. 23. the applicant committed to evaluate the environmental effects on the replacement high pressure injection (HPI) nozzle safe ends and associated welds in accordance with NUREG/CR-6260 and the guidance of EPRI Technical Report MRP-47, "Guidelines for Addressing Fatigue Environmental Effects in a License Renewal Application," Revision 1. Section 4.2 EPRI Technical Report MRP-47 has not been reviewed and approved by the NRC. In addition, the applicant does not specify the specific portions of MRP-47 that will be used as part of this evaluation of environmental effects on the replacement HPI nozzle safe ends and associated welds. The staff noted that the applicant's Fatigue Monitoring Program with enhancements, in which the applicant stated is consistent with GALL AMP X.M1, addresses the effects of the reactor coolant environment on component fatigue life.

Justify that the use of EPRI Technical Report MRP-47 will properly evaluate the environmental effects on the replacement HPI nozzle safe ends and associated welds, in lieu of performing the evaluation and managing cumulative fatigue damage as part of the Fatigue Monitoring Program, which is consistent with the recommendations of the GALL AMP KM1.

RAI4.3-19 LRA Section 4.3.4.2, specifically the discussion of the environmental fatigue usage evaluation for the stainless steel surge line piping, states that the 60-year transient projections were used

46 for the evaluation with the exception of the 60-year projection of heatuplcooldowns (HU/CDs),

where a best estimate number of 114 total cycles were used.

The staff noted that LRA Table 4.3-1 states that the 60-year projection cycles for HU and CDs are each 128 cycles, which is based on the linear extrapolation method described in the LRA Section 4.3.1.2.

In LRA Appendix A, Table A-1, Commitment No.9, the applicant committed to monitor any transient where the 60-year projected cycles were used in an environmentally-assisted fatigue evaluation and establish an administrative limit that is equal to or less than the 60-year projected cycles. However, in this particular analysis for the stainless steel surge line piping, the staff noted that the analyzed number of cycle for HU/CDs is less than the 60-year projected cycle.

The staff requests the following information:

1. Provide the basis of using 114 total HUlCDs in the environmental fatigue usage evaluation for the stainless steel surge line piping. Justify that the Fatigue Monitoring Program and Commitment NO.9 ensure that corrective actions are taken prior to the HUlCDs transients exceeding the analyzed number of cycles of 114 for each transient.

2. Clarify whether there are any additional locations in which the analyzed transient cycles are less than the 60-year projected cycles listed in LRA Table 4.3-1. If so, identify these locations and the associated analyzed cycles and the 60-year projected cycles for the applicable transients. In addition, justify that the Fatigue Monitoring Program ensures that corrective actions are taken prior to the applicable transients exceeding the analyzed number of cycles.

RAI4.3-20 LRA Section 4.3.2.2.6.4 states the CUF for the 3/8" tube stabilizers is calculated using both high cycle (flow-induced vibration) and low cycle (transients) fatigue. The applicant also stated that the cumulative usage factors are only 0.12 for the tube-to-stabilizer weld and 0.07 for the nail.

In addition, the applicant stated that the flow induced vibration portion of these cumulative usage factors can be increased by 1.5 for 60 years and the cumulative usage factors will remain below 1.0.

The applicant stated that in accordance with 10 CFR 54.21 (c)(1)(ii), the TLAA associated with the flow induced vibration of the steam generator tubes and tube stabilizers has been projected through the period of extended operation.

It is not clear to the staff whether the CUF values of 0.12 and 0.07 for the tube-to-stabilizer weld and the nail, respectively, include both high cycle and low cycle fatigue.

It is also not clear to the staff why only the flow induced vibration portion of these CUF values are increased by 1.5 to demonstrate that the TLAA is valid for the period of extended operation

47 and how the low cycle (transient) portion of the CUF value is being dispositioned in accordance with 10 CFR 54.21(c).

The staff requests the following information:

1. Clarify whether the CUFs of 0.12 and 0.07 are calculated considering both high cycle and low cycle fatigue.

2. Justify why the low cycle (transients) fatigue portion of the CUF values for the tube-to-stabilizer weld and nail do not need to be increased by 1.5 to determine if they will remain below 1.0. In addition. provide the disposition in accordance with 10 CFR 54.21 (c){1) for the low cycle (transient) portion of the fatigue TLAA for the tube-to-stabilizer weld and nail.

RAI4.3-21 LRA Section 4.3.4.2 states that an environmentally assisted fatigue correction factor. Fen. was determined using material specific guidance contained in NUREG/CR-6583 "Effects of LWR Coolant Environments on Fatigue Design Curves of Carbon and Low-Alloy Steels" and in NUREG/CR-6909. "Effect of LWR Coolant Environments on the Fatigue Life of Reactor Materials."

LRA Section 4.3.4.2 states that the following bounding Fen values calculated are: 1.74 for carbon steel, 2.45 for low-alloy steel and 4.16 for the nickel-based alloy incore instrument nozzles.

The staff noted that based on the guidance in NUREG/CR-6583 and NUREG/CR-6909. the Fen factor can vary based on sulfur content, temperature, dissolved oxygen, and strain rate. The staff noted that for nickel-based alloy components, per the guidance in NUREG/CR-6909. the Fen factor can be as high as 4.52. In addition for carbon and low-alloy steel components, per the guidance in NUREG/CR-6583, the Fen factor can vary Significantly depending on the plant's history of dissolved oxygen content.

It is not clear to the staff, how the applicant determined the bounding Fen factors for the carbon and low-alloy steel and nickel-based alloy components that are described in LRA Section 4.3.4.2 and LRA Table 4.3-2.

The staff requests the following information:

1. Clarify how the bounding Fen factors for the carbon and low-alloy steel and nickel-based alloy components were determined.

2. Justify any assumptions, on the parameters such as sulfur content, temperature, dissolved oxygen, and strain rate, which were used in determining the Fen factors for these components. As part of the justification, specifically for carbon and low-alloy steel, confirm that dissolved oxygen remained less than 0.05ppm since initial plant operation.

If it has not, justify that the Fen factors are bounding.

48

3. Justify that the dissolved oxygen content will remain less than 0.05ppm during the period of extended operation, such that the Fen factors are bounding for the conditions at the plant.

RAI4.3-22 LRA Section A.2.3, Metal Fatigue, is divided into the following subsections:

• Section A.2.3.1, Class 1 Code Fatigue Requirements

• Section A.2.3.2, Class 1 Fatigue Analyses

• Section A.2.3.3, Non-Class 1 Fatigue Analyses

• Section A.2.3.4, Generic Industry Issues on Fatigue 10 CFR 54.21(d) requires that UFSAR supplement contain an appropriate summary description of all TLAA evaluations in the LRA.

The staff noted that LRA Section A.2.3.1 discusses the fatigue requirements for the reactor vessel and its components, Class 1 piping, and the once-through steam generator (OTSG) components. However, LRA Section A.2.3.2 does not include a summary description for all of the Class 1 components that received fatigue analysis in LRA Section 4.3.2 and its subsections.

Specifically, the staff noted LRA Section A.2.3 does not include a summary description subsection for the following Class 1 components:

• Reactor vessel (RV) assembly shell components (LRA Section 4.3.2.2.1 has the corresponding analysis basis RV assembly components)

• Class 1 piping designed to ANSI 831.7 requirements (LRA Section 4.3.2.3.1 has the corresponding analysis basis)

• OTSG primary and secondary shell components (LRA Section 4.3.2.2.6.1 has the corresponding analysis basis)

Justify why LRA Section A.2.3 does not include a summary description for the RV shell assembly and its components, the Class 1 piping designed to ANSI 831.7 requirements, and the OTSG primary and secondary shells and their components.

May 2,2011 Barry S. Allen Vice President, Davis-Besse Nuclear Power Station FirstEnergy Nuclear Operating Company 5501 North State Route 2 Oak Harbor, OH 43449

SUBJECT:

REQUEST FOR ADDITIONAL INFORMATION FOR THE REVIEW OF THE DAVIS-BESSE NUCLEAR POWER STATION - BATCH 3 (TAC NO. ME4640)

Dear Mr. Allen:

By letter dated August 27, 2010, FirstEnergy Nuclear Operating Company, submitted an application pursuant to Title 10 Code of the Federal Regulation Part 54 for renewal of Operating License NPF-3 for the Davis-Besse Nuclear Power Station. The staff of the U.S. Nuclear Regulatory Commission (NRC or the staff) is reviewing this application in accordance with the guidance in NUREG-1800, "Standard Review Plan for Review of License Renewal Applications for Nuclear Power Plants.>> During its review, the staff has identified areas where additional information is needed to complete the review. The staff's requests for additional information are included in the Enclosure. Further requests for additional information may be issued in the future.

Items in the enclosure were discussed with Mr. Cliff Custer, of your staff, and a mutually agreeable date for the response is within 30 days from the date of this letter. If you have any questions, please contact me by telephone at 301-415-2277 or bye-mail at brian.harris2@nrc.gov.

Sincerely, IRA!

Brian K. Harris, Project Manager Projects Branch 1 Division of License Renewal Office of Nuclear Reactor Regulation Docket No. 50-346

Enclosure:

As stated cc w/encl: Listserv DISTRIBUTION:

See next page ADAMS Accession No ML111170204 OFFICE: LA:DLR* PM:RPB1 :DLR BC:RPB1 :DLR NAME: YEdmonds BHarris BPham DATE: 5/2111 512/11 512/11 OFFICIAL RECORD COpy

Letter to B. Allen from B. Harris Dated May 2,2011

SUBJECT:

REQUEST FOR ADDITIONAL INFORMATION FOR THE REVIEW OF THE DAVIS-BESSE NUCLEAR POWER STATION - BATCH 3 (TAC NO. ME4640)

HARD COPY:

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